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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______to ________.
Commission file number 0-22576
COHO ENERGY, INC.
(Exact name of registrant as specified in its charter)
Texas 75-2488635
- ------------------------------- ----------------------
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification Number)
14785 Preston Road, Suite 860
Dallas, Texas 75240
- ---------------------------------------- ----------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:
(972) 774-8300
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $0.01 per share
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding twelve months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
As of March 27, 2000, 25,603,512 shares of the registrant's Common
Stock were outstanding and the aggregate market value of all voting stock held
by non-affiliates was $3.8 million based upon the closing price on Nasdaq's OTC
Bulletin Board on such date. The officers and directors of the registrant are
considered affiliates for purposes of this calculation.
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TABLE OF CONTENTS
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PART I
Item 1. Business.............................................................................. 4
Item 2. Properties............................................................................ 4
Item 3. Legal Proceedings..................................................................... 24
Item 4. Submission of Matters to a Vote of Security Holders................................... 25
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters................. 26
Item 6. Selected Financial Data............................................................... 27
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................................. 28
Item 7A. Quantitative and Qualitative Disclosure about Market Risk............................. 41
Item 8. Consolidated Financial Statements..................................................... 42
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.............................................................. 66
PART III
Item 10. Directors and Executive Officers of the Registrant.................................... 67
Item 11. Executive Compensation................................................................ 70
Item 12. Security Ownership of Certain Beneficial Owners and Management........................ 75
Item 13. Certain Relationships and Related Transactions........................................ 76
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K....................... 78
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FORWARD-LOOKING STATEMENTS
This Form 10-K 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 Form
10-K that address activities, events or developments that we expect, project,
believe or anticipate will or may occur in the future, including:
o the progression of our bankruptcy proceedings,
o crude oil and natural gas reserves,
o future acquisitions,
o future drilling and operations,
o future capital expenditures,
o future production of crude oil and natural gas, and
o 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
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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:
o our bankruptcy proceedings,
o competition,
o general economic and business conditions,
o prices of crude oil and natural gas,
o the business opportunities, or lack thereof, that may be
presented to and pursued by us,
o changes in laws or regulations, and
o other factors, many of which are beyond our control.
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.
DEFINITIONS
See Page 8 for a list of definitions of certain technical terms used
herein.
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PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
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 Form 10-K 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
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 are currently
operating as a debtor-in-possession subject to the bankruptcy court's
supervision and orders. We filed schedules with the bankruptcy court on
September 21, 1999, and amended those schedules on December 14, 1999. Those
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:
o August 23, 1999 - We filed a voluntary Chapter 11
bankruptcy petition;
o November 30, 1999 - We filed our plan of reorganization;
o February 4, 2000 - At a hearing, the bankruptcy court
approved our disclosure statement
with respect to our plan of
reorganization;
- At a hearing, the bankruptcy court
scheduled a confirmation hearing for
March 15, 2000, to consider our plan
of reorganization;
o 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;
- We began mailing our approved
disclosure statement to holders of
claims and equity interests for
voting on our plan of
reorganization;
o February 15, 2000 - We filed our approved disclosure
statement with the bankruptcy court;
o March 10, 2000 - Deadline for submitting votes on our
plan of reorganization;
o March 15, 2000 - The confirmation hearing to consider
our plan of reorganization
commenced;
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o March 20, 2000 - The bankruptcy court entered an
order confirming our plan of
reorganization; and
o March 31, 2000 - Expected effective date for
consummation of our plan of
reorganization.
Our plan of reorganization describes the means for satisfying claims,
including liabilities subject to compromise, and interests in Coho. Our plan of
reorganization includes the cancellation of our existing common stock and the
issuance of a new class of common stock in exchange for our existing common
stock and our existing bonds. The issuance of our new class of common stock will
materially dilute the current equity interests.
Our ability to effect a successful reorganization through our
bankruptcy proceedings will depend upon our ability to consummate our plan of
reorganization, which was confirmed by the bankruptcy court on March 20, 2000.
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 the effect on our business or on the interests of our creditors or
shareholders. For more information regarding the bankruptcy proceedings, see
"Item 3. Legal Proceedings" and "Item 7. 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:
o the natural production decline,
o 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
o 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 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:
o approximately 50 MMBbls of crude oil and natural gas liquid
reserves,
o approximately 33 Bcf of natural gas reserves , and
o interests in more than 40,000 gross acres, concentrated
primarily in southern Oklahoma, including 14 principal
producing fields.
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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.
On December 2, 1998, we sold our natural gas assets located in Monroe,
Louisiana, for a net sales price of $61.5 million. The assets sold represented
approximately 14% of our year end 1997 proved reserves and included two gas
gathering systems.
