<PAGE> 1
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON MAY 2, 2000
REGISTRATION STATEMENT NO. 333-96331
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- --------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
AMENDMENT NO. 3 TO
FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
COHO ENERGY, INC.
(Exact name of registrant as specified in its charter)
<TABLE>
<CAPTION>
TEXAS 1311 75-2488635
<S> <C> <C>
(State or other jurisdiction of (Primary Standard Industrial (IRS Employer
incorporation or organization) Classification Code Number) Identification Number)
</TABLE>
<TABLE>
<S> <C>
14785 PRESTON ROAD, SUITE 860 MICHAEL MCGOVERN,
DALLAS, TEXAS 75240 PRESIDENT AND CHIEF EXECUTIVE OFFICER
(972) 774-8300 14785 PRESTON ROAD, SUITE 860
(Address, Including Zip Code, and DALLAS, TEXAS 75240
Telephone Number, Including Area Code, (972) 774-8300
of Registrant's Principal Executive Offices) (Name, Address, Including Zip Code, and
Telephone Number, Including Area Code,
of Agent for Service)
</TABLE>
With a Copy to:
HARVA R. DOCKERY, ESQ.
FULBRIGHT & JAWORSKI L.L.P.
2200 ROSS AVENUE, SUITE 2800
DALLAS, TEXAS 75201
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable after this Registration Statement becomes effective.
If any of the securities being registered on this form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, check the following box. [ ]
If this form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ]
If this form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If this form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]
---------------------
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SECTION 8(a), MAY
DETERMINE.
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<PAGE> 2
THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. WE
MAY NOT SELL THESE SECURITIES UNTIL THE REGISTRATION STATEMENT FILED WITH
THE SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PROSPECTUS IS NOT
AN OFFER TO SELL THESE SECURITIES AND IT IS NOT SOLICITING AN OFFER TO BUY
THESE SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT PERMITTED.
PROSPECTUS SUBJECT TO COMPLETION. DATED MAY 1, 2000.
UP TO 11,355,804 SHARES
[COHO LOGO]
COHO ENERGY, INC.
COMMON STOCK
---------------------
We are distributing to the holders of our old common stock rights as of
March 6, 2000, to purchase up to an aggregate of 8,663,846 shares of our new
common stock. The total purchase price of the shares offered will be $90,103,998
if this rights offering is fully subscribed. The rights are not transferable and
will not be listed for trading on any stock exchange. We are also registering an
additional 2,691,958 shares of new common stock for distribution to the lenders
who participated in the standby loan made under the terms of our plan of
reorganization.
If you owned common stock on March 6, 2000, the record date for this rights
offering, you will receive, at no cost, a right to buy 0.338 shares of new
common stock at a price of $10.40 per share for each share of common stock that
you owned on the record date. This right is called the basic subscription
privilege. If you decide to purchase all of the shares that you are eligible to
purchase under the basic subscription privilege, you may also offer to buy
additional shares of new common stock at the same subscription price per share.
This right is called the over-subscription privilege. We will round the number
of rights you receive to the nearest whole number.
The rights are exercisable beginning on the date of this prospectus. The
rights will expire if they are not exercised by 5:00 p.m., New York City time,
on May 31, 2000, the expected expiration date of the rights. If you wish to
participate in this rights offering, we recommend that you follow the
instructions set forth in this prospectus and that you submit all subscription
documents and payments to the subscription agent at least 10 days before the
deadline. All subscriptions will be held in escrow by our subscription agent,
ChaseMellon Shareholder Services, L.L.C., until accepted by us. We, in our sole
discretion, may extend the period for exercising the rights.
The new common stock has had a very limited trading history since we emerged
from bankruptcy. Since April 3, 2000, the new common stock has traded in the
over-the-counter market under the symbol "CHOH." On April 28, 2000, the last
price at which the new common stock traded in the over-the-counter market was
$5.00.
---------------------
INVESTING IN THE NEW COMMON STOCK INVOLVES A HIGH DEGREE OF RISK. YOU
SHOULD CAREFULLY CONSIDER THE "RISK FACTORS" BEGINNING ON PAGE 8 BEFORE
PURCHASING ANY OF THE NEW COMMON STOCK.
---------------------
SUBSCRIPTION PRICE: $10.40 PER SHARE
<TABLE>
<CAPTION>
PER SHARE TOTAL
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<S> <C> <C>
Public Offering Price....................................... $10.40 $90,103,998
Estimated Expenses.......................................... $ 0.06 $ 550,000
Net Proceeds to Coho........................................ $10.34 $89,553,998
</TABLE>
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED THESE SECURITIES OR DETERMINED IF THIS
PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
---------------------
THE DATE OF THIS PROSPECTUS IS MAY 1, 2000.
<PAGE> 3
TABLE OF CONTENTS
<TABLE>
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PAGE
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<S> <C>
QUESTIONS AND ANSWERS ABOUT THE RIGHTS OFFERING............. 1
PROSPECTUS SUMMARY.......................................... 4
SUMMARY CONSOLIDATED FINANCIAL INFORMATION.................. 5
SUMMARY HISTORICAL RESERVES AND OPERATING DATA.............. 7
RISK FACTORS................................................ 8
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS... 13
GLOSSARY.................................................... 14
THE RIGHTS OFFERING AND PLAN OF DISTRIBUTION................ 16
THE OFFERING TO STANDBY LENDERS............................. 23
USE OF PROCEEDS............................................. 24
DIVIDEND POLICY............................................. 24
PRICE RANGE OF COMMON STOCK................................. 25
CAPITALIZATION.............................................. 26
SELECTED FINANCIAL DATA..................................... 28
THE PLAN OF REORGANIZATION.................................. 29
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS................................. 35
BUSINESS.................................................... 48
OIL AND GAS OPERATIONS...................................... 52
MANAGEMENT.................................................. 71
EXECUTIVE COMPENSATION...................................... 73
SECURITY OWNERSHIP OF PRINCIPAL BENEFICIAL OWNERS AND
MANAGEMENT................................................ 78
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.............. 80
DESCRIPTION OF EXISTING INDEBTEDNESS........................ 81
DESCRIPTION OF OUR CAPITAL STOCK............................ 84
DILUTION.................................................... 86
LEGAL MATTERS............................................... 87
INDEPENDENT AUDITORS........................................ 87
ENGINEERS................................................... 87
WHERE YOU CAN FIND MORE INFORMATION......................... 87
INDEX TO FINANCIAL STATEMENTS............................... F-1
</TABLE>
i
<PAGE> 4
QUESTIONS AND ANSWERS ABOUT THE RIGHTS OFFERING
WHY ARE WE CONDUCTING THE RIGHTS OFFERING?
We are conducting this rights offering to raise capital as part of a
comprehensive plan of reorganization under Chapter 11 of the Bankruptcy Code.
Our plan of reorganization is designed to provide us with additional financial
flexibility and to allow us to continue as a going concern. The rights offering
is made to shareholders as of the record date, March 6, 2000.
WHAT IS THE RIGHTS OFFERING?
The rights offering is a distribution of rights on a pro rata basis to all
of our shareholders who held shares of our common stock on March 6, 2000, the
record date. "Pro rata" means in proportion to the number of shares of our old
common stock that you and the other shareholders held on the record date. We are
distributing 0.338 rights for each share of our old common stock held on the
record date. We will not issue any fractional rights, but rather will round any
fractional rights to the nearest whole number.
WHAT IS A RIGHT?
Each right entitles the shareholder to purchase one share of our new common
stock at a subscription price of $10.40 per share. Each right carries with it a
basic subscription privilege and an over-subscription privilege.
WHAT IS THE NEW COMMON STOCK?
On March 31, 2000, the effective date of confirmation of our plan of
reorganization, we canceled our old common stock and issued new common stock.
Generally, the new common stock carries the same rights as the old common stock,
except that holders of the new common stock will not have cumulative voting
rights. See the sections of this prospectus called "The Plan of Reorganization"
and "Description of Our Capital Stock" for more information regarding the new
common stock.
WHAT IS THE BASIC SUBSCRIPTION PRIVILEGE?
The basic subscription privilege of each right entitles you to purchase one
share of our new common stock for the subscription price.
WHAT IS THE OVER-SUBSCRIPTION PRIVILEGE?
The over-subscription privilege of each right entitles you, if you fully
exercise your basic subscription privilege, to subscribe to purchase additional
shares of new common stock at the same subscription price per share.
WHAT ARE THE LIMITATIONS ON THE OVER-SUBSCRIPTION PRIVILEGE?
We will be able to satisfy your exercise of the over-subscription privilege
only if other rights holders do not fully exercise their basic subscription
privileges. If sufficient shares of our new common stock are available, we will
honor the over-subscription requests in full. If over-subscription requests
exceed the number of shares which are available, we will allocate the available
shares pro rata among those rights holders who over-subscribed, based on the
number of shares purchased under the basic subscription privilege.
WHAT IS THE STANDBY LOAN?
On March 31, 2000, the effective date of confirmation of our plan of
reorganization, we entered into a loan with some of our bondholders and others
to borrow $72 million. This loan is also called the standby loan, and the
lenders are called the standby lenders, in this prospectus. Under the terms of
the standby loan, the standby lenders will be issued shares of new common stock
representing 14.4% of all shares of
1
<PAGE> 5
new common stock outstanding, including any shares issued in the rights
offering. See the section of this prospectus called "Dilution" for more
information. These shares that will be issued to the standby lenders are being
offered to the standby lenders under this prospectus.
ARE THERE ANY ANTI-DILUTION PROTECTIONS?
Yes, there is limited anti-dilution protection for shares subscribed in the
rights offering. Under the standby loan, we will issue additional shares of new
common stock to the standby lenders. The number of shares to be issued to those
lenders, assuming no shares are issued under the rights offering, is 2,691,958.
Shares issued under the rights offering will not be diluted by shares issued
under the standby loan. Persons who receive shares under the rights offering
will receive additional shares to ensure that their percentage ownership of our
new common stock issued under the rights offering remains constant after taking
into account shares issued under the standby loan. Shares purchased in this
rights offering will carry no other anti-dilution protection if and when we
issue more new common stock or other securities in the future. For more
information regarding anti-dilution protection, see the section of this
prospectus called "Dilution."
WHEN WILL THE RIGHTS EXPIRE?
The rights will expire at 5:00 p.m., New York City time, on May 31, 2000,
unless we extend the time for exercise of the rights.
WHAT SHOULD I DO IF I WANT TO PARTICIPATE IN THE RIGHTS OFFERING BUT MY SHARES
ARE HELD IN THE NAME OF MY BROKER OR A CUSTODIAN BANK?
If you hold shares of our old common stock through a broker, dealer or
other nominee, we will ask your broker, dealer or nominee to notify you of the
rights offering. If you wish to exercise your rights, you will need to have your
broker, dealer or nominee act for you. To indicate your decision with respect to
your rights, you should complete and return to your broker, dealer or nominee
the form entitled "Beneficial Owner Election Form," together with your check for
the subscription price of the rights you wish to exercise. You should receive
this form from your broker, dealer or nominee with the other offering materials.
WILL I BE CHARGED A COMMISSION OR FEE IF I EXERCISE MY RIGHTS?
No. We will not charge a brokerage commission or a fee to rights holders
for exercising their rights. However, if you exercise your rights through a
broker or nominee, you will be responsible for any fees charged by your broker
or nominee.
ARE THERE ANY CONDITIONS TO EXERCISING MY RIGHTS?
Yes. The exercise of your rights is subject to the conditions described
under the heading "The Rights Offering and Plan of Distribution -- Conditions to
the Rights Offering" in this prospectus.
MAY I SELL OR TRANSFER MY RIGHTS IF I DO NOT WANT TO PURCHASE ANY SHARES?
No. The rights are not transferable and may not be sold.
WILL I BE ABLE TO TRADE MY RIGHTS ON THE NASDAQ STOCK MARKET?
No. The rights will not be listed for trading on the Nasdaq Stock Market or
any other stock exchange.
IF I EXERCISE RIGHTS IN THE RIGHTS OFFERING, MAY I CANCEL OR CHANGE MY DECISION?
No. All exercises of rights are irrevocable unless the conditions to
completion of this rights offering are not satisfied or waived before the
subscription period ends. If we extend the subscription period, you will be able
to change your decision.
2
<PAGE> 6
IF THE RIGHTS OFFERING IS NOT COMPLETED, WILL MY SUBSCRIPTION PAYMENT BE
REFUNDED TO ME?
Yes. The subscription agent will hold all funds it receives in escrow until
the rights offering is completed or terminated. If the rights offering is not
completed, the subscription agent will return all subscription payments
promptly, without interest or deduction.
IS PARTICIPATION IN THE RIGHTS OFFERING RECOMMENDED?
We and the subscription agent are not making any recommendations as to
whether or not you should exercise your rights or participate in the rights
offering. You should decide whether to subscribe for our new common stock based
on your own assessment of your best interests in consultation with your
financial and legal advisors.
WHAT SHOULD I DO IF I HAVE OTHER QUESTIONS?
If you have questions or need assistance, please contact ChaseMellon
Shareholder Services L.L.C., the subscription agent for the rights offering, at
(888) 224-2734.
Banks and brokerage firms please call (917) 320-6285.
For a more complete description of this rights offering, see the section of
this prospectus called "The Rights Offering and Plan of Distribution."
3
<PAGE> 7
PROSPECTUS SUMMARY
This summary highlights information contained in this prospectus. This
summary does not contain all of the important information that you should
consider before exercising the rights and investing in our new common stock. You
should read the entire prospectus carefully, including the section called "Risk
Factors" and the financial data and related notes, before making an investment
decision. The terms "Coho," "our," "us" and "we" as used in this prospectus
refer to Coho Energy, Inc. and its consolidated subsidiaries, unless we indicate
otherwise or the context otherwise requires. Additional definitions related to
oil and gas terms are located in the section of this prospectus called
"Glossary."
COHO ENERGY, INC.
We are an independent energy company engaged, through our wholly owned
subsidiaries, in the development and production of, and exploration for, crude
oil and natural gas. Our operations are concentrated principally in the U.S.
Gulf Coast and Mid-Continent regions, including Mississippi, Oklahoma and Texas.
At December 31, 1999, our total proved reserves were 113.9 MMBOE, of which
approximately 94% were comprised of crude oil and approximately 69% were proved
developed. The present value of estimated future net cash flows, before income
taxes, of proved crude oil and natural gas reserves, discounted at an assumed
rate of 10%, was $790.2 million. We also have substantial exploitation reserve
growth opportunities, including recompletions, drilling and waterflood projects.
Additionally, we have exploration and exploitation reserve growth opportunities
associated with our 3-D seismic databases in Mississippi and Oklahoma within the
geographical confines of our existing fields. Of the 21 major producing
properties in which operations are conducted, we operate 17 and own an average
working interest of approximately 77% in these operated properties. Our
significant control of operations and geographic focus have resulted in
substantial operating economies of scale that have enabled us to maintain a low
cost structure.
Our strategy is to maximize production and increase reserves through
- relatively low-risk activities such as development and delineation
drilling, multi-zone completions, recompletions, enhancement of
production facilities and secondary recovery projects;
- use of 3-D seismic and other technologies to identify exploration
projects and to identify reserves;
- acquisition of controlling interests in underdeveloped crude oil and
natural gas properties; and
- significant control of operations.
Our executive offices are located at 14785 Preston Road, Suite 860, Dallas,
Texas 75240, and our telephone number is (972) 774-8300.
RECENT DEVELOPMENTS
On November 30, 1999, we filed our plan of reorganization with the United
States Bankruptcy Court for the Northern District of Texas. At a hearing on
February 4, 2000, the bankruptcy court approved our disclosure statement with
respect to the plan of reorganization. In that hearing, the bankruptcy court
also scheduled a confirmation hearing to consider the plan of reorganization for
March 15, 2000. On February 14, 2000, we and the Official Committee of Unsecured
Creditors jointly filed the Debtors' and Creditors Committee's First Amended and
Restated Chapter 11 Plan of Reorganization to reflect the matters contained in
the approved disclosure statement. On February 15, 2000, we filed the approved
disclosure statement with the bankruptcy court and on February 14, 2000, we
began mailing it to holders of claims and equity interests for voting on our
plan of reorganization.
Subsequently, we obtained approval of our plan of reorganization. On March
20, 2000, the bankruptcy court entered a confirmation order confirming our plan
of reorganization, as amended and restated, and on March 31, 2000, our plan of
reorganization became effective and was consummated.
4
<PAGE> 8
SUMMARY CONSOLIDATED FINANCIAL INFORMATION
Our summary historical consolidated financial information presented below
has been derived from our audited consolidated financial statements for each of
the years in the three-year period ended December 31, 1999. Additionally, the
December 31, 1999 balance sheet data has been adjusted for the following
circumstances:
- to give pro forma effect for projected operating results through March
31, 2000, the effective date of our plan of reorganization, and to give
pro forma effect to the consummation of our plan of reorganization;
- to give pro forma effect for the issuance of shares of new common stock
and the repayment of borrowings under the new credit facility assuming
that all of the rights are exercised in the rights offering, excluding
the additional 10,000 shares of new common stock we are registering in
this prospectus to account for the effects of the rounding of rights
being granted to the shareholders; and
- to give pro forma effect for the issuance of shares of new common stock
and the repayment of borrowings under the new credit facility assuming
20% of the rights are exercised in the rights offering, excluding the
additional 10,000 shares of new common stock we are registering in this
prospectus to account for the effects of the rounding of rights being
granted to the shareholders.
This information should be read in conjunction with the other information
contained under the captions "Capitalization," "Selected Financial Data," and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and in conjunction with our consolidated financial statements and
related notes to those financial statements included in this prospectus.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1997 1998 1999
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<S> <C> <C> <C>
STATEMENT OF EARNINGS DATA:
Operating revenues........................................ $63,130 $ 68,759 $ 57,323
Operating expenses........................................ 15,970 26,859 21,155
General and administrative expenses....................... 7,163 7,750 9,905(1)
Reorganization costs...................................... -- -- 3,123
Depletion and depreciation................................ 19,214 28,135 13,702
Writedown of crude oil and natural gas properties......... -- 188,000 5,433
Net interest expense...................................... 10,474 32,721 33,698
Other expense............................................. -- 3,023 1,048
Income tax expense (benefit).............................. 4,021 (14,383) (26)
Net earnings (loss)....................................... 6,288 (203,346) (30,715)
Basic earnings (loss) per common share.................... 0.29 (7.94) (1.20)
Diluted earnings (loss) per common share.................. 0.28 (7.94) (1.20)
OTHER FINANCIAL DATA:
Capital expenditures...................................... $72,667 $ 70,143 $ 6,349
EBITDA(2)................................................. 39,997 31,127 22,093
</TABLE>
<TABLE>
<CAPTION>
PRO FORMA PRO FORMA PRO FORMA
AS OF UPON PURCHASE OF PURCHASE OF
DECEMBER 31, EFFECTIVENESS ALL SHARES 20% OF SHARES
1999 OF THE PLAN IN RIGHTS OFFERING IN RIGHTS OFFERING
------------ ------------- ------------------ ------------------
<S> <C> <C> <C> <C>
BALANCE SHEET DATA:
Working capital (deficit)(3)........................... $(407,490) $ (1,151) $ (1,151) $ (1,151)
Net property and equipment............................. 311,788 310,408 310,408 310,408
Total assets........................................... 348,801 364,584 377,544 367,176
Long-term debt, excluding current portion.............. -- 259,452 169,452 241,452
Total shareholders' equity............................. (91,958) 81,598 184,558 102,190
</TABLE>
- ---------------
(1) General and administrative expenses for the year ended December 31, 1999
were substantially higher than those expenses for 1998 primarily due to the
expensing of all salaries and other general and administrative costs
associated with exploration and development activities during 1999 as
compared to the capitalization of $5.7 million of those costs in the year
ended December 31, 1998.
5
<PAGE> 9
(2) "EBITDA" refers to earnings before interest, taxes, depreciation, depletion
and amortization. EBITDA should not be considered as an alternative to, or
more meaningful than, net income or cash flow as determined in accordance
with generally accepted accounting principles as an indicator of our
operating performance or liquidity.
(3) Working capital (deficit) includes $388,685 related to the current portion
of long-term debt.
6
<PAGE> 10
SUMMARY HISTORICAL RESERVES AND OPERATING DATA
The following table sets forth summary information with respect to our
estimated proved crude oil and natural gas reserves and our operations as of the
dates or for the periods indicated. For more information regarding our reserves
and our operations, see the section of this prospectus called "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
our consolidated financial statements and the related notes to those financial
statements included in this prospectus.
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
----------------------------------
1997 1998 1999
---------- -------- ----------
<S> <C> <C> <C>
PROVED RESERVES:
Crude oil and condensate (MBbls)............................ 95,084 100,004 107,113
Natural gas (MMcf).......................................... 147,505 66,328 40,638
Total (MBOE)...................................... 119,668 111,059 113,886
Estimated future net cash flows (before income tax, in
thousands)................................................ $1,043,516 $549,018 $1,784,368
Present value of proved reserves (in thousands)............. $ 526,277 $269,298 $ 790,154
Proved developed reserves as a percent of total reserves.... 70% 67% 69%
</TABLE>
SUMMARY OPERATING DATA
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------
1997 1998 1999
------ ------ ------
<S> <C> <C> <C>
PRODUCTION VOLUMES:
Crude oil and condensate (MBbls)............................ 2,820 5,069 3,343
Natural gas (MMcf).......................................... 7,666 8,124 2,608
Total (MBOE)...................................... 4,098 6,424 3,778
AVERAGE SALES PRICE PER UNIT:
Crude oil and condensate (per Bbl).......................... $16.31 $10.40 $15.40
Natural gas (per Mcf)....................................... 2.23 1.98 2.24
PER BOE DATA:
Average sales price......................................... $15.41 $10.70 $15.17
Production expenses......................................... 3.90 4.18 5.60
</TABLE>
7
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RISK FACTORS
An investment in our new common stock is extremely risky. You should
carefully consider the following factors, together with the other information
contained in this prospectus, before deciding to exercise your rights. An
investment in our new common stock involves a high degree of risk and may not be
appropriate for investors who cannot afford to lose their entire investment.
RISK FACTORS RELATING TO OUR BUSINESS
THE BANKRUPTCY MAY HAVE CREATED A NEGATIVE IMAGE OF US.
The effect, if any, which our plan of reorganization may have on our
operations now that it has been consummated cannot be accurately predicted or
quantified. We believe that the consummation of our plan of reorganization will
have a minimal future effect on our relationships with our customers, employees
and suppliers. Our plan of reorganization was consummated on March 31, 2000, but
there could be a detrimental impact on future sales and patronage because of the
negative image of us that may have been created by the bankruptcy.
OUR LEVEL OF DEBT MAY NOT ALLOW US PROPERLY TO PLAN FOR FUTURE OPPORTUNITIES
OR TO COMPETE EFFECTIVELY.
After the consummation of our plan of reorganization, we have a significant
amount of indebtedness. Assuming the completion of the purchase of all shares of
new common stock under the rights offering, our total consolidated indebtedness
would be $169.5 million and the ratio of total consolidated indebtedness to
total capitalization would be 48%. Our high level of indebtedness will have
several important effects on our future operations, including:
- requiring us to devote a substantial portion of our cash flow from
operations to pay interest on our indebtedness and not for other uses,
such as funding working capital or capital expenditures;
- limiting our ability to obtain additional financing in the future for
working capital, capital expenditures, acquisitions, general corporate
purposes or other purposes;
- putting us at a competitive disadvantage to our competitors who have less
debt than us; and
- limiting our flexibility to plan for, or to react to, changes in our
business and the industry in which we operate.
Please refer to the sections of this prospectus called "The Plan of
Reorganization -- The New Debt and Equity" and "Description of Existing
Indebtedness" for a description of our new indebtedness after consummation of
our plan of reorganization.
LIQUIDITY CONSTRAINTS MAY HINDER OUR CONTINUED OIL AND GAS OPERATIONS.
We have historically funded our operations primarily through our cash flow
from operations and borrowings under credit sources. Due to our need to conserve
capital, we have reduced maintenance of our wells, which has substantially
reduced our cash flow from operations. We anticipate our principal sources of
liquidity during the next 12 months will be cash on hand, including the net
proceeds of the rights offering and the standby loan, and cash generated by
operations. For more information regarding our liquidity constraints, see the
sections of this prospectus called "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources," "Description of Existing Indebtedness" and our consolidated
financial statements and the related notes included in this prospectus.
Our ability to raise funds through additional indebtedness is limited by
the terms of our plan of reorganization. Additionally, substantially all of our
crude oil and natural gas properties are subject to a lien for the benefit of
the lenders under the new credit facility, further limiting our ability to incur
additional indebtedness. We may also choose to issue equity securities or sell
assets to fund our operations, although the terms of our new indebtedness limit
our use of the proceeds of any sale of assets. For a description of these
limitations, see the sections of this prospectus called "The Plan of
Reorganization --
8
<PAGE> 12
The New Debt and Equity" and "Description of Existing Indebtedness." If we elect
to raise additional capital by issuing equity securities, there can be no
assurance that we will be able to obtain equity financing on satisfactory terms.
PAST SUBSTANTIAL NET LOSSES MAY AFFECT FUTURE OPERATIONS.
We experienced a substantial loss for the year ended December 31, 1998 of
$203.3 million and for the year ended December 31, 1999 of $30.7 million. There
can be no assurances that we will become profitable in the future. For more
information regarding our losses, see the section of this prospectus called
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and our consolidated financial statements and the related notes
included in this prospectus.
WE MAY NOT BE ABLE TO REPLACE DEPLETED RESERVES THAT ARE NECESSARY TO CONTINUE
OUR PRODUCTION.
The rate of production from crude oil and natural gas properties declines
as reserves are depleted. Except to the extent we acquire additional properties
containing proved reserves, or conduct successful exploration and development
activities or, through engineering studies, identify additional formations with
primary or secondary reserve opportunities on our own properties, our proved
reserves will decline as reserves are produced. Future crude oil and natural gas
production is therefore highly dependent on our level of success in finding and
acquiring additional reserves. Our ability to continue acquiring producing
properties or companies that own producing properties assumes that major
integrated oil companies and independent oil companies will continue to divest
many of their crude oil and natural gas properties. There can be no assurance
that these divestitures will continue or that we will be able to acquire
producing properties at acceptable prices. Our ability to develop additional
reserves is limited by the terms of the new credit facility and the standby
loan, each of which limits our ability to obtain additional financing in the
future for acquisitions and capital expenditures.
OUR PROFITABILITY IS HIGHLY DEPENDENT ON INDUSTRY CONDITIONS THAT HAVE, IN THE
PAST, CAUSED US TO IMPLEMENT SIGNIFICANT WRITEDOWNS OF OUR ASSETS.
Our revenue, profitability and future rate of growth substantially depend
on prevailing prices for crude oil and natural gas. Crude oil and natural gas
prices can be extremely volatile and in recent times have been depressed by
excess total domestic and imported supplies. Prices are also affected by actions
of state and local agencies, the United States and foreign governments and
international cartels. Prices for crude oil and natural gas have recently
rebounded from historic lows on an inflation-adjusted basis. There can be no
assurance that commodity prices will rise or will not return to historic lows.
These external factors and the volatile nature of the energy markets make it
difficult to estimate future prices of crude oil and natural gas. The
substantial and extended decline in the prices of crude oil and natural gas,
until recently, adversely affected our financial condition and the results of
our operations, including reduced cash flow and borrowing capacity, which has
not been overcome by the most recent price rebound. All of these factors are
beyond our control.
We periodically review the carrying value of our crude oil and natural gas
properties under the full cost accounting rules of the Securities and Exchange
Commission. Under these rules, capitalized costs of proved oil and natural gas
properties may not exceed a present value, based on flat prices at a single
point in time, of estimated future net revenues from proved reserves, discounted
at 10%. Application of the ceiling test generally requires pricing future
revenue at the unescalated prices in effect as of the end of each fiscal quarter
and requires a write-down for accounting purposes if the ceiling is exceeded. We
were required to write down the carrying value of our crude oil and natural gas
properties during 1998 by an aggregate of $188 million. We took a write-down of
our Tunisian properties of $5.4 million during the third quarter of 1999 once it
was determined that an exploratory well drilled in Tunisia, North Africa would
not produce sufficient quantities of crude oil to justify further completion
work on the well. When a write-down is required, it results in a charge to
earnings, but does not affect cash flow from operating activities. Once
incurred, a write-down of crude oil and natural gas properties is not reversible
at a later date.
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WE RELY ON ESTIMATES OF PROVED RESERVES AND FUTURE NET REVENUE INFORMATION
THAT ARE SUBJECT TO MANY FACTORS AND ANY NEGATIVE VARIANCE IN THESE ESTIMATES
COULD AFFECT OUR REPORTED ASSETS AND OUR ABILITY TO BORROW FUNDS.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond our control. The reserve
data included in this prospectus represent only estimates. In addition, the
estimates of future net revenue from proved reserves and their present value are
based on assumptions about future production levels, prices and costs that may
not prove to be correct over time. In particular, estimates of crude oil and
natural gas reserves, future net revenue from proved reserves and the present
value of proved reserves for the crude oil and natural gas properties described
in this prospectus are based on the assumption that future crude oil and natural
gas prices remain the same as crude oil and natural gas prices at December 31,
1999. The NYMEX prices as of December 31, 1999, used for purposes of our
estimates were $25.60 per Bbl of crude oil and $2.33 per Mcf of natural gas. Any
significant variance in actual results from these assumptions could also
materially affect the estimated quantity and value of our reserves.
IF WE ARE UNABLE TO COMPETE EFFECTIVELY AGAINST MAJOR OIL COMPANIES AND OTHER
INDEPENDENT OPERATORS, WE MAY BE UNABLE TO OBTAIN NECESSARY MATERIALS AND
RESOURCES AND MAY EXPERIENCE A SIGNIFICANT DISRUPTION OF OUR OPERATIONS.
We encounter strong competition from major oil companies and independent
operators in acquiring properties and leases for the exploration for, and
production of, crude oil and natural gas. Competition is particularly intense
with respect to the acquisition of desirable undeveloped crude oil and natural
gas properties. Many of our competitors have financial resources, staff and
facilities substantially greater than ours. Although we believe our current
operating and financial resources will be adequate to preclude any significant
disruption of our operations in the immediate future, the continued availability
of these materials and resources to us cannot be assured.
WE ARE SUBJECT TO SIGNIFICANT GOVERNMENT REGULATION THAT MAY HINDER OUR
ABILITY TO CONDUCT OUR BUSINESS.
Our business is subject to federal, state, provincial and local laws and
regulations relating to the exploration for and development, production and
marketing of crude oil and natural gas, as well as environmental and safety
matters. These laws and regulations have generally become more stringent in
recent years, often imposing greater liability on a larger number of potentially
responsible parties. Because the requirements imposed by these laws and
regulations are frequently changed, we are unable to predict the ultimate cost
of compliance with these requirements. There is no assurance that laws and
regulations enacted in the future will not hinder our ability to conduct our
business. For more information regarding regulations that affect us, see the
sections of this prospectus called "Oil and Gas Operations -- Governmental
Regulations" and "Oil and Gas Operations -- Environmental Regulations."
WE HAVE A HIGH LEVEL OF DEPENDENCE ON TWO CUSTOMERS THAT CAN DIRECTLY AFFECT
OUR INCOME STATEMENT.
During 1999, two purchasers of our crude oil and natural gas, EOTT Energy
Operating Limited Partnership and Amoco Production Company, accounted for 39%
and 41%, respectively, of our revenues. While we believe that our relationships
with EOTT and Amoco are good, any loss of revenue from these customers due to
nonpayment by the customer would have an adverse effect on our net income and
earnings per share on our income statement and, ultimately, may affect our share
price. In addition, any significant late payment may adversely affect our short
term liquidity position.
OUR INDEPENDENT AUDITOR'S REPORT INDICATES THAT WE MAY NOT BE ABLE TO CONTINUE
AS A GOING CONCERN.
The independent auditor's report on our financial statements is qualified
with respect to our ability to continue as a going concern. Specifically, the
report notes that we had recurring losses, we defaulted on our old bank credit
facility, and we had negative cash flow from operations in 1999. The financial
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statements included in this prospectus have been prepared assuming we will
continue as a going concern, though that assumption may not necessarily be true.
See the section of this prospectus called "Management's Discussion and Analysis
of Financial Condition and Results of Operations" and Note 2 to our consolidated
financial statements included in this prospectus for more information regarding
our ability to continue as a going concern.
RISK FACTORS RELATING TO THE RIGHTS OFFERING AND OUR NEW COMMON STOCK
SHAREHOLDERS WHO DO NOT EXERCISE THEIR RIGHTS WILL EXPERIENCE DILUTION.
The rights offering, the issuance of additional shares to our standby
lenders based on the success of the rights offering, and the issuance of
additional shares to rights offering participants pursuant to the limited
anti-dilution protection may result in our issuance of up to an additional
12,992,282 shares of our new common stock. These additional issuances assume
full exercise of the rights, excluding the additional 10,000 shares of new
common stock we are registering in this prospectus to account for the effects of
rounding of rights being granted to shareholders. If you choose not to fully
exercise your rights, your relative ownership interests will be diluted. If you
do not exercise your rights, you will relinquish any value inherent in the
rights.
YOU MAY NOT REVOKE YOUR EXERCISE OF RIGHTS AND THE RIGHTS OFFERING MAY NOT BE
COMPLETED.
Once you exercise your rights, you may not revoke the exercise unless the
conditions to our obligations to complete the rights offering are not satisfied
or waived before the subscription period ends. In that case, we may extend the
date the rights expire. If we extend the termination date of the rights, you
will be able to change your decision. If we elect to withdraw or terminate the
rights offering, neither we nor the subscription agent will have any obligation
with respect to the rights except to return to you any subscription payments,
without interest or deduction.
THE SUBSCRIPTION PRICE MAY NOT REFLECT THE VALUE OF OUR SHARES.
The subscription price does not necessarily bear any relationship to the
book value of our assets, historic or future cash flows, financial condition,
recent or historic prices for our old common stock or new common stock or other
established criteria for valuation. You should not consider the subscription
price as an indication of the value of our shares. See the section of this
prospectus called "The Rights Offering and Plan of Distribution -- Determination
of Subscription Price" for further detail regarding the way in which the
subscription price was determined.
THE ANTITAKEOVER EFFECTS OF SOME OF THE PROVISIONS OF OUR GOVERNING DOCUMENTS
MAY PREVENT SOME TRANSACTIONS.
Some of the provisions of our amended and restated articles of
incorporation and amended and restated bylaws may tend to deter potential
unsolicited offers or other efforts to obtain control that are not approved by
our board of directors. These provisions include the right of our board of
directors, without any action by our shareholders, to fix the rights and
preferences of undesignated preferred stock, including dividend, liquidation and
voting rights. All of these provisions apply to the new common stock, and may
have the effect of delaying, deferring or preventing a change of control.
IF OUR NEW COMMON STOCK IS NOT LISTED ON THE NASDAQ STOCK MARKET OR ANY OTHER
STOCK EXCHANGE, THE PRICE OF THE NEW COMMON STOCK MAY BE DEPRESSED AND YOU MAY
HAVE DIFFICULTIES RESELLING THE STOCK.
We intend to explore the possibility of listing the new common stock on the
Nasdaq Stock Market or on one or more other national securities exchanges.
However, there can be no assurance that we will determine that it is feasible,
practicable or advisable to list the new common stock or that, if an application
is made, that the new common stock would be approved for listing. Our inability
to secure the listing of the new common stock or the decision not to list the
new common stock will affect the liquidity and marketability of the new common
stock. Whether or not the new common stock is approved for listing
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on the Nasdaq Stock Market or any other national securities exchange, the new
common stock may trade in the over-the-counter market. Even if the new common
stock is approved for listing on the Nasdaq Stock Market or any other national
securities exchange, there can be no assurance as to the price as to which any
shares of the new common stock may be traded when issued or that an established
market for those securities will develop.
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This prospectus includes statements that may be deemed to be
"forward-looking statements" within the meaning of Section 27A of the Securities
Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All
statements, other than statements of historical facts, included in this
prospectus that address activities, events or developments that we expect,
project, believe or anticipate will or may occur in the future, including:
- crude oil and natural gas reserves,
- future acquisitions,
- future drilling and operations,
- future capital expenditures,
- future production of crude oil and natural gas, and
- future net cash flow
are forward-looking statements. These statements are based on assumptions and
analyses made by us in light of our experience and our perception of historical
trends, current conditions, expected future developments and other factors we
believe are appropriate in the circumstances. These types of statements are
subject to a number of assumptions, risks and uncertainties, including those
related to:
- competition,
- general economic and business conditions,
- prices of crude oil and natural gas,
- the business opportunities, or lack thereof, that may be presented to and
pursued by us,
- changes in laws or regulations, and
- the other factors discussed above under the heading "Risk Factors" in
this prospectus.
These types of statements are not guarantees of future performance and
actual results or developments may differ materially from those projected in the
forward-looking statements. You should not rely on this information as an
estimate or prediction of future performance.
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GLOSSARY
Unless otherwise indicated, natural gas volumes are stated at the legal
pressure base of the state or area in which the reserves are located at 60
degrees Fahrenheit. The following definitions apply to the technical terms used
in this prospectus:
"2-D seismic" means an interpretive data set that allows a view of a
vertical cross-section beneath a prospective area.
"3-D seismic" means an interpretive data set that allows a view of a
vertical cross-section as well as a horizontal cross-section beneath a
prospective area.
"Bbls" means barrels of crude oil, condensate or natural gas liquids, and
is equivalent to 42 U.S. gallons.
"Bcf" means billions of cubic feet.
"BOE" means barrel of oil equivalent, assuming a ratio of six Mcf to one
Bbl.
"BOPD" means Bbls per day.
"Developed acreage" means acreage which consists of acres spaced or
assignable to productive wells.
"Dry hole" means a well found to be incapable of producing either crude oil
or natural gas in sufficient quantities to justify completion as a crude oil or
natural gas well.
"Gravity" means the Standard American Petroleum Institute method for
specifying the density of crude petroleum.
"Gross" means the number of wells or acres in which we have an interest.
"MBbls" means thousands of Bbls.
"MBOE" means thousands of BOE.
"Mcf" means thousands of cubic feet.
"MMBbls" means millions of Bbls.
"MMBOE" means millions of BOE.
"MMbtu" means millions of British Thermal Units.
"MMcf" means millions of cubic feet.
"Net" is determined by multiplying gross wells or acres by our working
interest in those wells or acres.
"Present value of proved reserves" means the present value discounted at
10% of estimated future net cash flows before income taxes of proved crude oil
and natural gas reserves.
"Productive well" means a well that is not a dry hole.
"Proved developed reserves" means only those proved reserves expected to be
recovered from existing completion intervals in existing wells and those
reserves that exist behind the casing of existing wells when the cost of making
those reserves available for production is relatively small relative to the cost
of a new well.
"Proved reserves" means natural gas, crude oil, condensate and natural gas
liquids on a net revenue interest basis, found to be commercially recoverable.
"Proved undeveloped reserves" means those reserves expected to be recovered
from new wells on undrilled acreage or from existing wells where a relatively
major expenditure is required for recompletion.
"Recompletion" means leaving one formation for another formation within a
well bore.
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"Secondary recovery" means a method of oil and natural gas extraction in
which energy sources extrinsic to the reservoir are used.
"Undeveloped acreage" means leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of crude oil and natural gas, regardless of whether or not that
acreage contains proved reserves.
"Unitized" means the royalty and working interests are pooled within a
given geological and/or geographical area.
"Waterflood" means the injection of water into oil bearing formations to
displace the oil.
"Workover" means the performing of work within a well bore associated with
the currently producing formation.
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THE RIGHTS OFFERING AND PLAN OF DISTRIBUTION
BEFORE EXERCISING OR SELLING ANY RIGHTS, YOU SHOULD READ CAREFULLY THE
INFORMATION CONTAINED UNDER THE CAPTION "RISK FACTORS" IN THIS PROSPECTUS.
The following describes the rights offering and plan of distribution in
general and assumes, unless specifically provided otherwise, that you were a
record holder of our old common stock as of March 6, 2000. If you hold your
shares in a brokerage account or through a dealer or other nominee, please see
"-- Beneficial Owners" below.
THE RIGHTS
If you were a record holder of our old common stock on the record date,
which is March 6, 2000, we are distributing to you, at no charge, 0.338 rights
for each share of our old common stock owned. Each right will allow you to
purchase one share of our new common stock at a price of $10.40. If you elect to
exercise your basic subscription privilege in full, you may also subscribe for
additional shares of our new common stock under your over-subscription
privilege, if there are enough shares available. The shares that you may
purchase under your basic subscription privilege or your over-subscription
privilege are in addition to the shares that are being distributed to our
shareholders in exchange for our old common stock under our plan of
reorganization.
NO FRACTIONAL RIGHTS
We will not issue fractional rights, but rather will round any fractional
rights to the nearest whole number. When any calculation of rights would
otherwise result in an allocation of rights that is not a whole number, the
actual allocation of rights will be adjusted by rounding fractions of 1/2 or
greater to the next higher whole number and by rounding fractions of less than
1/2 to the next lower whole number. Regardless of the number of shares owned,
each shareholder as of the record date will receive at least one right. We are
registering an additional 10,000 shares of new common stock in this prospectus
to account for the effects of rounding.