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:
o breach of the written contract terminated by HM4 in December
1998,
o breach of the oral agreements reached with HM4 on the
restructured transaction in February 1999, and
o promissory estoppel.
In the lawsuit, we seek monetary damages of approximately $500 million. The
lawsuit is currently in the discovery phase. 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 existing 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 existing 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 existing bank group loan. For more information about the
default under the existing credit facility, see "Item 7. 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 existing 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 existing
bonds which was due on April 15, 1999. On May 19, 1999, we received a written
notice of acceleration from two holders of existing bonds, which own in excess
of 25% in principal amount of the outstanding existing bonds. As a result, on
May 19, 1999, one of the holders of existing bonds filed a lawsuit against us
and each of our subsidiaries who is a guarantor of existing bonds 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
existing bonds, see "Item 7. 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:
o the conversion of a portion or all of our existing bonds to
equity,
o raising additional equity,
o cost reduction programs to enhance cash flow from operations,
and
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o refinancing our existing bank credit facility to:
o make overdue principal and interest payments on our
indebtedness,
o provide additional capital to fund well repairs,
and
o 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:
Relatively Low-Risk Field Development. We maximize production and
increase reserves through relatively low-risk activities such as:
o recompletions,
o enhancement of production facilities,
o multi-zone completions,
o development/delineation drilling, including high-angle and
horizontal drilling, and
o 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
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.
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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.
DEFINITIONS
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
herein:
"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 such 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
proved reserves that exist behind the casing of existing wells when the cost of
making those proved 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.
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"Recompletion" means leaving one formation for another formation within
a well bore.
"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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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:
o Mississippi o Oklahoma
o Brookhaven, o Bumpass,
o Laurel, o Sholem Alechem, and
o Martinville, o East Fitts.
o Soso,
o Summerland, and
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
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
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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.
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YEAR ENDED DECEMBER 31, AT DECEMBER 31, 1999 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 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.
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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:
o the Wilcox formations,
o the Eutaw formations,
o the Tuscaloosa formations, and
o 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 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.
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<PAGE> 13
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 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
13
<PAGE> 14
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,
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:
o East Velma Middle Block, o Graham Deese,
o North Alma Deese, o Eola S.E.,
o Tatums, o Eola N.W., and
o Jennings Deese, o 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
14
<PAGE> 15
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.
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.
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<PAGE> 16
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.
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 0.8 -- -- -- --
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.
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<PAGE> 17
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:
o actual future production,
o revenues,
o taxes,
o production costs,
o development expenditures and
o 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:
o actual production,
o results of future development,
o prevailing crude oil and natural gas prices and
o 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 Form 10-K.
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<PAGE> 18
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 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:
o leasehold prospects under which crude oil and natural gas
reserves may be discovered,
o drilling rigs and related equipment to explore for these
reserves, and
o 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.
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<PAGE> 19
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 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 "Item 7.
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:
o requiring permits for the drilling of wells,
o maintaining bonding requirements in order to drill or operate
wells,
o regulating the location of wells,
o regulating the method of drilling and casing wells,
o regulating the surface use and restoration of properties upon
which wells are drilled, and
o regulating the plugging and abandonment of wells.
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<PAGE> 20
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 :
o the size of drilling and spacing units or proration units,
o regulation of the density of wells that may be drilled,
o regulation of unitization or pooling of crude oil and natural
gas properties,
o maximum rates of production from crude oil and natural gas
wells,
o restrictions on the venting or flaring of natural gas, and
o 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 50% of regular rates for enhanced recovery projects. The state of
Oklahoma has adopted severance tax relief, adjusting tax rates to:
o 1% for posted crude oil priced less than $14.00 per barrel,
o 4% for posted crude oil priced between $14.00 and $17.00 per
barrel, and
o 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
20
<PAGE> 21
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, 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:
o tax and other laws relating to the petroleum industry,
o changes in these laws, and
o 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.
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<PAGE> 22
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:
o require us to obtain permits before drilling,
o restrict the types, quantities and concentration of various
substances that can be released into the environment through
drilling and production activities,
o limit or prohibit drilling activities on some lands lying
within wilderness, wildlife refuges or preserves, wetlands and
other protected areas, and
o 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.
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 some 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
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<PAGE> 23
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 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 "Item 3. Legal
Proceedings" 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.
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<PAGE> 24
EMPLOYEES
At March 1, 2000, we had 124 employees associated with our operations,
including 23 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.
ITEM 3. LEGAL PROCEEDINGS
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 have
been 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 has retained its own
financial consultants. The committees have been 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 existing 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 existing 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 existing bonds was reached.
Although we reasonably believed that we would reach an agreement with the bank
group and the holders of our existing 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.
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.
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<PAGE> 25
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 and its
outcome is contingent on trial or settlement.