EXPIRATION OF THE RIGHTS
You may exercise your rights at any time before 5:00 p.m., New York City
time, on May 31, 2000, the expiration date for the rights. We may, in our sole
discretion, extend the time for exercising the rights. If you do not exercise
your rights before the expiration date, your unexercised rights will be null and
void. We will not be obligated to honor your exercise of rights if the
subscription agent receives the documents relating to your exercise after the
expiration date of the rights, regardless of when you transmitted the documents.
We may extend the expiration date by giving oral or written notice to the
subscription agent on or before the scheduled expiration date. If we elect to
extend the expiration date of the rights, we will issue a press release
announcing the extension no later than 9:00 a.m., New York City time, on the
next business day after the most recently announced expiration date.
SUBSCRIPTION PRIVILEGES
Your rights entitle you to the basic subscription privilege and the
over-subscription privilege.
Basic Subscription Privilege. With your basic subscription privilege, you
may purchase one share of our new common stock per right, upon delivery of the
required documents and payment of the subscription price of $10.40 per share.
You are not required to exercise all of your rights unless you wish to purchase
shares under your over-subscription privilege. We will deliver to you
certificates representing the shares that you purchase with your basic
subscription privilege as soon as practicable after the rights offering has been
completed.
Over-Subscription Privilege. In addition to your basic subscription
privilege, you may subscribe for additional shares of our new common stock, upon
delivery of the required documents and payment of the subscription price of
$10.40 per share, before the expiration of the rights. You may only exercise
your
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over-subscription privilege if you exercised your basic subscription privilege
in full and other holders of rights do not exercise their basic subscription
privileges in full. There is no maximum or minimum number of shares that you may
subscribe for under the over-subscription privilege.
Pro Rata Allocation. If there are not enough shares to satisfy all
subscriptions made under the over-subscription privilege, we will allocate the
remaining shares pro rata, after eliminating all fractional shares, among those
over-subscribing rights holders. "Pro rata" means in proportion to the number of
shares of our new common stock that you and the other rights holders have
purchased by exercising your basic subscription privilege. If there is a pro
rata distribution of the remaining shares and you receive a pro rata allocation
of a greater number of shares than you subscribed for under your
over-subscription privilege, then we will allocate to you only the number of
shares for which you subscribed. We will allocate the remaining shares among all
other holders exercising their over-subscription privileges.
Full Exercise of Basic Subscription Privilege. You may exercise your
over-subscription privilege only if you exercise your basic subscription
privilege in full. To determine if you have fully exercised your basic
subscription privilege, we will consider only the basic subscription privileges
held by you in the same capacity. For example, suppose that you were granted
rights for shares of our old common stock that you own individually and shares
of our old common stock that you own collectively with your spouse. If you wish
to exercise your over-subscription privilege with respect to the rights you own
individually, but not with respect to the rights you own collectively with your
spouse, you only need to fully exercise your basic subscription privilege with
respect to your individually owned rights. You do not have to subscribe for any
shares under the basic subscription privilege owned collectively with your
spouse to exercise your individual over-subscription privilege.
When you exercise your over-subscription privilege, you will be
representing and certifying that you have fully exercised your basic
subscription privilege as to shares of our old common stock which you hold in
that capacity. You must exercise your over-subscription privilege at the same
time you exercise your basic subscription privilege in full.
If you own shares of our common stock through your bank, broker or other
nominee holder who will exercise your subscription privilege on your behalf, the
bank, broker or other nominee holder will be required to certify to us and the
subscription agent the following information:
- the number of shares held on your behalf on the record date;
- the number of rights exercised under your basic subscription privilege;
- that your basic subscription privilege held in the same capacity has been
exercised in full; and
- the number of shares subscribed for under your over-subscription
privilege.
Your bank, broker or other nominee holder may also disclose to us other
information received from you.
Return of Excess Payment. If you exercise your over-subscription privilege
and are allocated less than all of the shares for which you wish to subscribe,
your excess payment for shares that were not allocated to you will be returned
by mail without interest or deduction as soon as practicable after the
expiration date. We will deliver to you certificates representing the shares
that you purchase as soon as practicable after the expiration date, after all
pro rata allocations and adjustments have been completed.
CONDITIONS TO THE RIGHTS OFFERING
We may terminate the rights offering at any time in our sole discretion. We
may terminate the rights offering if at any time before completion of the rights
offering there is any judgment, order, decree, injunction, statute, law or
regulation entered, enacted, amended or held to be applicable to the rights
offering that in the sole judgment of our board of directors would or might make
the rights offering or its completion illegal or otherwise restrict or prohibit
completion of the rights offering. We may waive any of these conditions and
choose to proceed with the rights offering even if one or more of these events
occur.
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If we terminate the rights offering, all rights will expire without value and
all subscription payments received by the subscription agent will be returned
promptly, without interest or deduction. This rights offering is not conditioned
on any minimum number of shares being purchased.
METHOD OF SUBSCRIPTION -- EXERCISE OF RIGHTS
You may exercise your rights by delivering the following to the
subscription agent, at or before 5:00 p.m., New York City time, on May 31, 2000,
the date on which the rights expire:
- Your properly completed and executed notice of exercise of rights with
any required signature guarantees or other supplemental documentation;
and
- Your full subscription price payment for each share subscribed for under
your subscription privileges.
METHOD OF PAYMENT
Your payment of the subscription price must be made in U.S. dollars for the
full number of shares of new common stock you are subscribing for by either:
- Check or bank draft drawn upon a U.S. bank or postal, telegraphic or
express money order payable to the subscription agent; or
- Wire transfer of immediately available funds, to the subscription account
maintained by the subscription agent at Chase Manhattan Bank, ABA No.
021000021, Account No. 323015034, further credit to Coho Energy Rights
Offering, Attention: Evelyn O'Connor.
RECEIPT OF PAYMENT
Your payment will be considered received by the subscription agent only
upon:
- Clearance of any uncertified check;
- Receipt by the subscription agent of any certified check or bank draft
drawn on a U.S. bank or of any postal, telegraphic or express money
order; or
- Receipt of collected funds in the subscription account designated above.
CLEARANCE OF UNCERTIFIED CHECKS
If you are paying by uncertified personal check, please note that
uncertified checks may take at least five business days to clear. If you wish to
pay the subscription price by uncertified personal check, we urge you to make
payment sufficiently in advance of the time the rights expire to ensure that
your payment is received and cleared by that time. We urge you to consider using
a certified or cashier's check, money order or wire transfer of funds to avoid
missing the opportunity to exercise your rights.
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DELIVERY OF SUBSCRIPTION MATERIALS AND PAYMENT
You should deliver your notice of exercise of rights and payment of the
subscription price to the subscription agent by one of the methods described
below:
- If by mail to:
ChaseMellon Shareholder Services L.L.C.
Post Office Box 3301
South Hackensack, New Jersey 07606
Attention: Reorganization Department
- If by hand delivery to:
ChaseMellon Shareholder Services L.L.C.
120 Broadway, 13th Floor
New York, New York 10271
Attention: Reorganization Department
- If by overnight courier to:
ChaseMellon Shareholder Services L.L.C.
85 Challenger Road, Mail Drop -- Reorg
Ridgefield Park, New Jersey, 07660
Attention: Reorganization Department
You may call the subscription agent at (888) 224-2734.
Your delivery to an address other than the address set forth above will not
constitute valid delivery.
CALCULATION OF RIGHTS EXERCISED
If you do not indicate the number of rights being exercised, or do not
forward full payment of the total subscription price payment for the number of
rights that you indicate are being exercised, then you will be deemed to have
exercised your basic subscription privilege with respect to the maximum number
of rights that may be exercised with the aggregate subscription price payment
you deliver to the subscription agent. If your aggregate subscription price
payment is greater than the amount you owe for your subscription, you will be
deemed to have exercised your over-subscription privilege for the maximum number
of shares with your overpayment at a price of $10.40 per share. If we do not
apply your full subscription price payment to your purchase of shares of our new
common stock, we will return the excess amount to you by mail without interest
or deduction as soon as practicable after the rights offering is completed.
YOUR FUNDS WILL BE HELD BY THE SUBSCRIPTION AGENT UNTIL SHARES OF NEW COMMON
STOCK ARE ISSUED
The subscription agent will hold your payment of the subscription price in
a segregated account with other payments received from other rights holders
until we issue your shares to you.
SIGNATURE GUARANTEE MAY BE REQUIRED
Your signature on the notice of exercise of rights must be guaranteed by an
eligible institution such as a member firm of a registered national securities
exchange or a member of the National Association of Securities Dealers, Inc., or
from a commercial bank or trust company having an office or correspondent in the
United States, subject to standards and procedures adopted by the subscription
agent, unless:
- Your notice of exercise of rights provides that shares are to be
delivered to you as record holder of those rights; or
- You are an eligible institution.
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NOTICE TO BENEFICIAL HOLDERS
If you are a broker, a trustee or a depositary for securities who held
shares of our old common stock for the account of others on March 6, 2000, the
record date for the issuance of rights under this rights offering, you should
notify the beneficial owners of those shares of the rights offering as soon as
possible to find out their intentions with respect to exercising their rights.
You should obtain instructions from the beneficial owners with respect to the
rights, as set forth in the instructions we have provided to you for your
distribution to beneficial owners. If a beneficial owner so instructs, you
should complete the appropriate notice of exercise of rights and submit it to
the subscription agent with the proper payment. If you hold shares of our old
common stock for the account of more than one beneficial owner, you may exercise
the number of rights to which all beneficial owners in the aggregate otherwise
would have been entitled had they been direct record holders of our old common
stock on the record date for the issuance of rights under this rights offering,
if you, as a nominee record holder, make a proper showing to the subscription
agent by submitting the form entitled "Nominee Holder Certification," which we
will provide to you with your offering materials.
BENEFICIAL OWNERS
If you are a beneficial owner of shares of our old common stock or will
receive your rights through a broker, custodian bank or other nominee, we will
ask your broker, custodian bank or other nominee to notify you of this rights
offering. If you wish to exercise your rights, you will need to have your
broker, custodian bank or other nominee act for you. If you hold certificates of
our old common stock directly and would prefer to have your broker, custodian
bank or other nominee exercise your rights, you should contact your nominee and
request it to effect the transactions for you. To indicate your decision with
respect to your rights, you should complete and return to your broker, custodian
bank or other nominee the form entitled "Beneficial Owners Election Form,"
together with your check for the subscription price of the rights you wish to
exercise. You should receive this form from your broker, custodian bank or other
nominee with the other offering materials. If you wish to obtain a separate
notice of exercise of rights, you should contact the nominee as soon as possible
and request that a separate notice of exercise of rights be provided to you.
INSTRUCTIONS FOR COMPLETING YOUR NOTICE OF EXERCISE OF RIGHTS
You should read and follow the instructions accompanying the notice of
exercise of rights carefully.
If you want to exercise your rights, you should send your notice of
exercise of rights with your subscription price payment to the subscription
agent. Do not send your notice of exercise of rights and subscription price
payment to us.
You are responsible for the method of delivery of your notice of exercise
of rights with your subscription price payment to the subscription agent. If you
send your notice of exercise of rights and subscription price payment by mail,
we recommend that you send them by registered mail, properly insured, with
return receipt requested. You should allow a sufficient number of days to ensure
delivery to the subscription agent before the time the rights expire. Because
uncertified personal checks may take at least five business days to clear, you
are strongly urged to pay, or arrange for payment, by means of certified or
cashier's check, money order or wire transfer of funds.
DETERMINATIONS REGARDING THE EXERCISE OF YOUR RIGHTS
We will decide all questions concerning the timeliness, validity, form and
eligibility of your exercise of your rights and our determinations will be final
and binding. We, in our sole discretion, may waive any defect or irregularity,
or permit a defect or irregularity to be corrected within a period of time as we
may determine. We may reject the exercise of any of your rights because of any
defect or irregularity. We will not receive or accept any subscription until all
irregularities have been waived by us or cured by you within a period of time as
we decide, in our sole discretion.
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<PAGE> 24
Neither we nor the subscription agent will be under any duty to notify you
of any defect or irregularity in connection with your submission of notice of
exercise of rights and we will not be liable for any failure to notify you of
any defect or irregularity. We reserve the right to reject your exercise of
rights if your exercise is not in accordance with the terms of the rights
offering or in proper form. We will also not accept your exercise of rights if
our issuance of shares of our new common stock to you could be deemed unlawful
under applicable law or is materially burdensome to us.
QUESTIONS ABOUT EXERCISING RIGHTS -- SUBSCRIPTION AGENT
We have appointed ChaseMellon Shareholder Services L.L.C. as subscription
agent for the rights offering. We will pay its fees and expenses related to the
rights offering. We also have agreed to indemnify the subscription agent for
some of the liabilities that it may incur in connection with the rights
offering. You may direct any questions or requests for assistance concerning the
method of exercising your rights, additional copies of this prospectus, the
instructions, the nominee holder certification or other subscription documents
referred to in this prospectus, to the subscription agent, at the following
telephone number and address:
ChaseMellon Shareholder Services L.L.C.
120 Broadway, 13th Floor
New York, New York 10271
Attention: Reorganization Department
Telephone No.: (888) 224-2734
Banks and brokerage firms, please call (917) 320-6285.
NO REVOCATION
Once you have exercised your subscription privileges, you may not revoke
your exercise. Rights not exercised before the expiration date of the rights
will expire.
PROCEDURES FOR DTC PARTICIPANTS
We expect that your exercise of your basic subscription privilege and your
over-subscription privilege may be made through the facilities of the Depository
Trust Company, or the DTC. If your rights are held of record through DTC, you
may exercise your basic subscription privilege and your over-subscription
privilege by instructing DTC to transfer your rights from your account to the
account of the subscription agent, together with certification as to the
aggregate number of rights you are exercising and the number of shares of our
new common stock you are subscribing for under your basic subscription privilege
and your over-subscription privilege, if any, and your subscription price
payment for each share you subscribed for under your basic subscription
privilege and your over-subscription privilege.
SUBSCRIPTION PRICE
The subscription price is $10.40 per share.
DETERMINATION OF THE SUBSCRIPTION PRICE
The subscription price was determined through negotiations between us and
the holders of a majority of the old bonds. Under our plan of reorganization,
our bondholders are receiving 96% of the outstanding shares of the new common
stock, before giving effect to any shares issued under this rights offering or
under the standby loan. The original subscription price of $0.26 was derived
based on the value of the bondholder claim ($161,635,870) divided by the total
number of shares to be issued to the bondholders under our plan of
reorganization (614,484,288). Because we decreased the number of shares that
were issued under the plan of reorganization by a factor of 40, we multiplied
the original subscription price by 40 to arrive at the $10.40 subscription
price. If we issue additional shares to those who purchase shares in the rights
offering because of the limited anti-dilution feature, the effective purchase
price per share to
21
<PAGE> 25
those purchases will be less than $10.40. See the section of this prospectus
called "Dilution" for more information about the limited anti-dilution feature.
EXTENSIONS AND TERMINATION
We may extend the rights offering and the period for exercising your
rights, in our sole discretion. If we extend the rights offering or the period
for exercising rights, you will be able to change your subscription decision. In
addition, we may terminate the rights offering at any time before the time the
rights expire.
NO RECOMMENDATION TO HOLDERS OF RIGHTS OR OTHERS
We are not making any recommendations as to whether or not you should
subscribe for shares of our new common stock. You should decide whether to
subscribe for shares based upon your own assessment of your best interests in
consultation with your legal and financial advisors.
FOREIGN AND OTHER SHAREHOLDERS
A notice of exercise of rights will be mailed to rights holders whose
addresses are outside the United States or who have an Army Post Office or Fleet
Post Office address. To exercise those rights, you must notify the subscription
agent, and take all other steps that are necessary to exercise your rights on or
before the expiration date of the rights. If the procedures set forth in the
preceding sentence are not followed before the expiration date, your rights will
expire.
SHARES OF NEW COMMON STOCK OUTSTANDING AFTER THE RIGHTS OFFERING
Assuming we issue all of the shares offered in the rights offering
excluding the additional 10,000 shares of new common stock we are registering in
this prospectus to account for the effects of rounding of the rights being
granted to the shareholders, 31,686,435 shares of our new common stock will be
issued and outstanding after the rights offering expires. Based on the
16,002,195 shares of our new common stock that were issued on the effective date
of confirmation of our plan of reorganization plus the additional 2,691,958
shares to be issued under this prospectus to the standby lenders but before
taking into account shares sold in the rights offering, our issuance of all
shares in this rights offering would result on a pro forma basis in a 69%
increase in the number of outstanding shares of our new common stock. See the
section of this prospectus called "Dilution" for additional information
concerning the new common stock outstanding after the rights offering.
REGULATORY LIMITATION
We will not be required to issue to you shares of our new common stock in
the rights offering if, in our opinion, you would be required to obtain prior
clearance or approval from any state or federal regulatory authorities to own or
control the shares and if, at the time the rights expire, you have not obtained
that clearance or approval.
ISSUANCE OF COMMON STOCK
The subscription agent will issue to you certificates representing shares
of our new common stock you purchase under the rights offering as soon as
practicable after the time the rights expire.
Your payment of the aggregate subscription price will be retained by the
subscription agent and will not be delivered to us until your subscription is
accepted and you are issued your share certificates. We will not pay you any
interest on funds paid to the subscription agent, regardless of whether the
funds are applied to the subscription price or returned to you. You will have no
rights as a shareholder of Coho, with respect to shares of our new common stock
subscribed for, until certificates representing the shares are issued to you.
Upon our issuance of the certificates, you will be deemed the owner of the
shares you
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<PAGE> 26
purchased by exercise of your rights. Unless otherwise instructed in the notice
of exercise of rights, your certificates for shares issued as a result of your
exercise of rights will be registered in your name.
If the rights offering is not completed for any reason, the subscription
agent will promptly return, without interest or deduction, all funds received by
it.
We will retain any interest earned on the funds held by the subscription
agent.
COMPLIANCE WITH STATE REGULATIONS PERTAINING TO THE RIGHTS OFFERING
We are not making the rights offering in any state or other jurisdiction in
which it is unlawful to do so. We will not sell or accept an offer to purchase
our new common stock from you if you are a resident of any state or other
jurisdiction in which the sale or offer of the rights or the new common stock
would be unlawful. We may delay the commencement of the rights offering in these
states or other jurisdictions to comply with their laws. We do not expect that
there will be any changes in the terms of the rights offering. However, we may
decide, in our sole discretion, not to modify the terms of the rights offering
as may be requested by some of these states or other jurisdictions. If that
happens and you are a resident of the state or jurisdiction that requests the
modification, you will not be eligible to participate in the rights offering.
THE OFFERING TO STANDBY LENDERS
In this prospectus, we are registering an additional 2,691,958 shares of
new common stock for distribution to the lenders who participated in the standby
loan made under the terms of our plan of reorganization. Under the terms of the
standby loan, the standby lenders are to be issued shares of new common stock
representing 14.4% of all shares of new common stock outstanding, including any
shares issued in the rights offering, as additional compensation to the standby
lenders for their services as lenders under the standby loan. See the section of
this prospectus called "Dilution" for more information regarding the dilutive
effects of the issuance of shares to the standby lenders. Upon the effectiveness
of the registration statement of which this prospectus constitutes a part, we
will issue these shares to the standby lenders.
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<PAGE> 27
USE OF PROCEEDS
There is no minimum number of shares of new common stock that must be
subscribed for in this rights offering. If all the rights are exercised, we will
receive approximately $90 million upon completion of this rights offering,
before deducting the offering expenses. We will not receive any proceeds from
our issuance of 2,691,958 shares to the standby lenders. The offering expenses
are estimated to be $550,000. We may negotiate with the standby lenders to
receive satisfactory terms for the use of proceeds from the rights offering to
pay down the standby loan. The standby loan has a principal amount of $72
million with a term of seven years. The interest rate on the standby loan is 15%
per annum until March 31, 2001. The interest rate on the standby loan after
March 31, 2001 is a rate per annum of 15% plus a variable component of up to an
additional 10% per annum based on the price we receive for our production, for a
maximum possible interest rate of 25% per annum.
If satisfactory repayment terms are not reached with the standby lenders,
we will use the proceeds from the rights offering to pay down our debt under the
new credit facility. We currently have outstanding $183 million in principal
amount under the new credit facility. The new credit facility has a term of
three years and an interest rate of the lesser of prime plus 2% or LIBOR plus
3%. Any proceeds not used to pay down either the standby loan or the new credit
facility will be used for working capital.
Indebtedness under each of the standby loan and the new credit facility was
incurred in connection with discharging claims under our plan of reorganization.
See the section of this prospectus called "Description of Existing Indebtedness"
for more information regarding the standby loan and the new credit facility.
DIVIDEND POLICY
We never paid cash dividends on our old common stock and we do not intend
to pay cash dividends on our new common stock. Because Coho Energy, Inc. is a
holding company, our ability to pay dividends depends on the ability of our
subsidiaries to pay cash dividends or make other cash distributions. Our debt
agreements generally prohibit the subsidiaries from paying dividends or making
cash distributions. Our board of directors has sole discretion over the
declaration and payment of future dividends. Any future dividends will depend
on:
- our profitability,
- our financial condition,
- our cash requirements,
- our future prospects,
- general business conditions,
- the terms of our debt agreements, and
- other factors our board of directors believes relevant.
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<PAGE> 28
PRICE RANGE OF COMMON STOCK
The new common stock has had a very limited trading history since we
emerged from bankruptcy. Since April 3, 2000, the new common stock has traded in
the over-the-counter market under the symbol "CHOH." On April 28, 2000, the last
price at which the new common stock traded in the over-the-counter market was
$5.00. We anticipate that our new common stock will be quoted on Nasdaq's OTC
Bulletin Board under the symbol "CHOH."
Our old common stock was, until June 4, 1999, listed on the Nasdaq Stock
Market under the symbol "COHO." From June 7, 1999 until March 31, 2000, our old
common stock was traded on Nasdaq's OTC Bulletin Board under the symbol
"COHOQ.OB." The following table shows the high and low sales prices of our old
common stock over recent periods.
<TABLE>
<CAPTION>
HIGH LOW
------ ------
<S> <C> <C>
1998
1st Quarter............................................... $ 9 5/8 $ 6 1/4
2nd Quarter............................................... 9 1/4 6 1/4
3rd Quarter............................................... 7 1/8 4 1/2
4th Quarter............................................... 5 1/8 2 5/16
1999
1st Quarter............................................... $ 3 1/8 $ 1/2
2nd Quarter............................................... 1 1/32
3rd Quarter............................................... 1 5/8 7/32
4th Quarter............................................... 3/4 5/32
2000
1st Quarter (through March 31, 2000)...................... 51/64 3/16
</TABLE>
At April 1, 2000, there were 414 holders of record of the new common stock.
We believe we have in excess of 8,000 beneficial holders of our new common
stock.
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<PAGE> 29
CAPITALIZATION
The following table sets forth our consolidated capitalization at December
31, 1999, and as adjusted for the following circumstances:
- to give pro forma effect for projected operating results through March
31, 2000, the effective date of our plan of reorganization, and to give
pro forma effect for the consummation of our plan of reorganization,
- to give pro forma effect for the issuance of shares of new common stock
and the repayment of borrowings under the new credit facility assuming
that all of the rights are exercised in the rights offering, excluding
the additional 10,000 shares of new common stock we are registering in
this prospectus to account for the effects of the rounding of rights
being granted to the shareholders, and
- to give pro forma effect for the issuance of shares of new common stock
and the repayment of borrowings under the new credit facility assuming
that 20% of the rights are exercised in the rights offering, excluding
the additional 10,000 shares of new common stock we are registering in
this prospectus to account for the effects of the rounding of rights
being granted to the shareholders.
This information should be read in conjunction with "Management's Discussion and
Analysis of Financial Conditions and Results of Operations" and our consolidated
financial statements and related notes to those statements included in this
prospectus.
<TABLE>
<CAPTION>
PRO FORMA
PRO FORMA PRO FORMA PURCHASE OF
UPON PURCHASE OF 20% OF
DECEMBER 31, EFFECTIVENESS ALL SHARES SHARES
1999 OF THE IN RIGHTS IN RIGHTS
HISTORICAL PLAN(3) OFFERING(4) OFFERING(5)
------------ ------------- ----------- -----------
<S> <C> <C> <C> <C>
Current Liabilities:
Old Bank Group Loan(1)........................... $258,836 $ -- $ -- $ --
Old Bonds(1)..................................... 161,094 -- -- --
Other............................................ 19,029 21,734 21,734 21,734
-------- --------- --------- ---------
Total Current Liabilities................ $438,959 $ 21,734 $ 21,734 $ 21,734
-------- --------- --------- ---------
Long-Term Liabilities:
Credit Facility.................................. $ -- $ 183,000 $ 93,000 $ 165,000
Standby Loan..................................... -- 72,000 72,000 72,000
Promissory Notes................................. -- 4,452 4,452 4,452
-------- --------- --------- ---------
Total Long-Term Liabilities.............. -- 259,452 169,452 241,452
-------- --------- --------- ---------
Shareholders' Equity:
Preferred stock, par value $0.01 per share.......
Old common stock and new common stock, par value
$0.01 per share; authorized 50,000,000
shares(2)..................................... 256 187 317 211
Additional paid-in capital....................... 137,812 298,606 400,886 318,624
Retained deficit................................. (230,026) (217,195) (216,645) (216,645)
-------- --------- --------- ---------
Total Shareholders' Equity............... (91,958) 81,598 184,558 102,190
-------- --------- --------- ---------
Total Capitalization, excluding current
liabilities............................ $(91,958) $ 341,050 $ 354,010 $ 343,642
======== ========= ========= =========
</TABLE>
- ---------------
(1) All amounts outstanding under the old bank group loan agreement and the old
bonds and the related accrued interest are classified as current liabilities
as of December 31, 1999 due to accelerations by the lenders.
(2) Shares of old common stock outstanding were 25,603,512 at December 31, 1999
and shares of new common stock outstanding were 18,694,153 under Pro Forma
Upon Effectiveness of the Plan. Shares of new common stock outstanding were
31,686,435 under Pro Forma Purchase of All Shares in Rights Offering and
21,099,991 under Pro Forma Purchase of 20% of Shares in Rights Offering.
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<PAGE> 30
(3) The pro forma column that presents the effectiveness of the plan of
reorganization reflects pro forma adjustments to record the following
transactions:
- Adjustments of current liabilities and retained deficit to reflect the
effect of projected operating results for the period from January 1, 2000
through March 31, 2000, the effective date of the plan of reorganization.
- Repayment of borrowings outstanding under the old bank group loan
agreement together with accrued interest totaling $258.8 million from
borrowings under the credit facility together with borrowings under the
standby loan, and the write-off of $1.6 million related to unamortized
debt issue costs.
- Conversion of the old bonds into 15,362,107 shares of new common stock at
an assumed fair market value of $8.90 per share for a total of $136.8
million and the recognition of a gain on the extinguishment of debt of
$20.7 million due to the dilution in the assumed fair market value of the
shares as a result of the additional shares issued for the standby loan.
- Payment of $501,000 of general secured and administrative convenience
claims paid on the effective date and the recognition of additional
reorganization expenses totaling $8.3 million, including $4.0 million for
estimated severance and retention bonus payments.
- The $4.5 million reclassification of the long-term portion of the
five-year promissory notes to be issued in settlement of the priority tax
claims from current liabilities.
- The borrowings of $183.0 million under the credit facility on the
effective date.
- The borrowings of $72.0 million under the standby loan and the related
issuance of 2,691,958 shares of new common stock at an assumed fair
market value of approximately $8.90 per share for a total of $24.0
million.
- Issuance of 640,088 shares of new common stock in exchange for 25,603,512
shares of old common stock.
(4) The pro forma column that presents the purchase of shares in the rights
offering assuming all shares are purchased reflects pro forma adjustments to
record the following transactions:
- Repayment of borrowings outstanding under the credit facility with
proceeds from the rights offering of $90 million.
- Issuance of 11,121,393 shares of new common stock at an assumed fair
market value of approximately $8.09 per share for total proceeds of $90
million comprised of 8,653,846 shares at the offering price of $10.40 per
share and 2,467,547 additional shares issued to offset the dilutive
effect of the additional shares issued to the standby lenders.
- Issuance of 1,870,889 shares of additional new common stock at an assumed
fair market value of approximately $8.09 per share to the standby lenders
to offset the dilutive effect of the rights offering.
(5) The pro forma column that presents the purchase of shares in the rights
offering assuming 20% of the shares are purchased reflects pro forma
adjustments to record the following transactions:
- Repayment of borrowings outstanding under the credit facility with
proceeds from the rights offering of $18 million.
- Issuance of 2,059,397 shares of new common stock at an assumed fair
market value of $8.74 per share for total proceeds of $18 million
comprised of 1,730,769 shares at the offering price of $10.40 per share
and 328,628 additional shares issued to offset the dilutive effect of the
additional shares issued to the standby lenders.
- Issuance of 346,441 additional shares of new common stock at an assumed
fair market value of approximately $8.74 per share to the standby lenders
to offset the dilutive effect of the rights offering.
27
<PAGE> 31
SELECTED FINANCIAL DATA
The following selected consolidated financial data for each of the five
years in the period ended December 31, 1999 are derived from, and qualified by
reference to, our audited consolidated financial statements included in this
prospectus. The information presented below should be read in conjunction with
our consolidated financial statements and the related notes included in this
prospectus and the section of this prospectus called "Management's Discussion
and Analysis of Financial Condition and Results of Operations." The selected
consolidated financial data presented below is not necessarily indicative of the
future results of our operations or financial performance.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------
1995 1996 1997 1998 1999
-------- -------- -------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
STATEMENT OF EARNINGS DATA:
Operating revenues........................................ $ 40,903 $ 54,272 $ 63,130 $ 68,759 $ 57,323
Operating costs........................................... 12,457 13,875 15,970 26,859 21,155
General and administrative expenses(1).................... 5,400 7,264 7,163 7,750 9,905
Reorganization costs...................................... -- -- -- -- 3,123
Depletion and depreciation................................ 14,717 16,280 19,214 28,135 13,702
Writedown of crude oil and natural gas properties......... -- -- -- 188,000 5,433
Net interest expense...................................... 8,048 7,464 10,474 32,721 33,698
Other expense............................................. -- -- -- 3,023 1,048
Income tax expense (benefit).............................. 112 3,483 4,021 (14,383) (26)
Earnings (loss) from continuing operations................ 169 5,906 6,288 (203,346) (30,715)
Net earnings (loss)....................................... 1,780 5,906 6,288 (203,346) (30,715)
Basic earnings (loss) from continuing operations per
common share............................................ (0.02) 0.29 0.29 (7.94) (1.20)
Diluted earnings (loss) from continuing operations per
common share............................................ (0.02) 0.29 0.28 (7.94) (1.20)
Basic earnings (loss) per common share(2)................. 0.05 0.29 0.29 (7.94) (1.20)
Diluted earnings (loss) per common share(3)............... 0.05 0.29 0.28 (7.94) (1.20)
OTHER FINANCIAL DATA:
Capital expenditures...................................... $ 29,970 $ 52,384 $ 72,667 $ 70,143 $ 6,349
EBITDA(4)................................................. 23,046 33,133 39,997 31,127 22,093
BALANCE SHEET DATA:
Working capital (deficit)(5).............................. $ 14,433 $ 6,662 $ (2,021) $(388,297) $(407,490)
Net property and equipment................................ 175,899 210,212 531,409 324,574 311,788
Total assets.............................................. 204,042 230,041 555,128 350,068 348,801
Long-term debt, excluding current portion................. 107,403 122,777 369,924 -- --
Total shareholders' equity................................ 74,321 81,466 142,103 (61,243) (91,958)
</TABLE>
- ---------------
(1) General and administrative expenses for 1999 are substantially higher than
those expenses for the same period in 1998 primarily due to the expensing of
all salaries and other general and administrative costs associated with
exploration and development activities during 1999 as compared to the
capitalization of $5.7 million of those costs in 1998.
(2) Basic per share amounts have been computed by dividing net earnings after
preferred dividends by the weighted average number of shares outstanding:
17,392 in 1995; 20,179 in 1996; 21,693 in 1997; 25,604 in 1998; and 25,604
in 1999.
(3) Diluted per share amounts have been computed by dividing net earnings after
preferred dividends by the weighted average number of shares outstanding
including common stock equivalents, consisting of stock options and
warrants, when their effect is dilutive: 17,392 in 1995; 20,342 in 1996;
22,334 in 1997; 25,604 in 1998; and 25,604 in 1999.
(4) "EBITDA" refers to earnings before interest, taxes, depreciation, depletion
and amortization. EBITDA should not be considered as an alternative to, or
more meaningful than, net income or cash flow as determined in accordance
with generally accepted accounting principles as an indicator of our
operating performance or liquidity.
(5) Amounts for 1998 and 1999 include $384,031 and $388,685, respectively,
related to the current portion of long-term debt. The working capital
deficit as of December 31, 1999 includes liabilities subject to compromise
as a result of the bankruptcy filing.
28
<PAGE> 32
THE PLAN OF REORGANIZATION
INTRODUCTION
A summary of the principal provisions of the plan of reorganization and the
treatment of classes of claims and equity interests is set forth below. This
summary is qualified by reference to the plan of reorganization. You may obtain
a copy of the plan of reorganization and related disclosure statement by sending
us a written request at 14785 Preston Road, Suite 860, Dallas, Texas 75240 to
the attention of Ms. Anne Marie O'Gorman.
We conceived the plan of reorganization as an alternative to the more
drastic measures available to us for restructuring our debt, such as a
liquidation of our properties. The terms of the plan of reorganization were
arrived at after a diligent search for, and extensive evaluation of, numerous
financing and liquidation proposals by us, and consultation with our financial
advisors as to what type of plan of reorganization might be feasible after
lengthy negotiations with our creditors. On March 17, 2000, the Honorable Harold
C. Abramson, United States Bankruptcy Judge, confirmed the plan of
reorganization. The order confirming the plan of reorganization was entered on
March 20, 2000. Judge Abramson found that the plan of reorganization provides
our creditors and our shareholders with distributions of property in the form of
new securities having a value not less than the amount that those holders would
receive if we were to be liquidated under Chapter 7 of the Bankruptcy Code.
Judge Abramson further found that reorganization under the plan of
reorganization is feasible. We believe that the plan of reorganization provides
for the greatest and earliest possible recoveries for our creditors and our
shareholders. Since the plan of reorganization was confirmed and consummated,
we, as reorganized under the plan of reorganization, may operate our businesses
and buy, use and otherwise acquire and dispose of our property free of any
restrictions contained in the Bankruptcy Code.
1. Old Bank Group.
We and some of our subsidiaries were parties to an old bank group loan
agreement. The lenders under the old bank group loan were MeesPierson Capital
Corp.; Paribas, Houston Agency; Christiania Bank OG Kreditkasse, ASA; Den Norske
Bank ASA; Bank of Scotland; Bank One, Texas, N.A.; Credit Lyonnais New York
Branch; and Toronto Dominion (Texas), Inc. Approximately $240 million of
principal, plus accrued interest and reasonable fees, owed to the bank group in
connection with the old bank group loan agreement was treated as fully secured
under the plan of reorganization. The exact amount of the bank group claim,
including interest at a reasonable rate and reasonable fees, was subject to
allowance. The allowed amount of the bank group claim was fixed by the
bankruptcy court at approximately $260 million.
The bank group claim was paid in full in cash on the effective date of the
plan of reorganization, March 31, 2000. We obtained the funds necessary for the
payment of the allowed bank group claim through the combination of:
- a new senior revolving credit facility, from a syndicate of lenders led
by The Chase Manhattan Bank, as agent for the lenders,
- cash on hand from our operations and
- the sale of senior subordinated notes to the standby lenders, including:
- PPM America, Inc. and their assignees,
- Oaktree Capital Management, L.L.C. and their assignees,
- Pacholder Associates, Inc. and their assignees, and
- Appaloosa Management, L.P. and their assignees.
2. Old Bond Holders.
We were the issuer of $150 million principal amount of 8 7/8% senior
subordinated notes due 2007. These old bonds were issued under an indenture
dated October 1, 1997, which some of our subsidiaries
29
<PAGE> 33
guaranteed. Approximately $162 million was owed to the holders of the old bonds
in connection with the old bond indenture. Under the plan of reorganization, the
old bond indenture and the old bonds were extinguished on the effective date.
Holders of old bonds received as of the effective date their pro rata share of
96% of our new common stock. This 96% of new common stock will be diluted by
shares of new common stock issued in connection with this rights offering and
the standby loan.
3. Old Shareholders.
Prior to the effective date, we had issued and outstanding 25,603,512
shares of old common stock, $0.01 par value. The old common stock was held by
approximately 425 shareholders of record. As of the effective date, the old
common stock was extinguished and the shareholders received their pro rata share
of 4% of the new common stock, except that we paid cash in lieu of distributing
fractional shares of new common stock. This 4% of new common stock will be
diluted by shares of new common stock issued in connection with the rights
offering and the standby loan. The shareholders will also receive the exclusive
right to purchase their pro rata portions of additional shares of the new common
stock in the rights offering for a purchase price of $10.40 per share, up to a
total amount of approximately $90 million.
Additionally, shareholders as of February 7, 2000, are eligible to receive
their pro rata share of the following:
- 20% of the proceeds available from the Hicks Muse lawsuit after payment
of all fees and expenses, including any contingent fee paid in connection
with these proceeds, and
- 40% of the proceeds of the disposition of our interest in Coho Anaguid,
Inc. or the disposition of substantial assets of Coho Anaguid, Inc.
For more information about the Hicks Muse lawsuit, see the section of this
prospectus called "Oil and Gas Operations -- Legal Matters." For more
information about the assets of Coho Anaguid, Inc., see the section of this
prospectus called "Oil and Gas Operations -- Tunisia, North Africa."
4. New Capitalization.
Originally, our plan of reorganization anticipated that we would issue one
new share of stock for each share of old stock, and that the shares of stock
offered pursuant to this prospectus would be offered for a purchase price of
$0.26 per share. In the plan of reorganization, we noted that we may effect a
reverse stock split after the effective date of the plan to proportionately
reduce the number of our authorized and outstanding shares. As we noted, we
believed that this measure would help us to satisfy the listing requirements of
the Nasdaq Stock Market. After the plan of reorganization was confirmed by the
bankruptcy court, we determined that it would be in the best interests of us and
our shareholders to make the effect of that reverse stock split applicable as of
the effective date of the plan of reorganization, so that we would not have to
take any actions after the effective date to adjust the number of shares
authorized and outstanding. Therefore, we amended the plan of reorganization so
that as of the effective date, we issued one share of our new common stock for
each forty shares of our old common stock, and so that the purchase price for
shares of stock offered pursuant to this prospectus will be $10.40 per share.
This amendment had the effect of decreasing the number of our outstanding shares
of new common stock and increasing the per-share price. The amendment did not
affect the relative percentage ownership interests among various groups of
shareholders after the effective date.
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<PAGE> 34
CLASSIFICATION AND TREATMENT SUMMARY
The following is a summary of the classification of claims and interests,
and their treatment under the plan of reorganization.
<TABLE>
<CAPTION>
CLASSIFICATION TREATMENT
- -------------- ---------
<S> <C>
Class 1 Unimpaired
Administrative expense claims Will be paid in full, in cash including any
Total estimated amount of Class 1 retainers on hand, on the later of the
claims: effective date, the due date or court
$2,329,000 approval (if required by law), or paid on
other agreed terms.
Estimated recovery: Full recovery.
Class 2 Impaired
Priority tax claims Will receive five-year promissory notes
Total estimated amount of Class 2 bearing interest at a rate of 6% per annum
claims: unless a different rate is chosen by the
$5,260,000 bankruptcy court, or paid on other agreed
terms.
Estimated recovery: Full recovery over time.
Class 3 Impaired
Bank group claim Received payment in full, in cash on the
Total estimated amount of Class 3 effective date from advances made under the
claims: new credit facility and the standby loan.
$260,000,000
Estimated recovery: Full recovery.
Class 4 Impaired
Senior miscellaneous secured claims Will receive cash payment of 100% of allowed
Total estimated amount of Class 4 claims on the effective date, or paid on
claims: other agreed terms.
$300,000
Estimated recovery: Full recovery.
Class 5 Impaired
Unsecured bond claims Received shares representing 96% of the new
Total estimated amount of Class 5 common stock as of the effective date
claims: (without giving effect to dilution from
$161,635,870 shares issued under the rights offering and
the standby loan).
Estimated recovery: Approximately full
recovery over time.
Class 6 Impaired
General unsecured claims Will receive cash payment of 100% of allowed
Total estimated amount of Class 6 claims, payable in four equal quarterly
claims: $4,700,000 (Estimate assumes installments without interest.
no
significant adverse result to us in Estimated recovery: Full recovery over one
the year.
bankruptcy court's allowance and
estimation process. See "Oil and Gas
Operations-Legal Matters.")
Class 7 Unimpaired
Administrative convenience claims Will receive payment in full, in cash 30 days
Total estimated amount of Class 7 from the effective date, up to a maximum of
claims: $1,000 per claim.
$72,000
Estimated recovery: Full recovery.
</TABLE>
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<PAGE> 35
<TABLE>
<CAPTION>
CLASSIFICATION TREATMENT
- -------------- ---------
<S> <C>
Class 8 Impaired
Holders of our old common stock Will receive shares representing 4% of the
25,603,512 shares outstanding new common stock as of the effective date,
without giving effect to dilution from
shares issued under the rights offering and
the standby loan; and rights to purchase
additional shares of the new common stock
at $10.40 per share. Will receive cash in
lieu of any fractional shares of new common
stock to be issued in exchange for old
common stock. Will receive 20% of any
proceeds of the Hicks Muse lawsuit after
fees and expenses. Will receive 40% of any
proceeds from the disposition of our
interests in, or the assets of, Coho
Anaguid, Inc.
Estimated recovery: 2% to 37% of our new
outstanding common stock, depending on the
degree of participation in the rights
offering and other variables.
</TABLE>
THE NEW DEBT AND EQUITY
The Credit Facility.
On the effective date, we established a new credit facility with a group of
lenders and The Chase Manhattan Bank, as agent for the new lenders, for a
principal amount of up to $250 million. The new credit facility limits advances
to the amount of the borrowing base, which has been set initially at $205
million. The borrowing base is the loan value to be assigned to the proved
reserves attributable to our oil and gas properties. The borrowing base is
subject to semiannual review based on reserve reports. The initial borrowing
base was subject to Chase's review of the January 1, 2000 reserve report, which
was prepared and audited by independent petroleum engineering firms acceptable
to the new lenders.
The new credit facility is subject to semiannual borrowing base
redeterminations, each April 1 and October 1, and will be made in the sole
discretion of the lenders. We will deliver to the lenders by March 1 of each
year a reserve report prepared as of the immediately preceding January 1 and by
September 1 of each year a reserve report prepared as of the immediately
preceding July 1. The January 1 reserve report will be prepared internally by us
and audited by an independent petroleum engineering firm, acceptable to Chase,
and the July 1 reserve report will be prepared internally by us, in a form
acceptable to Chase. Based in part on the reserve report, the lenders will
redetermine the borrowing base in their sole discretion. For an increase in the
borrowing base, consent of 100% of the lenders will be required. To maintain the
borrowing base, or to reduce the borrowing base, consent of the lenders holding
75% of outstanding loans and letter of credit exposure or, if no loans or
letters of credit are outstanding, the lenders representing 75% of the current
loan commitments under the new credit facility, will be required. We or Chase
may request one additional borrowing base determination during any calendar
year.
Interest on advances under the new credit facility will be payable on the
earlier of the expiration of any interest period under the new credit facility
or quarterly, beginning the first quarter after the effective date. Amounts
outstanding under the new credit facility will accrue interest at our option at
either the Eurodollar rate, which is the annual interest rate equal to the
London interbank offered rate for deposits in United States dollars that is
determined by reference to the Telerate Service or offered to Chase plus an
applicable margin, or the prime rate, which is the floating annual interest rate
established by Chase from time to time as its prime rate of interest and which
may not be the lowest or best interest rate charged by Chase on loans similar to
the new credit facility, plus an applicable margin. All outstanding advances
under the new credit facility are due and payable in full three years from the
effective date.
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<PAGE> 36
The new credit facility has been secured by granting Chase the following
collateral for the benefit of the lenders:
- first and prior security interests in our issued and outstanding capital
stock and other equity interests of our material subsidiaries,
- first and prior mortgage liens and security interests covering proved
mineral interests selected by Chase having a present value, as determined
by Chase, of not less than 85% of the present value of all of our proved
mineral interests evaluated by the lenders for purposes of determining
the borrowing base, and
- first and prior security interests in our other tangible and intangible
assets.
The rights and responsibilities of Chase, the lenders and us are governed by a
new senior revolving credit agreement and related documents, which, in part,
permit the lenders to enforce their rights to the collateral on the occurrence
of an event of default under the new credit agreement.
The new credit agreement contains financial and other covenants including:
- maintenance of minimum ratios of cash flow to interest expense, senior
debt to cash flow, and current assets to current liabilities as of the
end of each quarter, commencing as of the end of the initial fiscal
quarter to commence after the effective date,
- restrictions on the payment of dividends and
- limitations on the incurrence of additional indebtedness, the creation of
liens and the incurrence of capital expenditures.
Fees for the lenders contained in the Chase commitment letter to us dated
December 9, 1999 were approved by the bankruptcy court at a hearing on the fees
held on January 27, 2000. These fees include an initial due diligence fee of
$200,000. Because the lenders funded under the new credit facility on the
effective date, they are entitled to an additional aggregate $5.8 million of
closing fees. All fees paid by us in connection with the new credit facility are
non-refundable and are in addition to reimbursements to be paid for expenses
incurred by Chase in connection with the preparation of the new credit agreement
and related documentation.
The Rights Offering.
To implement the plan of reorganization, we will raise up to $90 million of
new investment by the rights offering made under this prospectus and $72 million
in a standby loan that has been made by the standby lenders.
Under the rights offering, our shareholders as of the record date have the
exclusive opportunity to buy additional shares of the new common stock for a
price of $10.40 per share, up to an aggregate of $90 million. Shareholders who
wish to purchase more than their allocable portion of the shares offered to them
in this rights offering may do so, to the extent that other shareholders do not
elect to participate in the rights offering.
The Standby Loan.
The majority of the funds necessary for the payment of the allowed bank
group claim were obtained through an advance under the new credit facility with
Chase of $183.0 million of the initial borrowing base. The remaining amount of
the allowed bank group claim has been paid with the standby loan. The standby
loan has been made under a senior subordinated note facility under which we
issued, and PPM America, Inc., Appaloosa Management, L.P., Oaktree Capital
Management, L.L.C. and Pacholder Associates, Inc. and their assignees,
purchased, $72 million of senior subordinated notes. Our rights and
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<PAGE> 37
responsibilities and those of the standby lenders are governed by a standby loan
agreement which was executed and delivered on March 31, 2000.
Debt under the standby loan agreement is evidenced by notes, maturing seven
years after the effective date, and bearing interest at a minimum annual rate of
15% and payable in cash semiannually. After the first anniversary of the
effective date, additional semiannual interest payments will be payable in an
amount equal to 1/2% for every $0.25 that the "actual price" for our oil and
gas production exceeds $15 per barrel of oil equivalent during the applicable
semiannual interest period, up to a maximum of 10% additional interest per year.
The "actual price" for our oil and gas production is the weighted average price
received by us for all of our oil and gas production, including hedged and
unhedged production, net of hedging costs, in dollars per barrel of oil
equivalent using a 6:1 conversion ratio for natural gas. The actual price will
be calculated over a six-month measurement period ending on the date two months
before the applicable interest payment date. Additionally, upon an event of
default occurring under the standby loan, interest will be payable in cash,
unless otherwise required to be paid-in-kind, at a rate equal to 2% per year
over the applicable interest rate. Interest payments under the standby loan may
be paid-in-kind subject to the requirements of the new credit agreement.
"Paid-in-kind" refers to the payment of interest owed under the standby loan by
increasing the amount of principal outstanding under the standby loan notes,
rather than paying the interest in cash.
Payment of the standby loan notes is expressly subordinate to payments in
full in cash of all obligations arising in connection with the new credit
facility. After the initial 12-month period, cash interest payments may be made
only to the extent by which EBITDA, or earnings before interest, tax,
depreciation and amortization expense, on a trailing four-quarter basis exceed
$65 million. The new credit agreement also prohibits us from making any cash
interest payments on the standby loan indebtedness if the outstanding
indebtedness under both the new credit facility and the standby loan exceeds
3.75 times the EBITDA for the trailing four quarters. We may prepay the standby
loan notes at the face amount, in whole or in part, in minimum denominations of
$1,000,000, plus either a standard make-whole payment at 300 basis points over
the "treasury rate" for the first four years. Beginning in the fifth year, the
prepayment fee is 7.5% of the principal amount being prepaid; in the sixth year,
the prepayment fee is 3.75% of the principal amount being prepaid; and after the
sixth year there is no prepayment fee. The "treasury rate" is the yield of U.S.
Treasury securities with a term equal to the then-remaining term of the standby
loan notes that has become publicly available on the third business day before
the date fixed for repayment.
When the standby loan notes were issued, the standby lenders became
entitled to receive a percentage of our fully diluted new common stock. Because
$72 million in principal amount of the standby loan notes were issued, the
standby lenders will receive 14.4% of the fully diluted new common stock. The
shares of new common stock issued to the standby lenders will be in addition to
the shares of new common stock issued to holders of the old bonds, to our
shareholders prior to reorganization and to persons participating in this rights
offering. See the section of this prospectus called "Dilution" for an
illustration of the dilution of the new common stock.
Fees for the standby lenders contained in the standby lender fee letter to
us dated January 24, 2000 were approved by the bankruptcy court at a hearing on
the fees held on January 27, 2000. These fees include a due diligence fee of
$200,000, payable immediately, and a closing fee in an amount equal to the
greater of $1.0 million or 3 1/2% of the aggregate principal amount of the
standby loan notes purchased. Our obligation to pay the closing fee was an
administrative expense claim having priority over all administrative expenses in
accordance with Section 364(c)(1) of the bankruptcy code. We have paid the
closing fee of $2.52 million.
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<PAGE> 38
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with our
consolidated financial statements included in this prospectus. Some information
contained in this prospectus, including information with respect to our plans
and strategy for its business, are forward-looking statements. For more
information about the limitations associated with these types of statements, see
the section of this prospectus called "Cautionary Statement Regarding
Forward-Looking Statements."
SUBSEQUENT EVENTS
See the subsections below called "Bankruptcy Proceedings" and "Liquidity
and Capital Resources" for a description of certain events affecting our current
liquidity.
OUR HISTORY
We were incorporated in June 1993 under the laws of the State of Texas and
currently conduct a majority of our operations through Coho Resources, Inc.
In December 1994, we acquired all of the capital stock of Interstate
Natural Gas Company. Interstate Natural Gas, through its subsidiaries, was a
privately-held natural gas producer, gatherer and pipeline company operating in
Louisiana and Mississippi. To acquire Interstate Natural Gas, we:
- paid $20 million cash,
- assumed net liabilities of $3.3 million, excluding deferred taxes, and
- issued 2,775,000 shares of our old common stock and 161,250 shares of
redeemable preferred stock having an aggregate stated value of $16.1
million.
The preferred shares were exchanged on August 30, 1998 for 3,225,000 shares of
our old common stock. We accounted for the acquisition of Interstate Natural Gas
with the purchase method.
In April 1996, Interstate Natural Gas sold all of the stock of three
wholly-owned subsidiaries comprising its natural gas marketing and
transportation segment to an unrelated third party in exchange for:
- cash of $19.5 million,
- the assumption of net liabilities of approximately $2.3 million, and
- the payment of taxes of up to $1.2 million generated as a result of the
tax treatment of the transaction.
The marketing and transportation segment is accounted for as discontinued
operations in this prospectus.
On October 3, 1997, we issued 5,000,000 shares of common stock at $10.50
per share and $150 million of 8 7/8% senior subordinated notes due 2007, which
are our old bonds. The combined $193.7 million in proceeds from these offerings
were used to repay $144.8 million of indebtedness outstanding under our old bank
group loan, to fund general corporate purposes and to fund a portion of the
December 1997 Oklahoma property acquisition discussed in the next paragraph.
Effective December 31, 1997, we acquired from Amoco Production Company
interests in crude oil and natural gas properties located primarily in southern
Oklahoma for approximately $257.5 million in cash and for warrants valued at
$3.4 million to purchase one million shares of our common stock at $10.425 per
share for a period of five years. The Oklahoma properties comprise more than
25,000 gross acres in southern Oklahoma, and include 14 major producing oil
fields. Of the 14 major producing fields, we operate eleven fields. At December
31, 1999, we had an average working interest of approximately 74% in these
eleven fields we operate.
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<PAGE> 39
On December 2, 1998, we sold our natural gas assets, including our natural
gas properties and the related gas gathering systems, located in Monroe,
Louisiana, to an unaffiliated third party for net proceeds of approximately
$61.5 million. The proved reserves attributable to these natural gas properties
represented approximately 14% of our year end 1997 proved reserves. The sale of
these assets represented substantially all of the remaining assets of Interstate
Natural Gas.
GENERAL
Our operating revenues result solely from crude oil and natural gas sales,
with crude oil sales representing approximately 75% of production revenues for
1997, 77% of production revenues for 1998 and 90% of production revenues for
1999. Natural gas sales represented approximately 25% of production revenues for
1997, 23% of production revenues for 1998 and 10% of production revenues for
1999. Approximately 60% of natural gas sales revenues during 1998 were
attributable to the gas properties located in Monroe, Louisiana, which we sold
in December 1998.
Operating revenues increased from $26.5 million in 1994 to $68.8 million in
1998 primarily due to an increase in production volumes from successful
development and exploration activities in our existing Mississippi fields and
due to the following acquisitions:
- the December 1994 acquisition of the Monroe natural gas field,
- the August 1995 acquisition of the Brookhaven field, and
- the December 1997 acquisition of the Oklahoma properties.
Operating revenues were $57.3 million for 1999, representing a 17% decrease
from the same period in 1998. This decrease is attributable to:
- our sale of our natural gas assets in Monroe, Louisiana in December 1998,
which contributed approximately 2,452 BOE per day during 1998,
- overall production declines on our operated properties in Oklahoma and
Mississippi as a result of natural decline and the decrease and ultimate
cessation of well repair work and drilling activity during the last five
months of 1998 and the first four months of 1999, and
- our halting of production on wells that we considered uneconomical
because of depressed crude oil prices.
We also strive to maintain a low cost structure through asset
concentration, such as in the interior salt basin of Mississippi and the
Oklahoma properties. Asset concentration permits operating economies of scale
and leverages operational, technical and marketing capabilities.
The price we receive for crude oil and natural gas may vary significantly
during the year due to the volatility of the crude oil and natural gas market,
particularly during the cold winter and hot summer months. As a result, we have
entered, and expect to continue to enter, into forward sale agreements or other
arrangements for a portion of our crude oil and natural gas production to hedge
our exposure to price fluctuations, though at December 31, 1999, we were not a
party to any forward sale agreements or other arrangements. It is unlikely that
we will be able to enter into any forward sales agreements or other similar
arrangements until we remedy our current liquidity problems because of the
associated credit risks of the counterparty to these agreements. See the
subsection of this prospectus called "Liquidity and Capital Resources" for more
information. While our hedging program is intended to stabilize cash flow and
thus allow us to plan our capital expenditure program with greater certainty,
any hedging transactions may limit our potential gains if crude oil and natural
gas prices rise substantially over the price established by the hedge. Because
all hedging transactions are tied directly to our crude oil and natural gas
production and natural gas marketing operations, we do not believe that these
transactions are of a speculative nature. Gains and losses on these hedging
transactions are reflected in crude oil and natural gas revenues at the time of
sale of the hedged production. Any gain or loss on our crude oil hedging
transactions is determined
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<PAGE> 40
as the difference between the contract price and the average closing price for
West Texas Intermediate crude oil on NYMEX for the contract period. Any gain or
loss on our natural gas hedging transactions is generally determined as the
difference between the contract price and the average settlement price on NYMEX
for the last three days during the month in which the hedge is in place.
Consequently, hedging activities do not affect the actual price received for our
crude oil and natural gas.
We also control the magnitude and timing of our capital expenditures by
obtaining high working interests in and operating our properties. At December
31, 1999, we owned an average working interest of 77% in the fields we operate.
BANKRUPTCY PROCEEDINGS
On August 23, 1999, we and our wholly owned subsidiaries, Coho Resources,
Inc., Coho Oil & Gas, Inc., Coho Exploration, Inc., Coho Louisiana Production
Company and Interstate Natural Gas Company, filed a voluntary petition for
relief under Chapter 11 of the U.S. Bankruptcy Code in the United States
Bankruptcy Court for the Northern District of Texas. We filed schedules with the
bankruptcy court on September 21, 1999, and amended these schedules on December
14, 1999. These schedules contain our unaudited, and in some cases estimated,
assets and liabilities as of August 23, 1999, as shown by our accounting
records.
The bankruptcy petitions were filed to facilitate the restructuring of our
long term debt and to protect us while we develop a solution to our capital
needs with the banks, bondholders and potential investors. The following list
contains some important dates in our bankruptcy process:
<TABLE>
<S> <C>
- - August 23, 1999 -- We filed a voluntary Chapter 11 bankruptcy petition.
- - November 30, 1999 -- We filed our initial plan of reorganization.
- - December 21, 1999 -- We filed our disclosure statement and amended plan of
reorganization.
- - February 4, 2000 -- At a hearing, the bankruptcy court approved our
disclosure statement with respect to our plan of
reorganization and scheduled a confirmation hearing for
March 15, 2000, to consider our plan of reorganization.
- - February 14, 2000 -- We and the Committee of Unsecured Creditors jointly filed
the Debtors' and Creditors Committee's First Amended and
Restated Chapter 11 Plan of Reorganization to reflect the
matters contained in the approved disclosure statement
and we began mailing our approved disclosure statement to
holders of claims and equity interests for voting on our
plan of reorganization.
- - February 15, 2000 -- We filed our approved disclosure statement with the
bankruptcy court.
- - March 10, 2000 -- Deadline for submitting votes on our plan of
reorganization.
- - March 15, 2000 -- The confirmation hearing to consider our plan of
reorganization commenced.
- - March 20, 2000 -- The bankruptcy court entered an order confirming our plan
of reorganization and approving our settlement with
Chevron.
- - March 31, 2000 -- The effective date of consummation of our plan of
reorganization.
</TABLE>
Our plan of reorganization described the means for satisfying claims,
including liabilities subject to compromise, and interests in Coho. Our plan of
reorganization included the cancellation of our old common stock and the
issuance of a new class of common stock in exchange for our old common stock and
our old bonds. The issuance of our new class of common stock materially diluted
the old equity interests.
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<PAGE> 41
Our ability to effect a successful reorganization through our bankruptcy
proceedings depended upon our ability to obtain approval for the plan of
reorganization. As of March 3, 2000, the date the financial statements were
finalized, it was not possible to predict the outcome of the bankruptcy
proceedings, in general, or their effect on our business or on the interests of
our creditors or shareholders. We believed, however, that it would not be
possible to satisfy in full all of the claims against us if the plan of
reorganization was not approved. As a result of the bankruptcy filing, all of
our liabilities incurred before August 23, 1999, including secured debt, are
subject to compromise. Under the Bankruptcy Code, payment of these liabilities
may not be made except under a plan of reorganization or bankruptcy court
approval.
The December 31, 1999 financial statements do not include any adjustments
relating to the recoverability and classification of asset carrying amounts,
including $311.8 million in net property, plant and equipment, or the amount and
classification of liabilities that might result should we be unable to continue
as a going concern. Our ability to continue as a going concern is dependent on
adequate sources of capital and the ability to sustain positive results of
operations and cash flows sufficient to continue to explore for and develop oil
and gas reserves.
As a result of the Chapter 11 filing, we have incurred and will continue to
incur significant costs for professional fees as the plan of reorganization is
developed. We have incurred approximately $3.1 million in reorganization costs
during 1999, relating to the professional fees for consultants and attorneys who
are assisting in the negotiations associated with the financing and
reorganization alternatives, partially offset by interest income earned since
August 23, 1999, on accumulated cash.
As of the effective date for consummation of our plan of reorganization we
anticipate significant adjustments will be made to our first quarter 2000
financial statements to effect the reorganization.
RESULTS OF OPERATIONS
Selected Operating Data
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1997 1998 1999
------- ------- -------
<S> <C> <C> <C>
PRODUCTION:
Crude oil (Bbl/day)....................................... 7,726 13,889 9,159
Natural gas (Mcf/day)..................................... 21,003 22,260 7,146
BOE (Bbl/day).......................................... 11,227 17,599 10,350
AVERAGE SALES PRICES:
Crude oil (per Bbl)....................................... $ 16.31 $ 10.40 $ 15.40
Natural gas (per Mcf)(a).................................. 2.23 1.98 2.24
PER BOE DATA:
Production costs(b)....................................... $ 3.90 $ 4.18 $ 5.60
Depletion................................................. 4.69 4.38 3.63
PRODUCTION REVENUES (IN THOUSANDS):
Crude oil................................................. $45,991 $52,689 $51,469
Natural gas............................................... 17,139 16,070 5,854
------- ------- -------
Total production revenues......................... $63,130 $68,759 $57,323
======= ======= =======
</TABLE>
- ---------------
(a) Natural gas prices are net of fuel costs used in gas gathering.
(b) Includes lease operating expenses and production taxes, exclusive of
general and administrative costs.
1999 COMPARED WITH 1998
Operating Revenues. During 1999, production revenues decreased 17% to $57.3
million as compared to $68.8 million in 1998. This decrease was principally due
to a 34% decrease in crude oil production and
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<PAGE> 42
a 68% decrease in natural gas production, substantially offset by increases of
48% in the price received for crude oil and 13% in the price received for
natural gas, including hedging gains and losses discussed below.
The 68% decrease in daily natural gas production during 1999 is primarily
due to the December 1998 sale of the Monroe field gas properties which accounted
for 67% of our natural gas production during 1998. The 34% decrease in daily
crude oil production during 1999 is due to overall production declines in the
Mississippi and Oklahoma properties that we operate. Due to our capital
constraints caused by the decline in crude oil prices during 1998, we:
- significantly reduced both minor and major well repairs and drilling
activity on our operated properties during the last five months of 1998,
- ceased all well repairs and drilling activity in December 1998, and
- halted production on wells which were uneconomical due to depressed crude
oil prices.
All of these actions contributed to our overall production declines. Since May
1999, we have been using working capital provided by operations to perform well
repair work to return some of our shut-in wells to production in response to the
improved crude oil prices in the second quarter of 1999. We intend to continue
to use available working capital, if any, generated from improved prices and
improved production to fund further well repairs and some well recompletions to
stabilize production. Despite the recent increases in price and the recent
repair work, we do not anticipate a significant improvement in production over
the production in 1999 until substantial additional funds are available for well
repairs and additional development activity.
Average crude oil prices increased 48% during 1999 compared to the same
period in 1998. During 1998 and the first quarter of 1999, substantially all of
our crude oil was sold under contracts which were keyed off of posted crude oil
prices. Beginning in April 1999, we entered into a new crude oil contract for
substantially all of our Oklahoma crude oil, now keyed off of the NYMEX price,
which should result in a net increase in our realized price. Our overall average
crude oil price per Bbl was $15.40, which represented a discount of 20% to the
average NYMEX price in 1999.
Our realized price for our natural gas, including hedging gains and losses
discussed below, increased 13% from $1.98 per Mcf in 1998 to $2.24 per Mcf in
1999 due to an increase in demand for natural gas during 1999.
Production revenues for 1999 and 1998 did not include any crude oil hedging
gains or losses. Production revenues in 1999 did not include any natural gas
hedging gains or losses compared to natural gas hedging gains of $488,000 ($0.06
per Mcf) for 1998.
Expenses. Production expenses, including production taxes, were $21.2
million for 1999 compared to $26.9 million for 1998. The decrease in expenses
between years is primarily due to:
- decreased production,
- decreased production taxes, and
- the December 1998 sale of the Monroe properties.
On a BOE basis, production costs increased 34% to $5.60 per BOE in 1999 compared
to $4.18 per BOE in 1998. On a BOE basis, the increase in production costs is
primarily due to a decrease in production volumes, which resulted in a higher
fixed cost per BOE, and $3.3 million of well repair work performed during the
last half of 1999 to return shut-in wells to production. Additionally, severance
taxes increased $0.25 per BOE over the same period last year due to higher price
realization. The current well repair work represents an accumulation of projects
because we had reduced both minor and major well repairs during the last five
months of 1998 and ceased substantially all well repair work in December 1998
due to depressed oil prices.
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<PAGE> 43
General and administrative costs increased $2.2 million or 28% between the
comparable periods. This increase is primarily due to the expensing of all
salaries and other general and administrative costs associated with exploration
and development activities during 1999 as compared to the capitalization of $5.7
million of these costs in 1998. Total general and administrative costs,
excluding capitalization of administrative costs associated with exploration and
development activities, decreased $3.6 million or 27% between the comparable
periods. This decrease is primarily due to:
- cost reductions associated with the Monroe field sale,
- reductions in employee-related costs due to staff attrition,
- reductions in estimated franchise tax accruals as a result of our losses
in 1998, and
- reductions in professional fees and general corporate costs.
These decreases were partially offset by lower cost recoveries from working
interest owners due to a decrease in well activity.
State income tax penalties of $1.0 million for 1999 result from
approximately $4 million in Louisiana state income taxes which were due on April
15, 1999, resulting from the gain on the December 1998 sale of the Monroe gas
field. The past due taxes include the accrual of the maximum penalty of 25% of
the taxes due.
Interest expense increased 3% in 1999 compared to 1998 primarily as a
result of higher interest rates from payment defaults and debt acceleration, but
partially offset by the discontinuance of interest expense accruals on our
unsecured debt. On August 24, 1999, we discontinued the accrual of interest on
our unsecured debt as a result of our Chapter 11 filing. We would have
recognized approximately $5.7 million of additional interest expense in 1999,
including $2.2 million of interest on our old bonds that would have been due on
October 15, 1999, if not for the discontinuation of these interest expense
accruals. The average interest rate on outstanding indebtedness was 8.55% in
1999, compared to 8.07% in 1998.
Depletion and depreciation expense decreased 51% to $13.7 million in 1999
from $28.1 million in 1998. This decrease is primarily the result of decreased
production volumes and a decreased depletion and depreciation rate per BOE,
which was $3.63 in 1999, compared with $4.38 in 1998. The depletion and
depreciation rate per BOE decreased between 1998 and 1999 due to the writedowns
of oil and gas properties in 1998 as discussed in the next paragraph.
In accordance with generally accepted accounting principles, at a point in
time coinciding with the quarterly and annual reporting periods, we must test
the carrying value of our crude oil and natural gas properties, net of related
deferred taxes, against the "cost center ceiling." The "cost center ceiling" is
a calculated amount based on estimated reserve volumes valued at then-current
realized prices held flat for the life of the properties discounted at 10% per
annum plus the lower of cost or estimated fair value of unproved properties. If
the carrying value exceeds the cost center ceiling, the excess must be expensed
in that period and the carrying value of the oil and gas reserves lowered
accordingly. Amounts required to be written off may not be reinstated for any
subsequent increase in the cost center ceiling. During 1998, the carrying values
related to our United States properties exceeded the cost center ceilings,
resulting in non-cash writedowns of our crude oil and natural gas properties of
$188 million. These writedowns resulted from the declines in crude oil prices in
1998. No writedowns of this kind were required on our United States properties
in 1999.
In June 1999, we commenced drilling an exploratory well on our Anaguid
permit in Tunisia, North Africa, due to our obligation under the permit. In
September 1999, we tested the well and determined that the well would not
produce sufficient quantities of crude oil to justify further completion work on
it. As a result, we took a writedown of our Tunisian properties of $5.4 million
during the third quarter of 1999. Anadarko Tunisia Anaguid Company, one of the
working interest owners in this permit, assumed responsibility as operator in
December 1999 and plans to continue exploration of this permit. Our
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<PAGE> 44
remaining carrying cost in this permit is $2.4 million associated with
geological and geophysical costs that will be used for this continued
exploration.
Reorganization costs of $3.1 million in 1999 relate to professional fees
for consultants and attorneys assisting us in the negotiations associated with
our financing and reorganization alternatives and are partially offset by
interest income earned since August 23, 1999, on accumulated cash.
Our net operating loss carryforwards for United States and Canadian federal
income tax purposes were approximately $124.0 million at December 31, 1999 and
expire between 2000 and 2019. Statement of Financial Accounting Standards No.
109, "Accounting for Income Taxes," requires that the tax benefit of those net
operating loss carryforwards be recorded as an asset to the extent that
management assesses the utilization of those net operating loss carryforwards to
be more likely than not. A valuation allowance has been established for the
entire net deferred tax asset balance of these net operating loss carryforwards
as it is uncertain whether they will be used before they expire.
Due to the factors discussed above, our net loss for 1999 was $30.7
million, as compared to a net loss of $203.3 million for 1998. The 1999 loss
includes a writedown of our Tunisian oil and gas properties of $5.4 million and
the 1998 loss includes writedowns of our United States crude oil and natural gas
properties of $188.0 million.
1998 COMPARED WITH 1997
Operating Revenues. During 1998, production revenues increased 9% to $68.8
million as compared to $63.1 million in 1997. This increase was principally due
to an 80% increase in crude oil production and a 6% increase in natural gas
production, substantially offset by decreases of 36% in the prices received for
crude oil and decreases of 11% in the prices received for natural gas including
hedging gains and losses discussed below.
The 6% increase in daily natural gas production is primarily due to a 26%
increase in production as a result of the December 1997 acquisition of the
Oklahoma properties, substantially offset by production declines on our
Brookhaven, Martinville, North Padre and Monroe fields. Additionally, the Monroe
field was sold to an unaffiliated third party on December 2, 1998, resulting in
lower gas production for 1998 as compared to 1997. The Monroe field represented
85% of our gas production in 1997 and 67% of our gas production in 1998. The 80%
increase in daily crude oil production during 1998 is primarily due to a 76%
increase in production as a result of the acquisition of the Oklahoma
properties. Although we increased crude oil production during the first three
quarters of 1998 as compared to the same period in 1997 in the Martinville and
Brookhaven fields, these increases were substantially offset by fourth quarter
1998 crude oil production declines of 21% on our Mississippi fields as compared
to the fourth quarter of 1997 and overall crude oil production declines in the
Soso and Summerland fields throughout 1998 as compared to 1997.
Crude oil and natural gas production declined in the fourth quarter of 1998
from an average of 18,495 BOE per day during the first nine months of 1998 to
14,939 BOE per day during the fourth quarter of 1998 due to the December 1998
sale of the Monroe field natural gas properties and to overall production
declines in the operated Mississippi and Oklahoma properties. Due to our capital
restraints caused by the decline in crude oil prices, we significantly reduced
both minor and major well repairs on our operated properties during the last
five months of 1998 and ceased all well repairs in December 1998, resulting in
overall production declines.
Average crude oil prices realized in 1998, including hedging gains and
losses discussed below, decreased from 1997 due to declining oil prices which
can be attributed to several factors, including:
- a lack of cold weather in the 1998 winter months,
- increased storage inventories, and
- perceptions of the effects of increased quotas or lack of adherence to
quotas from the Organization of Petroleum Exporting Countries.
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<PAGE> 45
The posted price for our crude oil averaged $11.32 per Bbl in 1998, a 38%
decrease over the average posted price of $18.34 per Bbl experienced in 1997.
The price per Bbl we received is adjusted for the quality and gravity of the
crude oil and is generally lower than the posted price.
The realized price for our natural gas, including hedging gains and losses
discussed below, decreased 11% from $2.23 per Mcf in 1997 to $1.98 per Mcf in
1998 due to a lack of cold weather and market volatility.
Production revenues for 1998 did not include crude oil hedging gains or
losses compared to crude oil hedging losses of $0.3 million ($0.11 per Bbl) in
1997. Production revenues in 1998 included natural gas hedging gains of $0.5
million ($0.06 per Mcf) compared with natural gas hedging gains of $0.1 million
($0.01 per Mcf) for 1997.
Interest and other income decreased to $214,000 in 1998 from $646,000 in
1997 primarily due to a decline of interest received on cash investments in
1998. In 1997, we received $137,000 of interest in the first quarter on a
federal tax refund and earned $465,000 of interest in the fourth quarter on cash
investments.
Expenses. Production expenses, including production taxes, were $26.9
million for 1998 compared to $16 million for 1997. On a BOE basis, production
costs increased to $4.18 per BOE in 1998 compared to $3.90 per BOE in 1997. The
increase in expenses between years is primarily due to an increase of
approximately $11.8 million relating to the December 1997 acquisition of the
Oklahoma properties. This increase was partially offset by reduced operating
costs on our Mississippi properties due to the improved operating efficiencies
and due to our reduction of repairs during the last half of 1998 because of the
decline in crude oil prices.
General and administrative costs increased 8% from $7.2 million in 1997 to
$7.8 million in 1998. This increase resulted primarily from increased personnel
costs due to staff additions to handle the increased capital activities in
Mississippi during the first half of 1998 and the December 1997 acquisition of
the Oklahoma properties. In addition, this increase resulted from the accrual of
a $0.4 million fee related to the termination of a drilling contract which
extended through mid-year 1999, partially offset by an increase in
capitalization of salaries and other general and administrative costs directly
associated with our exploration and development activities.
Allowance for bad debt in 1998 represents an allowance for uncollectible
accounts receivable from working interest owners and an allowance for director
and employee receivables as discussed in Note 11 to the consolidated financial
statements contained elsewhere in this prospectus.
Unsuccessful transaction costs of $2.1 million incurred in 1998 relate to
the termination of an agreement in which we were to issue $250 million of
equity. These costs are comprised of $1.2 million for financial advisory
services in conjunction with this transaction, $0.5 million for an outside
financial advisor regarding the fairness of the agreement and $0.4 million for
legal, accounting and other services.
Interest expense increased 296% in 1998 compared to 1997, due to higher
borrowing levels during 1998 as compared to 1997 and to the sale of $150 million
of senior notes on October 3, 1997, which bear a higher interest rate than our
revolving credit facility. The average interest rate paid on outstanding
indebtedness was 8.07% in 1998, compared to 7.84% in 1997. Our borrowing levels
increased throughout 1997 and 1998 due to additional borrowings to fund our
capital expenditure program and the December 1997 acquisition of the Oklahoma
properties.
Depletion and depreciation expense increased 46% to $28.1 million in 1998
from $19.2 million in 1997. These increases are primarily the result of
increased production volumes partially offset by a decreased rate per BOE, which
decreased to $4.38 in 1998, compared with $4.69 in 1997. The depletion and
depreciation rate per BOE decreased between 1997 and 1998 because of the
writedowns of oil and gas properties in 1998 as discussed below.
During 1998, the carrying values of our crude oil and natural gas
properties exceeded the cost center ceilings, resulting in non-cash writedowns
of the crude oil and natural gas properties, aggregating
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<PAGE> 46
$188 million, including $32 million recognized in the first quarter of 1998, $41
million recognized in the second quarter of 1998 and $115 million recognized in
the fourth quarter of 1998.
Current tax expense of $4.1 million in 1998 primarily relates to state
income taxes due on the December 1998 sale of the Monroe field natural gas
properties and related gas gathering systems.
Our net loss for 1998 was $203.3 million, as compared to net earnings of
$6.3 million for 1997, for the reasons discussed above.
LIQUIDITY AND CAPITAL RESOURCES
Capital Sources. During 1999, cash flow provided by operating activities
was $14.9 million compared with $1.0 million during 1998. Operating revenues,
net of lease operating expenses, production taxes and general and administrative
expenses, decreased $7.9 million during 1999 as compared to 1998. This decrease
resulted primarily from a 42% decline in production on a BOE basis between
comparable periods, partially offset by price increases between comparable
periods of 48% for crude oil and 13% for natural gas. In addition, due to the
cessation of exploration and development of crude oil and natural gas reserves,
no overhead expenditures were capitalized during 1999 as compared to $5.7
million of capitalized overhead during 1998. We also incurred costs totaling
$4.2 million in 1999 related to state income tax penalties and reorganization
costs and additional interest expense of $1.0 million in 1999 over 1998. Changes
in operating assets and liabilities provided $25.8 million of cash for operating
activities for 1999, compared to $4.6 million provided for 1998, primarily due
to an increase in accrued interest payable. See the subsection called "Results
of Operations" for a discussion of operating results.
As discussed more fully under "Results of Operations," operating revenues
declined during 1998 and the first half of 1999 due to crude oil and natural gas
price declines. Additionally, our crude oil and natural gas production declined
from an average of 17,599 BOE per day during 1998 to 10,350 BOE per day during
1999. We do not anticipate a significant improvement in production over the
production in 1999 until substantial additional funds are available for well
repairs and additional development activity. See "Results of Operations -- 1999
Compared to 1998" for a discussion of production declines.
Based on the December 1999 production level of approximately 10,320 BOE per
day and the average price received in December 1999 of approximately $21.78 per
barrel of crude oil and $2.25 per Mcf of natural gas, our operating revenues are
adequate to cover lease operating expenses, production taxes, general and
administrative expenses and current interest accruing on the borrowings under
the old bank group loan but are not sufficient to cover past due interest on our
old bonds or on the borrowings under the old bank group loan.
Our working capital deficit, including $423.7 million of liabilities
subject to compromise, was $407.5 million at December 31, 1999 compared to a
working capital deficit of $388.3 million at December 31, 1998. The increase in
the working capital deficit relates to several factors. Accrued interest
increased by $24.2 million primarily because we were unable to make interest
payments when due prior to filing bankruptcy on August 23, 1999 and because
interest had been accruing on the old bank group loan at the default rate of
prime plus 4% since August 23, 1999. We also borrowed an additional $4.6 million
under the old bank group loan in January 1999 that is reflected in the current
portion of long term debt. Cash balances on hand increased from $6.9 million at
December 31, 1998 to $18.8 million at December 31, 1999, partially offsetting
the increase in current liabilities. The increase in cash occurred as a result
of our Chapter 11 filing and reductions in spending under limitations imposed by
the bankruptcy court.
Subsequent to August 23, 1999 we filed three motions with the bankruptcy
court to seek the use of the bank group's cash collateral in on-going
operations. From August 26, 1999 to March 31, 2000, we operated under three
interim orders authorizing the use of cash collateral as approved by the
bankruptcy court. Under these orders, we could pay for ordinary course of
business goods and services incurred after August 23, 1999 that were within the
court approved budgets attached to each order. We had
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<PAGE> 47
accumulated, as of December 31, 1999, $18.8 million in cash, an increase of
$12.8 million since August 23, 1999, that could be used for operations under the
terms of the cash collateral orders.
We and the bank group agreed to an extension of the cash collateral order
through March 31, 2000. We paid additional interest payments of $1.8 million on
February 1, 2000 and March 1, 2000.
On February 22, 1999, we were informed by the bank group that our borrowing
base was reduced from $242 to $150 million effective January 31, 1999 creating
an over advance of $89.6 million under the new borrowing base. Under the terms
of the old bank group loan, we were required to cure the over advance amount by
March 2, 1999 by either:
- providing collateral with value and quantity in amounts equal to the
excess,
- prepaying, without premium or penalty, the excess plus accrued interest,
or
- paying the first of five equal monthly installments to repay the over
advance.
We were unable to cure the over advance as required by the old bank group loan
and received written notice from the bank group on March 8, 1999, that we were
in default under the terms of the old bank group loan and the bank group
reserved all rights, remedies and privileges as a result of the payment default.
Additionally, we were unable to pay the second installment due at the beginning
of April, the third installment due at the beginning of May, the fourth
installment due at the beginning of June and the fifth installment due at the
beginning of July, 1999. We have made aggregate interest payments of
approximately $3.4 million during the period between March and July 1999. As a
result of the payment defaults, advances under the old bank group loan bore
interest at the prime rate, and the loan agreement provided that past due
installments to repay the over advance and past due interest would bear interest
at the default interest rate of prime plus 4%. On August 19, 1999, the bank
group accelerated the full amount outstanding under the old bank group loan. The
bank group contended that the default rate of interest was owed on all amounts,
not only the over advance, since the date of acceleration. Under a cash
collateral order approved by the bankruptcy court in November 1999, we made an
interest payment of $878,000 to the bank group in December 1999 and were
required to make monthly interest payments of approximately $1.8 million. Due to
the default, the outstanding advances of $239.6 million have been included in
liabilities subject to compromise as of December 31, 1999. The total amounts
related to the installment payments due on the over advance and past due
interest were approximately $108.8 million as of December 31, 1999, including
approximately $19.2 million of past due interest, $10.2 million included in
liabilities not subject to compromise, and $89.6 million related to installments
due on the over advance.
The old bank group loan contained financial and other covenants including:
- the maintenance of minimum amounts of shareholders' equity -- $108
million plus 50% of accumulated consolidated net income beginning in 1998
for the cumulative period excluding adjustments for any writedown of
property, plant and equipment, plus 75% of the cash proceeds of any sales
of our capital stock,
- maintenance of minimum ratios of cash flow to interest expense of 1.5 to
1.0 as well as current assets including unused borrowing base to current
liabilities of 1.0 to 1.0,
- limitations on our ability to incur additional debt, and
- restrictions on the payment of dividends.
At December 31, 1999, we were not in compliance with the minimum shareholders'
equity, cash flow to interest expense and current asset to current liability
covenants.