Brookhaven Lawsuits. Coho Resources, Inc., was a defendant in a number
of individual lawsuits in Mississippi, which alleged 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 claim of Chevron, as discussed in the next
paragraph, and we are vigorously defending against the indemnity claim of
Florabama. The Florabama claim is asserted at $3,671,953.33.
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 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. That will have the effect of greatly
reducing the dollar amount of Florabama's claim in the Coho bankruptcy to less
than $1.3 million, subject to further negotiations and final resolution.
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 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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our common stock was, until June 7, 1999, listed on the Nasdaq Stock
Market under the symbol "COHO." Our common stock is currently traded on the
Nasdaq's OTC Bulletin Board under the symbol "COHO." The following table shows
the high and low sale prices of our common stock over recent periods.
<TABLE>
<CAPTION>
HIGH LOW
-------- -------
<S> <C> <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
</TABLE>
As a result of our financial condition and decreases in the market value
of our common stock, the Nasdaq Stock Market on March 8, 1999, suspended trading
of our common stock. As of the close of business on June 4, 1999, our common
stock was delisted from Nasdaq. As a result of these actions, our common stock
is not currently listed on any stock exchange but is trading over the counter.
At December 31, 1999, there were 425 holders of record of our common stock. We
believe we have in excess of 8,000 beneficial holders of our common stock.
We have never paid cash dividends on our existing 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:
o profitability,
o financial condition,
o cash requirements,
o future prospects,
o general business conditions,
o the terms of our debt agreements, and
o other factors our board of directors believes relevant.
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ITEM 6. 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 Item 8
of this Form 10-K. The information presented below should be read in conjunction
with our consolidated financial statements and the related notes and "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" included in this Form 10-K. The selected consolidated financial data
presented below is not necessarily indicative of the future results of our
operations or financial performance.
<TABLE>
<CAPTION>
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
Allowance for bad debt ........................... -- -- -- 894 --
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
BALANCE SHEET DATA:
Working capital (deficit)(4) ..................... $ 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 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) 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.
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<PAGE> 28
ITEM 7. 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 Form 10-K. Some of this
information, including information with respect to our plans and strategy for
our business, are forward-looking statements. See "Forward-Looking Statements"
for the limitations associated with these types of 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:
o paid $20 million cash,
o assumed net liabilities of $3.3 million, excluding deferred taxes,
and
o issued 2,775,000 shares of our 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 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:
o cash of $19.5 million,
o the assumption of net liabilities of approximately $2.3 million, and
o 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 Form 10-K.
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 existing bonds. The combined $193.7 million in proceeds from these
offerings were used to repay $144.8 million of indebtedness outstanding under
our existing 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.
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
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<PAGE> 29
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:
o the December 1994 acquisition of the Monroe natural gas field,
o the August 1995 acquisition of the Brookhaven field, and
o 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:
o our sale of our natural gas assets in Monroe, Louisiana in December
1998, which contributed approximately 2,452 BOE per day during 1998,
o 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
o 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 "Liquidity
and Capital Resources" below 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 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.
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<PAGE> 30
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, made a Chapter 11 filing with the
bankruptcy court. We are currently operating as a debtor-in-possession subject
to the bankruptcy court's supervision and orders. We filed schedules on
September 21, 1999 with the bankruptcy court, which were amended on December 14,
1999, setting forth our unaudited, and in some cases our estimated, assets and
liabilities as of the date of the Chapter 11 filing, as shown by our accounting
records.
The bankruptcy petitions were filed in order to facilitate the
restructuring of our long term debt and to provide protection while we develop a
solution to our capital needs with the banks, bondholders and potential
investors. Our plan of reorganization was approved by the bankruptcy court on
March 20, 2000. Our plan of reorganization sets forth the means for satisfying
claims, including liabilities subject to compromise, and current equity
interests. Our plan of reorganization includes the cancellation of our existing
common stock and the issuance of a new class of common stock in exchange for our
existing common stock and our existing bond debt. The issuance of new common
stock will materially dilute the current equity interests.
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 upon
consummation 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.
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.
On 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.
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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 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:
o significantly reduced both minor and major well repairs and drilling
activity on our operated properties during the last five months of
1998,
o ceased all well repairs and drilling activity in December 1998, and
o 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
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<PAGE> 32
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:
o decreased production,
o decreased production taxes, and
o 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.
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:
o cost reductions associated with the Monroe field sale,
o reductions in employee-related costs due to staff attrition,
o reductions in estimated franchise tax accruals as a result of our
losses in 1998, and
o 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 existing 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.
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<PAGE> 33
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 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.
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<PAGE> 34
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:
o a lack of cold weather in the 1998 winter months,
o increased storage inventories, and
o perceptions of the effects of increased quotas or lack of adherence
to quotas from the Organization of Petroleum Exporting Countries.