We did not pay the April 15, 1999 interest payment of approximately $6.7
million due on our old bonds and were in default under the terms of the old bond
indenture. Under the old bond indenture, the trustee under the old bond
indenture by written notice to us, or the holders of at least 25% in principal
amount of the outstanding old bonds by written notice to the trustee and us,
could declare the principal
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<PAGE> 48
and accrued interest on all the old bonds due and payable immediately. However,
we could not pay the principal of, any premium or interest on the old bonds so
long as any required payments due on the old bank group loan remained
outstanding and had not been cured or waived. On May 19, 1999, we received a
written notice of acceleration from two holders of the old bonds, which owned in
excess of 25% in principal amount of the outstanding old bonds. Both the
accelerated principal and the past due interest payment bore interest at the
default rate of 9.875%, which is 1% in excess of the stated rate for the old
bonds, from the date of acceleration to August 23, 1999. As a result of our
bankruptcy filing we ceased accruing interest on unsecured debt, including the
old bonds. Approximately $5.7 million of additional old bond interest expense,
including $2.2 million of old bond interest expense that would have been due on
October 15, 1999, would have been recognized by us in 1999 if not for the
discontinuance of the interest expense accruals. All amounts outstanding under
the old bonds as of December 31, 1999 have been included in liabilities subject
to compromise.
We did not pay approximately $4 million in Louisiana state income taxes
which were due on April 15, 1999, related to the gain on the December 1998 sale
of the Monroe gas field. The past due taxes accrue a monthly penalty of 10% not
to exceed 25% of the taxes due. The maximum penalty of $1.0 million was expensed
during the second and third quarters of 1999. We anticipate that these taxes and
penalties will be paid under the plan of reorganization with a five year
promissory note bearing interest at 6% per annum, unless the bankruptcy court
chooses another rate, or paid on other agreed terms.
On December 2, 1998, we sold our natural gas assets, including our natural
gas properties and the related gas gathering systems, located in Monroe,
Louisiana for approximately $61.5 million. Proceeds from the sale were used to
reduce borrowings under the old bank group loan.
Plan of Reorganization. We filed our plan of reorganization with the
bankruptcy court on November 30, 1999, subsequently amended and modified, and a
confirmation hearing was held beginning on March 15, 2000 for final approval of
the plan of reorganization. On March 20, 2000, the bankruptcy court entered a
confirmation order confirming our plan of reorganization and on March 31, 2000,
the effective date of our plan, our plan of reorganization was consummated. For
more information about our plan or reorganization, see the section of this
prospectus called "The Plan of Reorganization."
Under the plan of reorganization, we established a new senior revolving
credit facility from a syndicate of new lenders led by The Chase Manhattan Bank,
as agent for the new lenders, for a principal amount of up to $250 million.
Additionally, we are attempting to raise up to $90 million of new investment by
the rights offering. We also borrowed $72 million under the standby loan. For
more information, see the section of this prospectus called "The Plan of
Reorganization -- The New Debt and Equity."
Cash on hand as of the effective date, together with borrowings under the
new credit facility and borrowings under the standby loan will be used to:
- repay amounts due under the old bank group loan, including accrued
interest and reasonable fees and expenses,
- pay administrative expenses associated with the bankruptcy proceeding,
and
- provide working capital for future operations.
Proceeds from the rights offering will be used to pay down indebtedness under
either the standby loan or the new credit facility, and to provide working
capital and for general corporate purposes. See the section of this prospectus
called "Use of Proceeds" for more information. General unsecured creditors will
be paid in full in four equal quarterly installments from working capital during
the year following the effective date and tax claims will receive five-year
promissory notes bearing interest at a rate of 6% per annum, unless a different
rate is chosen by the bankruptcy court, or paid on other agreed terms. For more
information, see the section of this prospectus called "The Plan of
Reorganization -- Classification and Treatment Summary."
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The holders of our old bonds received shares representing 96% of our new
common stock as of the effective date without giving effect to dilution from
shares issued under this rights offering or the standby loan. For more
information, see the section of this prospectus called "The Plan of
Reorganization -- 2. Old Bondholders."
Old shareholders received shares representing 4% of our new common stock on
a basis of one share of new common stock for 40 shares of old common stock as of
the effective date without giving effect to dilution from shares issued under
this rights offering or the standby loan and rights to purchase additional
shares of our new common stock at $10.40 per share. Additionally, old
shareholders are eligible to receive 20% of any proceeds from the Hicks Muse
lawsuit after fees and expenses, and 40% of any proceeds from the disposition of
our interest in, or the assets of, Coho Anaguid, Inc. For more information, see
the section of this prospectus called "The Plan of Reorganization -- 3. Old
Shareholders."
Dividends. It is unlikely that we will pay dividends in the foreseeable
future. The terms of the new credit facility and the standby loan restrict our
paying dividends.
Capital Expenditures. During 1999, we incurred capital expenditures of $6.3
million, which includes $2.1 million spent on the Tunisian well drilled in
mid-1999, compared with $70.1 million for 1998. We ceased substantially all of
our capital projects in 1999 due to our liquidity problems and our bankruptcy
filing. No general and administrative costs associated with our exploration and
development activities were capitalized for 1999, compared with $5.7 million of
capitalized costs for 1998.
During 1998, we incurred capital expenditures of $70.1 million compared
with $72.7 million in 1997. The capital expenditures incurred during 1998 were
largely in connection with the continuing development efforts, including
recompletions, workovers and waterfloods, on existing wells in the following
fields:
<TABLE>
<S> <C>
- - Brookhaven - Tatums
- - Laurel - East Fitts
- - Martinville - North Alma Deese
- - Summerland - Sholem Alechem
- - Bumpass
</TABLE>
In addition, during 1998, we drilled 42 wells which include the following:
<TABLE>
<S> <C> <C>
- - Mississippi fields - Oklahoma fields - Louisiana fields
-- 16 producing oil wells -- 11 producing oil wells -- 2 producing gas wells
-- 1 producing gas well -- 5 producing gas wells -- 3 dry holes
-- 3 dry holes -- 1 dry hole
</TABLE>
General and administrative costs directly associated with our exploration
and development activities were $4.1 million and $5.7 million for the years
ended December 31, 1997 and 1998, respectively, and were included in total
capital expenditures.
Hedging Activities. Crude oil and natural gas prices are subject to
significant seasonal, political and other variables which are beyond our
control. In an effort to reduce the effect of the volatility of the prices
received for crude oil and natural gas, we have entered, and expect to continue
to enter, into crude oil and natural gas hedging transactions. It is unlikely
that we will be able to enter into any forward sales agreements or other similar
arrangements until we remedy our current liquidity problems because of the
associated credit risks of the counterparty to these agreements. Our hedging
program is intended to stabilize cash flow and thus allow us to minimize our
exposure to price fluctuations. Because all hedging transactions are tied
directly to our crude oil and natural gas production, we do not believe that
these transactions are of a speculative nature. Gains and losses on these
hedging transactions are reflected in crude oil and natural gas revenues at the
time of sale of the hedged production. We had no natural gas or crude oil
production hedges during 1999.
We will be required to adopt Statement of Financial Accounting Standard No.
133, "Accounting for Derivative Instruments and Hedging Activities" for the
fiscal year ended 2001. If we had adopted this
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<PAGE> 50
standard during 1999, there would be no effect as we had no hedges outstanding
at December 31, 1999. Although the future impact of adopting this standard has
not yet been determined, we believe that the impact will not be material.
QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
We use financial instruments which inherently have some degree of market
risk. The primary sources of market risk include fluctuations in commodity
prices and interest rate fluctuations.
Price Fluctuations. Our results of operations are highly dependent upon the
prices received for crude oil and natural gas production. We have entered, and
expect to continue to enter, into forward sale agreements or other arrangements
for a portion of our crude oil and natural gas production to hedge our exposure
to price fluctuations. At December 31, 1999, we were not a party to any forward
sale agreements or other arrangements. It is unlikely that we will be able to
enter into any forward sales agreements or other similar arrangements until we
remedy our current liquidity problems because of the associated credit risks of
the counterparty to these agreements. For more information see the section of
this prospectus called "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
Interest Rate Risk. Total debt as of December 31, 1999, included $239.6
million of floating-rate debt attributed to the old bank group loan. As a
result, our annual interest cost in 2000 will fluctuate based on short-term
interest rates. Additionally, due to the current payment defaults under the old
bank group loan discussed under the section of this prospectus called
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," the old bank group loan borrowings and the past due interest will
bear interest at the default interest rate of prime plus 4%. The impact on
annual cash flow of a ten percent change in the floating interest rate
(approximately 125 basis points) would be approximately $3.0 million assuming
outstanding debt of $239.6 million throughout the year.
Total debt as of December 31, 1999, also included $149 million, net of
$900,000 of unamortized original issue discount, of fixed rate old bonds with an
estimated fair market value of $83 million based on quoted prices from market
sources.
On the effective date of the plan of reorganization, the old bank group
loan was paid in full in cash and the old bonds were converted to our new common
stock. A new line of credit has been established with the new lenders and Chase,
as agent for the new lenders. We have also obtained additional funds under the
standby loan in the amount of $72 million. The establishment of the new debt
instruments, as discussed above, is expected to change our interest rate risk.
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<PAGE> 51
BUSINESS
GENERAL
Coho Energy, Inc. is an independent energy company engaged, through its
wholly owned subsidiaries, in the development and production of, and exploration
for, crude oil and natural gas. Our crude oil activities are concentrated
principally in Mississippi and Oklahoma. At December 31, 1999, our total proved
reserves were 113.9 MMBOE with a present value of proved reserves of $790.2
million, approximately 69% of which were proved developed reserves. At December
31, 1999, approximately 94% of our total proved reserves were comprised of crude
oil. At December 31, 1999, our operations were conducted in 21 major producing
fields, 17 of which we operated. Our average working interest in the fields we
operate was approximately 77%.
We were incorporated in June 1993 under the laws of the State of Texas and
conduct a majority of our operations through our subsidiary Coho Resources, Inc.
References in this Prospectus to "Coho," "we," "our," or "us," except as
otherwise indicated, refer to Coho Energy, Inc. and our subsidiaries. Our
principal executive office is located at 14785 Preston Road, Suite 860, Dallas,
Texas 75240, and our telephone number is (972) 774-8300.
BANKRUPTCY PROCEEDINGS
Our ability to effect a successful reorganization through our bankruptcy
proceedings depended on our ability to consummate our plan of reorganization. At
this time, it is not possible to predict the effect of our bankruptcy
proceedings on our business or on the interests of our creditors or
shareholders. For more information regarding the bankruptcy proceedings, see the
sections of this prospectus called "Oil and Gas Operations -- Legal Matters" and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
OUR HISTORY
We commenced operations in Mississippi in the early 1980s and have focused
most of our development efforts in that area. We believe that the salt basin in
central Mississippi offers significant long-term potential due to the basin's
large number of mature fields with multiple oil and gas producing sands. The
application of proven technology to these underexploited and underexplored
fields yields attractive, lower-risk exploitation and exploration opportunities.
As a result of the attractive geology and our experience in exploiting fields in
the area, we have accumulated a large inventory of potential development
drilling, secondary recovery and exploration projects in this basin.
Our focus in the onshore Gulf Coast and Mid-Continent regions has resulted
in significant growth in production and reserves. Our average net daily
production has increased over the last six years from 5,203 BOE in 1993 to
10,350 BOE in 1999, representing a compound annual growth rate of 12.1%;
however, our crude oil and natural gas production has declined from the average
of 17,599 BOE per day produced during 1998. This decline was due in part to the
sale of the Monroe field gas properties in December 1998, which contributed
approximately 2,452 BOE per day during 1998. Further, we experienced overall
production declines on our operated properties in Oklahoma and Mississippi as a
result of:
- the natural production decline,
- the decrease and ultimate cessation of well repair work and drilling
activity during the last five months of 1998 and the first four months of
1999, and
- the halting of production on wells which were uneconomical due to
depressed crude oil prices.
Over the five-year period ended December 31, 1999, we discovered or
acquired approximately 90.9 MMBOE of proved reserves at an average finding cost
of $4.83 per BOE. Over the same period, we
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<PAGE> 52
have replaced over 428% of our production. This increase in reserves from 44.2
MMBOE at year-end 1994 to 113.9 MMBOE at year-end 1999 represents a five-year
compound annual growth rate of 21.0%.
Effective December 31, 1997, we acquired from Amoco Production Company:
- approximately 50 MMBbls of crude oil and natural gas liquid reserves,
- approximately 33 Bcf of natural gas reserves, and
- interests in more than 40,000 gross acres, concentrated primarily in
southern Oklahoma, including 14 principal producing fields.
Daily net production from these properties during December 1997 was
approximately 7,300 BOE. To acquire these properties, we paid $257.5 million in
cash and issued warrants to purchase one million of our common shares at $10.425
per share for a period of five years.
In August 1998, we announced an agreement to issue $250 million of our
common stock at $6.00 per share, approximately 41.7 million shares, to HM4 Coho
L.P., a limited partnership managed by Hicks, Muse, Tate & Furst Incorporated,
giving HM4 an ownership interest in Coho of approximately 62%. On December 15,
1998, we announced that HM4 was terminating the agreement reached in August
1998, which had received shareholder approval, and that we were working on
revising the HM4 agreement to lower the $6.00 price per share to $4.00 on the
$250 million purchase price. After working through all of the issues and
reaching a verbal agreement with all of the interested parties regarding the
proposed restructuring, HM4 informed us on February 12, 1999 that they were no
longer interested in the investment.
On May 27, 1999, we filed a lawsuit against HM4 in the District Court of
Dallas County, Texas. The lawsuit alleges:
- breach of the written contract terminated by HM4 in December 1998,
- breach of the oral agreements reached with HM4 on the restructured
transaction in February 1999, and
- promissory estoppel.
In the lawsuit, we seek monetary damages of approximately $500 million. The
lawsuit is currently in the discovery phase. We filed a motion for summary
judgment on December 22, 1999. While we believe that the lawsuit has merit and
that the actions of HM4 in December 1998 and February 1999 were the primary
cause of our current liquidity crisis, there can be no assurances as to the
outcome of this litigation.
On February 22, 1999, the bank group under our old bank credit facility
notified us that they had decided to reduce our borrowing capacity at January
31, 1999, from $242 million to $150 million, creating an $89.6 million over
advance. The bank group's decision to change our borrowing capacity was based on
the then-current decline in crude oil prices. We were unable to cure the over
advance, and on March 8, 1999, we received written notice from the bank group
that we were in default under the old credit facility, and the bank group
reserved all rights, remedies and privileges as a result of the payment default.
On August 19, 1999, the bank group accelerated the full amount outstanding under
the old bank group loan. For more information about the default under the old
credit facility, see the section of this prospectus called "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
Additionally, our $150 million 8 7/8% bond indenture includes cross-default
provisions, which would effect a default under the terms of our $150 million
8 7/8% bonds if indebtedness under the old bank group loan was not repaid within
the applicable grace period after final maturity. We were unable to make the
$6.7 million interest payment to the holders of our old bonds which was due on
April 15, 1999. On May 19, 1999, we received a written notice of acceleration
from two holders of old bonds, which own in excess of 25% in principal amount of
the outstanding old bonds. As a result, on May 19, 1999, one of the holders of
old bonds filed a lawsuit against us and each of our subsidiaries who is a
guarantor of old bonds
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<PAGE> 53
in the Supreme Court of the State of New York. On January 5, 2000, this lawsuit
was dismissed without prejudice to the plaintiff's ability to refile the lawsuit
in the future, if appropriate. For more information about the default under the
old bonds, see the section of this prospectus called "Management's Discussion
and Analysis of Financial Condition and Results of Operations."
We explored our alternatives to resolve the problems created by the bank
group's actions, including:
- the conversion of a portion or all of our old bonds to equity,
- raising additional equity,
- cost reduction programs to enhance cash flow from operations, and
- refinancing our old bank credit facility to:
- make overdue principal and interest payments on our indebtedness,
- provide additional capital to fund well repairs, and
- provide additional capital to fund the continued development of our
properties.
However, on August 23, 1999, we made the Chapter 11 filing since we believed
that the resolution of our restructuring could not be completed without the
protection and assistance of the bankruptcy court.
BUSINESS STRATEGY
While we remain committed in the long term to our multifaceted growth
strategy, as discussed below, oil prices and cash flow estimates dictate our
near-term business strategy. Most of our near-term capital expenditures are
expected to be made in Oklahoma and Mississippi. Our Oklahoma properties offer
numerous shallow oil and gas recompletion and drilling opportunities with
favorable economics.
In the past we have pursued a multifaceted growth strategy, as follows:
Field Development. Due to our experience in developing oil and gas
properties with long production histories, we maximize production and increase
reserves through activities such as:
- recompletions,
- enhancement of production facilities,
- multi-zone completions,
- development/delineation drilling, including high-angle and horizontal
drilling, and
- secondary recovery projects.
Since 1994, we have drilled 94 development wells, of which 87% were completed
successfully.
Use of Technology. We identify exploration prospects and develop reserves
in the vicinity of our existing fields using technologies that include 3-D
seismic technology. 3-D seismic technology is a tool that allows us to look at
vertical cross-sections as well as horizontal cross-sections beneath the
prospective area of our properties on a very small grid pattern. We first began
using 3-D seismic technology in the Laurel field in Mississippi in 1983, and
have shot two large 3-D seismic programs in and around our existing properties
in Mississippi within the last four years. At the time of purchase, we acquired
four 3-D seismic programs in and around our Oklahoma properties. These programs
have produced an attractive inventory of exploration projects that can be
pursued in the future.
Acquire Properties with Underdeveloped Reserves. We acquire underdeveloped
crude oil and natural gas properties which have geological complexity and
multiple producing horizons. We believe that our extensive experience in
Mississippi developed over the past 15 years should enable us to efficiently
increase reserves and improve production rates in similar geologically complex
environments. Additionally, we believe that this experience gives us a
competitive advantage in evaluating similarly situated acquisition
50
<PAGE> 54
prospects. For more information about our experience in Mississippi, see "Oil
and Gas Operations -- Principal Areas of Activity -- Gulf Coast Area."
Significant Control of Operations. Our long-term strategy of increasing
production and reserves through acquiring and developing multiple-zone fields
requires us to develop a thorough understanding of the complex geological
structures and to maintain operational control of field development. Therefore,
we strive to operate and obtain high working interests in all of our properties.
As of December 31, 1999, we operated 17 of the 21 major fields in which we have
production. Of the operated properties, our average working interest is
approximately 77%. Operating control, combined with our significant technical
and geological expertise, enables us to control the magnitude and timing of our
capital expenditures and field development.
Geographic Focus. We have been able to maintain a low cost structure
through asset concentration. At December 31, 1999, approximately 89% of our Gulf
Coast reserves were concentrated in five fields, and 80% of our Mid-Continent
reserves were concentrated in six fields. Asset concentration permits operating
economies of scale and leverages operational, technical and marketing
capabilities.
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<PAGE> 55
OIL AND GAS OPERATIONS
General. We have focused our operations on three main activities:
conventional exploitation, secondary recovery and exploration. Each of these
interrelated activities plays an important role in our continuing production and
reserve growth. Our 1998 and 1999 operations have been conducted primarily in
the following fields:
- Mississippi -- Brookhaven, Laurel, Martinville, Soso, and Summerland
fields.
- Oklahoma -- Bumpass, Sholem Alechem, and East Fitts fields.
Our capital expenditures totaled $70.1 million in 1998 and $6.3 million in 1999.
The substantial reduction in 1999 capital expenditures was due to budget
constraints resulting from the substantial decline in crude oil prices in 1998
and early 1999, as well as expenditure constraints imposed by the bankruptcy
court subsequent to August 23, 1999.
Conventional Exploitation. Our properties are characterized by the large
number of formations that have been productive, as well as by the large number
of wells that have been drilled over the past 50 years. These well histories
provide considerable geological and reservoir information for use in further
exploration and exploitation.
Acquisition of mature underdeveloped and underexplored fields has been one
of the key elements of our strategy of building reserves and creating
shareholder value. By capitalizing on our operating knowledge and technical
expertise, we have been able to acquire properties and develop substantial
additional low-cost reserves through conventional development drilling and
exploration opportunities. This strategy is illustrated by our 1995 acquisition
of the Brookhaven field in Mississippi. Since acquiring this property in 1995,
we increased total daily field production, by successful exploitation and
exploration, to approximately 1,123 net BOE by year end 1998 from approximately
230 net BOE at the time of acquisition. However, due to natural reservoir
decline and limited well activity, production in the Brookhaven field declined
to 560 BOE per day in 1999. In addition, we increased the proved reserves
associated with our Mid Continent properties to 74.6 MMBOE at December 31, 1999
from 55.5 MMBOE at the time of their acquisition in December 1997, due to our
acquisition of additional working interest in the Mid Continent properties and
the successful exploitation of the Springer, Deese, Viola, Hunton and Bromide
reservoirs in 1998 and 1999.
Secondary Recovery. Over the last five years, we have evaluated 20
secondary recovery projects in the Mississippi salt basin. Six of these projects
have been successfully developed and 14 are undergoing further evaluation or are
in the pilot phase. Since the acquisition of our Oklahoma properties, we have
identified 11 new secondary recovery projects to be developed. These projects
are currently in the study or planning phases. Facilities and wellbores are
being evaluated to begin pilot waterfloods in three of these projects. The
current waterflood operations have been part of our efforts to lower operating
expenses and improve production enhancement opportunities through low cost
waterflood conformance work. These projects have demonstrated strong production
response and meaningful reserve additions. In addition, these projects incur low
production costs due to existing field infrastructures and the ability to
reinject produced water from current operations. We believe opportunities exist
for adding secondary recovery projects throughout our current field inventory.
Exploration. The many productive formations located within our producing
properties substantially reduce dry hole risks, which improves exploration
economics. We have drilled several successful exploration wells in the
Brookhaven, Laurel, Martinville and Eola fields. In 1995, we completed a 24
square mile 3-D seismic survey on the Martinville field. Based on this data, two
successful exploratory wells were completed, one in 1996 and one in 1997. We
have identified additional opportunities in the Martinville field; however,
lower oil prices and budget constraints did not allow us to pursue these
opportunities in 1998 and 1999. We may pursue these drilling opportunities as
oil prices and cash flow allow. In 1996, we completed a 37 square mile 3-D
seismic survey encompassing the Laurel field, our largest crude oil producing
field, which currently has producing properties covering less than one square
52
<PAGE> 56
mile within the survey area. Based on initial interpretations, several
exploration wells are planned in the future, and a prospect which has similar
geological properties west of the Laurel field has been identified. We believe
each of these fields has significant exploration reserve potential relative to
our reserve base.
Along with the producing properties acquired in Oklahoma in 1997, we
acquired approximately 95 square miles of 3-D seismic data and 2,750 miles of
2-D seismic data. 2-D seismic data is a tool that allows us to look at vertical
cross-sections beneath the prospective area of our properties typically on a
much wider grid pattern. A large portion of the 3-D seismic data is over areas
of future reserve potential. The 3-D data will be useful in enhancing waterflood
development and exploration of the deeper objectives.
PRINCIPAL AREAS OF ACTIVITY
The following table sets forth, for our major producing areas, average net
daily production of crude oil and natural gas on a BOE basis for each of the
years in the three-year period ended December 31, 1999, and the number of
productive wells producing at December 31, 1999. The Oklahoma properties were
acquired effective December 31, 1997, with no production being recorded in 1997.
The Louisiana properties were sold December 2, 1998.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, AT DECEMBER 31, 1999
------------------------ -----------------------------------
1997 1998 1999 NET
------ ------ ------ PRODUCTIVE
WELLS AVERAGE
BOE/ BOE/ BOE/ ----------- PERCENTAGE WORKING
STATE DAY DAY DAY(A) OIL GAS OPERATED INTEREST
- ----- ------ ------ ------ ---- ---- ---------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
Mississippi......................... 8,178 8,202 4,621 116 1 95% 91%
Oklahoma............................ -- 6,345 5,414 572 51 50% 41%
Louisiana........................... 2,848 2,452 -- -- -- -- --
Other............................... 201 600 315 1 3 8% 14%
------ ------ ------ --- --
Total.......................... 11,227 17,599 10,350 689 55
====== ====== ====== === ==
</TABLE>
- ---------------
(a) In response to depressed crude oil prices during 1998 and early 1999, we
significantly reduced minor and major repairs and drilling activity on our
operated properties beginning in August 1998, ceased all repair work and
drilling activity in December 1998 and halted production on wells which
were uneconomical. We restarted repairs and maintenance on the properties
we operate and began doing limited recompletion and workover activity in
the second half of 1999.
Gulf Coast Area
Brookhaven Field, Mississippi. In 1995, we purchased a 93% working interest
in the unitized Brookhaven field covering more than 13,000 acres. Unitized means
that the royalty and working interests are pooled within a given geological
and/or geographical area. At the time of acquisition, there were 11 active wells
and 159 inactive wells. Proved reserves were 1.2 MMBOE and net production
averaged approximately 230 BOE per day, producing only from the Tuscaloosa
formation at 10,500 feet.
As with other fields, we acquired the Brookhaven field in anticipation of
additional field-wide recoveries through development drilling, recompletions,
secondary recovery and exploration. During our first year of ownership, we
focused our efforts on expanding our understanding of the Tuscaloosa reservoir.
Our mapping suggested less than 25% of the oil in place from the Tuscaloosa
reservoir had been recovered. As a result of our study, we identified and have
drilled six new Tuscaloosa well bores in the field to date. The six penetrations
found remaining crude oil reserves due to structural and stratigraphic
complexity. Four of these penetrations have been completed as commercial
producers and two wells will be used as injectors to aid our secondary recovery
operations. In 1998 and 1999, we continued our detailed study and mapping of the
stratigraphically complex Tuscaloosa reservoirs and initiated several waterflood
pilot areas.
In addition to our exploitation success, we have had significant
exploration success. In 1997 and early 1998, we had successful deep exploratory
results in the Washita Fredricksburg, Paluxy and Rodessa formations, with
initial production from these horizons in excess of 1,600 gross BOE per day. Due
to deep
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<PAGE> 57
structural complexity realized with the 1997 and early 1998 drilling, additional
drilling was halted until new seismic data was acquired. In 1998, 35 miles of
2-D seismic data was acquired and interpreted. This 2-D seismic data has
improved the structural definition of the deep drilling potential in these
formations which assists us in selecting drilling locations.
Production in Brookhaven in 1999 averaged 560 BOE per day and proved
reserves at December 31, 1999 were 6.4 MMBOE. Daily production was 50% below
1998 levels and reserves were 10% below 1998 levels as a result of the reduced
capital activity and natural reservoir decline.
Cranfield Field, Mississippi. As a result of the exploration success at
Brookhaven, we leased approximately 7,900 net acres on a similar geologic
structure near the Brookhaven field in the Cranfield field. In 1998, detailed
mapping using subsurface data from existing well bores and existing 2-D seismic
data was performed. Drilling prospects were generated at depths from 6,000 feet
to 11,000 feet in four different horizons:
- the Wilcox formations,
- the Eutaw formations,
- the Tuscaloosa formations, and
- the Washita Fredricksburg formations.
Two existing wellbores were reentered during the second half of 1998. The
Hosston and Mooringsport formations were tested unsuccessfully in one deep
existing wellbore; however, excellent reservoir quality rock was found in the
Mooringsport formation, which we believe remains a future exploitation
opportunity. A re-entry of an existing shallow wellbore proved successful in
both the Washita Fredricksburg and Wilcox formations. The Washita Fredricksburg
formation tested at a rate of 700 Mcf per day and turned to sales in early 1999.
Production in Cranfield in 1999 averaged 378 Mcf per day and proved reserves at
December 31, 1999 were 0.6 MMBOE.
Laurel Field, Mississippi. The Laurel field is a multi-pay geological
setting with producing horizons from the Eutaw formation at approximately 7,500
feet, to the Hosston formation at approximately 13,500 feet. It is our largest
oil producing property and represented approximately 50% of our total
Mississippi production on a BOE basis in 1999. At December 31, 1999, the field
contained 47 wells producing from the Stanley, Christmas, Tuscaloosa, Washita
Fredricksburg, Paluxy, Mooringsport, Rodessa, Sligo and Hosston reservoirs.
We consider the Laurel field both an exploration and exploitation success.
In 1983, at the time of the initial acquisition, the only then-existing well in
what is now the Laurel field had been operating for 24 years and was producing
only 47 BOPD. We employed 3-D seismic technology to assist in defining the
multi-pay zones in the field and began an extensive drilling program to increase
primary production, using a combination of vertical, high-angle and horizontal
drilling techniques.
We have also implemented successful secondary recovery programs in a number
of Laurel's producing reservoirs. In recent years, secondary recovery programs
were started in the Mooringsport, Rodessa, Sligo and Tuscaloosa Stringer
reservoirs. The production response from the secondary recovery projects has
been strong.
In addition to the continued exploitation program, we have continued an
active exploration program at Laurel. In 1996 and 1997, much of our focus at
Laurel was directed toward a mineral leasing program and the permitting and
surveying associated with shooting a 37 square mile 3-D seismic program. In 1998
and 1999, we evaluated the 3-D seismic data to better understand the exploration
potential within the Laurel field as it is currently defined, as well as to
define exploration possibilities in the acreage surrounding the field.
The average net daily production in 1999 from Laurel was 2,300 BOE, down
35% from 1998 levels due to our scaled back operating and capital program. These
programs were scaled back because of the
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<PAGE> 58
substantial decline in commodity prices in 1998 and early 1999 and the resulting
budget constraints. At December 31, 1999, proved reserves were 12.5 MMBOE, up
approximately 33% over year end 1998. The reserve increase is attributable
primarily to improved crude oil prices experienced at year end 1999 relative to
year end 1998.
Martinville Field, Mississippi. We acquired the Martinville field in April
1989; it was originally discovered in 1957. At the time of acquisition,
Martinville was producing only 80 net BOE per day; the average production for
1999 was 776 net BOE per day. The field covers more than 7,400 acres and
currently has 17 producing wells. Like Laurel, the field is characterized by
highly complex faulting and produces from multiple horizons. We currently have
an average working interest of 98% in the field.
In late 1995, we conducted a 3-D seismic shoot over a 24 square mile area
to enhance our ability to exploit primary reserves through continued reservoir
delineation and to develop secondary recovery projects in the Mooringsport,
Rodessa and Sligo formations.
Since 1996, we have successfully drilled wells to the Hosston, Sligo,
Rodessa, Mooringsport and Washita Fredricksburg formations, including two
successful development wells drilled and completed in 1998 in the Sligo and
Washita Fredricksburg reservoirs.
Because declining oil prices in 1998 and early 1999 made property
development less economical, we spent much of the year refining our
interpretation of the 3-D seismic data of Martinville. We currently have defined
six exploration prospects along with numerous development drilling
opportunities. Proved reserves at year end 1999 totaled 5.4 MMBOE, a 13% decline
from year end 1998. This decline is due to the lack of development of the
Martinville properties in 1999 due to low oil prices during the first half of
1999, reduced capital activity and the natural reservoir decline.
Soso Field, Mississippi. In mid-1990, we acquired a 90% working interest in
the Soso field, which was originally discovered in 1945 and covers approximately
6,500 acres. At the time we acquired it, the field produced 225 BOPD. For 1999,
the average daily production was 354 BOE, a decrease of 56% from 1998 average
daily production. Reserves at December 31, 1999 totaled 5.6 MMBOE, a 12%
increase over year end 1998. The decline in average daily production is due to
reduced development activity on the properties as a result of capital budget
constraints, while the increase in reserves is due to improved crude oil prices
experienced at year end 1999 relative to year end 1998.
Soso is a large, geologically complex field which had already produced over
75 MMBOE at the time we acquired it in 1990. Also, like Brookhaven, our detailed
mapping of the field suggested that less than 25% of the total crude oil had
been recovered. We acquired Soso primarily to increase total recoverable
reserves by another 5% to 15% through recompletions in existing wellbores,
development drilling and secondary recovery projects.
Most of our early production growth at Soso was associated with workovers
and recompletions on existing wells, with some development drilling taking
place. Because of the success of secondary recovery projects at Laurel and
Martinville, we took a fresh look at the field in 1997, and since then,
secondary recovery projects have been initiated in the Cotton Valley, Sligo and
Rodessa formations.
In 1998, we acquired 35 miles of new 2-D seismic data across the Soso
field. This 2-D seismic data should enhance our development of the Hosston and
Cotton Valley formations. We believe many more exploitation opportunities exist
for primary as well as secondary reserves in the multi-reservoir field.
Summerland Field, Mississippi. The Summerland field, discovered in 1959, is
a broad, elongated, fault bounded anticline with productive intervals from the
Tuscaloosa formation at approximately 6,000 feet to the Mooringsport formation
at 12,500 feet. At December 31, 1999, we operated 18 producing wells and had an
average working interest of 90% in this unitized field.
We assumed operating control of the Summerland field in November 1989. At
the date of acquisition, net crude oil production was 415 BOE per day, of which
only 200 BOE per day were economic. Recompletions, development drilling and the
installation of higher volume artificial lift equipment increased net crude oil
production to 1,019 BOE per day in 1998. For 1999, however, daily production
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<PAGE> 59
averaged 494 BOE, down from 1998 as a result of the natural decline of the
reservoirs, low oil prices during the first half of 1999 and reduced capital
activity.
At December 31, 1999, the Summerland field had proved reserves of 5.6
MMBOE, up approximately 6% over year end 1998 due to improved crude oil prices.
Mid-Continent Area
In December 1997, we acquired interests in approximately 40,000 gross acres
concentrated primarily in southern Oklahoma, including 14 principal producing
fields. Of the 14 principal producing fields, we are the operator of eleven
fields. At December 31, 1999, we had an average working interest in the eleven
fields we operate of approximately 74%.
These properties are very similar to our Mississippi salt basin operations
and we believe that our substantial knowledge base should benefit in the
development of these properties. In 1998, we began an exploration and
exploitation program which resulted in the drilling of 19 gross wells, 18 of
which were completed successfully. Additionally, we began interpreting 3-D
seismic information on two fields in 1998 and have identified several drilling
opportunities as a direct result of this seismic information. In 1999, activity
on these properties was very limited due to capital budget constraints.
Bumpass Unit, Oklahoma. The Bumpass Unit, located in Carter County,
Oklahoma, was discovered in 1924. Production is primarily from both structural
and stratigraphic traps within the Deese and Springer reservoirs. The Deese
reservoirs are typically encountered at depths between 3,500 and 4,500 feet with
the Springer reservoirs located from 4,500 to 6,700 feet.
Currently, our primary focus at Bumpass is to exploit the Flattop and
Goodwin sands located in the Springer formation, which we believe to be
underdeveloped. In 1998 and 1999, we drilled one well, deepened one well and
recompleted two wells in these lower Springer sands. All four of these jobs were
successful and resulted in a combined initial production rate in excess of 3,000
net Mcf per day. We intend to continue this exploitation program in 2000.
Additionally, we are studying the Humphrey sands, which are in the upper portion
of the Springer formation, to determine their waterflood potential. At December
31, 1999, we had an average working interest of approximately 65% in the Bumpass
field.
Average net daily production in 1999 was 451 BOE compared with 623 BOE per
day in 1998. Proved reserves at December 31, 1999 totaled 4.5 MMBOE, a decrease
of 10% from the 5.0 MMBOE at the end of 1998. The decrease in both production
and reserves is due to the reduced development activity on the property as a
result of capital budget constraints experienced during 1999.
Sholem Alechem Fault Block "A" Unit, Oklahoma. Located in Stephens County,
Oklahoma, the Sholem Alechem Fault Block "A" Unit was discovered in 1947. As
with the Bumpass Unit, production at Sholem Alechem originates primarily from
the Deese and Springer reservoirs.
In 1998 and 1999, we deepened eight wells and recompleted one well into the
Flattop and Goodwin sands located in the Springer formation. Six of these nine
jobs were successful and resulted in a combined initial production rate of 240
net BOE per day and 1,630 net Mcf per day. Exploitation of the Springer
formation will continue into 2000. At December 31, 1999, we had an average
working interest in Sholem Alechem of approximately 89%.
Net production in 1999 averaged 705 BOE per day, down from the 843 BOE per
day in 1998 as a result of our limited development activity during the year.
Proved reserves at December 31, 1999 totaled 7.0 MMBOE, basically unchanged from
year end 1998.
East Fitts Unit, Oklahoma. The East Fitts Unit was discovered in 1933, with
production originating from the Cromwell, Hunton and Viola reservoirs, at depths
ranging from 2,400 to 5,000 feet.
Our current emphasis at East Fitts is to take the Viola reservoir from ten
acre spacing to five acre spacing. We believe that this development will not
only increase existing production but prove up additional reserves. In 1998, we
drilled five wells to the Viola reservoir, all of which were successful,
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<PAGE> 60
increasing production by 200 BOE per day and adding approximately 600 MBOE in
reserves. No significant activity occurred in the East Fitts Unit in 1999 due to
capital budget constraints. However, additional wells to the Viola reservoir are
planned in 2000, and we are planning to initiate pilot waterflood projects in
the Chimney Hill formation, a lower member of the Hunton reservoir, and the
Bromide formation. At December 31, 1999, our average working interest in East
Fitts was approximately 83%.
Average net daily production in 1999 was 997 BOE and proved reserves at
December 31, 1999 totaled 23.7 MMBOE. This is down marginally from the average
1998 production of 1,174 BOE per day and 1998 proved reserves of 24.6 MMBOE.
Other Oklahoma. We operate eight other fields in Oklahoma:
- East Velma Middle Block,
- North Alma Deese,
- Tatums,
- Jennings Deese,
- Graham Deese,
- Eola S.E.,
- Eola N.W., and
- Cox Penn.
Total average net daily production in 1999 from these fields was 2,169 BOE. East
Velma Middle Block has significant upside potential through secondary recovery.
Similar reservoirs have been successfully waterflooded along the Velma complex.
East Velma Middle Block is the remaining block along this complex which has not
been enhanced through secondary recovery. Tatums is a shallow Deese producing
unit which has been evaluated to have significant upside potential through down
spacing. Currently the unit is developed on a ten acre spacing with some areas
of the field underexploited. A five acre drilling program and adjustments to
current waterflood injection could provide substantial upside potential. At year
end, net proved reserves from these properties totaled 33.6 MMBOE, essentially
unchanged from year end 1998.
We also have non-operating working interests in three fields in Oklahoma.
At December 31, 1999, year-end proved reserves in these three fields were
estimated at 3.0 MMBOE.
Since the acquisition of the Oklahoma properties, we have identified 11 new
secondary recovery projects to be developed. These projects are currently in the
study or planning phases. Facilities and wellbores are being evaluated to begin
pilot waterfloods. In addition, these projects should incur low capital and
production costs due to existing field infrastructures. We believe opportunities
exist for adding secondary recovery projects throughout our current field
inventory. Additionally, we believe that substantial Springer through Simpson
gas potential exists in and around our currently operated properties. This
potential will be a focal point of low-risk exploration through the deepening of
existing wellbores or through recompletions, both of which require less capital
as compared to drilling for these objectives. Historically in these areas, gas
has not been the primary focus of exploitation; however, improved technology has
now allowed commercial development of these deeper, tighter objectives.
Other Domestic Properties
We also have working interests in other producing properties in Mississippi
and Texas. We operate the Bentonia and Frio properties in Mississippi and own
non-operated working interests in the Glazier property in Mississippi, the
Clarksville field in Texas and a field in state waters offshore North Padre
Island, Texas. As of December 31, 1999, these fields had combined net proved
reserves of 4.9 MMBOE.
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<PAGE> 61
Tunisia, North Africa
We have a 45.8% interest in a permit covering 1.1 million gross acres in
Tunisia, North Africa that we acquired from our former Canadian parent company.
During 1994, we and our joint interest partners conducted a seismic survey on
the Anaguid permit in Tunisia. In October 1995, we and our partners drilled an
unsuccessful exploratory well on the Anaguid permit in southern Tunisia. In
early 1997, we and our partners conducted a 465 kilometer 2-D seismic program in
a new area of the Anaguid permit. In June 1999, we commenced drilling an
exploratory well on this permit. In September 1999, we tested the well and
determined that the well would not produce sufficient quantities of crude oil to
justify further completion work on the well. As a result, we wrote down our
Tunisian properties by $5.4 million during the third quarter of 1999. Anadarko
Tunisia Anaguid Company, one of the working interest partners in this permit,
has assumed responsibility as operator and plans to continue exploration of this
permit.
In June 1999, we extended our Anaguid permit in Tunisia through June 2001.
We have a commitment to drill two additional wells during that two-year period.
PRODUCTION
The following table contains information regarding our production volumes,
average prices received and average production costs associated with our sales
of crude oil and natural gas for each of the years in the three-year period
ended December 31, 1999:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------
1997 1998 1999
------ ------ ------
<S> <C> <C> <C>
CRUDE OIL:
Volumes (MBbls).......................................... 2,820 5,069 3,343
Average sales price (per Bbl)(a)......................... $16.31 $10.40 $15.40
NATURAL GAS:
Volumes (MMcf)........................................... 7,666 8,124 2,608
Average sales price (per Mcf)(b)......................... $ 2.23 $ 1.98 $ 2.24
AVERAGE PRODUCTION COST (PER BOE)(c)....................... $ 3.90 $ 4.18 $ 5.60
</TABLE>
- ---------------
(a) Includes the effects of crude oil price hedging contracts. Price per Bbl
before the effect of hedging was $16.42 for the year ended December 31,
1997, $10.40 for the year ended December 31, 1998 and $15.40 for the year
ended December 31, 1999.
(b) Includes the effects of natural gas price hedging contracts. Price per Mcf
before the effect of hedging was $2.22 for the year ended December 31,
1997, $1.92 for the year ended December 31, 1998 and $2.24 for the year
ended December 31, 1999.
(c) Includes lease operating expenses and production taxes.
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DRILLING ACTIVITIES
During the periods indicated, we drilled or participated in the drilling of
the following wells:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1997 1998 1999
------------ ------------ -----------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ---
<S> <C> <C> <C> <C> <C> <C>
EXPLORATORY:
Crude oil................................... 3 2.8 1 1.0 -- --
Natural gas................................. 1 .8 -- -- -- --
Dry holes(1)................................ 1 1.0 2 2.0 1 0.5
DEVELOPMENT:(2)
Crude oil................................... 10 9.3 26 21.7 -- --
Natural gas................................. 11 9.8 8 6.5 3 3.0
Dry holes................................... 2 2.0 5 4.9 2 1.5
Service wells............................... -- -- 2 1.0 -- --
-- ---- -- ---- --- ---
Total............................... 28 25.7 44 37.1 6 5.0
== ==== == ==== === ===
</TABLE>
- ---------------
(1) 1999 well was drilled in Tunisia, North Africa.
(2) Included in drilling activities are wells deepened to a lower reservoir
through existing well bores. In 1999, all wells under "Development" were
deepenings within existing well bores.
At December 31, 1999, we were not participating in the drilling or
completion stages of a well.
RESERVES
The following table summarizes our net proved crude oil and natural gas
reserves as of December 31, 1999, which have been reviewed by Ryder Scott
Company with regard to our Mississippi properties and Sproule Associates, Inc.
with regard to our Oklahoma properties. The other properties in the table are
related to our crude oil and natural gas reserves located in Texas which have
been audited, depending on location, by the independent engineers named in the
preceding sentence.
<TABLE>
<CAPTION>
CRUDE NATURAL NET PROVED
OIL GAS RESERVES
(MBBLS) (MMCF) (MBOE)
------- ------- ----------
<S> <C> <C> <C>
Mississippi............................................ 36,736 2,978 37,232
Oklahoma............................................... 68,533 25,863 72,844
Other.................................................. 1,844 11,797 3,810
------- ------ -------
Total........................................ 107,113 40,638 113,886
======= ====== =======
</TABLE>
At December 31, 1999, we had net proved developed reserves of 78,047 MBOE
and net proved undeveloped reserves of 35,839 MBOE. The present value of proved
reserves was $790.2 million, which represented $543.7 million for the proved
developed reserves and $246.5 million for the proved undeveloped reserves. At
December 31, 1998, we reported total proved reserves of 111,059 MBOE, and the
present value of proved reserves was $269.3 million.
There are numerous uncertainties inherent in estimating quantities of
proved crude oil and natural gas reserves, including many factors beyond our
control. The estimates of the reserve engineers are based on several
assumptions, including the following:
- actual future production,
- revenues,
- taxes,
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- production costs,
- development expenditures and
- quantities of recoverable crude oil and natural gas reserves.
Any significant variance in these assumptions could materially affect the
estimated quantity and value of reserves set forth herein. In addition, our
reserves might be subject to revision based upon:
- actual production,
- results of future development,
- prevailing crude oil and natural gas prices and
- other factors.
In general, the volumes of production from crude oil and natural gas
properties decline as reserves are depleted. Except to the extent we acquire
additional properties containing proved reserves or conduct successful
exploration and development activities, or both, our proved reserves will
decline as reserves are produced. Future crude oil and natural gas production is
therefore highly dependent upon the level of success in acquiring or finding
additional reserves.
For further information on reserves, costs relating to crude oil and
natural gas activities and results in operations from producing activities, see
"Supplementary Information Related to Oil and Gas Activities" appearing in note
14 to our consolidated financial statements included in this prospectus.
ACREAGE
The following table summarizes the developed and undeveloped acreage we
owned or leased at December 31, 1999:
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
--------------- ---------------
GROSS NET GROSS NET
------ ------ ------ ------
<S> <C> <C> <C> <C>
Mississippi........................................ 24,126 22,881 26,901 22,640
Oklahoma........................................... 38,463 28,301 40 40
Texas.............................................. 4,276 3,428 1,691 1,691
Offshore Gulf of Mexico............................ 5,760 2,269 -- --
------ ------ ------ ------
Total.................................... 72,625 56,879 28,632 24,371
====== ====== ====== ======
</TABLE>
At December 31, 1999, we also held a 45.8% working interest in an
exploratory permit in Tunisia, North Africa, covering approximately 1,130,000
gross acres.
TITLE TO PROPERTIES
As is customary in the oil and gas industry, in many circumstances, we make
only a limited review of title to undeveloped crude oil and natural gas leases
at the time we acquire them. However, before we acquire developed crude oil and
natural gas properties, and before drilling commences on any leases, we cause a
thorough title search to be conducted, and any material defects in title are
remedied to the extent possible. To the extent title opinions or other
investigations reflect title defects, we, rather than the seller of the
undeveloped property, are typically obligated to cure any title defects at our
expense. We could lose our entire investment in any property we drill, if we
have a title defect of a nature that makes it prudent to commence drilling upon
but which we could not remedy or cure. We believe that we have good title to our
crude oil and natural gas properties, some of which are subject to immaterial
encumbrances, easements and restrictions. The crude oil and natural gas
properties we own are also typically subject to
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royalty and other similar non-cost bearing interests customary in the industry.
We do not believe that any of these encumbrances or burdens will materially
affect our ownership or use of our properties.
COMPETITION
The crude oil and natural gas industry is highly competitive. We encounter
strong competition from major oil companies and independent operators in
acquiring properties and leases for the exploration for, and production of,
crude oil and natural gas. Competition is particularly intense with respect to
the acquisition of desirable undeveloped crude oil and natural gas properties.
The principal competitive factors in the acquisition of desirable undeveloped
crude oil and natural gas properties include the staff and data necessary to
identify, investigate and purchase these properties, and the financial resources
necessary to acquire and develop these properties. Many of our competitors have
financial resources, staff and facilities substantially greater than ours. In
addition, the producing, processing and marketing of crude oil and natural gas
is affected by a number of factors which are beyond our control, the effect of
which cannot be accurately predicted.
The principal resources necessary for the exploration and production of
crude oil and natural gas are:
- leasehold prospects under which crude oil and natural gas reserves may be
discovered,
- drilling rigs and related equipment to explore for these reserves, and
- knowledgeable personnel to conduct all phases of crude oil and natural
gas operations.
We compete for these resources with both major crude oil and natural gas
companies and independent operators. Although we believe our current operating
and financial resources will be adequate to preclude any significant disruption
of our operations in the immediate future if our plan of reorganization is
consummated, the continued availability of these materials and resources to us
cannot be assured.
CUSTOMERS AND MARKETS
Substantially all of our crude oil is sold at the wellhead at posted
prices, as is customary in the industry. In some circumstances, natural gas
liquids are removed from our natural gas production and are sold by us at posted
prices. During 1999, EOTT Energy Operating Limited Partnership accounted for 39%
of our revenues and Amoco Production Company accounted for 41% of our revenues.
While we believe our relationships with EOTT and Amoco are good, any loss of
revenue from these customers due to nonpayment would have an adverse effect on
our net income and earnings per share on our income statement and, ultimately,
may affect our share price. In addition, any significant late payment may
adversely affect our short term liquidity position.
We have a three-year crude oil purchase agreement with EOTT which was
effective March 1, 1996. Under the crude oil purchase agreement, we committed
the majority of our crude oil production in Mississippi to EOTT for a period of
three years on a pricing basis of posting plus a premium. This contract is
currently on a month-to-month basis. As part of this contract, we have agreed to
sell to EOTT approximately 50% of our heavy Mississippi crude oil with a minimum
well head price of $8.50 per barrel.
The majority of crude oil production in Oklahoma is sold to Amoco on a
NYMEX pricing basis minus a discount. Beginning January 1, 1999 and for a
nine-year period thereafter, Amoco has a right of first refusal to match, in all
respects, a competitive bid. The crude contract was a component of the original
Amoco purchase and sale agreement and provides for a competitive annual review
of the pricing mechanism.
The price we receive for crude oil and natural gas may vary significantly
during the year due to the volatility of the crude oil and natural gas market,
particularly during the cold winter and hot summer months. As a result, we
periodically enter into forward sale agreements or other arrangements for a
portion of our crude oil and natural gas production to hedge our exposure to
price fluctuations. Gains and losses on these forward sale agreements are
reflected in crude oil and natural gas revenues at the time of sale of
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<PAGE> 65
the related hedged production. While intended to reduce the effects of the
volatility of the prices received for crude oil and natural gas, these hedging
transactions may limit our potential gains if crude oil and natural gas prices
were to rise substantially over the price established by the hedge. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- General" and Note 1 to our consolidated financial statements for
more information related to hedging.
OFFICE AND FIELD FACILITIES
We currently lease 47,942 square feet for our executive and administrative
offices in Dallas, Texas, under a lease that continues through October 2000. We
are considering a renewal of some portion of this lease as well as other
available square footage. We also lease field offices in Laurel, Mississippi,
covering approximately 5,000 square feet under a non-cancelable lease extending
through June 2000. We are currently evaluating the renewal of the Laurel lease
as well as other alternatives. We also lease office space in Ratliff City,
Oklahoma, covering approximately 10,000 square feet through January 2003.
GOVERNMENTAL REGULATION
Regulation of Crude Oil and Natural Gas Exploration and Production. Crude
oil and natural gas exploration, development and production are subject to
various types of regulation by local, state and federal agencies. These
regulations include:
- requiring permits for the drilling of wells,
- maintaining bonding requirements in order to drill or operate wells,
- regulating the location of wells,
- regulating the method of drilling and casing wells,
- regulating the surface use and restoration of properties upon which wells
are drilled, and
- regulating the plugging and abandonment of wells.
Our operations are also subject to various conservation laws and regulations in
which our properties are located, including those of Mississippi, Oklahoma and
Texas. These laws and regulations include the regulation of :
- the size of drilling and spacing units or proration units,
- regulation of the density of wells that may be drilled,
- regulation of unitization or pooling of crude oil and natural gas
properties,
- maximum rates of production from crude oil and natural gas wells,
- restrictions on the venting or flaring of natural gas, and
- requirements regarding the ratability of production.
Some states allow the forced pooling or integration of tracts to facilitate
exploration while other states rely on voluntary pooling of land and leases. The
effect of these regulations is to limit the amount of crude oil and natural gas
we can produce from our wells and to limit the number of wells or the locations
at which we can drill.
Each state generally imposes a production or severance tax with respect to
production and sale of crude oil, natural gas and natural gas liquids within
their respective jurisdictions. For the most part, state production taxes are
applied as a percentage of production or sales. Currently, we are subject to
production tax rates of up to 6% in Mississippi and 7% in Oklahoma. In addition,
we have been active in the adoption of legislation dealing with production and
severance tax relief in Mississippi, specifically where severance tax is either
waived for a fixed period of time, as in renewed production from inactive wells,
or reduced to
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50% of regular rates for enhanced recovery projects. The state of Oklahoma has
adopted severance tax relief, adjusting tax rates to:
- 1% for posted crude oil priced less than $14.00 per barrel,
- 4% for posted crude oil priced between $14.00 and $17.00 per barrel, and
- the regular tax rate of 7% for prices over $17.00 per barrel.
Legislation affecting the crude oil and natural gas industry is under
constant review for amendment and expansion. Also, numerous departments and
agencies, both federal and state, are authorized by statute to issue and have
issued rules and regulations binding on the crude oil and natural gas industry
and its individual members. Some of these rules and regulations carry
substantial penalties for failure to comply. The regulatory burden on the crude
oil and natural gas industry increases our cost of doing business and,
consequently, affects our profitability.
Offshore Leasing. Some of our operations are located on federal crude oil
and natural gas leases, which are administered by the United States Minerals
Management Service. These leases are issued through competitive bidding, contain
relatively standardized terms and require compliance with detailed regulations
and orders, which are subject to change by the Minerals Service. For offshore
operations, lessees must obtain approval from the Minerals Service for
exploration plans and development and production plans before the commencement
of operations. In addition to permits required from other agencies, such as the
Coast Guard, the Army Corps of Engineers and the Environmental Protection
Agency, lessees must obtain a permit from the Minerals Service before the
commencement of drilling. The Minerals Service has promulgated regulations
requiring offshore production facilities located on the outer continental shelf
to meet stringent engineering and construction specifications. Similarly, the
Minerals Service has promulgated other regulations governing the plugging and
abandonment of wells located offshore and the removal of all production
facilities. Under some circumstances, the Minerals Service may require any
operations on federal leases to be suspended or terminated. To cover the various
obligations of lessees on the outer continental shelf, the Minerals Service
generally requires that lessees or operators post substantial bonds or other
acceptable assurances that these obligations will be met. The cost of these
bonds or other surety can be substantial and there is no assurance that we can
obtain bonds or other surety in all cases.
Gas Royalty Valuation Regulations. In December 1997, the Minerals Service
published a final rule amending its regulations governing valuation for royalty
purposes of gas produced from federal and Indian leases. The rule primarily
addresses allowances for transportation of gas and purports to clarify the
methods by which gas royalties and deductions for gas transportation are
calculated. The final rule became effective February 1, 1998. The rule purports
to continue the commitment of the Minerals Service to assure that lessees deduct
only the actual, reasonable costs of transportation and not any marketing costs.
The rule identifies specific allowable and nonallowable costs of transportation.
The rule is, however, under judicial review. In August 1999, the Minerals
Service published a final rule amending its regulations governing the valuation
for royalty purposes of natural gas produced from Indian leases. The changes add
alternative valuation methods to the existing regulations, to ensure that Indian
lessors receive maximum revenues from their mineral resources. The final rule
became effective January 1, 2000.
Crude Oil Sales and Transportation Rates. Sales of crude oil and condensate
can be made by us at market prices not subject at this time to price controls.
In January 1997, the Minerals Service published a proposed rule to amend the
current federal crude oil royalty valuation regulations. In July 1997, the
Minerals Service published a supplementary proposed rule concerning the proposed
regulations. In February 1998, the Minerals Service published another
supplementary proposed rule. The intent of the rule is to decrease reliance on
posted prices and to assign a value to crude oil that better reflects market
value. In general, the rule as proposed would base royalties on gross proceeds
when the oil is sold under an arm's length contract by either the producer or
the producer's marketing affiliate. Index pricing or other benchmarks would be
used when oil is not sold under an arm's length contract. On July 16, 1998, the
Minerals Service proposed additional changes to its second supplementary
proposed rule. On March 12,
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1999, the Minerals Service published a notice reopening the public comment
period on the second supplementary proposed rule until April 12, 1999. On April
13, 1999, the Minerals Service published a notice extending the comment period
until April 27, 1999. On December 30, 1999, the Minerals Service published
additional changes, inviting public comment by January 31, 2000. In February
1998, the Minerals Service also published a notice of a proposed rule to amend
the current regulations establishing a value for royalty purposes of oil
produced from Indian leases. The proposed changes would decrease reliance on oil
posted prices and use more publicly available information for oil royalty
calculation purposes under Indian leases. On January 5, 2000, the Minerals
Service published additional proposed changes to the regulations regarding
Indian leases, inviting public comment by March 6, 2000. We cannot predict what
action the Minerals Service will take on these matters, nor can we predict at
this stage of the rulemaking proceedings how we might be affected by amendments
to these regulations.
The price that we receive from the sale of these products is affected by
the cost of transporting the products to market. The Energy Policy Act of 1992
directed the Federal Energy Regulatory Commission to establish a simplified and
generally applicable rate-making methodology for crude oil pipeline rates.
Effective as of January 1, 1995, the Federal Energy Regulatory Commission
implemented regulations establishing an indexing system for transportation rates
for crude oil pipelines, which would generally index these rates to inflation.
We are not able to predict with certainty what effect, if any, these regulations
will have on us, but other factors being equal, the regulations may tend to
increase transportation costs or reduce wellhead prices for these commodities.
Future Legislation and Regulation. Our operations will be affected from
time to time in varying degrees by political developments and federal and state
laws and regulations. In particular, crude oil and natural gas production
operations and economics are affected by:
- tax and other laws relating to the petroleum industry,
- changes in these laws, and
- constantly changing administrative regulations.
For example, the price at which natural gas may lawfully be sold has
historically been regulated under the Natural Gas Act. Only since the
deregulation of the last remaining regulated price categories of natural gas on
January 1, 1993, have free market forces been allowed to control the sales price
of natural gas. There is no guarantee that new regulations, similar or
otherwise, will not be imposed on the production or sale of crude oil,
condensate or natural gas. It is impossible to predict the terms of any future
legislation or regulations that might ultimately be enacted or the effects of
any legislation or regulations on us.
ENVIRONMENTAL REGULATIONS
Numerous laws and regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection affect our
operations. These laws and regulations may:
- require us to obtain permits before drilling,
- restrict the types, quantities and concentration of various substances
that can be released into the environment through drilling and production
activities,
- limit or prohibit drilling activities on some lands lying within
wilderness, wildlife refuges or preserves, wetlands and other protected
areas, and
- impose substantial liabilities for pollution resulting from our
operations.
Changes in environmental laws and regulations occur frequently, and any changes
that result in more stringent and costly waste handling, disposal and clean-up
requirements may significantly impact our operating costs, as well as the oil
and gas industry in general. We believe that we substantially comply with
current applicable environmental laws and regulations and that continued
compliance with existing requirements will not result in material adverse
impacts to us.
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The Oil Pollution Act of 1990 attempts to prevent crude oil spills by
imposing on "responsible parties" liability for damages resulting from crude oil
spills into or upon navigable waters, adjoining shorelines or in the exclusive
economic zone of the United States. A "responsible party" includes the owner or
operator of an onshore facility or a vessel, and the lessee or permittee of the
area in which an offshore facility is located. The Oil Pollution Act requires
the lessee or permittee to establish and maintain evidence of financial
responsibility in the amount of $35.0 million, $10.0 million if the offshore
facility is located landward of the seaward boundary of a state, to cover
liabilities that result from a crude oil spill for which that person is
statutorily responsible. The minimum amount of financial responsibility may be
increased to $150.0 million depending on the risks posed by the quantity or
quality of crude oil handled by the facility. The Minerals Service has
promulgated regulations that implement the financial responsibility requirements
of the Oil Pollution Act. The regulations use an offshore facility's worst case
oil-spill discharge volume to determine if the responsible party must maintain
increased financial responsibility. We are not presently subject to the
financial responsibility requirement because our only offshore well is a natural
gas well that does not produce oil.
The Oil Pollution Act subjects responsible parties to strict, joint and
several and potentially unlimited liability for removal costs and other damages
caused by an oil spill covered by the statute. It also imposes other
requirements on responsible parties, including the preparation of a crude oil
spill contingency plan. We maintain a crude oil spill contingency plan. A
responsible party may face civil or criminal enforcement actions if it fails to
comply with the Oil Pollution Act's ongoing requirements or inadequately
cooperates during a spill event. We are not the subject of any civil or criminal
enforcement actions under the Oil Pollution Act and we are not aware of any
basis for a civil or criminal enforcement action against us.
The Federal Water Pollution Control Act of 1972 imposes restrictions and
strict controls regarding the discharge of produced waters and other oil and gas
wastes into navigable waters. These controls have become more stringent over the
years, and it is probable that additional restrictions will be imposed in the
future. We must obtain permits to discharge pollutants into state and federal
waters. State discharge regulations and general permits under the Federal
National Pollutant Discharge Elimination System prohibit the discharge of
produced water and sand, drilling fluids, drill cuttings and other substances
related to the oil and gas industry into coastal waters. The Federal Water
Pollution Control Act allows civil, criminal and administrative penalties for
any unauthorized discharges of oil and any other hazardous substances in
reportable quantities. The Federal Water Pollution Control Act and the Oil
Pollution Act also impose potential liability for the costs of removal,
remediation and damages. State laws for the control of water pollution also
provide civil, criminal and administrative penalties and impose liabilities in
the case of a discharge of petroleum or its derivatives, or other hazardous
substances, into state waters.
The Comprehensive Environmental Response, Compensation, and Liability Act,
also known as the "Superfund" law, imposes liability, without regard to fault or
the legality of the original conduct, on classes of persons considered to have
contributed to the release of a hazardous substance into the environment. These
persons include the owner or operator of the disposal site or sites where the
release occurred and the companies that disposed or arranged for the disposal of
the hazardous substances found at the site. Persons who are responsible for
releases of hazardous substances under Superfund may be subject to joint and
several liability for the costs of cleaning up the hazardous substances and for
damages to natural resources. In addition, it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances released into the
environment. We do not own or operate any Superfund-identified sites and have
not received notice that we are liable for response or remediation costs at any
Superfund site.
The Resource Conservation and Recovery Act is the principal federal statute
governing the treatment, storage and disposal of hazardous wastes. The Resource
Conservation and Recovery Act imposes stringent operating requirements, and
liability for failure to meet these requirements, on a person who is either a
generator or transporter of hazardous waste or an owner or operator of a
hazardous waste treatment, storage or disposal facility. At present, the
Resource Conservation and Recovery Act includes a statutory exemption that
allows most crude oil and natural gas exploration and production wastes to be
classified as non-hazardous waste. A similar exemption is contained in many of
the state counterparts to the Resource
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Conservation and Recovery Act. Proposals have been made to amend the Resource
Conservation and Recovery Act and the various state statutes to rescind the
exemption that excludes crude oil and natural gas exploration and production
wastes from regulation as hazardous waste. Repeal or modification of this
exemption by administrative, legislative or judicial process, or through changes
in applicable state statutes, could increase the volume of hazardous waste that
we must manage and dispose of. Hazardous wastes are subject to more rigorous and
costly disposal requirements than are non-hazardous wastes. Any change in the
applicable statutes may require us to make additional capital expenditures or
incur increased operating expenses.
A significant portion of our operations in Mississippi is conducted within
city limits. Each year we are required to meet tests of financial responsibility
to obtain permits to conduct new drilling operations. We are conducting a
voluntary program to remove inactive aboveground storage tanks from our well
sites and to replace them, as necessary, with newer aboveground storage tanks.
Some states have enacted statutes governing the handling, treatment,
storage and disposal of waste containing naturally occurring radioactive
material. Naturally occurring radioactive material is present in varying
concentrations in subsurface and hydrocarbon reservoirs around the world and may
be concentrated in scale, film and sludge in equipment that comes in contact
with crude oil and natural gas production and processing streams. Mississippi
legislation prohibits the transfer of property for residential or other
unrestricted use if the property evidences concentrations of naturally occurring
radioactive material above prescribed levels because of crude oil and natural
gas production activities. We are voluntarily remediating naturally occurring
radioactive material concentrations identified at several fields in Mississippi.
In addition, we are a defendant in several lawsuits brought by landowners
alleging personal injury and property damage from naturally occurring
radioactive material at various wellsite locations. See the subsection below
called "Legal Matters" for more information concerning these lawsuits.
Because our strategy is to acquire interests in underdeveloped crude oil
and natural gas properties, many of which have been operated by others for many
years, we may incur liability for damages or pollution caused by the former
operators of these crude oil and natural gas properties. We provide for future
site restoration charges on a unit-of-production basis by including these
charges in depletion and depreciation expense. In addition, we may continue to
be responsible for environmental contamination on properties we transferred to
others. Our operations are also subject to all the risks related to the
operation and development of crude oil and natural gas properties and the
drilling of crude oil and natural gas wells. These risks include encountering
unexpected formations or pressures, blowouts, cratering and fires, any of which
could result in personal injuries, loss of life, pollution damage and other
damage to our properties and that of others. Moreover, offshore operations are
subject to a variety of operating risks peculiar to the marine environment, such
as hurricanes or other adverse weather conditions. Offshore operations also
involve extensive governmental regulations, including regulations that may
impose strict liability for pollution damage, and interruptions or terminations
of operations by governmental authorities based on environmental or other
considerations. We maintain insurance against losses or liabilities arising from
our operations in accordance with customary industry practices and in amounts
that we believe reasonable. However, insurance is often not available against
all operational risks or is not economically feasible for us to obtain. If a
significant event occurs that imposes liability on us that is either not insured
or not fully insured, a material adverse effect on our financial condition and
results of operations could result.
EMPLOYEES
At April 10, 2000, we had 99 employees associated with our operations,
including 20 field personnel in Mississippi and 28 field personnel in Oklahoma.
None of our employees is represented by a union. We consider our employee
relations to be satisfactory.
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LEGAL MATTERS
The Bankruptcy Proceedings.
On August 23, 1999, we and our consolidated subsidiaries filed a voluntary
Chapter 11 petition with the bankruptcy court. Consistent with bankruptcy cases
involving large, publicly traded companies and their affiliates, a number of
proceedings have occurred since August 23, 1999, the most significant of which
are discussed below.
The bankruptcy court approved Fulbright & Jaworski L.L.P. as our counsel
and Arthur Andersen LLP as our financial consultants and auditors. The
bankruptcy court also approved our retention of oil and gas reserve engineers,
special counsel for litigation, and ordinary course of business professionals.
All of these professionals are assisting us in our efforts to reorganize our
businesses.
Official committees for the unsecured creditors and equity holders were
formed by the Office of the United States Trustee. The bankruptcy court approved
counsel for the Official Unsecured Creditors Committee and the Official Equity
Committee. The Unsecured Creditors Committee retained its own financial
consultants. The committees were actively involved in our bankruptcy
proceedings.
The bankruptcy court approved our use of cash collateral in the continued
operations of our business, including its use in our capital expenditure
programs. Our use of cash collateral was extended through March 31, 2000. In
December 1999, under the Third Interim Order to Use Cash Collateral, we began
paying the bank group monthly payments of $1.8 million per month as adequate
protection payments. We paid additional interest payments of $1.8 million on
February 1, 2000 and $1.8 million on March 1, 2000.
Immediately following the commencement of our bankruptcy case, we obtained
permission from the bankruptcy court to pay working and royalty interest owners
to insure that payments to them were not interrupted. As a result, working and
royalty interest owners have continued to receive all payments to which they are
entitled throughout the pendency of our bankruptcy cases.
In October, 1999, one of our shareholders filed a motion to compel our
holding an annual shareholders' meeting. Our annual shareholders' meeting is
historically held between May and August. We decided not to hold the annual
shareholders' meeting by August 23, 1999, the date we filed for bankruptcy
protection, because of extensive, ongoing negotiations between us, the bank
group and the holders of our old bonds concerning the restructuring of our debt
and operations. Rather than incur the significant expenses associated with
holding the annual meeting, and then having to incur additional significant
expenses to hold a special shareholders' meeting to approve a restructuring of
the debt to the bank group and holders of our old bonds, we elected to postpone
the annual meeting and combine it with a special meeting once an agreement with
the bank group and holders of our old bonds was reached. Although we reasonably
believed that we would reach an agreement with the bank group and the holders of
our old bonds before August 23, 1999, an agreement was not reached and we filed
for bankruptcy protection.
The bankruptcy court denied the shareholders' request to compel a
shareholders' meeting provided that we permit representatives of the Equity
Committee to attend and participate, in a non-voting capacity, at a future board
meeting to discuss our plan of reorganization. We complied with the bankruptcy
court's directive. The bankruptcy court also issued an order for us to show
cause as to why our exclusive period to file a plan of reorganization under
Section 1121 of the Bankruptcy Code should not be terminated to allow other
parties to file plans of reorganization in the case. The bank group moved for a
termination of this exclusivity period as well. Exclusivity was terminated as to
the bank group, the Equity Committee and the Unsecured Creditors Committee.
On March 20, 2000, the bankruptcy court entered an order confirming our
plan of reorganization, as amended and restated. On March 31, 2000, our plan of
reorganization became effective and was consummated.
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Other Proceedings.
Hicks Muse Lawsuit. We are the plaintiff in a lawsuit styled Coho Energy,
Inc. v. Hicks, Muse, et al, which was filed in the District Court of Dallas
County, Texas, 68th Judicial District. This lawsuit has been removed to the
United States Bankruptcy Court for the Northern District of Texas, Dallas
Division, where it currently is pending.
We allege in the Hicks Muse lawsuit that Hicks Muse reneged on a commitment
to inject $250 million dollars of equity capital into our operations, which
would have given Hicks Muse control of Coho through the purchase of 41,666,666
shares of newly-issued common stock at $6 per share.
We further allege that Hicks Muse waited until after our shareholders
approved the commitment, then reneged on the commitment at the last minute to
renegotiate the price down to $4 per share to increase the number of shares that
Hicks Muse would receive for the $250 million. We also allege that Hicks Muse
reneged on this new commitment to purchase stock. We seek damages against Hicks
Muse in excess of $500 million. This description is only a general description
of the Hicks Muse lawsuit and should not be relied on as conclusively stating
all the alleged facts, claims or circumstances surrounding the lawsuit. We are
not able to evaluate the recovery we might receive in the lawsuit.
Brookhaven Lawsuits. Coho Resources, Inc., was named a defendant in a
number of individual lawsuits in Mississippi, which allege environmental damage
to property and personal injury, resulting from our drilling and production
operations and those of our predecessors in the Brookhaven field, located in
Lincoln County, Mississippi. The plaintiffs alleged that their damages were
caused by naturally occurring radioactive material resulting from petroleum
exploration and production operations. Our predecessors on the Brookhaven field
were Florabama Associates, Inc., and Chevron Corp. or Chevron USA. Inc.
Florabama and Chevron filed claims for indemnification for any liability they
may have to the Brookhaven field plaintiffs, including claims for monetary and
punitive damages, as well as clean-up costs associated with the properties, and
costs of defense. We have settled the indemnity claim of Chevron, as discussed
in the next paragraph, and are vigorously defending against the indemnity claim
of Florabama. The Florabama claim is asserted at $3,671,953.33, but given our
success in settling with Chevron, all parties now agree that our liability to
Florabama will be resolved at less than $803,000.
The plaintiffs have compromised and settled their $250 million claim
against Coho Resources, Inc. for the cash sum of $900,000 to be paid in
installments over the 180 days following the effective date of our confirmed
plan of reorganization. The court has approved this settlement. We have also
settled the claims of Chevron Corp. and Chevron USA, Inc. by agreeing to
contribute $2.5 million over the next two years to a common fund to be used to
finance the implementation of a thorough remediation plan for the Brookhaven
field. Chevron USA will contribute at least $3 million to that fund as well, and
will supervise the implementation of the remediation plan. The remediation plan
was filed with the court and circulated to numerous parties in interest. This
Coho-Chevron settlement also calls for Chevron to withdraw its claims in the
Florabama bankruptcy in Mississippi. As stated above, that will have the effect
of greatly reducing the dollar amount of Florabama's claim in the Coho
bankruptcy to less than $803,000, subject to further negotiations and final
resolution.
Insurance Coverage Disputes with United National Insurance Company Involving
Pending Litigation.
We have notified United National Insurance Company of those claims asserted
in the Brookhaven lawsuit.
United National has submitted detailed reservations of rights letters to
us, outlining the grounds upon which coverage will not or may not be available
for the claims included in this lawsuit. United National has also informed us
about limitations to potential coverage, including applicable deductibles
chargeable to us.
We are assessing the coverage issue and, if we pursue coverage, the
disputed coverage issues raised by these lawsuits may require judicial
resolution through declaratory judgment litigation.
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<PAGE> 72
(a) THE BROOKHAVEN LAWSUITS
United National has informed us that United National reserves its
rights to decline coverage on grounds that we had not adequately disclosed
the pending prior suits, including the Brookhaven litigation, during the
underwriting process before the issuance of the United National insurance
policies.
We have conducted some operations at particular locations within the
Brookhaven field since mid-1995. The primary claims in the Brookhaven
lawsuits arise out of radioactive waste material and alleged contamination
of drinking water aquifers in and around the Brookhaven field. Operations
at the Brookhaven field date back into the 1940's.
(b) UNITED NATIONAL POLICIES
United National has issued two primary liability policies and two
umbrella liability policies in effect from June 5, 1998 through June 5,
1999, and June 5, 1999 through June 5, 2000, respectively subject to
various deductible and limits.
There are two basic coverage parts in the policies, commercial general
liability and energy industries pollution liability, both of which are
modified by various endorsements included in the policies. The energy
industries pollution liability form is issued on a claims made basis.
(c) GENERAL LIABILITY COVERAGE ISSUES
United National has informed us of its position that potential
coverage is not available for the claims in the Brookhaven lawsuit under
the general liability provisions of the policies. In particular, United
National has informed us that the lawsuits do not seek damages because of
"bodily injury" and "personal injury" defined in the policies, although the
suits include claims for "property damage." United National has also
advised that the Brookhaven lawsuit may be seeking recovery for damage
occurring before the issuance of the United National policies. United
National has also informed us that the policy exclusions would preclude
potential coverage under the general liability provisions, including, but
not limited to, pollution exclusions, health hazard exclusions, and
exclusions applicable to liability arising from waste disposal sites owned,
operated or used by an insured.
Other general liability policy provisions, exclusions and coverage
positions have been outlined and reserved by United National.
(d) ENERGY INDUSTRIES POLLUTION LIABILITY COVERAGE ISSUES
United National has also informed us of its position that the claims
in the Brookhaven lawsuit also may not be subject to potential coverage
under the energy industries pollution liability provisions. United National
has informed us that United National reserves its rights to decline
potential coverage under the energy industries pollution liability
provisions of the policies. Grounds to avoid coverage include the fact that
some of the lawsuits do not include allegations of a pollution incident,
that any pollution incidents may not have commenced before the policy
retroactive date, that property damage to waste facilities is excluded; and
that bodily injury or property damage arising out of a pollution incident
which results from a deliberate failure to comply with applicable statutes
or regulations is excluded from potential coverage. Other energy industries
pollution liability provisions, exclusions and coverage positions have been
outlined and reserved by United National.
(e)COVERAGE POSITIONS APPLICABLE TO BOTH GENERAL LIABILITY AND ENERGY
INDUSTRIES POLLUTION LIABILITY PROVISIONS
United National has also informed us of its position that the claims
in the Brookhaven lawsuit also may not be subject to potential coverage
under both the general liability and the energy industries pollution
liability provisions based on one or more of exclusions or other grounds
applicable to both coverage forms, including damage expected or intended
from the standpoint of the insured, or damage which the insured is
obligated to pay by reason of the assumption of liability in a contract or
agreement, liability arising out of the actual, alleged or threatened
properties of any "radioactive
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material;" and any loss, cost or expense arising out of any request, demand
or order to respond to or assess the effects or presence of radioactive
material; and property damage or personal injury arising from known damages
or an occurrence or offense known to any insured before the inception of
the policies. Other policy provisions, exclusions and coverage positions
applicable to both coverage forms have been outlined and reserved by United
National.
United National also has maintained that:
- its policies do not extend potential coverage to punitive damages
sought in the lawsuits,
- there is a per occurrence deductible applicable to pollution claims
in the amount of $50,000 per occurrence, and
- each lawsuit is subject to a minimum of one $50,000-per-occurrence
pollution deductible for which we would be liable before policy
proceeds attaching.
We believe that there is no merit to United National's various positions
described above and we have reserved all rights with respect to these policies
and United National's conduct in connection therewith.
Unasserted Causes of Action.
We have an unasserted claim against Texaco Exploration and Production, Inc.
regarding imbalances in gas volume from wells in which we have an interest.
The Equity Committee in our bankruptcy proceedings contends that causes of
action may exist against one or more of our management team as it existed on
August 23, 1999. We contend that these claims lack merit.
We believe that we have been damaged as a result of the actions of some
members of the Equity Committee, including communications by those members on
the internet. The Equity Committee contends that these claims lack merit.
We are involved in various other legal actions arising in the ordinary
course of business. While it is not feasible to predict the ultimate outcome of
these actions or those listed above, we believe that the resolution of these
matters will not have a material adverse effect, either individually or in
aggregate, on our financial position or results of operations.
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MANAGEMENT
DIRECTORS
The names of our directors and other information with respect to each of
them are set forth below:
<TABLE>
<CAPTION>
DIRECTOR AGE SINCE
- -------- --- -----
<S> <C> <C>
Michael McGovern(a)......................................... 48 2000
Eugene Davis(a)............................................. 45 2000
John G. Graham(a)(b)........................................ 61 2000
James E. Bolin.............................................. 41 2000
Michael E. Salvati(c)....................................... 47 2000
Ronald M. Goldstein......................................... 45 2000
</TABLE>
- ---------------
(a) Member of the Executive Committee.
(b) Chairman of the Audit Committee. Our board of directors has not yet
appointed other members of the Audit Committee.
(c) Chairman of the Compensation Committee. Our board of directors has not yet
appointed other members of the Compensation Committee.
Michael McGovern. Mr. McGovern has served as our President and Chief
Executive Officer since March 31, 2000. Mr. McGovern served as Managing Director
of Pembrook Capital Corporation, an energy investment and advisory services
company, since 1998 and served as Chairman and Chief Executive Officer for
Edisto Resources Corporation, a publicly held oil and gas company, from 1993 to
1997. Mr. McGovern is a director of Greystar Corporation, a private production
management service company; Century Seismic LLC, a private seismic data library
service; and Goodrich Petroleum Corporation, a public oil and gas company.
Eugene Davis. Mr. Davis has served as Chairman and Chief Executive Officer
of Pirinate Consulting Group, L.L.C., a consulting firm specializing in crisis
and turn-around management advisory services for public and private businesses,
since 1999. Mr. Davis served as Chief Operating Officer of Total-Tel USA
Communications, Inc., an integrated telecommunications provider, from 1998 to
1999. He also served in various officer positions, lastly as Vice Chairman and
Director, of Emerson Radio Corporation, an international distributor of consumer
electronics products, since 1990.
John G. Graham. Mr. Graham has served as President and Chief Executive
Officer of Utilities Mutual Insurance Company, a mutual provider of workers'
compensation and other insurance lines, since May 1999. Mr. Graham also served
as Senior Vice President and Chief Financial Officer of GPU Service Corporation,
a domestic and international electric utility, from 1976 to April 1999. Mr.
Graham is a director of Viatel Inc., a publicly held telecommunications company.
James E. Bolin. Mr. Bolin has served as Vice President and Secretary of
Appaloosa Partners, Inc., an investment firm and one of our principal
shareholders, since 1995. Mr. Bolin served as a Vice President and Analyst for
Goldman, Sachs & Company, an investment banking firm, from 1989 to 1995, and as
Director of Corporate Bond Research from 1992 to 1995.
Michael E. Salvati. Mr. Salvati is an independent financial consultant. Mr.
Salvati served as Executive Vice President and Chief Operating Officer of
National Financial Partners Corp., a financial services firm, from 1998 to
February 2000. Mr. Salvati served as Vice President and Chief Financial Officer
of Culligan Water Technologies, Inc., from 1996 to 1998, and was a Partner with
KPMG Peat Marwick LLP, a public accounting firm, prior to 1996.
Ronald M. Goldstein. Mr. Goldstein currently serves as Vice President and
Chief Financial Officer of Appaloosa Partners, Inc., an investment firm and one
of our principal shareholders. Prior to joining
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Appaloosa Partners, Inc. in 1993, Mr. Goldstein was a Senior High Yield Trader
for Bear Stearns & Company, an investment banking firm.
There is no family relationship between any director, executive officer or
person nominated or chosen by the registrant to become a director or executive
officer.
EXECUTIVE OFFICERS
The names of our executive officers and other information with respect to
them are set forth below:
<TABLE>
<CAPTION>
NAME AGE POSITION
- ---- --- --------
<S> <C> <C>
Michael McGovern................................ 48 President, Chief Executive Officer and Director
Gary L. Pittman................................. 44 Chief Financial Officer and Corporate Secretary
Gerald E. Ruley................................. 59 Vice President -- Operations
</TABLE>
For information concerning Michael McGovern, see the table under the
caption "Directors," above.
Gary L. Pittman has served as our Chief Financial Officer and Corporate
Secretary since April 1, 2000. Mr. Pittman served as Chief Financial Officer of
Bell Geospace, Inc., a privately held technology-based provider of high
resolution gradient data to the oil and gas industry, from 1999 to 2000. Mr.
Pittman also served as a financial consultant to a privately held company from
1998 to 1999, and as Executive Vice President and Chief Financial Officer of
Convest Energy Corporation, a publicly traded independent energy company, from
1995 to 1997.
Gerald E. Ruley has served as our Vice President -- Operations since April
1, 2000 and as a Production Manager for Coho since 1996. Mr. Ruley also served
as Exploration and Production Manager of Winchester Production Company, an
independent energy company, from 1994 to 1995.
Under our plan of reorganization, for the first year after the
confirmation, our board of directors will consist of seven members. Four members
of the board of directors will be selected by the principal holders of the old
bonds. One member of the board of directors will be selected by the
post-confirmation board of directors from our post-confirmation management. Two
members of the board of directors will be selected by the entities whose funding
is used after the confirmation of our plan of reorganization, based upon their
relative contributions of capital.
Three of the four members of the board of directors selected by the
principal holders of old bonds are Eugene Davis, John G. Graham, and James E.
Bolin. The one member of the board of directors selected from our
post-confirmation management is Michael McGovern. The two members selected by
the entities whose funding was used after confirmation of our plan of
reorganization are Ronald Goldstein and Michael Salvati. Information about each
of the persons named in this paragraph is set forth under the caption
"Directors," above.
We are not currently aware of the identity of the remaining board member
for the one-year period after confirmation that will be nominated in accordance
with our plan of reorganization.
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EXECUTIVE COMPENSATION
The following tables contain information about our five most highly
compensated executive officers, including our Chief Executive Officer, in 1997,
1998 and 1999.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG-TERM
COMPENSATION
AWARDS
-------------
ANNUAL COMPENSATION SECURITIES
-------------------------- UNDERLYING ALL OTHER
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS OPTIONS(#)(7) COMPENSATION
- --------------------------- ---- -------- -------- ------------- ------------
<S> <C> <C> <C> <C> <C>
Jeffrey Clarke........................ 1999 $300,000 $ 0 -- $ 53,194
President and Chief 1998 300,000 0 -- 378,060
Executive Officer(1)(6) 1997 265,000 250,000 300,000 52,539
R.M. Pearce........................... 1999 $225,000 $ 0 -- $ 17,508
Executive Vice President and 1998 225,000 0 -- 17,171
Chief Operating Officer(2) 1997 195,000 140,000 160,000 13,954
Eddie M. LeBlanc, III................. 1999 $175,000 $ 0 -- $ 13,042
Senior Vice President and 1998 175,000 0 -- 12,835
Chief Financial Officer(3) 1997 161,650 85,000 150,000 11,170
Anne Marie O'Gorman................... 1999 $175,000 $ 0 -- $ 11,511
Senior Vice President 1998 175,000 0 -- 83,106
Corporate Development and 1997 161,650 85,000 100,000 10,516
Corporate Secretary(4)(6)
Larry L. Keller....................... 1999 $163,000 $ 0 -- $ 10,481
Vice President, Mid Continent 1998 163,000 0 -- 83,685
Division(5)(6) 1997 143,100 65,000 45,000 10,050
</TABLE>
- ---------------
(1) Mr. Clarke's All Other Compensation includes our contributions to a 401(k)
savings plan of $8,000 in each year of 1999, 1998 and 1997; premiums paid on
a disability and life insurance policy of $33,118, $32,656 and $32,463 in
1999, 1998 and 1997, respectively; and $12,076 in each year of 1999, 1998
and 1997 of imputed interest on a loan from Coho. Mr. Clarke ceased to serve
as President, Chief Executive Officer and Chairman on March 31, 2000, and is
no longer employed by us.
(2) Mr. Pearce's All Other Compensation includes our contributions to a 401(k)
savings plan of $8,000 in each year of 1999, 1998 and 1997; and premiums
paid on a disability policy of $9,508, $9,171 and $5,954 in 1999, 1998 and
1997, respectively. Mr. Pearce ceased to serve as Executive Vice President
and Chief Operating Officer on April 4, 2000, and is no longer employed by
us.
(3) Mr. LeBlanc's All Other Compensation includes our contributions to a 401(k)
savings plan of $8,000 in each year of 1999, 1998 and 1997; and premiums
paid on a disability policy of $5,042, $4,835 and $3,171 in 1999, 1998 and
1997, respectively. In late 1999, we proposed a work force reduction. In
connection with the proposed work force reduction, Mr. LeBlanc is no longer
employed by us.
(4) Ms. O'Gorman's All Other Compensation includes our contributions to a 401(k)
savings plan of $8,000, in each year of 1999, 1998 and 1997; and premiums
paid on a disability policy of $3,511, $3,429 and $2,050 in 1999, 1998 and
1997, respectively. Ms. O'Gorman ceased to serve as Senior Vice President,
Corporate Development and Corporate Secretary on April 1, 2000.
(5) Mr. Keller's All Other Compensation includes our contributions to a 401(k)
savings plan of $8,000 in each year of 1999, 1998 and 1997; and premiums
paid on a disability policy of $2,481, $2,345 and $2,050 in 1999, 1998 and
1997, respectively. Mr. Keller ceased to serve as Vice President, Mid
Continent Division on April 4, 2000.
(6) Included in All Other Compensation for Messrs. Clarke and Keller and Ms.
O'Gorman for 1998 are $324,992, $73,331 and $71,678, respectively. The
amounts represent our payment on January 22, 1998 of the difference of the
guaranteed price of $10.50 and the strike price of stock options exercised
in
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October 1997. For more information, see the section of this prospectus
called "Certain Relationships and Related Transactions."
(7) Upon consummation of our plan of reorganization, all options were canceled.
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION/SAR VALUES
<TABLE>
<CAPTION>
NUMBER OF SECURITIES VALUE OF UNEXERCISED
SHARES UNDERLYING UNEXERCISED IN-THE-MONEY OPTIONS
ACQUIRED OPTIONS AT FISCAL YEAR-END(1) AT FISCAL YEAR-END(2)
ON VALUE ----------------------------- -----------------------------
NAME EXERCISE REALIZED EXERCISABLE NON-EXERCISABLE EXERCISABLE NON-EXERCISABLE
- ---- -------- -------- ----------- --------------- ----------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Jeffrey Clarke(3)........... -- $-- 482,023 0 $0 $0
R.M. Pearce(4).............. -- $-- 380,000 0 $0 $0
Eddie M. LeBlanc, III(5).... -- $-- 250,000 0 $0 $0
Anne Marie O'Gorman(6)...... -- $-- 203,432 0 $0 $0
Larry L. Keller(7).......... -- $-- 78,333 15,000 $0 $0
</TABLE>
- ---------------
(1) Upon consummation of our plan of reorganization, all options were canceled.
(2) Computed based upon the difference between the market price on December 31,
1999 of $7/16 per share and the exercise price per share.
(3) Mr. Clarke ceased to serve as President, Chief Executive Officer and
Chairman on March 31, 2000, and is no longer employed by us.
(4) Mr. Pearce ceased to serve as Executive Vice President and Chief Operating
Officer on April 4, 2000, and is no longer employed by us.
(5) In late 1999, we proposed a work force reduction. In connection with the
proposed work force reduction, Mr. LeBlanc is no longer employed by us.
(6) Ms. O'Gorman ceased to serve as Senior Vice President, Corporate Development
and Corporate Secretary on April 1, 2000.
(7) Mr. Keller ceased to serve as Vice President, Mid Continent Division on
April 4, 2000.
EMPLOYMENT AGREEMENTS
Our board of directors has proposed that our plan of reorganization provide
for a retention plan under which key employees are provided with additional
incentives to continue their employment with Coho throughout our bankruptcy
reorganization. The amount of cash awards that will be granted under the
retention plan is approximately $1.5 million, 33% of which is paid shortly after
the confirmation of our plan of reorganization and 67% of which is paid on the
first business day following the 270th day after the effectiveness of the
confirmation.
We have entered into employment agreements with each of Messrs. McGovern,
Ruley and Pittman, which provide for minimum annual compensation in the amount
of $350,000, $250,000, and $200,000, respectively. Each employment agreement is
for a term of two years, which term automatically renews daily for a term to
extend two years from the renewal date until either party gives notice.
Additionally, each employment agreement automatically terminates on the date of
a "Change of Control," as defined below. Each employment agreement entitles the
officer to participate in the bonus, incentive compensation and other programs
that are created by our board of directors. If any of Messrs. McGovern, Ruley or
Pittman is terminated by Coho without "Cause" (as defined below), or if the
employment agreements are automatically terminated because of a "Change of
Control," Coho would:
- pay that individual a cash lump sum payment equal to two times the
executive's then-current annual rate of total compensation, and
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- continue, until the second anniversary of the employment termination,
health and life insurance coverage under our plans or the equivalent
thereof on the same basis as our other senior executives.
If any of Messrs. McGovern, Ruley or Pittman becomes disabled or dies during the
term of the respective employment agreement, the employment agreement may be
terminated by us, and we will pay the executive or his estate any unpaid
compensation and other benefits under the employment agreement until the date of
termination.
The term "Cause" is defined in each employment agreement generally to mean:
- any material failure of the executive after written notice to perform his
or her duties,
- commission of fraud, embezzlement or misappropriation by the executive
against Coho,
- a material breach by the executive of the employment agreement or of the
fiduciary duty owed to Coho, or
- conviction of the executive of a felony offense or a crime involving
moral turpitude.
Under each employment agreement, a "Change of Control" of Coho is deemed to
have occurred if:
- there is a sale, lease or other transfer of all or substantially all of
the assets of Coho,
- our shareholders adopt a plan relating to the liquidation or dissolution
of Coho,
- any person or group of persons acting in concert becomes the beneficial
owner of more than 50 percent of the voting power of our securities
generally entitled to vote in the election of directors, with certain
exceptions, or
- there occurs a merger or consolidation of Coho unless, after the
transaction, all of those persons who were the beneficial owners of our
common stock before the transaction beneficially own 50 percent or more
of the total voting power of all securities generally entitled to vote in
the election of directors, managers or trustees of the surviving entity.
We had employment agreements with each of Jeffrey Clarke, R. M. Pearce, and
Anne Marie O'Gorman. Additionally, we had a severance agreement with Larry L.
Keller. Each of these people is a former officer of Coho, and Mr. Clarke is also
a former director. We rejected each of these agreements under our plan of
reorganization, and each of these people filed proofs of claim in our bankruptcy
case. We have negotiated settlement agreements with Messrs. Clarke and Keller
and Ms. O'Gorman, which agreements are described below. We are currently
negotiating an agreement with Mr. Pearce.
We have entered into an executive employment severance agreement with
Jeffrey Clarke, our former president and chief executive officer. The purpose of
this agreement is to compromise and settle any claims Mr. Clarke may have had
under his prior employment agreement and to secure Mr. Clarke's assistance in
the Hicks Muse lawsuit. In addition, Mr. Clarke has agreed to serve us as a
consultant for up to two days per week through June 30, 2000. Under the
compromise and settlement agreement, Mr. Clarke is entitled to receive a total
of $875,000 as a cash settlement, $412,500 of which was paid as of the effective
date of the plan of reorganization and $462,500 of which is to be paid on the
270th day following the effective date.
In addition, under the agreement Mr. Clarke will receive the following
non-cash benefits:
- payment of two years of medical insurance, life insurance and disability
insurance,
- release of any claims we may have in connection with the non-interest
bearing sole recourse loan made to Mr. Clarke in October 1997 to assist
him in the exercise of expiring options,
- forebearance of the interest-free loan from us to Mr. Clarke in the
amount of $205,000 used to purchase a house, in exchange for Mr. Clarke's
assistance in the Hicks Muse lawsuit, which loan will be forgiven on the
date the Hicks Muse lawsuit is settled or otherwise completed,
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- a three year directors and officers insurance policy as described in the
plan of reorganization, covering actions prior to the effective date, and
- our agreement not to assign any claims we may have against Mr. Clarke, if
any.
Our agreement with Mr. Clarke also includes a one-year non-compete clause and
confidentiality provisions.
We entered into an agreement with Anne Marie O'Gorman, our former Senior
Vice President Corporate Development and Corporate Secretary, to compromise and
settle her claims under her employment agreement, which was rejected under our
plan of reorganization. Under the compromise and settlement agreement, Ms.
O'Gorman is entitled to receive $175,000 as a cash settlement, payable in four
equal quarterly installments, with the first payment made on the date of the
agreement. Ms. O'Gorman is also eligible to participate in the retention plan
described above, and is entitled to a pro rata portion of the retention bonus if
she is terminated prior to the 270th day after the effective date of the plan of
reorganization.
In addition, under the agreement Ms. O'Gorman will receive the following
benefits:
- payment of medical and dental coverage for one year after her
termination,
- release of any claims we may have in connection with the non-interest
bearing sole recourse loan made to Ms. O'Gorman in October 1997 to assist
her in the exercise of expiring options, and
- upon termination, payment of two weeks severance for each year or
fraction of year of employment.
We entered into an agreement with Larry L. Keller, our former Vice
President, Mid-Continent Division, to compromise and settle his claims under his
severance agreement, which was rejected under our plan of reorganization. Under
the compromise and settlement agreement, Mr. Keller is entitled to receive a
$163,000 cash settlement, payable in four equal quarterly installments, with the
first payment made on the date of the agreement. Mr. Keller is also eligible to
participate in the retention plan described above, and is entitled to a pro rata
portion of the retention bonus if he is terminated prior to the 270th day after
the effective date of the plan of reorganization.
In addition, under the agreement Mr. Keller will receive the following
benefits:
- payment of medical and dental coverage for one year after his
termination, and
- release of any claims we may have in connection with the non-interest
bearing sole recourse loan made to Mr. Keller in October 1997 to assist
him in the exercise of expiring options.
We are currently negotiating settlement agreements with our other former
officers.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
At December 31, 1999 the members of our compensation committee were Douglas
R. Martin, Alan Edgar and Jake Taylor. No member of our compensation committee
was an officer or employee of Coho at any time during 1999. Mr. Martin was the
Chief Financial Officer of Coho Resources Limited from April 1990 through August
1993.
During 1999 no executive officer of Coho served as:
- a member of the compensation committee or other board committee
performing equivalent functions of another entity, one of whose executive
officers served on the compensation committee of our board of directors,
- director of another entity, one of whose executive officers served on the
compensation committee of our board of directors, or
- a member of the compensation committee or other board committee
performing equivalent functions of another entity, one of whose executive
officers served as a director of Coho.
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COMPENSATION OF DIRECTORS
Directors who are not our employees receive an annual retainer of $15,000
plus a fee of $1,000 for each meeting of our board of directors or meeting of a
committee of our board of directors attended in person. Additionally, members of
the Audit, Compensation and Executive Committees will receive an annual fee of
$2,000, with the exception of the chairman of each Committee, who will receive
an annual chairman fee of $3,500. Eugene Davis has also entered into a month to
month contract with us for consulting services at $15,000 per month. All
directors are reimbursed for expenses incurred in attending meetings of our
board of directors or meetings of committees of our board of directors. Our
employees who are also directors do not receive a retainer or fees for attending
meetings of our board of directors or meetings of committees of our board of
directors.
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<PAGE> 81
SECURITY OWNERSHIP OF PRINCIPAL BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth information as to persons or entities who,
to our knowledge based on information received from those persons or entities,
were the beneficial owners of more than 5% of the outstanding shares of common
stock as of April 1, 2000. Unless otherwise specified, these persons have sole
voting power and sole dispositive power with respect to all shares attributable
to them.
<TABLE>
<CAPTION>
NAME AND ADDRESS OF AMOUNT AND NATURE OF
BENEFICIAL OWNER BENEFICIAL OWNERSHIP PERCENT OF CLASS(1)
- ------------------- -------------------- -------------------
<S> <C> <C>
PPM America, Inc.(2)..................................... 5,254,353 32.8%
225 West Wacker Drive, Suite 1200
Chicago, Illinois 60606
Appaloosa Management, L.P.(3)............................ 4,765,083 29.8%
26 Main Street
Chatham, New Jersey 07928
Oaktree Capital Management, LLC(4)....................... 4,102,707 25.6%
333 South Grand Avenue, 28th Floor
Los Angeles, California 90071
</TABLE>
- ---------------
(1) Based on 16,002,195 shares issued and outstanding as of April 1, 2000.
(2) Based on information contained in a Schedule 13D filed April 11, 2000 filed
with the Commission. PPM America, Inc. has shared voting and dispositive
power with respect to 5,254,253 shares of new common stock that are owned by
it.
(3) Based on information contained in a Schedule 13D filed April 11, 2000 filed
with the Commission. Appaloosa Management, L.P. is a limited partnership and
has sole voting and dispositive power with respect to 4,765,083 shares of
new common stock that are owned by the partnership.
(4) Based on information available to us. To our knowledge, Oaktree Capital
Management, LLC has sole voting and dispositive power with respect to
4,102,707 shares of Common Stock that are owned by it.
The following table sets forth information with respect to common stock
beneficially owned as of April 1, 2000 by each of our directors, by each
executive officer named in the Summary Compensation Table (each of whom is no
longer an executive officer, as described in the footnotes following the table
below) and by all directors and officers as a group (including former executive
officers). Unless otherwise specified, these persons have sole voting power and
sole dispositive power with respect to all shares attributable to him or her.
<TABLE>
<CAPTION>
AMOUNT AND NATURE OF PERCENT
BENEFICIAL OWNERSHIP OF CLASS
-------------------- --------
<S> <C> <C>
James E. Bolin(1)........................................... 4,765,083 29.8
Jeffrey Clarke(2)........................................... 1,745 *
Eugene L. Davis............................................. -- --
Ronald Goldstein(3)......................................... 4,765,083 29.8
John G. Graham.............................................. -- --
Larry L. Keller(4).......................................... 379 *
Eddie M. LeBlanc, III(5).................................... 25 *
Michael McGovern............................................ -- --
Anne Marie O'Gorman(6)...................................... 408 *
R. M. Pearce(7)............................................. 125 *
Michael Salvati............................................. -- --
All directors and executive officers as a group (13
persons).................................................. 4,767,765 29.8%
</TABLE>
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<PAGE> 82
- ---------------
* Less than 1%
(1) Mr. Bolin, one of our directors, is a vice president and secretary of
Appaloosa Partners, Inc. and, as such, may be deemed to beneficially own the
shares owned by Appaloosa Partners, Inc.
(2) Mr. Clarke ceased to serve as President, Chief Executive Officer and
Chairman on March 31, 2000, and is no longer employed by us.
(3) Mr. Goldstein, one of our directors, is a vice president and chief financial
officer of Appaloosa Partners, Inc. and, as such, may be deemed to
beneficially own the shares owned by Appaloosa Partners, Inc.
(4) Mr. Keller ceased to serve as Vice President, Mid-Continent Division, on
April 4, 2000.
(5) In late 1999, we proposed a work force reduction. In connection with the
proposed work force reduction, Mr. LeBlanc's employment relationship with us
was severed effective December 31, 1999.
(6) Ms. O'Gorman ceased to serve as Senior Vice President, Corporate Development
and Corporate Secretary on April 1, 2000.
(7) Mr. Pearce ceased to serve as Executive Vice President and Chief Operating
Officer on April 4, 2000, and is no longer employed by us.
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<PAGE> 83
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Under the terms of a Financial Advisory Agreement entered into between us
and Hicks, Muse & Co. Partners, L.P., on August 21, 1998, we paid Hicks, Muse &
Co. Partners $1,250,000 as compensation for its services as our financial
advisor in connection with an agreement to issue shares of our common stock to
HM4 Coho L.P., an affiliate of Hicks, Muse & Co. Partners. John R. Muse and
Lawrence D. Stuart, Jr., are limited partners in Hicks, Muse & Co. Partners and
limited partners of a limited partner in HM4, and at the time of the payment to
Hicks, Muse & Co. Partners, were two of our directors under an agreement with
EIP. For more information regarding EIP, see the section of this prospectus
called "Management." On March 18, 1999, Messrs. Muse and Stuart resigned from
our board of directors.
In May 1990 we made a non-interest bearing loan in the amount of $205,000
to Mr. Jeffrey Clarke, our former Chairman, President and Chief Executive
Officer, to assist him in the purchase of a house in Dallas, Texas. We have
agreed to forgive this loan when the Hicks Muse lawsuit is settled or otherwise
completed in exchange for Mr. Clarke's continued assistance in pursuing the
litigation.
In October 1997 we made non-interest bearing sole recourse loans to Jeffrey
Clarke, our former Chairman, President and Chief Executive Officer; Anne Marie
O'Gorman, our former Senior Vice President, Corporate Development; Larry Keller,
our former Vice President Exploitation; and Kenneth Lambert, one of our former
directors, in the amounts of $383,064; $84,006; $66,665 and $88,375,
respectively, to assist them in the exercise of expiring options. At the time of
the expiration of these options all of our officers and directors were subject
to a 90-day lock up agreement with the underwriters of our 1997 equity offering.
Under the terms of this agreement, the officers and directors were not able to
sell any of their shares and would not have had the funds necessary to purchase
the stock without the loan. In addition to the loan, we also provided a
guaranteed price of $10.50, which was the price of the common stock in the 1997
equity offering, to be received by Messrs. Clarke, Keller and Lambert and Ms.
O'Gorman. These loans were forgiven in connection with our restructuring.
In 1999, we entered into an agreement with Alan Edgar, one of our former
directors, that provided for Mr. Edgar to receive a percentage of the net
proceeds received by us from the lawsuit we commenced against Hicks Muse up to a
maximum of $5.75 million, in consideration of Mr. Edgar's extensive and ongoing
involvement in working with our special litigation counsel in prosecuting the
lawsuit. When the plan of reorganization was consummated, this agreement was
rejected.
In April 2000, we entered into a consulting services agreement with Eugene
Davis, one of our directors, on a month to month basis. Under the agreement, Mr.
Davis is to receive $15,000 per month.
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<PAGE> 84
DESCRIPTION OF EXISTING INDEBTEDNESS
The Credit Facility.
On the effective date, we established a new credit facility with a group of
lenders and The Chase Manhattan Bank, as agent for the new lenders, for a
principal amount of up to $250 million. The new credit facility limits advances
to the amount of the borrowing base, which has been set initially at $205
million. The borrowing base is the loan value to be assigned to the proved
reserves attributable to our oil and gas properties. The borrowing base is
subject to semiannual review based on reserve reports. The initial borrowing
base was subject to Chase's review of the January 1, 2000 reserve report, which
was prepared and audited by independent petroleum engineering firms acceptable
to the new lenders. The principal amount currently outstanding under the new
credit facility is $183.0 million.
The new credit facility is subject to semiannual borrowing base
redeterminations, each April 1 and October 1, and will be made in the sole
discretion of the lenders. We will deliver to the lenders by March 1 of each
year a reserve report prepared as of the immediately preceding January 1 and by
September 1 of each year a reserve report prepared as of the immediately
preceding July 1. The January 1 reserve report will be prepared internally by us
and audited by an independent petroleum engineering firm, acceptable to Chase,
and the July 1 reserve report will be prepared internally by us, in a form
acceptable to Chase. Based in part on the reserve report, the lenders will
redetermine the borrowing base in their sole discretion. For an increase in the
borrowing base, consent of 100% of the lenders will be required. To maintain the
borrowing base, or to reduce the borrowing base, consent of the lenders holding
75% of outstanding loans and letter of credit exposure or, if no loans or
letters of credit are outstanding, the lenders of 75% of the current loan
commitments under the new credit facility, will be required. We or Chase may
request one additional borrowing base determination during any calendar year.
Interest on advances under the new credit facility will be payable on the
earlier of the expiration of any interest period under the new credit facility
or quarterly, beginning the first quarter after the effective date. Amounts
outstanding under the new credit facility will accrue interest at our option at
either the Eurodollar rate, which is the annual interest rate equal to the
London interbank offered rate for deposits in United States dollars that is
determined by reference to the Telerate Service or offered to Chase plus an
applicable margin, or the prime rate, which is the floating annual interest rate
established by Chase from time to time as its prime rate of interest and which
may not be the lowest or best interest rate charged by Chase on loans similar to
the new credit facility, plus an applicable margin. All outstanding advances
under the new credit facility are due and payable in full three years from the
effective date.
The new credit facility has been secured by granting Chase the following
collateral for the benefit of the lenders:
- first and prior security interests in our issued and outstanding capital
stock and other equity interests of our material subsidiaries,
- first and prior mortgage liens and security interests covering proved
mineral interests selected by Chase having a present value, as determined
by Chase, of not less than 85% of the present value of all of our proved
mineral interests evaluated by the lenders for purposes of determining
the borrowing base, and
- first and prior security interests in our other tangible and intangible
assets.
The rights and responsibilities of Chase, the lenders and us are governed by a
new senior revolving credit agreement and related documents, which, in part,
permit the lenders to enforce their rights to the collateral on the occurrence
of an event of default under the new credit agreement.
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<PAGE> 85
The new credit agreement contains financial and other covenants including:
- maintenance of minimum ratios of cash flow to interest expense, senior
debt to cash flow, and current assets to current liabilities as of the
end of each fiscal quarter, commencing as of the initial fiscal quarter
to commence after the effective date,
- restrictions on the payment of dividends and
- limitations on the incurrence of additional indebtedness, the creation of
liens and the incurrence of capital expenditures.
Fees for the lenders contained in the Chase commitment letter to us dated
December 9, 1999 were approved by the bankruptcy court at a hearing on the fees
held on January 27, 2000. These fees include an initial due diligence fee of
$200,000. Because the lenders funded under the new credit facility on the
effective date, they are entitled to an additional aggregate $5.8 million of
closing fees. All fees paid by us in connection with the new credit facility are
non-refundable and are in addition to reimbursements to be paid for expenses
incurred by Chase in connection with the preparation of the new credit agreement
and related documentation.
The Standby Loan.
The majority of the funds necessary for the payment of the allowed bank
group claim were obtained through an advance under the new credit facility with
Chase of $183.0 million of the initial borrowing base. The remaining amount of
the allowed bank group claim has been paid with the standby loan. The standby
loan has been made under a senior subordinated note facility under which we
issued, and PPM America, Inc., Appaloosa Management, L.P., Oaktree Capital
Management, L.L.C. and Pacholder Associates, Inc. and their assignees,
purchased, $72 million of senior subordinated notes. Our rights and
responsibilities and those of the standby lenders are governed by a standby loan
agreement which was executed and delivered on March 31, 2000.
Debt under the standby loan agreement is evidenced by notes, maturing seven
years after the effective date, and bearing interest at a minimum annual rate of
15% and payable in cash semiannually. After the first anniversary of the
effective date, additional semiannual interest payments will be payable in an
amount equal to 1/2% for every $0.25 that the "actual price" for our oil and
gas production exceeds $15 per barrel of oil equivalent during the applicable
semiannual interest period, up to a maximum of 10% additional interest per year.
The "actual price" for our oil and gas production is the weighted average price
received by us for all of our oil and gas production, including hedged and
unhedged production, net of hedging costs, in dollars per barrel of oil
equivalent using a 6:1 conversion ratio for natural gas. The actual price will
be calculated over a six-month measurement period ending on the date two months
before the applicable interest payment date. Additionally, upon an event of
default occurring under the standby loan, interest will be payable in cash,
unless otherwise required to be paid-in-kind, at a rate equal to 2% per year
over the applicable interest rate. Interest payments under the standby loan may
be paid-in-kind subject to the requirements of the new credit agreement.
"Paid-in-kind" refers to the payment of interest owed under the standby loan by
increasing the amount of principal outstanding under the standby loan notes,
rather than paying the interest in cash.
Payment of the standby loan notes is expressly subordinate to payments in
full in cash of all obligations arising in connection with the new credit
facility. After the initial 12-month period, cash interest payments may be made
only to the extent by which EBITDA, or earnings before interest, tax,
depreciation and amortization expense, on a trailing four-quarter basis exceed
$65 million. The new credit agreement also prohibits us from making any cash
interest payments on the standby loan indebtedness if the outstanding
indebtedness under both the new credit facility and the standby loan exceeds
3.75 times the EBITDA for the trailing four quarters. We may prepay the standby
loan notes at the face amount, in whole or in part, in minimum denominations of
$1,000,000, plus either a standard make-whole payment at 300 basis points over
the "treasury rate" for the first four years. Beginning in the fifth year, the
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<PAGE> 86
prepayment fee is 7.5% of the principal amount being prepaid; in the sixth year,
the prepayment fee is 3.75% of the principal amount being prepaid; and in the
seventh year there is no prepayment fee. The "treasury rate" is the yield of
U.S. Treasury securities with a term equal to the then-remaining term of the
standby loan notes that has become publicly available on the third business day
before the date fixed for repayment.
When the standby loan notes were issued, the standby lenders became
entitled to receive a percentage of our fully diluted new common stock. Because
$72 million in principal amount of the standby loan notes were issued, the
standby lenders will receive 14.4% of the fully diluted new common stock. The
shares of new common stock issued to the standby lenders will be in addition to
the shares of new common stock issued to holders of the old bonds, to our
shareholders prior to reorganization and to persons participating in this rights
offering. See the section of this prospectus called "Dilution" for an
illustration of the dilution of the new common stock.
Fees for the standby lenders contained in the standby lender fee letter to
us dated January 24, 2000 were approved by the bankruptcy court at a hearing on
the fees held on January 27, 2000. These fees include a due diligence fee of
$200,000, payable immediately, and a closing fee in an amount equal to the
greater of $1.0 million or 3 1/2% of the aggregate principal amount of the
standby loan notes purchased. Our obligation to pay the closing fee was an
administrative expense claim having priority over all administrative expenses in
accordance with Section 364(c)(1) of the bankruptcy code. We have paid the
closing fee of $2.52 million.
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<PAGE> 87
DESCRIPTION OF OUR CAPITAL STOCK
OUR AUTHORIZED CAPITAL STOCK
Our authorized capital stock consists of 50,000,000 shares of new common
stock, par value $0.01 per share, and 10,000,000 shares of preferred stock, par
value $0.01 per share. At April 1, 2000, 16,002,195 shares of new common stock
were outstanding and no shares of preferred stock were outstanding.
DESCRIPTION OF OUR NEW COMMON STOCK
Holders of shares of new common stock
- are entitled to one vote per share in the election of directors and on
all other matters submitted to a vote of shareholders;
- do not have the right to cumulate their votes in the election of
directors;
- have no redemption or conversion rights and no preemptive or other rights
to subscribe for our other securities in the event of our liquidation,
dissolution or winding up;
- upon our liquidation, dissolution or winding up, are entitled to share
equally and ratably in all of the assets remaining, if any, after
satisfaction of all of our debts and liabilities and the preferential
rights of any series of preferred stock then outstanding; and
- have an equal and ratable right to receive dividends, when, as and if
declared by the board of directors out of funds legally available
therefor and only after payment of, or provision for, full dividends on
all outstanding shares of any series of preferred stock and after we have
made provision for any required sinking or purchase funds for series of
preferred stock.
The shares of new common stock outstanding are fully paid and
non-assessable.
DESCRIPTION OF OUR PREFERRED STOCK
The preferred stock may be issued, from time to time, in one or more
series, and our board of directors, without further approval of the
shareholders, is authorized to fix the dividend rights and terms, redemption
rights and terms, liquidation preferences, conversion rights, voting rights and
sinking fund provisions applicable to each series of preferred stock. If we
issue a series of preferred stock in the future that has voting rights or
preferences over the new common stock with respect to the payment of dividends
and upon our liquidation, dissolution or winding up, the rights of the holders
of the new common stock offered may be adversely affected. The issuance of
shares of preferred stock could be used in an attempt to prevent an acquisition
of us. We have no present intention to issue any shares of preferred stock.
LIMITATION OF DIRECTOR LIABILITY
Our articles of incorporation contain a provision that limits the liability
of our directors as permitted under Texas law. The provision eliminates the
liability of a director to us or our shareholders for monetary damages for
negligent or grossly negligent acts or omissions in the director's capacity as a
director. The provision does not affect the liability of a director
- for breach of his duty of loyalty to us or to our shareholders,
- for acts or omissions not in good faith or that involve intentional
misconduct or a knowing violation of law,
- for acts or omissions for which the liability of a director is expressly
provided by an applicable statute, or
- in respect of any transaction from which a director received an improper
personal benefit.
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<PAGE> 88
Under the articles of incorporation, the liability of directors will be further
limited or eliminated without action by shareholders if Texas law is amended to
further limit or eliminate the personal liability of directors.
OTHER FEATURES OF OUR AMENDED AND RESTATED ARTICLES OF INCORPORATION
In accordance with Section 1123(a)(6) of the United States Bankruptcy Code,
our amended and restated articles of incorporation prohibit the issuance of any
shares of non-voting equity securities. The shares of common stock resulting
after the effectiveness of our amended and restated articles of incorporation
are referred to in this prospectus as the new common stock.
In addition, our amended and restated articles of incorporation deny
cumulative voting in the election of directors and provide that if an
affirmative vote of shareholders is required for any matter, the required vote
shall be the greater of the vote required under the Texas Business Corporation
Act and the vote required under the amended and restated articles of
incorporation.
DIVIDENDS
Our standby loan agreement prohibits our paying of dividends, except share
dividends, until all principal and interest has been paid, except as otherwise
required in the plan of reorganization. Our plan of reorganization requires us
to pay shareholders of record on February 7, 2000, 20% of the proceeds available
from the Hicks Muse lawsuit after expenses and 40% of any proceeds from the
disposition of our interest in Coho Anaguid, Inc. or the disposition of
substantial assets of Coho Anaguid, Inc.; these payments are expressly permitted
by the standby loan agreement. For more information about these potential
payments, see the section of this prospectus called "The Plan of
Reorganization -- 3. Old Shareholders."
Our new credit facility contains similar provisions prohibiting our payment
of dividends.
REGISTRATION AND NOMINATION RIGHTS
Under our plan of reorganization we entered into a registration rights
agreement with the principal holders of our old bonds under which the shares of
new common stock issued to them under our plan of reorganization will be
registered under federal securities laws under prescribed circumstances.
TRANSFER AGENT AND REGISTRAR
The transfer agents for the new common stock are ChaseMellon Shareholder
Services L.L.C. and Montreal Trust Company of Canada and the registrar is
ChaseMellon Shareholder Services L.L.C.
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<PAGE> 89
DILUTION
Under our plan of reorganization, our shareholders as of February 7, 2000,
the date the bankruptcy court entered its order approving our disclosure
statement, received 640,088 shares of the new common stock and the holders of
old bonds received 15,362,107 shares of the new common stock. Before taking into
account shares issued under this rights offering or the standby loan, the
bondholder group received 96%, and the shareholders received 4%, of the total
number of outstanding shares of new common stock. These percentages may not be
exact, as cash is being distributed in lieu of fractional shares upon the
exchange of old common stock for new common stock. THESE PERCENTAGES ARE SUBJECT
TO DILUTION UNDER SOME FEATURES OF OUR PLAN OF REORGANIZATION, AS DISCUSSED
BELOW.
Under the rights offering, each of our shareholders as of the record date
of this rights offering is being given the opportunity to purchase additional
new common stock at an initial purchase price of $10.40 per share. For each
share of old common stock held as of the record date of this rights offering, a
shareholder will have the right to buy initially 0.338 shares of new common
stock. To the extent the shareholders do not purchase their allocable portion of
these offered shares, those shareholders who do purchase their allocable portion
of these offered shares may elect to purchase any number of additional shares of
the new common stock, up to the maximum number of shares offered under this
rights offering, for $10.40 per share. To the extent some shares of the new
common stock were allocated for purchase by the shareholders but were not
purchased by them, those unsubscribed shares will be distributed to the fully
subscribed shareholders who have elected to purchase the unsubscribed shares on
a pro rata basis.
The total number of shares offered to shareholders under the rights
offering, including any "gross-up" shares as described below, is 11,121,343. If
all of these shares are sold under the rights offering, excluding the additional
10,000 shares of new common stock we are registering in this prospectus to
account for the effect of rounding of rights being granted to the shareholders
but taking into account the shares to be issued under the standby loan, the
shareholders will have received a total of 11,761,481 shares of the new common
stock, constituting 37.1% of the total number of shares outstanding, and the
bondholder group will have received 15,362,107 shares of the new common stock,
constituting 48.5% of the total number of shares outstanding. We do not know
whether we will be able to sell all of the shares offered under the rights
offering.
Under the terms of the standby loan, we must issue to the standby lenders a
number of shares sufficient to give them a specified percentage of the total
outstanding shares of the new common stock as of the effective date of the
confirmation of our plan of reorganization. Because we borrowed $72 million on
the effective date, that percentage will be 14.4%.
Also under the terms of the standby loan, any shares issued to the standby
lenders will dilute the percentage ownership but not the actual number of shares
issued to the bondholder group and the shareholders in exchange for their shares
of the old common stock. However, shares issued to the standby lenders may not
dilute the percentage ownership issued to the shareholders for shares purchased
under the rights offering. To assure that these results are achieved, we will
issue additional shares of the new common stock to the purchasers under the
rights offering sufficient to assure those purchasers that they will maintain
their relative percentage ownership interests before taking into account the
shares to be issued under the standby loan. This "gross-up" feature will have
the effect of further diluting the percentage ownership interests represented by
shares issued to the shareholders in exchange for their old common stock and of
the bondholder group in exchange for their claims. It will also have the effect
of reducing the per-share purchase price under this rights offering because the
gross-up feature will not require those purchasing shares under this rights
offering to make any additional payments for the additional gross-up shares.
Because the number of shares that will be purchased under the rights
offering cannot be predicted, it is not possible to state accurately the
relative percentage ownership interests that ultimately will be held by the
shareholders who elect not to participate in the rights offering, the bondholder
group and the standby
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<PAGE> 90
lenders. However, for illustrative purposes, the following table indicates what
those percentages would be under the stated assumptions.
<TABLE>
<CAPTION>
ASSUMING 20% OF THE
ASSUMING ALL SHARES SHARES OF NEW
OF NEW COMMON STOCK COMMON STOCK
OFFERED IN THIS RIGHTS OFFERED IN THIS RIGHTS
OFFERING ARE PURCHASED OFFERING ARE PURCHASED
---------------------- ----------------------
<S> <C> <C>
Shareholders (solely in exchange for their shares of
the old common stock)............................... 2.0% 3.0%
Bondholder group...................................... 48.5% 72.8%
Purchasers under this rights offering................. 35.1% 9.8%
Standby lenders....................................... 14.4% 14.4%
</TABLE>
LEGAL MATTERS
Legal matters related to the rights offered by this prospectus are being
passed upon for us by Fulbright & Jaworski L.L.P., Dallas, Texas.
INDEPENDENT AUDITORS
Our consolidated financial statements as of December 31, 1998 and 1999 and
for each of the three years in the period ended December 31, 1999 included in
this prospectus have been audited by Arthur Andersen LLP, independent auditors,
as set forth in their reports appearing in this prospectus.
ENGINEERS
The historical reserve information prepared by Ryder Scott Company and
Sproule Associates, Inc. included in this prospectus has been included in
reliance upon the authority of each firm as experts with respect to matters
contained in their respective reserve reports.
WHERE YOU CAN FIND MORE INFORMATION
We file annual, quarterly and current reports, proxy statements and other
information with the Securities and Exchange Commission. You may read, or copy,
any document we file at the public reference room maintained by the Commission
at 450 Fifth Street, N.W., Washington, D.C. 20549, and at the following regional
offices of the Commission: New York Regional Office, Seven World Trade Center,
13th Floor, New York, New York 10048; and Chicago Regional Office, Citicorp
Center, 5000 West Madison Street, Suite 1400, Chicago, Illinois 60661. Copies of
this information can be obtained by mail from the Commission's Public Reference
Branch at 450 Fifth Street, N.W., Washington, D.C. 20549. In addition, our
filings with the Commission are also available to the public on the Commission's
internet website at http://www.sec.gov.
We have filed with the Commission a registration statement on Form S-1
under the Securities Act of 1933 with respect to the rights offered in this
rights offering and the shares of our new common stock to be issued upon
exercise of the rights or otherwise under this rights offering. This prospectus
does not contain all of the information set forth in the registration statement
and its exhibits and schedules. Statements made by us in this prospectus as to
the contents of any contract, agreement or other document referred to in this
prospectus are not necessarily complete. For a more complete description of
these contacts, agreements or other documents, you should carefully read the
exhibits to the registration statement.
The registration statement, together with its exhibits and schedules, which
we filed with the Commission, may also be reviewed and copied at the public
reference facilities of the Commission located at the addresses set forth above.
Please call the Commission at 1-800-SEC-0330 for further information on its
public reference facilities.
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INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
AUDITED CONSOLIDATED FINANCIAL STATEMENTS:
Report of Independent Public Accountants.................... F-2
Consolidated Balance Sheets, December 31, 1998 and 1999..... F-3
Consolidated Statements of Operations, Years Ended December
31, 1997, 1998 and 1999................................... F-4
Consolidated Statements of Shareholders' Equity, Years Ended
December 31, 1997, 1998
and 1999.................................................. F-5
Consolidated Statements of Cash Flows, Years Ended December
31, 1997, 1998 and 1999................................... F-6
Notes to Consolidated Financial Statements, Years Ended
December 31, 1997, 1998 and 1999.......................... F-7
</TABLE>
F-1
<PAGE> 92
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Shareholders of
Coho Energy, Inc. (debtor-in-possession)
We have audited the accompanying consolidated balance sheets of Coho
Energy, Inc. (a Texas corporation debtor-in-possession) and subsidiaries as of
December 31, 1998 and 1999, and the related consolidated statements of
operations, shareholders' investments and cash flows for each of the three years
in the period ended December 31, 1999. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits 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 statements presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Coho Energy, Inc. and
subsidiaries as of December 31, 1998 and 1999, and the results of our operations
and our cash flows for each of the three years in the period ended December 31,
1999 in conformity with generally accepted accounting principles.
The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. As discussed in Note 2 to the
financial statements, the Company has suffered recurring losses and negative
cash flows from operations, has received a notice of default from its lenders
under its existing bank credit facility and is in default under the terms of its
8 7/8% Senior Subordinated notes, that raise substantial doubt about the
Company's ability to continue as a going concern. On August 23, 1999, the
Company, together with certain of its wholly owned subsidiaries, filed a
voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code and
is currently operating as a debtor-in-possession subject to the bankruptcy
court's supervision and orders. As discussed in Note 2 to the financial
statements, management believes that it may not be possible to satisfy all
claims against the Company if the reorganization plan filed with the Bankruptcy
Court is not approved. The financial statements do not include any adjustments
relating to the recoverability and classification of asset carrying amounts or
the amount and classification of liabilities that might result should the
Company be unable to continue as a going concern.
Arthur Andersen LLP
Dallas, Texas
March 3, 2000 (Except with respect to
the matters discussed in Note 15, as to
which the date is April 17, 2000.)
F-2
<PAGE> 93
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31
---------------------
1998 1999
--------- ---------
<S> <C> <C>
Current assets
Cash and cash equivalents................................. $ 6,901 $ 18,805
Cash in escrow............................................ 1,505 78
Accounts receivable, principally trade.................... 9,960 11,158
Other current assets...................................... 948 1,428
--------- ---------
19,314 31,469
Property and equipment, at cost net of accumulated depletion
and depreciation, based on full cost accounting method
(note 3).................................................. 324,574 311,788
Other assets................................................ 6,180 5,544
--------- ---------
$ 350,068 $ 348,801
========= =========
LIABILITIES AND SHAREHOLDERS' DEFICIT
Liabilities not subject to compromise:
Current liabilities
Accounts payable, principally trade.................... $ 5,577 $ 1,294
Accrued liabilities and other payables................. 6,656 3,751
Accrued interest....................................... 7,302 10,175
Accrued state income taxes payable..................... 4,045 --
Current portion of long term debt (note 4)............. 384,031 --
--------- ---------
Total current liabilities......................... 407,611 15,220
Liabilities subject to compromise:
Accounts payable, principally trade....................... -- 4,166
Accrued liabilities and other payables.................... -- 5,373
Accrued interest.......................................... -- 21,379
Accrued state income taxes payable........................ -- 4,136
Current portion of long term debt (note 4)................ -- 388,685
--------- ---------
Total liabilities subject to compromise........... -- 423,739
--------- ---------
407,611 438,959
--------- ---------
Commitments and contingencies (note 9)...................... 3,700 1,800
Shareholders' deficit (note 7)
Preferred stock, par value $0.01 per share
Authorized 10,000,000 shares, none issued..............
Common stock, par value $0.01 per share
Authorized 50,000,000 shares
Issued and outstanding 25,603,512 shares............... 256 256
Additional paid-in capital................................ 137,812 137,812
Retained deficit.......................................... (199,311) (230,026)
--------- ---------
Total shareholders' deficit....................... (61,243) (91,958)
--------- ---------
$ 350,068 $ 348,801
========= =========
</TABLE>
See accompanying Notes to Consolidated Financial Statements
F-3
<PAGE> 94
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-------------------------------
1997 1998 1999
-------- --------- --------
<S> <C> <C> <C>
Operating revenues
Net crude oil and natural gas production.................. $ 63,130 $ 68,759 $ 57,323
-------- --------- --------
Operating expenses
Crude oil and natural gas production...................... 13,747 23,475 18,218
Taxes on oil and gas production........................... 2,223 3,384 2,937
General and administrative (note 3)....................... 7,163 7,750 9,905
State income tax penalties................................ -- -- 1,048
Allowance for bad debt.................................... -- 894 --
Unsuccessful transaction costs............................ -- 2,129 --
Depletion and depreciation................................ 19,214 28,135 13,702
Writedown of crude oil and gas properties................. -- 188,000 5,433
-------- --------- --------
Total operating expenses.......................... 42,347 253,767 51,243
-------- --------- --------
Operating income (loss)..................................... 20,783 (185,008) 6,080
-------- --------- --------
Other income and expenses
Interest and other income................................. 646 214 246
Interest expense (note 4)................................. (11,120) (32,935) (33,944)
-------- --------- --------
(10,474) (32,721) (33,698)
-------- --------- --------
Earnings (loss) from operations before reorganization costs
and income taxes.......................................... 10,309 (217,729) (27,618)
-------- --------- --------
Reorganization costs
Professional fees......................................... -- -- 3,319
Interest income........................................... -- -- (210)
Other..................................................... -- -- 14
-------- --------- --------
-- -- 3,123
-------- --------- --------
Earnings (loss) from operations before income taxes......... 10,309 (217,729) (30,741)
-------- --------- --------
Income taxes (note 5)
Current (benefit) expense................................. 163 4,111 (26)
Deferred (benefit) expense................................ 3,858 (18,494) --
-------- --------- --------
4,021 (14,383) (26)
-------- --------- --------
Net earnings (loss)......................................... $ 6,288 $(203,346) $(30,715)
======== ========= ========
Basic earnings (loss) per common share (note 1)............. $ .29 $ (7.94) $ (1.20)
======== ========= ========
Diluted earnings (loss) loss per common share (note 1)...... $ .28 $ (7.94) $ (1.20)
======== ========= ========
</TABLE>
See accompanying Notes to Consolidated Financial Statements
F-4
<PAGE> 95
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
NUMBER OF
COMMON ADDITIONAL RETAINED
SHARES COMMON PAID-IN EARNINGS
OUTSTANDING STOCK CAPITAL (DEFICIT) TOTAL
----------- ------ ---------- --------- ---------
<S> <C> <C> <C> <C> <C>
Balance at December 31, 1996................. 20,347,126 $203 $ 83,516 $ (2,253) $ 81,466
Issued on
(i) Exercise of Employee Stock
Options............................... 256,386 3 1,733 -- 1,736
(ii) Public offering of common stock.... 5,000,000 50 49,173 -- 49,223
(iii) Warrants.......................... -- -- 3,390 -- 3,390
Net earnings............................... -- -- -- 6,288 6,288
---------- ---- -------- --------- ---------
Balance at December 31, 1997................. 25,603,512 256 137,812 4,035 142,103
Net loss................................... -- -- -- (203,346) (203,346)
---------- ---- -------- --------- ---------
Balance at December 31, 1998................. 25,603,512 256 137,812 (199,311) (61,243)
Net loss................................... -- -- -- (30,715) (30,715)
---------- ---- -------- --------- ---------
Balance at December 31, 1999................. 25,603,512 $256 $137,812 $(230,026) $ (91,958)
========== ==== ======== ========= =========
</TABLE>
See accompanying Notes to Consolidated Financial Statements
F-5
<PAGE> 96
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
--------------------------------
1997 1998 1999
--------- --------- --------
<S> <C> <C> <C>
Cash flows from operating activities
Net earnings (loss)...................................... $ 6,288 $(203,346) $(30,715)
Adjustments to reconcile net earnings (loss) to net cash
provided (used) by operating activities:
Depletion and depreciation............................... 19,214 28,135 13,702
Writedown of crude oil and natural gas properties........ -- 188,000 5,433
Deferred income taxes.................................... 3,858 (18,488) --
Amortization of debt issue costs and other............... 591 1,756 679
Changes in:
Cash in escrow........................................... -- (1,505) 1,427
Accounts receivable...................................... 1,160 (1,150) (1,194)
Other assets............................................. (351) (628) (454)
Accounts payable and accrued liabilities................. 4,346 7,917 25,981
Investment in marketable securities...................... 1,962 -- --
--------- --------- --------
Net cash provided by operating activities.................. 37,068 691 14,859
--------- --------- --------
Cash flows from investing activities
Acquisitions............................................. (259,355) -- --
Property and equipment................................... (72,667) (70,143) (6,349)
Changes in accounts payable and accrued liabilities
related to exploration and development................ 3,559 (2,986) (1,186)
Proceeds on sale of property and equipment............... -- 61,452 --
--------- --------- --------
Net cash used in investing activities...................... (328,463) (11,677) (7,535)
--------- --------- --------
Cash flows from financing activities
Increase in long term debt............................... 402,894 76,113 4,600
Debt issuance costs...................................... (4,275) -- --
Repayment of long term debt.............................. (155,989) (62,043) (20)
Proceeds from exercised stock options.................... 1,495 -- --
Issuance of common stock................................. 49,223 -- --
--------- --------- --------
Net cash provided by financing activities.................. 293,348 14,070 4,580
--------- --------- --------
Net increase in cash and cash equivalents.................. 1,953 3,084 11,904
Cash and cash equivalents at beginning of year............. 1,864 3,817 6,901
--------- --------- --------
Cash and cash equivalents at end of year................... $ 3,817 $ 6,901 $ 18,805
========= ========= ========
Cash paid (received) during the period for:
Interest................................................. $ 7,774 $ 28,426 $ 8,936
Income taxes............................................. $ 603 $ (256) $ 33
Reorganization costs (including prepayments)............. $ -- $ -- $ 3,352
Reorganization costs (interest income)................... $ -- $ -- $ (210)
</TABLE>
See accompanying Notes to Consolidated Financial Statements
F-6
<PAGE> 97
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999
(TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization
Coho Energy, Inc. ("CEI") was incorporated in June 1993 as a Texas
corporation and conducts a majority of its operations through its subsidiary,
Coho Resources, Inc. ("CRI"), and its subsidiaries (collectively the "Company").
Principles of Presentation
These consolidated financial statements have been prepared in conformity
with generally accepted accounting principles as presently established in the
United States and include the accounts of CEI as successor to CRI, and its
subsidiaries. All significant intercompany balances and transactions have been
eliminated. Certain reclassifications have been made to the prior year
statements to conform with the current year presentation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Substantially all of the Company's exploration, development and production
activities are conducted in the United States and Tunisia jointly with others
and, accordingly, the financial statements reflect only the Company's
proportionate interest in such activities.
Cash Equivalents
For purposes of reporting cash flows, cash and cash equivalents include
cash and highly liquid debt instruments purchased with an original maturity of
three months or less.
Cash in Escrow
Substantially all of the cash at December 31, 1998 was held pending
completion of the April 1999 post closing review by the buyer of the Monroe
field natural gas properties, as discussed in Note 6.
Accounts Receivable
The Company performs ongoing reviews with respect to accounts receivable
and maintains an allowance for doubtful accounts receivable ($929,000 and
$885,000 at December 31, 1998 and 1999, respectively) based on expected
collectibility.
Crude Oil and Natural Gas Properties
The Company's crude oil and natural gas producing activities, substantially
all of which are in the United States, are accounted for using the full cost
method of accounting. Accordingly, the Company capitalizes all costs incurred in
connection with the acquisition of crude oil and natural gas properties and with
the exploration for and development of crude oil and natural gas reserves,
including related gathering facilities. All internal corporate costs relating to
crude oil and natural gas producing activities are expensed as incurred.
Proceeds from disposition of crude oil and natural gas properties are accounted
for as a
F-7
<PAGE> 98
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
reduction in capitalized costs, with no gain or loss recognized unless such
dispositions involve a significant alteration in the depletion rate in which
case the gain or loss is recognized.
Depletion of crude oil and natural gas properties is provided using the
equivalent unit-of-production method based upon estimates of proved crude oil
and natural gas reserves and production which are converted to a common unit of
measure based upon their relative energy content. Unproved crude oil and natural
gas properties are not amortized but are individually assessed for impairment.
The costs of any impaired properties are transferred to the balance of crude oil
and natural gas properties being depleted. Estimated future site restoration and
abandonment costs are charged to earnings at the rate of depletion of proved
crude oil and natural gas reserves and are included in accumulated depletion and
depreciation.
In accordance with the full cost method of accounting, the net capitalized
costs of crude oil and natural gas properties as well as estimated future
development, site restoration and abandonment costs are not to exceed their
related estimated future net revenues discounted at 10%, net of tax
considerations, plus the lower of cost or estimated fair value of unproved
properties.
Impairment of Long-Lived Assets
During fiscal year 1996, the Company adopted Statement of Financial
Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived-Assets To Be Disposed Of." The Company has
no long-lived assets which are subject to the impairment test requirements of
SFAS No. 121. The Company's only long-lived assets are oil and gas properties
which are subject to the full cost ceiling test in accordance with the full cost
method of accounting, as discussed above.
Other Assets
Other assets generally include deferred financing charges which are
amortized over the term of the related financing under the straight line method.
Stock-Based Compensation
SFAS No. 123, "Accounting for Stock-Based Compensation," encourages, but
does not require, companies to record compensation cost for stock-based employee
compensation plans at fair value. The Company has chosen to continue to apply
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees," and related interpretations to account for stock-based compensation.
Accordingly, compensation cost for stock options is measured as the excess, if
any, of the quoted market price of the Company's stock at the date of the grant
over the amount an employee must pay to acquire the stock.
Earnings Per Common Share
The Company accounts for earnings per share ("EPS") in accordance with SFAS
No. 128, "Earnings Per Share." Under SFAS No. 128, no dilution for any
potentially dilutive securities is included for basic EPS. Diluted EPS are based
upon the weighted average number of common shares outstanding including
F-8
<PAGE> 99
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
common shares plus, when their effect is dilutive, common stock equivalents
consisting of stock options and warrants.
<TABLE>
<CAPTION>
1997 1998 1999
---------------------------------- ------------------------------------ ---------------------------
COMMON COMMON COMMON
INCOME SHARES EPS LOSS SHARES EPS LOSS SHARES
-------------- ---------- ---- -------------- ---------- ------ -------------- ----------
(IN THOUSANDS) (IN THOUSANDS) (IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Basic Earnings per
Share................... $6,288 21,692,804 $.29 $(203,346) 25,603,512 $(7.94) $(30,715) 25,603,512
==== ======
Stock Options............. 641,099 -- --
------ ---------- --------- ---------- -------- ----------
Diluted Earnings Per
Share................... $6,288 22,333,903 $.28 $(203,346) 25,603,512 $(7.94) $(30,715) 25,603,512
====== ========== ==== ========= ========== ====== ======== ==========
<CAPTION>
1999
------
EPS
------
<S> <C>
Basic Earnings per
Share................... $(1.20)
======
Stock Options.............
Diluted Earnings Per
Share................... $(1.20)
======
</TABLE>
Basic EPS were computed by dividing net income by the weighted average
number of shares of common stock outstanding during the year. Diluted EPS were
calculated based upon the weighted average number of common shares outstanding
during the year including common stock equivalents, consisting of stock options
and warrants, when their effect is dilutive. In 1998 and 1999, conversion of the
stock equivalents would have been anti-dilutive and, therefore, was not
considered in diluted EPS.
Income Taxes
The Company accounts for income taxes in accordance with SFAS No. 109,
"Accounting for Income Taxes." Under the asset and liability method of SFAS No.
109, deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled.
Hedging Activities
Periodically, the Company enters into futures contracts which are traded on
the stock exchanges in order to fix the price on a portion of its crude oil and
natural gas production. Changes in the market value of crude oil and natural gas
futures contracts are reported as an adjustment to revenues in the period in
which the hedged production or inventory is sold. The gain or loss on the
Company's hedging transactions is determined as the difference between the
contract price and a reference price, generally closing prices on the New York
Mercantile Exchange.
The Company will be required to adopt SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" for fiscal year ended 2000. If
the Company had adopted SFAS No. 133 during 1999, there would be no effect on
the Company's financial statements as the Company had no hedges outstanding at
December 31, 1999. Although the future impact of adopting SFAS No. 133 has not
been determined yet, the Company believes that the impact will not be material.
Revenue Recognition Policy
Revenues generally are recorded when products have been delivered and
services have been performed.
Environmental Expenditures
Environmental expenditures that relate to current operations are expensed
or capitalized as appropriate. Expenditures which improve the condition of a
property as compared to the condition when
F-9
<PAGE> 100
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
originally constructed or acquired or prevent environmental contamination are
capitalized. Expenditures which relate to an existing condition caused by past
operations, and do not contribute to future operations, are expensed. The
Company accrues remediation costs when environmental assessments and/or remedial
efforts are probable and the cost can be reasonably estimated.
Business Segments
In June 1997, the Financial Accounting Standards Board issued SFAS No. 131,
"Disclosure about Segments of an Enterprise and Related Information", which
requires information to be reported in segments. The Company currently operates
in a single reportable segment; therefore, no additional disclosure will be
required.
2. BANKRUPTCY PROCEEDINGS
On August 23, 1999 (the "Petition Date"), the Company and its wholly-owned
subsidiaries, Coho Resources, Inc., Coho Oil & Gas, Inc., Coho Exploration,
Inc., Coho Louisiana Production Company and Interstate Natural Gas Company,
filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy
Code (the "Chapter 11 filing") in the U.S. District Court for the Northern
District of Texas (the "Bankruptcy Court"). The Company is currently operating
as a debtor-in-possession subject to the Bankruptcy Court's supervision and
orders. Schedules were filed by the Company on September 21, 1999 with the
Bankruptcy Court, which were subsequently amended on December 14, 1999, setting
forth the unaudited, and in some cases estimated, assets and liabilities of the
Company as of the date of the Chapter 11 filing, as shown by the Company's
accounting records.
The bankruptcy petitions were filed in order to facilitate the
restructuring of the Company's long term debt and to protect the Company while
it develops a solution to its capital needs with the banks, bondholders and
potential investors. On November 30, 1999, the Company filed a plan of
reorganization with the Bankruptcy Court. On February 15, 2000, the Company and
the Official Unsecured Creditors Committee filed the First Amended and Restated
Joint Plan of Reorganization (which, as amended, is referred to as the "Plan of
Reorganization") with the Bankruptcy Court. At a hearing on February 4, 2000,
the Bankruptcy Court approved the Company's disclosure statement (which, as
amended is referred to as the "Disclosure Statement"). In that hearing, the
Bankruptcy Court also scheduled the confirmation hearing to consider the Plan of
Reorganization for March 15, 2000 ("Confirmation Hearing"). The Disclosure
Statement and Plan of Reorganization were mailed to holders of interests in the
Chapter 11 filing for a vote on February 14, 2000. The Company has requested
that all votes be submitted by March 10, 2000. The Plan of Reorganization sets
forth the means for satisfying claims, including liabilities subject to
compromise, and interests in the Company. The Plan of Reorganization includes
the cancellation of the existing common stock of the Company and the issuance of
a new class of common stock in exchange for such existing common stock and debt
of the Company which materially dilutes the current equity interests.
The ability of the Company to effect a successful reorganization will
depend upon the Company's ability to obtain approval for the Plan of
Reorganization. At this time, it is not possible to predict the outcome of the
bankruptcy proceedings, in general, or the effect on the business of the Company
or on the interests of creditors or shareholders. The Company believes, however,
that it may not be possible to satisfy in full all of the claims against the
Company if the Plan of Reorganization is not approved. As a result of the
bankruptcy filing, all of the Company's liabilities incurred before the Petition
Date, including secured debt, are subject to compromise. Under the Bankruptcy
Code, payment of these liabilities may not be made except under a Plan of
Reorganization or Bankruptcy Court approval.
F-10
<PAGE> 101
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The December 31, 1999 financial statements do not include any adjustments
relating to the recoverability and classification of asset carrying amounts
(including $311.8 million in net property, plant and equipment) or the amount
and classification of liabilities that might result should the Company be unable
to continue as a going concern. The ability of the Company to continue as a
going concern is dependent upon confirmation of a plan of reorganization,
adequate sources of capital and the ability to sustain positive results of
operations and cash flows sufficient to continue to explore for and develop oil
and gas reserves. These factors, among others, raise substantial doubt
concerning the ability of the Company to continue as a going concern.
As a result of the Chapter 11 filing, the Company has incurred and will
continue to incur significant costs for professional fees as the Plan of
Reorganization is developed. The Company has incurred approximately $3.1 million
in reorganization costs during 1999 which relate to professional fees for
consultants and attorneys assisting in the negotiations associated with
financing and reorganization alternatives, partially offset by interest income
earned since the Petition Date on accumulated cash.
The Chapter 11 filing included the Company's wholly-owned subsidiaries Coho
Resources, Inc., Coho Oil & Gas, Inc., Coho Exploration, Inc., Coho Louisiana
Production Company and Interstate Natural Gas Company. The following information
summarizes the combined results of operations for the Company and these
subsidiaries. This information has been prepared on the same basis as the
consolidated financial statements.
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31, 1999
-----------------
<S> <C>
Current assets.............................................. $ 30,929
Accounts receivable from affiliates......................... 3,023
Property and equipment...................................... 309,262
Other assets................................................ 5,515
--------
Total assets................................................ $348,729
========
Current liabilities not subject to compromise............... $ 15,149
Liabilities subject to compromise........................... 423,739
Commitments and contingencies............................... 1,800
Shareholder's equity........................................ (91,959)
--------
$348,729
========
Operating revenues.......................................... $ 57,323
Operating expenses.......................................... $ 48,923
Net loss.................................................... $(30,716)
</TABLE>
3. PROPERTY AND EQUIPMENT
<TABLE>
<CAPTION>
DECEMBER 31
------------------------
1998 1999
--------- ---------
<S> <C> <C>
Crude oil and natural gas leases and rights including
exploration, development and equipment thereon, at cost... $ 678,547 $ 684,896
Accumulated depletion and depreciation...................... (353,973) (373,108)
--------- ---------
$ 324,574 $ 311,788
========= =========
</TABLE>
Overhead expenditures directly associated with exploration for and
development of crude oil and natural gas reserves have been capitalized in
accordance with the accounting policies of the Company.
F-11
<PAGE> 102
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Such charges totaled $4,081,000, $5,749,000 and $-0- in 1997, 1998 and 1999,
respectively. Due to the cessation of exploration and development of crude oil
and natural gas reserves in 1998, all overhead expenditures during 1999 have
been charged to general and administrative expense.
During 1997, 1998 and 1999, the Company did not capitalize any interest or
other financing charges on funds borrowed to finance unproved properties or
major development projects.
Unproved crude oil and natural gas properties totaling $58,854,000 and
$56,296,000 at December 31, 1998 and 1999, respectively, have been excluded from
costs subject to depletion. These costs are anticipated to be included in costs
subject to depletion within the next five years.
Depletion and depreciation expense per equivalent barrel of production was
$4.69, $4.38 and $3.63 in 1997, 1998 and 1999, respectively.
4. LONG-TERM DEBT
<TABLE>
<CAPTION>
1998 1999
--------- ---------
<S> <C> <C>
Revolving credit facility................................... $ 235,000 $ 239,600
8 7/8% Senior Subordinated Notes Due 2007................... 150,000 150,000
Other....................................................... 24 3
--------- ---------
385,024 389,603
Unamortized original issue discount on senior subordinated
notes..................................................... (993) (918)
Current maturities on long term debt........................ (384,031) (388,685)
--------- ---------
$ -- $ --
========= =========
</TABLE>
Revolving Credit Facility
In August 1992, the Company established a revolving credit and term loan
facility with a group of international and domestic financial institutions. The
agreement, as amended and restated (the "Existing Bank Group Loan Agreement"),
provided a maximum commitment amount available to the Company ("Borrowing Base")
of $242 million for general corporate purposes at December 31, 1998. Outstanding
advances as of December 31, 1998, were $235 million, and increased to $239.6
million as of January 5, 1999. The average effective interest rates for 1998 and
1999 were 7.38% and 9.91%, respectively. The Existing Bank Group Loan Agreement,
which permits advances and repayments, terminates January 2, 2003. The repayment
of all advances is guaranteed by Coho Energy, Inc. and outstanding advances are
secured by substantially all of the assets of the Company.
Loans under the Existing Bank Group Loan Agreement up to $220 million bear
interest, at the option of the Company, at the bank prime rate or a Eurodollar
rate plus a maximum of 1.5% (currently 1.5%), with amounts outstanding in excess
of $220 million bearing interest, at the option of the Company at (i) the prime
rate plus 1.0% or (ii) LIBOR plus 2.50%. Loans under the Existing Bank Group
Loan Agreement are secured by a lien on substantially all of the Company's crude
oil and natural gas properties and the capital stock of the Company's wholly
owned subsidiaries. If the outstanding amount of the loan exceeds the Borrowing
Base at any time, the Company is required to either (a) provide collateral with
value equal to such excess, (b) prepay, without premium or penalty, such excess
plus accrued interest or (c) prepay the principal amount of the notes equal to
such excess in five (5) equal monthly installments provided the entire excess
shall be paid prior to the immediately succeeding redetermination date. The fee
on the portion of the unused credit facility is .375% per annum. The commitment
fee applicable to increases from time to time in the Borrowing Base is .375% of
the incremental Borrowing Base amount.
F-12
<PAGE> 103
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
On February 22, 1999, the Company was informed by the lenders under the
Company's Existing Bank Group Loan Agreement that its borrowing base was reduced
to $150 million effective January 31, 1999 creating an over advance of $89.6
million under the new Borrowing Base. The Company was unable to cure the over
advance as required by the Existing Bank Group Loan Agreement by March 2, 1999
by either (a) providing collateral with value and quantity in amounts equal to
such excess, (b) prepaying, without premium or penalty, such excess plus accrued
interest or (c) paying the first of five equal monthly installments to repay the
over advance. The Company has received written notice from the lenders under the
Existing Bank Group Loan Agreement that it is in default under the terms of the
Existing Bank Group Loan Agreement and the lenders reserved all rights, remedies
and privileges as a result of the payment default. Additionally, the Company was
unable to pay the second, third, fourth and fifth installments, which were due
at the beginning of April, May, June and July 1999, respectively, and has been
unable to make interest payments when due, although the Company has made
aggregate interest payments of $4.3 million during March, April, May, July and
December 1999. As a result of the payment defaults, the lenders accelerated the
full amount outstanding under the Existing Bank Group Loan Agreement. Advances
under the Existing Bank Group Loan Agreement and the past due interest payments
bear interest at the default interest rate of prime plus 4%. The outstanding
advances of $239.6 million as of December 31, 1999 have been included in
Liabilities Subject to Compromise as of December 31, 1999. The total arrearage
related to the installment payments due on the over advance and past due
interest was approximately $108.8 million as of December 31, 1999, including
approximately $19.2 million of past due interest ($10.2 million included in
Liabilities Not Subject to Compromise) and $89.6 million related to installments
due on the over advance.
The Existing Bank Group Loan Agreement contains certain financial and other
covenants including, among other covenants, (i) the maintenance of minimum
amounts of shareholder's equity, (ii) maintenance of minimum ratios of cash flow
to interest expense as well as current assets to current liabilities, (iii)
limitations on the Company's and CRI's ability to incur additional debt, and
(iv) restrictions on the payment of dividends. At December 31, 1999, the Company
was not in compliance with the shareholder's equity, cash flow to interest
expense and current assets to current liabilities covenants.
8 7/8% Senior Subordinated Notes
On October 3, 1997, the Company completed a sale to the public of $150
million of 8 7/8% Senior Subordinated Notes due 2007 ("Existing Bonds").
Proceeds of the offering, net of offering costs, were approximately $144.5
million. The proceeds from this offering, together with the proceeds from the
common stock offering discussed in Note 7, were used to repay indebtedness
outstanding under the Existing Bank Group Loan Agreement and for general
corporate purposes.
The Existing Bonds are unsecured senior subordinated obligations of the
Company and rank pari passu in right of payment with all existing and future
senior subordinated indebtedness of the Company. The Existing Bonds mature on
October 15, 2007 and bear interest from October 3, 1997 at the rate of 8 7/8%
per annum payable semi-annually, commencing on April 15, 1998. Certain
subsidiaries of the Company issued guarantees of the Existing Bonds on a senior
subordinated basis.
The indenture issued in conjunction with the Existing Bonds (the
"Indenture") contains certain covenants, including, among other covenants,
covenants that limit (i) indebtedness, (ii) restricted payments, (iii)
distributions from restricted subsidiaries, (iv) transactions with affiliates,
(v) sales of assets and subsidiary stock (including sale and leaseback
transactions), (vi) dividends and other payment restrictions affecting
restricted subsidiaries and (vii) mergers or consolidations.
F-13
<PAGE> 104
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company did not pay the April 15, 1999 interest payment of $6.7 million
due on its Existing Bonds and currently is in default under the terms of the
Indenture. Under the Indenture, the trustee under the Indenture by written
notice to the Company, or the holders of at least 25% in principal amount of the
outstanding Existing Bonds by written notice to the trustee and the Company, may
declare the principal and accrued interest on all the Existing Bonds due and
payable immediately. However, the Company may not pay the principal of, premium
(if any) or interest on the Existing Bonds so long as any required payments due
on the Existing Bank Group Loan Agreement remain outstanding and have not been
cured or waived. On May 19, 1999, the Company received a written notice of
acceleration from two holders of the Existing Bonds, which own in excess of 25%
in principal amount of the outstanding Existing Bonds. Both the accelerated
principal and the past due interest payment bore interest at the default rate of
9.875% (1% in excess of the stated rate for the Existing Bonds) from the date of
acceleration to the Petition Date. As a result of the Chapter 11 filing the
Company has ceased accruing interest on unsecured debt, including the Existing
Bonds. Approximately $5.7 million of additional Existing Bond interest expense,
including $2.2 million of Existing Bond interest expense that would have been
due on October 15, 1999, would have been recognized by the Company in 1999 if
not for the discontinuation of such interest expense accruals. All amounts
outstanding under the Existing Bonds as of December 31, 1999 have been included
in Liabilities Subject to Compromise.
Debt Repayments
Based on the balances outstanding and current default under the Existing
Bank Group Loan Agreement and the Existing Bonds indenture, estimated aggregate
principal repayments for each of the next five years are as follows:
2000 -- $389,603,000 and $0 thereafter.
5. INCOME TAXES
Deferred income taxes are recorded based upon differences between financial
statement and income tax basis of assets and liabilities. The tax effects of
these differences which give rise to deferred income tax assets and liabilities
at December 31, 1998 and 1999, were as follows:
<TABLE>
<CAPTION>
1998 1999
-------- -------
<S> <C> <C>
DEFERRED TAX ASSETS
Net operating loss carryforwards.......................... $ 25,283 $46,614
Property and equipment, due to differences in depletion,
depreciation, amortization and writedowns.............. 35,442 20,822
Alternative minimum tax credit carryforwards.............. 1,467 1,466
Employee benefits......................................... 58 61
Reorganization costs...................................... -- 1,062
Other..................................................... 182 502
-------- -------
Total gross deferred tax assets........................... 62,432 70,527
Less valuation allowance.................................. (62,432) (70,527)
-------- -------
Net deferred tax assets................................... -- --
-------- -------
DEFERRED TAX LIABILITIES
Property and equipment, due to differences in depletion,
depreciation, amortization and writedowns.............. -- --
-------- -------
NET DEFERRED TAX LIABILITY.................................. $ -- $ --
======== =======
</TABLE>
F-14
<PAGE> 105
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The valuation allowance for deferred tax assets as of December 31, 1998 and
1999 includes $2,051,000 and $248,314, respectively, related to Canadian
deferred tax assets.
To determine the amount of net deferred tax liability it is assumed no
future capital expenditures will be incurred other than the estimated
expenditures to develop the Company's proved undeveloped reserves.
The following table reconciles the differences between recorded income tax
expense and the expected income tax expense obtained by applying the basic tax
rate to earnings (loss) before income taxes:
<TABLE>
<CAPTION>
1997 1998 1999
------- --------- --------
<S> <C> <C> <C>
Earnings (loss) before income taxes................. $10,309 $(217,729) $(30,742)
======= ========= ========
Expected income tax expense (recovery)
(statutory rate - 34%)............................ $ 3,505 $ (74,028) $(10,452)
State taxes -- deferred............................. 552 (6,242) (913)
Federal benefit of state taxes...................... (188) 2,122 310
Permanent differences............................... -- -- 367
Expiring NOLs....................................... -- 1,043 2,390
Change in valuation allowance....................... 444 57,838 8,095
Other............................................... (293) 4,884 177
------- --------- --------
$ 4,020 $ (14,383) $ (26)
======= ========= ========
</TABLE>
At December 31, 1999, the Company had the following income tax
carryforwards available to reduce future years' income for tax purposes:
<TABLE>
<CAPTION>
EXPIRES AMOUNT
--------- --------
<S> <C> <C>
Net operating loss carryforwards for federal income tax
purposes.................................................. 2000 $ 4,253
2001 3,015
2002 211
2003 4,697
2004-2019 111,540
--------
$123,716
========
Operating loss carryforwards for Canadian income tax
purposes.................................................. 2000-2003 $ 653
========
Operating loss carryforwards for federal alternative minimum
tax purposes.............................................. 2010-2019 $ 71,973
========
Federal alternative minimum tax credit carryforwards........ -- $ 1,466
========
Operating loss carryforwards for Mississippi income tax
purposes.................................................. 2010-2014 $ 85,081
========
Operating loss carryforwards for Oklahoma income tax
purposes.................................................. 2012-2013 $ 45,290
========
</TABLE>
6. ACQUISITIONS AND DISPOSITIONS
Effective December 31, 1997, the Company acquired from Amoco Production
Company ("Amoco") interests in certain crude oil and natural gas properties
("Oklahoma Properties") located primarily in southern Oklahoma for cash
consideration of approximately $257.5 million and warrants to purchase one
million shares of common stock at $10.425 per share for a period of five years
valued at $3.4 million. The Oklahoma Properties are in more than 25,000 gross
acres concentrated in southern Oklahoma, including 14 major producing oil
fields. The aggregate purchase price was $267.8 million, including transaction
costs
F-15
<PAGE> 106
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
of approximately $1.9 million and assumed liabilities of $5 million. Investing
activities in the cash flow statement for the year ended December 31, 1997
related to this acquisition, exclude the noncash portions of the purchase price
of $3.4 million attributable to the warrants and $5 million for assumed
liabilities.
On December 2, 1998, the Company sold its natural gas assets, including its
natural gas properties and the related gas gathering systems, located in Monroe,
Louisiana to an unaffiliated third party for net proceeds of approximately $61.5
million. The proved reserves attributable to such natural gas properties were
approximately 94 billion cubic feet of natural gas and represented approximately
14% of the Company's year end 1997 proved reserves.
7. SHAREHOLDERS' EQUITY
On October 3, 1997, the Company completed the sale to the public of
5,000,000 shares of common stock at $10.50 per share. Proceeds of the offering,
net of offering costs, were approximately $49.2 million. The proceeds from this
offering, together with the proceeds from the Existing Bond offering discussed
in Note 4, were used to repay indebtedness outstanding under the Company's
Existing Bank Group Loan Agreement and for general corporate purposes.
In December 1997, the Company issued warrants, valued at $3,390,000, to
purchase one million shares of common stock at $10.425 per share for a period of
five years to Amoco Production Company as partial consideration for the purchase
of certain crude oil and natural gas properties discussed in Note 6.
8. STOCK-BASED COMPENSATION
Options to purchase the Company's common stock have been granted to
officers, directors and key employees pursuant to the Company's 1993 Stock
Option Plan and 1993 Non Employee Director Stock Option Plan, or assumed from
the reorganization of the Company's subsidiaries in 1993. The stock option plans
provide for the issuance of five year options with a three-year vesting period
and a grant price equal to or above market value. Some exceptions have been made
to provide immediate or shortened vesting periods as approved by the Company's
board of directors. All options outstanding available for grant pursuant to the
Company's existing stock option plans will be terminated according to the Plan
of Reorganization if the Plan of Reorganization is confirmed. A summary of the
status of the Company's stock option plans at December 31, 1997, 1998 and 1999
and changes during the years then ended follows:
<TABLE>
<CAPTION>
1997 1998 1999
--------------------- --------------------- ---------------------
WTD AVG WTD AVG WTD AVG
SHARES EX PRICE SHARES EX PRICE SHARES EX PRICE
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at January 1... 1,815,784 $5.55 2,823,815 $6.96 2,631,260 $6.98
Granted.................. 1,286,000 8.73 14,000 6.88 -- --
Exercised................ (256,386) 5.82 -- -- -- --
Canceled................. (21,583) 6.50 (75,000) 8.90 (30,000) 8.42
Expired.................. -- -- (131,555) 5.40 (363,159) 5.97
--------- ----- --------- ----- --------- -----
Outstanding at December
31....................... 2,823,815 6.96 2,631,260 6.98 2,238,101 7.13
--------- ----- --------- ----- --------- -----
Exercisable at December
31....................... 2,250,903 6.31 2,310,438 6.60 2,112,445 6.94
Available for grant at
December 31.............. 36,419 189,919 437,668
</TABLE>
F-16
<PAGE> 107
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Significant option groups outstanding at December 31, 1999 and related
weighted average price and life information follows:
<TABLE>
<CAPTION>
WTD
AVG
OPTIONS OPTIONS EXERCISE REMAINING
GRANT DATE OUTSTANDING EXERCISABLE PRICE LIFE (YEARS)
- ---------- ----------- ----------- -------- ------------
<S> <C> <C> <C> <C>
May 12, 1998.............................. 4,000 4,000 $ 6.88 4
December 2, 1997.......................... 361,000 240,677 10.50 5
August 22, 1997........................... 16,000 10,667 9.38 5
May 12, 1997.............................. 8,000 8,000 8.13 3
March 3, 1997............................. 799,000 799,000 7.88 2
June 13, 1996............................. 12,000 12,000 6.63 2
February 22, 1996......................... 150,000 150,000 5.13 3
January 8, 1996........................... 40,000 40,000 5.00 3
September 25, 1995........................ 50,000 50,000 5.00 2
September 12 ,1995........................ 29,666 29,666 5.00 3
August 3, 1995............................ 24,000 24,000 4.88 2
April 14, 1995............................ 32,500 32,500 5.00 2
December 4, 1994.......................... 105,000 105,000 5.01 3
November 10, 1994......................... 240,000 240,000 5.00 2
June 7, 1994.............................. 63,167 63,167 5.49 1
October 22, 1993.......................... 252,056 252,056 6.00 1
September 29, 1993........................ 11,689 11,689 6.52 1
October 19, 1992.......................... 40,023 40,023 6.52 1
</TABLE>
The weighted average fair value of options at date of grant for options
granted during 1997 and 1998 was $4.02 and $3.12 per option, respectively. The
fair value of options at date of grant was estimated using the Black-Scholes
model with the following weighted average assumptions:
<TABLE>
<CAPTION>
1997 1998 1999
----- ----- ----
<S> <C> <C> <C>
Expected life (years)....................................... 5 5 --
Interest rate............................................... 6.44% 5.67% --
Volatility.................................................. 43.76% 42.01% --
Dividend yield.............................................. -- -- --
</TABLE>
Had compensation cost for these plans been determined consistent with SFAS
No. 123, "Accounting for Stock-Based Compensation", the Company's pro forma net
income and earnings per share from continuing operations would have been as
follows:
<TABLE>
<CAPTION>
1997 1998 1999
------ --------- --------
<S> <C> <C> <C> <C>
Net income (loss) As reported......... $6,288 $(203,346) $(30,715)
Pro forma........... $4,385 $(204,108) $(31,321)
Basic earnings (loss) per share As reported......... $ 0.29 $ (7.94) $ (1.20)
Pro forma........... $ 0.20 $ (7.97) $ (1.22)
Diluted earnings (loss) per share As reported......... $ 0.28 $ (7.94) $ (1.20)
Pro forma........... $ 0.20 $ (7.97) $ (1.22)
</TABLE>
F-17
<PAGE> 108
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. COMMITMENTS AND CONTINGENCIES
(a) Coho Resources, Inc., is a defendant in a number of individual lawsuits
in Mississippi, which allege environmental damage to property, and personal
injury, in connection with drilling and production operations of the Company and
its predecessors in Lincoln County, Mississippi (the "Brookhaven Field"). The
plaintiffs allege that their damages were caused by "naturally occurring
radioactive materials" resulting from petroleum exploration and production
operations. The Company's predecessors on the Brookhaven Field were Florabama
Associates, Inc. ("Florabama"), and Chevron Corp. or Chevron USA. Inc.
("Chevron"). The Company is vigorously defending against these claims. Florabama
and Chevron allege claims for indemnification for any liability they may have to
the Brookhaven Field plaintiffs (the "Plaintiffs"), including claims for
monetary and punitive damages, as well as clean-up costs associated with the
properties. The Company is also vigorously defending against the indemnity
claims of Florabama and Chevron. The Plaintiffs, Florabama and Chevron have
filed proofs of claim in the Company's bankruptcy cases. The Company has
objected to these claims and has requested that they be disallowed. The Company
has also requested that these claims be estimated pursuant to Section 502 of the
Bankruptcy Code. The claims of Chevron are unliquidated, except for a contingent
claim in the amount of $2,349,275 which is subject to a pending appeal, and
cannot be quantified at this time. The Florabama claim is asserted at
$3,671,953.33. The Plaintiffs' claim is alleged at a combined amount of $250
million.
The Plaintiffs have compromised and settled their $250,000,000 claim for
the cash sum of $900,000 to be paid in installments over the 180 days following
the effective date of a confirmed chapter 11 plan of reorganization. We have
agreed to that settlement subject to court approval. The court will take up the
question of approval of this settlement on March 15, 2000. We have also settled
the claims of Chevron Corp. and Chevron USA, Inc., subject to court approval, by
agreeing to contribute $2.5 million over the next two years to a fund to be used
to finance the implementation of a thorough remediation plan for the Brookhaven
Field. Chevron USA will contribute at least $3 million to that fund as well, and
will supervise the implementation of the remediation plan. The remediation plan
has been filed with the court and circulated to numerous parties in interest.
This Coho-Chevron settlement arrangement is opposed by the Plaintiffs, and the
court will take up the question of approval of the Coho-Chevron settlement on
March 10, 2000. The Coho-Chevron settlement also calls for Chevron to withdraw
its claims in the Florabama bankruptcy in Mississippi. That will have the effect
of greatly reducing the dollar amount of Florabama's claim in the bankruptcy to
less than $1.3 million, subject to further negotiations and final resolution.
The feasibility of the Plan of Reorganization is dependent upon the court's
approval of these settlements.
The Company is involved in various other legal actions arising in the
ordinary course of business. While it is not feasible to predict the ultimate
outcome of these actions or those listed above, management believes that the
resolution of these matters will not have a material adverse effect, either
individually or in the aggregate, on the Company's financial position or results
of operations. The Company has accrued $4.0 million, including $2.2 million
which has been reflected in current accrued liabilities, for the proposed
settlements discussed in the preceding paragraph and for future remediation
costs.
On May 27, 1999, the Company filed a lawsuit (the "Hicks Muse Lawsuit")
against HM4 Coho L.P. ("HM4") and affiliated persons. The lawsuit alleges (1)
breach of the written contract terminated by HM4 in December 1998, (2) breach of
the oral agreements reached with HM4 on the restructured transaction in February
1999 and (3) promissory estoppel. In the lawsuit, the Company seeks monetary
damages of approximately $500 million. The lawsuit is currently in the discovery
stages. While the Company believes that the lawsuit has merit and that the
actions of HM4 in December 1998 and February 1999 were the primary cause of the
Company's current liquidity crisis, there can be no assurance as to the outcome
of this litigation.
F-18
<PAGE> 109
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(b) During June 1999, the Company extended its Anaguid permit in Tunisia,
North Africa through June 2001. The Company has a commitment to drill two
additional wells during this two year period.
(c) The Company has leased (i) 47,942 square feet of office space in
Dallas, Texas under a non-cancellable lease extending through October 2000, (ii)
5,000 square feet of office space in Laurel, Mississippi under a non-cancellable
lease extending through June 2000, (iii) various vehicles under non-cancellable
leases extending through February 2000, and (iv) surface leases in Laurel,
Mississippi with expiration dates extending through the year 2018. Rental
expense totaled $1,196,000, $1,668,000 and $1,798,000 in 1997, 1998 and 1999,
respectively. Minimum rentals payable under these leases for each of the next
five years are as follows: 2000 -- $1,225,000; 2001 -- $441,000; 2002 -$437,000;
2003 -- $418,000 and 2004 -$416,000. Total rentals payable over the remaining
terms of the leases are $8,765,000.
(d) Like other crude oil and natural gas producers, the Company's
operations are subject to extensive and rapidly changing federal, state and
local environmental regulations governing emissions into the atmosphere, waste
water discharges, solid and hazardous waste management activities, noise levels
and site restoration and abandonment activities. The Company's policy is to make
a provision for future site restoration charges on a unit-of-production basis.
Total future site restoration costs are estimated to be $6,000,000, including
the Oklahoma Properties. A total of $1,589,000 has been included in depletion
and depreciation expense with respect to such costs as of December 31, 1998.
(e) The Company has entered into employment agreements with certain of its
officers. In addition to base salary and participation in employee benefit plans
offered by the Company, these employment agreements generally provide for a
severance payment in an amount equal to two times the rate of total annual
compensation of the officer in the event the officer's employment is terminated
for other than cause. If the officer's employment is terminated for other than
cause following a change in control in the Company, the officer generally is
entitled to a severance payment in the amount of 2.99 times the rate of total
annual compensation of the officer. The above described employment agreements
will be modified according to the terms of the Plan of Reorganization if the
Plan of Reorganization is confirmed.
The officers' aggregate base salary and bonus portion of total annual
compensation covered under such employment agreements is approximately $1.4
million.
(f) The Company has entered into executive severance agreements with its
other officers which are designed to encourage executive officers to continue to
carry out their duties with the Company in the event of a change in control of
the Company. In the event the officer's employment is terminated for other than
cause following a change of control, these severance agreements generally
provide for a severance payment in an amount equal to 1.5 times the highest
salary plus bonus paid to such officer in any of the five years preceding the
year of termination. These severance rights will be terminated according to the
terms of the Plan of Reorganization if the Plan of Reorganization is confirmed.
The highest salary plus bonus paid to the officers covered under such
severance agreements during the preceding five year period would aggregate
approximately $1.2 million.
(g) In conjunction with the acquisition of the Oklahoma Properties, the
acquisition of ING and the 1993 reorganization of the Company, the Company has
granted certain persons the right to require the Company, at its expense, to
register their shares under the Securities Act of 1933. These registration
rights may be exercised on up to 4 occasions. The number of shares of Common
Stock subject to registration rights as of December 31, 1999, is approximately
3,324,000. These registration rights will be terminated according to the terms
of the Plan of Reorganization if the Plan of Reorganization is confirmed.
F-19
<PAGE> 110
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. FINANCIAL INSTRUMENTS AND CREDIT RISK CONCENTRATIONS
Financial instruments which are potentially subject to concentrations of
credit risk consist principally of cash, cash equivalents and accounts
receivable. Cash and cash equivalents are placed with high credit quality
financial institutions to minimize risk. The carrying amounts of these
instruments approximate fair value because of their short maturities. The
Company has entered into certain financial arrangements which act as a hedge
against price fluctuations in future crude oil and natural gas production.
Included in operating revenues are gains (losses) of $(232,000), $488,000 and
$-0- for 1997, 1998 and 1999, respectively, resulting from these hedging
programs. At December 31, 1998 and 1999, the Company had no deferred hedging
gains or losses. As of December 31, 1999, the Company had no crude oil or
natural gas hedged.
Fair values of the Company's financial instruments are estimated through a
combination of management's estimates and by reference to quoted prices from
market sources and financial institutions, if available. As of December 31,
1999, the fair market value of the Company's Existing Bonds was $83 million
compared to the related carrying value of $149 million. The fair value of the
Existing Bonds at December 31, 1998 was $57 million compared to the related
carrying value of $149 million. The carrying value of the Existing Bank Group
Loan Agreement approximated fair market value at December 31, 1998 and 1999
since the applicable interest rate approximated the market rate. On the
effective date of the Plan of Reorganization, the Existing Bonds will be
converted to new common stock of the reorganized company and the Existing Group
Loan Agreement will be paid in full in cash.
During 1998, three purchasers of our crude oil and natural gas, EOTT Energy
Corp. ("EOTT"), Amoco Production Company, and Mid Louisiana Marketing Company,
accounted for 42%, 28% and 14%, respectively, of the Company's revenues. During
1999, EOTT and Amoco Production Company accounted for 39% and 41%, respectively,
of the Company's revenue. Included in accounts receivable is $2,969,000,
$1,965,000 and $114,000 from these customers at December 31, 1997, 1998 and
1999, respectively.
11. RELATED PARTY TRANSACTIONS
(a) In 1990, the Company made a non-interest bearing loan in the amount of
$205,000 to Jeffrey Clarke, President, Chief Executive Officer and Director of
the Company, to assist him in the purchase of a house in Dallas. The loan is
unsecured and is repayable on the date Mr. Clarke ceases employment with the
Company, unless Mr. Clarke's employment is terminated as a result of the
Company's current restructuring process, at which time the loan will be
forgiven, and is included in other assets at December 31, 1998 and December 31,
1999.
(b) Pursuant to the equity offering, the Company's officers and directors
were precluded from selling stock for a 90-day period beginning October 3, 1997
(the "Lock Up Period"). On October 6, 1997, the Company made sole recourse,
non-interest bearing loans of $622,111, payable on demand, secured by the
related Company's common stock to certain officers and a director. The loans
were made to provide assistance in acquiring stock upon exercise of expiring
stock options during the Lock Up Period. During 1998, the Company has provided
an allowance for bad debt for the entire amount of such loans due to the
decrease in the share price of the Company's common stock provided by such
officers and directors as collateral.
(c) During 1997, certain of the Company's hedging agreements were with an
affiliate of the Company, Morgan Stanley Capital Group, which owned over 10% of
the Company's outstanding common stock until October 3, 1997, when its ownership
dropped to 5.3% as a result of the equity offering discussed in Note 7.
Management of the Company believes that such transactions are on similar terms
as could be obtained from unrelated third parties.
F-20
<PAGE> 111
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(d) Under the terms of a Financial Advisory Agreement entered into between
the Company and Hicks, Muse & Co. Partners, L.P. ("HMCo"), on August 21, 1998,
the Company paid HMCo $1,250,000 as compensation for HMCo's services as a
financial advisor to the Company and its subsidiaries in connection with an
agreement to issue common stock of the Company to HM4. John R. Muse and Lawrence
D. Stuart, Jr., are each limited partners in HMCo and limited partners of a
limited partner in HM4, and at the time of the payment to HMCo, were directors
of the Company under an agreement with Energy Investment Partnership No. 1, L.P.
On March 18, 1999, Messrs, Muse and Stuart resigned from the board of directors
of the Company.
(e) In 1999, the Company entered into a contract with Alan Edgar, a
director of the Company, that provides for Mr. Edgar to receive a percentage of
the net proceeds received by the Company from the Hicks Muse Lawsuit up to a
maximum of $5.75 million, in consideration of Mr. Edgar's extensive and ongoing
involvement in working with the special litigation counsel for the Company in
prosecuting the Hicks Muse Lawsuit.
12. CANADIAN ACCOUNTING PRINCIPLES
These financial statements have been prepared in conformity with generally
accepted accounting principles ("GAAP") as presently established in the United
States. These principles differ in certain respects from those applicable in
Canada. These differences would have affected net earnings (loss) as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-----------------------------
1997 1998 1999
------ --------- --------
<S> <C> <C> <C>
Net earnings (loss) based on US GAAP.................. $6,288 $(203,346) $(30,715)
Canadian writedown of oil and natural gas
properties(i)....................................... -- (109,000) --
Adjustment to depletion based on difference in
carrying value of oil and gas properties related to:
ING acquisition (ii)................................ 562 483 358
Business combination with Odyssey Exploration, Inc.
in 1990.......................................... (168) (135) (94)
Application of Canadian full cost ceiling test...... (455) (364) 4,410
Deferred tax effect of differences in US GAAP and
Canadian GAAP....................................... 21 (4,790) --
------ --------- --------
Net earnings (loss) based on Canadian GAAP............ $6,248 $(317,152) $(26,041)
====== ========= ========
Net earnings (loss) per common share based on Canadian
GAAP................................................ $ 0.29 $ (12.39) $ (1.02)
====== ========= ========
</TABLE>
- ---------------
(i) Canadian GAAP requires a ceiling test to ensure that capitalized costs
relating to oil and gas properties are recoverable in the future. The net
book value of capitalized costs, less related deferred income taxes, is
compared to the future net revenue plus the cost of major development
projects and unproved properties, less future expenditures, which include
removal and site restoration costs, income taxes, general and
administrative costs and interest expense. General and administrative costs
were calculated on a per barrel basis and calculated over the life of the
reserves. Interest expense was calculated through the year 2013 based on
the Company's current debt at December 31, 1998, assuming all future
positive cash flow from future net revenue, net of general and
administrative costs, income taxes and interest expense, was used for
retirement of existing debt.
F-21
<PAGE> 112
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(ii) Under SFAS No. 109 in the United States, the Company was required to
increase deferred income taxes and property and equipment by $8,355,000 for
the deferred tax effect of the excess of the Company's tax basis of the
stock acquired in the ING acquisition over the tax basis of the net assets
of ING acquired. Under Canadian GAAP this adjustment is not required.
The effect on the consolidated balance sheets of the differences between
United States GAAP and Canadian GAAP is as follows:
<TABLE>
<CAPTION>
UNDER
AS INCREASE CANADIAN
REPORTED (DECREASE) GAAP
-------- ---------- ---------
<S> <C> <C> <C>
DECEMBER 31, 1999
Property and Equipment................................... $311,788 $(102,211) $ 209,577
Shareholder's Equity..................................... (91,958) (102,211) (194,169)
DECEMBER 31, 1998
Property and Equipment................................... $324,574 $(106,885) $ 217,689
Shareholder's Equity..................................... (61,243) $(106,885) (168,128)
</TABLE>
13. SUPPLEMENTARY QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH TOTAL
-------- -------- -------- --------- ---------
<S> <C> <C> <C> <C> <C>
1999
Operating revenues................. $ 8,967 $ 12,161 $ 16,829 $ 19,366 $ 57,323
Operating income (loss)............ (1,127) 428 (675) 7,454 6,080
Net loss........................... (8,987) (10,102) (10,733) (893) (30,715)
Basic loss per share............... $ (0.35) $ (0.40) $ (0.41) $ (0.04) $ (1.20)
Diluted loss per share............. $ (0.35) $ (0.40) $ (0.41) $ (0.04) $ (1.20)
1998
Operating revenues................. $ 21,143 $ 18,147 $ 16,539 $ 12,930 $ 68,759
Operating income (loss)............ $(28,206) (38,306) 1,344 (119,840) (185,008)
Net loss........................... (22,301) (41,611) (7,168) (132,266) (203,346)
Basic loss per share............... $ (0.87) $ (1.63) $ (0.28) $ (5.16) $ (7.94)
Diluted loss per share............. $ (0.87) $ (1.63) $ (0.28) $ (5.16) $ (7.94)
1997
Operating revenues................. $ 15,536 $ 13,985 $ 15,985 $ 17,624 $ 63,130
Operating income................... 5,604 4,151 4,990 6,038 20,783
Net earnings....................... 2,104 1,081 1,401 1,702 6,288
Basic earnings per share........... $ 0.10 $ 0.05 $ 0.07 $ 0.07 $ 0.29
Diluted earnings per share......... $ 0.10 $ 0.05 $ 0.07 $ 0.06 $ 0.28
</TABLE>
Basic per share figures are computed based on the weighted average number
of shares outstanding for each period shown. Diluted per share figures are
computed based on the weighted average number of shares outstanding including
common stock equivalents, consisting of stock options and warrants, when their
effect is dilutive.
F-22
<PAGE> 113
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
14. SUPPLEMENTARY INFORMATION RELATED TO OIL AND GAS ACTIVITIES
(a) Costs Incurred
Costs incurred for property acquisition, exploration and development
activities were as follows:
<TABLE>
<CAPTION>
1997 1998 1999
-------- -------- --------
<S> <C> <C> <C>
Property acquisitions
Proved............................................. $199,485 $ 8,432 $ --
Unproved........................................... 73,281 4,646 --
Exploration.......................................... 13,374 5,061 2,198
Development.......................................... 53,542 51,049 4,101
Other................................................ 729 955 50
-------- -------- --------
$340,411 $ 70,143 $ 6,349
======== ======== ========
Property and equipment, net of accumulated
depletion.......................................... $531,409 $324,574 $311,788
======== ======== ========
</TABLE>
(b) Quantities of Oil and Gas Reserves (Unaudited)
The following table presents estimates of the Company's proved reserves,
all of which have been prepared by the Company's engineers and evaluated by
independent petroleum consultants. Substantially all of the Company's crude oil
and natural gas activities are conducted in the United States.
<TABLE>
<CAPTION>
RESERVE QUANTITIES
-------------------
OIL GAS
(MBBLS) (MMCF)
-------- --------
<S> <C> <C>
Estimated reserves at December 31, 1996..................... 34,822 113,132
Revisions of previous estimates............................. 1,601 8,556
Purchase of reserves in place............................... 49,723 32,581
Extensions and discoveries.................................. 11,758 902
Production.................................................. (2,820) (7,666)
------- -------
Estimated reserves at December 31, 1997..................... 95,084 147,505
Revisions of previous estimates............................. (7,645) 4,459
Purchase of reserves in place............................... 6,842 480
Sales of reserves in place.................................. -- (94,106)
Extensions and discoveries.................................. 10,792 16,114
Production.................................................. (5,069) (8,124)
------- -------
Estimated reserves at December 31, 1998..................... 100,004 66,328
Revisions of previous estimates............................. 9,718 (25,257)
Purchase of reserves in place............................... -- --
Sales of reserves in place.................................. -- --
Extensions and discoveries.................................. 734 2,175
Production.................................................. (3,343) (2,608)
------- -------
Estimated reserves at December 31, 1999..................... 107,113 40,638
======= =======
Proved developed reserves at December 31,
1997...................................................... 62,663 129,392
1998...................................................... 66,869 48,176
1999...................................................... 73,748 25,794
</TABLE>
F-23
<PAGE> 114
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(c) Standardized Measure of Oil and Gas Reserves (unaudited)
Standardized Measure of Discounted Future Net Cash Flows and Changes
Therein Relating to Proved Reserves.
The following standardized measure of discounted future net cash flows was
computed in accordance with the rules and regulations of the Securities and
Exchange Commission and SFAS No. 69 using year end prices and costs, and year
end statutory tax rates. Royalty deductions were based on laws, regulations and
contracts existing at the end of each period. No values are given to unproved
properties or to probable reserves that may be recovered from proved properties.
The inexactness associated with estimating reserve quantities, future
production and revenue streams and future development and production
expenditures, together with the assumptions applied in valuing future
production, substantially diminishes the reliability of this data. The values so
derived are not considered to be an estimate of fair market value. The Company
therefore cautions against this use.
The following tabulation reflects the Company's estimated discounted future
cash flows from crude oil and natural gas production:
<TABLE>
<CAPTION>
1997 1998 1999
---------- ---------- ----------
<S> <C> <C> <C>
Future cash inflows.............................. $1,764,924 $1,081,003 $2,562,981
Future production costs.......................... (607,114) (419,820) (642,024)
Future development costs......................... (114,294) (112,165) (136,589)
Future income taxes.............................. (233,945) (55,008) (435,311)
---------- ---------- ----------
Future net cash flows............................ 809,571 494,010 1,349,057
Annual discount at 10%........................... (341,378) (224,712) (656,182)
---------- ---------- ----------
Standardized measure of discounted future net
cash flows..................................... $ 468,193 $ 269,298 $ 692,875
========== ========== ==========
Crude oil posted reference price ($ per
Bbl)(a)........................................ $ 16.17 $ 12.05 $ 25.60
Estimated December 31 Company average realized
price
$/Bbl.......................................... $ 15.06 $ 9.36 $ 21.78
$/Mcf.......................................... $ 2.26 $ 2.10 $ 2.25
</TABLE>
- ---------------
(a) 1997 and 1998 prices were based on West Texas Intermediate posted prices and
1999 was based on the NYMEX posted price.
F-24
<PAGE> 115
COHO ENERGY, INC. AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following are the significant sources of changes in discounted future
net cash flows relating to proved reserves:
<TABLE>
<CAPTION>
1997 1998 1999
--------- --------- --------
<S> <C> <C> <C>
Crude oil and natural gas sales, net of production
costs............................................ $ (47,392) $ (41,412) $(36,168)
Net changes in anticipated prices and production
costs............................................ (176,309) (184,445) 582,297
Extensions and discoveries, less related costs..... 73,565 39,510 7,683
Changes in estimated future development costs...... (6,393) (905) (19,335)
Development costs incurred during the period....... 10,817 22,040 2,212
Net change due to sales and purchase of reserves in
place............................................ 224,579 (53,534) --
Accretion of discount.............................. 41,708 52,628 26,930
Revision of previous quantity estimates............ 11,737 (20,178) 45,605
Net changes in income taxes........................ 21,780 58,084 (97,279)
Changes in timing of production and other.......... (23,118) (70,683) (88,368)
--------- --------- --------
Net increase (decrease)............................ 130,974 (198,895) 423,577
Beginning of year.................................. 337,219 468,193 269,298
--------- --------- --------
Standardized measure of discounted future net cash
flows............................................ $ 468,193 $ 269,298 $692,875
========= ========= ========
</TABLE>
15. SUBSEQUENT EVENTS
The confirmation hearing for the bankruptcy court to consider the plan of
reorganization commenced on March 15, 2000. On March 20, 2000, the bankruptcy
court entered a confirmation order confirming our plan of reorganization. The
effective date of confirmation of our plan of reorganization was March 31, 2000.
As of the effective date of our plan of reorganization we anticipate
significant adjustments will be made to our first quarter 2000 financial
statements to effect the reorganization.
F-25
<PAGE> 116
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
You may rely on the information contained in this prospectus. We have not
authorized anyone to provide information different from that contained in this
prospectus. This prospectus is not an offer to sell or a solicitation of an
offer to buy these securities in any state where the offer or sale is not
permitted. This prospectus is not an offer to sell or a solicitation of an offer
to buy these securities in any circumstance under which the offer or
solicitation is not permitted. The information contained in this prospectus is
correct only as of the date of this prospectus, regardless of the time of the
delivery of this prospectus or any sale of these securities.
---------------------
UP TO 11,355,804 SHARES
COHO ENERGY, INC.
COMMON STOCK
---------------------
PROSPECTUS
---------------------
MAY 1, 2000
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE> 117
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.
The estimated expenses in connection with the offering are:
<TABLE>
<S> <C>
Securities and Exchange Commission Registration Fee......... $ 31,180
Blue Sky Registration Fees.................................. 4,025
Legal Fees and Expenses..................................... 200,000
Accounting Fees and Expenses................................ 30,000
Printing Expenses........................................... 200,000
Subscription Agent Fees..................................... 30,000
Miscellaneous............................................... 54,795
--------
TOTAL............................................. $550,000
========
</TABLE>
ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
Article 2.02-1 of the Texas Business Corporation Act provides that any
director or officer of a Texas corporation may be indemnified against judgments,
penalties, fines, settlements and reasonable expenses actually incurred by him
in connection with or in defending any action, suit or proceeding in which he is
a party by reason of his position. With respect to any proceeding arising from
actions taken in his official capacity as a director or officer, he may be
indemnified so long as it shall be determined that he conducted himself in good
faith and that he reasonably believed that his conduct was in the corporation's
best interests. In cases not concerning conduct in his official capacity as a
director or officer, a director may be indemnified as long as he reasonably
believed that his conduct was not opposed to the corporation's best interests.
In the case of any criminal proceeding, a director or officer may be indemnified
if he had no reasonable cause to believe his conduct was unlawful. If a director
or officer is wholly successful, on the merits or otherwise, in connection with
this type of proceeding, indemnification is mandatory. The Amended and Restated
Bylaws of Coho Energy, Inc. provide for indemnification of its present and
former directors and officers to the fullest extent provided by Article 2.02-1.
Coho's amended and restated articles of incorporation contain a provision
that limits the liability of Coho's directors as permitted under Texas law. The
provision eliminates the liability of a director to Coho or its shareholders for
monetary damages for negligent or grossly negligent acts or omissions in the
director's capacity as a director. The provision does not affect the liability
of a director (i) for breach of his duty of loyalty to Coho or to shareholders,
(ii) for acts or omissions not in good faith or that involve intentional
misconduct or a knowing violation of law, (iii) for acts or omissions for which
the liability of a director is expressly provided by an applicable statute, or
(iv) in respect of any transaction from which a director received an improper
personal benefit. Under the amended and restated articles of incorporation, the
liability of directors will be further limited or eliminated without action by
shareholders if Texas law is amended to further limit or eliminate the personal
liability of directors.
The above discussion of Texas law and the amended and restated articles of
incorporation is not intended to be exhaustive and is qualified in its entirety
by Texas law and the amended and restated articles of incorporation.
Texas corporations are also authorized to obtain insurance to protect
officers and directors from specified liabilities, including liabilities against
which the corporation cannot indemnify its directors and officers. Coho Energy,
Inc. currently has in effect a director's and officer's liability insurance
policy, which provides coverage in the maximum amount of $40,000,000, subject to
a $250,000 deductible. This policy covers the directors' and officers' actions
prior to the effective date, as described in the plan of reorganization.
II-1
<PAGE> 118
Insofar as indemnification for liabilities arising under the Securities Act
may be permitted to directors, officers or persons controlling Coho under the
foregoing provisions, Coho has been informed that in the opinion of the
Commission this type of indemnification is against public policy as expressed in
the Securities Act and is therefore unenforceable.
ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.
In December 1997, Coho issued warrants, valued at $3.4 million, to purchase
one million shares of Coho old common stock at $10.425 per share for a period of
five years to Amoco Production Company as partial consideration for the purchase
of crude oil and natural gas properties. This transaction was exempt from
registration under Section 4(2) of the Securities Act of 1933, as no public
offering was involved.
ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Exhibits.
Exhibits designated by the symbol * were filed with the original
Registration Statement. Exhibits designated by the symbol ** were filed with
Amendment No. 1 to Registration Statement. Exhibits designated by the symbol ***
were filed with Amendment No. 2 to Registration Statement. Exhibits designated
by the symbol **** are filed with this Amendment No. 3 to Registration
Statement. All exhibits not so designated are incorporated by reference to a
prior filing as indicated.
<TABLE>
<C> <S>
2.1** -- Debtor's First Amended and Restated Chapter 11 Plan of
Reorganization as filed with the United States Bankruptcy
Court for the Northern District of Texas on February 14,
2000 (included as Exhibit A to Exhibit 2.2 below).
2.2** -- Debtor's First Amended and Restated Disclosure Statement
with Respect to the Joint Plan of Reorganization under
Chapter 11 of the United States Bankruptcy Code as filed
with the United States Bankruptcy Court for the Northern
District of Texas on February 14, 2000.
2.3 -- Findings of Fact, Conclusions of Law, and Order
Confirming Debtors' First Amended and Restated Chapter 11
Plan of Reorganization as filed with the United States
Bankruptcy Court for the Northern District of Texas on
March 20, 2000 (incorporated by reference to the
Company's Report on Form 8-K dated March 20, 2000).
3.1*** -- Amended and Restated Articles of Incorporation of the
Company.
3.2*** -- Amended and Restated Bylaws of the Company.
4.1 -- Amended and Restated Articles of Incorporation (included
as Exhibit 3.1 above).
4.2 -- Amended and Restated Bylaws of the Company (included as
Exhibit 3.2 above).
5.1*** -- Opinion of Fulbright & Jaworski L.L.P.
10.1*** -- Executive Employment Severance Agreement dated April 3,
2000, by and between Jeffrey Clarke and Coho Energy, Inc.
10.2 -- Crude Oil Purchase Contract dated January 25, 1996, by
and between Coho Marketing and Transportation, Inc. and
EOTT Energy Operating Limited Partnership (incorporated
by reference to Exhibit 10.17 to the Company's Annual
Report on Form 10-K for the year ended December 31,
1995).
10.3*** -- Credit Agreement dated as of March 31, 2000, among Coho
Energy, Inc., The Chase Manhattan Bank, Meespierson
Capital Corp., Fleet National Bank, Chase Securities
Inc., Credit Lyonnais, New York Branch, ABN AMRO Bank
N.V., General Electric Capital Corporation, CIBC Inc.,
Credit Agricole Indosuez, and Natexis Banque BFCE.
</TABLE>
II-2
<PAGE> 119
<TABLE>
<C> <S>
10.4*** -- Registration Rights Agreement dated as of March 31, 2000,
among Coho Energy, Inc., PPM America Special Investments
Fund, L.P., PPM America Special Investments CBO II, L.P.,
Appaloosa Management L.P., as agent and on behalf of
certain funds including Appaloosa Investment Limited
Partnership I, Palomino Fund Ltd., and Tersk LLC;
Pacholder Associates, Inc., as agent and on behalf of
certain funds including Pacholder Value Opportunity Fund,
L.P., High Yield Fund, Inc., One Group High Yield Bond
and Evangelical Lutheran Church In America Board of
Pensions; and Oaktree Capital Management, LLC, as general
partner of and investment manager for the entities set
forth therein.
10.5*** -- Note Agreement dated as of March 31, 2000, among Coho
Energy, Inc., Coho Resources, Inc., Coho Louisiana
Production Company, Coho Exploration, Inc., Coho Oil &
Gas, Inc., Interstate Natural Gas Company, PPM America
Special Investments Fund, L.P., PPM America Special
Investments CBO II, L.P., Appaloosa Investment Limited
Partnership I, Palomino Fund Ltd., Tersk LLC, Oaktree
Capital Management, LLC, Pacholder Value Opportunity
Fund, L.P., Pacholder High Yield Fund, Inc., One Group
High Yield Bond Fund, and Evangelical Lutheran Church in
America Board of Pensions.
10.6*** -- Securities Purchase Agreement dated as of March 31, 2000,
among Coho Energy, Inc., Coho Resources, Inc., Coho
Louisiana Production Company, Coho Exploration, Inc.,
Coho Oil & Gas, Inc., Interstate Natural Gas Company, PPM
America Special Investments Fund, L.P., PPM America
Special Investments CBO II, L.P., Appaloosa Management,
L.P., Oaktree Capital Management, LLC, and Pacholder
Associates, Inc.
10.7 -- Crude Call Purchase Contract dated November 26, 1997 by
and between Amoco Production Company and Coho
Acquisitions Company (incorporated by reference to
Exhibit 2.1 to the Company's Report on Form 8-K dated
December 18, 1997).
10.8 -- Adoption Agreement for Coho Resources, Inc.'s Amended and
Restated 401(k) Savings Plan dated July 1, 1995
(incorporated by reference to Exhibit 10.27 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1998).
10.9** -- Letter Agreement dated March 5, 1999, by and between Coho
Marketing and Transportation, Inc. and EOTT Energy
Operating Limited Partnership, amending the Crude Oil
Purchase Contract dated January 25, 1996, by and between
Coho Marketing and Transportation, Inc. and EOTT Energy
Operating Limited Partnership (filed as Exhibit 10.27 to
Amendment No. 1 to Registration Statement).
10.10*** -- Agreement dated as of April 13, 2000 by and among Anne
Marie O'Gorman and Coho Energy, Inc.
10.11*** -- Agreement dated as of April 13, 2000 by and among Larry
L. Keller and Coho Energy, Inc.
10.12*** -- Employment Agreement dated as of April 1, 2000 by and
among Michael Y. McGovern and Coho Energy, Inc.
10.13*** -- Employment Agreement dated as of April 1, 2000 by and
among Gary L. Pittman and Coho Energy, Inc.
10.14*** -- Employment Agreement dated as of April 1, 2000 by and
among Gerald E. Ruley and Coho Energy, Inc.
21.1* -- List of Subsidiaries of the Company.
23.1**** -- Consent of Arthur Andersen LLP.
</TABLE>
II-3
<PAGE> 120
<TABLE>
<C> <S>
23.2**** -- Consent of Ryder Scott Company, L.P.
23.3**** -- Consent of Sproule Associates, Inc.
23.4*** -- Consent of Fulbright & Jaworski L.L.P. (included in
Exhibit 5.1 above).
27.1** -- Financial Data Schedule.
99.1*** -- Form of Notice of Exercise of Rights and related
documents.
</TABLE>
(b) Financial Statement Schedules.
All schedules for which provision is made in applicable accounting
regulations of the Securities and Exchange Commission have been omitted as the
schedules are either not required under the related instructions or are not
applicable, or the information required thereby is set forth in the Financial
Statements or the Notes thereto.
ITEM 17. UNDERTAKINGS.
Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers and controlling persons of Coho
pursuant to the foregoing provisions, or otherwise, Coho has been advised that
in the opinion of the Securities and Exchange Commission such indemnification is
against public policy as expressed in the Act and is, therefore, unenforceable.
In the event that a claim for indemnification against such liabilities (other
than the payment by Coho of expenses incurred or paid by a director, officer or
controlling person of Coho in the successful defense of any action, suit or
proceeding) is asserted by such director, officer or controlling person in
connection with the securities being registered, Coho will, unless in the
opinion of its counsel the matter has been settled by controlling precedent,
submit to a court of appropriate jurisdiction the question whether this type of
indemnification by it is against public policy as expressed in the Securities
Act and will be governed by the final adjudication of such issue.
II-4
<PAGE> 121
SIGNATURES
Pursuant to the requirements of the Securities Act, Coho Energy, Inc. has
duly caused this Registration Statement to be signed on its behalf by the
undersigned, thereunto duly authorized, in the City of Dallas, State of Texas,
on May 1, 2000.
COHO ENERGY, INC.
By: /s/ MICHAEL MCGOVERN
----------------------------------
Michael McGovern
President
and Chief Executive Officer
This report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ MICHAEL MCGOVERN President, Chief Executive Officer May 1, 2000
- ----------------------------------------------------- (Principal Executive Officer)
Michael McGovern
* Chief Financial Officer (Principal May 1, 2000
- ----------------------------------------------------- Financial Officer)
Gary L. Pittman
* Controller (Principal Accounting May 1, 2000
- ----------------------------------------------------- Officer)
Susan J. McAden
* Director May 1, 2000
- -----------------------------------------------------
Eugene L. Davis
* Director May 1, 2000
- -----------------------------------------------------
John G. Graham
* Director May 1, 2000
- -----------------------------------------------------
James E. Bolin
* Director May 1, 2000
- -----------------------------------------------------
Ronald Goldstein
* Director May 1, 2000
- -----------------------------------------------------
Michael Salvati
*By: /s/ MICHAEL MCGOVERN
------------------------------------------------
Michael McGovern
Attorney-in-Fact
</TABLE>
II-5
<PAGE> 122
INDEX TO EXHIBITS
Exhibits designated by the symbol * were filed with the original
Registration Statement. Exhibits designated by the symbol ** were filed with
Amendment No. 1 to Registration Statement. Exhibits designated by the symbol ***
were filed with Amendment No. 2 to Registration Statement. Exhibits designated
by the symbol **** are filed with this Amendment No. 3 to Registration
Statement. All exhibits not so designated are incorporated by reference to a
prior filing as indicated.
<TABLE>
<C> <S>
2.1** -- Debtor's First Amended and Restated Chapter 11 Plan of
Reorganization as filed with the United States Bankruptcy
Court for the Northern District of Texas on February 14,
2000 (included as Exhibit A to Exhibit 2.2 below).
2.2** -- Debtor's First Amended and Restated Disclosure Statement
with Respect to the Joint Plan of Reorganization under
Chapter 11 of the United States Bankruptcy Code as filed
with the United States Bankruptcy Court for the Northern
District of Texas on February 14, 2000.
2.3 -- Findings of Fact, Conclusions of Law, and Order
Confirming Debtors' First Amended and Restated Chapter 11
Plan of Reorganization as filed with the United States
Bankruptcy Court for the Northern District of Texas on
March 20, 2000 (incorporated by reference to the
Company's Report on Form 8-K dated March 20, 2000).
3.1*** -- Amended and Restated Articles of Incorporation of the
Company.
3.2*** -- Amended and Restated Bylaws of the Company.
4.1 -- Amended and Restated Articles of Incorporation (included
as Exhibit 3.1 above).
4.2 -- Amended and Restated Bylaws of the Company (included as
Exhibit 3.2 above).
5.1*** -- Opinion of Fulbright & Jaworski L.L.P.
10.1*** -- Executive Employment Severance Agreement dated April 3,
2000, by and between Jeffrey Clarke and Coho Energy, Inc.
10.2 -- Crude Oil Purchase Contract dated January 25, 1996, by
and between Coho Marketing and Transportation, Inc. and
EOTT Energy Operating Limited Partnership (incorporated
by reference to Exhibit 10.17 to the Company's Annual
Report on Form 10-K for the year ended December 31,
1995).
10.3*** -- Credit Agreement dated as of March 31, 2000, among Coho
Energy, Inc., The Chase Manhattan Bank, Meespierson
Capital Corp., Fleet National Bank, Chase Securities
Inc., Credit Lyonnais, New York Branch, ABN AMRO Bank
N.V., General Electric Capital Corporation, CIBC Inc.,
Credit Agricole Indosuez, and Natexis Banque BFCE.
10.4*** -- Registration Rights Agreement dated as of March 31, 2000,
among Coho Energy, Inc., PPM America Special Investments
Fund, L.P., PPM America Special Investments CBO II, L.P.,
Appaloosa Management L.P., as agent and on behalf of
certain funds including Appaloosa Investment Limited
Partnership I, Palomino Fund Ltd., and Tersk LLC;
Pacholder Associates, Inc., as agent and on behalf of
certain funds including Pacholder Value Opportunity Fund,
L.P., High Yield Fund, Inc., One Group High Yield Bond
and Evangelical Lutheran Church in America Board of
Pensions; and Oaktree Capital Management, LLC, as general
partner of and investment manager for the entities set
forth therein.
</TABLE>
<PAGE> 123
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<C> <S>
10.5*** -- Note Agreement dated as of March 31, 2000, among Coho
Energy, Inc., Coho Resources, Inc., Coho Louisiana
Production Company, Coho Exploration, Inc., Coho Oil &
Gas, Inc., Interstate Natural Gas Company, PPM America
Special Investments Fund, L.P., PPM America Special
Investments CBO II, L.P., Appaloosa Investment Limited
Partnership I, Palomino Fund Ltd., Tersk LLC, Oaktree
Capital Management, LLC, Pacholder Value Opportunity
Fund, L.P., Pacholder High Yield Fund, Inc., One Group
High Yield Bond Fund, and Evangelical Lutheran Church in
America Board of Pensions.
10.6*** -- Securities Purchase Agreement dated as of March 31, 2000,
among Coho Energy, Inc., Coho Resources, Inc., Coho
Louisiana Production Company, Coho Exploration, Inc.,
Coho Oil & Gas, Inc., Interstate Natural Gas Company, PPM
America Special Investments Fund, L.P., PPM America
Special Investments CBO II, L.P., Appaloosa Management,
L.P., Oaktree Capital Management, LLC, and Pacholder
Associates, Inc.
10.7 -- Crude Call Purchase Contract dated November 26, 1997 by
and between Amoco Production Company and Coho
Acquisitions Company (incorporated by reference to
Exhibit 2.1 to the Company's Report on Form 8-K dated
December 18, 1997).
10.8 -- Adoption Agreement for Coho Resources, Inc.'s Amended and
Restated 401(k) Savings Plan dated July 1, 1995
(incorporated by reference to Exhibit 10.27 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1998).
10.9** -- Letter Agreement dated March 5, 1999, by and between Coho
Marketing and Transportation, Inc. and EOTT Energy
Operating Limited Partnership, amending the Crude Oil
Purchase Contract dated January 25, 1996, by and between
Coho Marketing and Transportation, Inc. and EOTT Energy
Operating Limited Partnership (filed as Exhibit 10.27 to
Amendment No. 1 to Registration Statement).
10.10*** -- Agreement dated as of April 13, 2000 by and among Anne
Marie O'Gorman and Coho Energy, Inc.
10.11*** -- Agreement dated as of April 13, 2000 by and among Larry
L. Keller and Coho Energy, Inc.
10.12*** -- Employment Agreement dated as of April 1, 2000 by and
among Michael Y. McGovern and Coho Energy, Inc.
10.13*** -- Employment Agreement dated as of April 1, 2000 by and
among Gary L. Pittman and Coho Energy, Inc.
10.14*** -- Employment Agreement dated as of April 1, 2000 by and
among Gerald E. Ruley and Coho Energy, Inc.
21.1* -- List of Subsidiaries of the Company.
23.1**** -- Consent of Arthur Andersen LLP.
23.2**** -- Consent of Ryder Scott Company, L.P.
23.3**** -- Consent of Sproule Associates, Inc.
23.4*** -- Consent of Fulbright & Jaworski L.L.P. (included in
Exhibit 5.1).
27.1** -- Financial Data Schedule.
99.1*** -- Form of Notice of Exercise of Rights and related
documents.
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EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the use of our report
and to all references to our Firm included in this registration statement.
ARTHUR ANDERSEN LLP
Dallas, Texas
May 1, 2000
<PAGE> 1
EXHIBIT 23.2
[RYDER SCOTT COMPANY LETTERHEAD]
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
We hereby consent to the incorporation by reference in this
Registration Statement on Form S-1 of our reserve report regarding the interests
of Coho Energy, Inc. (the Company) dated February 16, 2000, relating to
estimated quantities of certain of the Company's proved reserves of oil and gas.
We also consent to the references to us under the headings "Reserves" and
"Engineers" in such Registration Statement.
/s/ RYDER SCOTT COMPANY, L.P.
RYDER SCOTT COMPANY, L.P.
Houston, Texas
May 1, 2000
<PAGE> 1
EXHIBIT 23.3
[SPROULE ASSOCIATES INC. LETTERHEAD]
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
We hereby consent to the incorporation in this Registration Statement on Form
S-1 of our reserve report regarding the interests of Coho Energy, Inc. (the
Company) dated February 3, 2000, relating to estimated quantities of certain of
the Company's proved reserves of oil and gas. We also consent to the references
to us under the headings "Reserves" and "Engineers" in such Registration
Statement.
/s/ SPROULE ASSOCIATES INC.
SPROULE ASSOCIATES INC.
Geological and Petroleum Engineering Consultants
Denver, Colorado
May 1, 2000