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 Form 10-K.
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,
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<PAGE> 35
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 $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 "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 existing bank group loan but are not sufficient to cover past due interest
on our existing bonds or on the borrowings under the existing 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 has been accruing on the existing 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 existing 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. Since August 26, 1999, we have been operating under three interim
orders
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<PAGE> 36
authorizing the use of cash collateral as approved by the bankruptcy court. We
are currently operating under the Third Interim Cash Collateral Order
authorizing the use of cash collateral which was approved by the bankruptcy
court on November 9, 1999. Under these orders, we may pay for ordinary course of
business goods and services incurred after August 23, 1999 that are within the
court approved budgets attached to each order. Any expenditure that is outside
the ordinary course of business or that is not reflected in the approved budgets
must be specifically authorized by the bankruptcy court. We have accumulated, as
of December 31, 1999, $18.8 million in cash, an increase of $12.8 million since
August 23, 1999, that can be used for operations under the terms of the cash
collateral orders.
The current interim cash collateral order of the bankruptcy court expired
on January 30, 2000. 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 existing bank group loan, we were required to cure the over
advance amount by March 2, 1999 by either:
o providing collateral with value and quantity in amounts equal to
the excess,
o prepaying, without premium or penalty, the excess plus accrued
interest, or
o 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 existing 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 existing 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 existing bank group loan bear
interest at the prime rate, and the loan agreement provides that past due
installments to repay the over advance and past due interest 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 existing bank group loan. The
bank group contends that the default rate of interest is 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 are 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 existing bank group loan contains financial and other covenants
including:
o 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,
o 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,
o limitations on our ability to incur additional debt, and
o 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 existing bonds and are currently in default under the terms
of the existing bond indenture. Under the existing bond indenture, the trustee
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under the existing bond indenture by written notice to us, or the holders of at
least 25% in principal amount of the outstanding existing bonds by written
notice to the trustee and us, may declare the principal and accrued interest on
all the existing bonds due and payable immediately. However, we may not pay the
principal of, any premium or interest on the existing bonds so long as any
required payments due on the existing bank group loan remain outstanding and
have not been cured or waived. On May 19, 1999, we 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%, which is 1% in excess of the stated rate for the existing bonds, from
the date of acceleration to the August 23, 1999. As a result of our bankruptcy
filing we have 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 us in 1999 if
not for the discontinuance of the interest expense accruals. All amounts
outstanding under the existing 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.
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 existing bank group loan.
Plan of Reorganization. We filed our plan of reorganization with the
bankruptcy court on November 30, 1999. Subsequently, we obtained approval of our
plan of reorganization. On March 20, 2000, the bankruptcy court entered an order
confirming our plan of reorganization. We expect the effective date for
consummation of our plan of reorganization will be March 31, 2000.
Under the plan of reorganization, we expect to establish 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. The new credit facility will limit advances to the amount of the
borrowing base, which has been set initially at $205 million. Additionally, $15
million must be available on the effective date in cash and undrawn borrowing
capacity. The borrowing base is the loan value to be assigned to the proved
reserves attributable to our oil and gas properties after reorganization. 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 an independent petroleum
engineering firm acceptable to the new lenders.
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 of the following rates:
o 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
o 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 will be
secured by granting Chase, for the benefit of the new lenders, a lien against
substantially all of our oil and gas properties after reorganization.
The new credit agreement will contain financial and other covenants
including:
o 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 the initial fiscal quarter to commence after the
effective date,
o restrictions on the payment of dividends, and
37
<PAGE> 38
o limitations on the incurrence of additional indebtedness, the
creation of liens and the incurrence of capital expenditures.
To implement the plan of reorganization, we are expected to raise up to
$90 million of new investment by the offering of rights to acquire shares of a
new class of our common stock as discussed in the next paragraph and, if
necessary, up to $90 million in a standby loan.
Under the rights offering, our shareholders as of the record date will
have the exclusive opportunity to buy additional shares of our 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 the rights offering may do so, to the extent that other shareholders do
not elect to participate in the rights offering.
The majority of the funds necessary for the payment of the amount due
under the existing bank group loan will be obtained through an advance under the
new credit facility of the full amount of the initial borrowing base. The
remaining amount due under the existing bank group loan will be paid, if
necessary, from the standby loan. The standby loan is to be made under a senior
subordinated note facility. This amount will be a maximum of $70 million given
the current level of commitment under the standby loan and a maximum of $90
million if more standby loan commitments are obtained and made available before
the effective date. The rights and responsibilities of the standby lenders and
Coho will be governed by a standby loan agreement which will be executed and
delivered on the effective date of the plan of reorganization. We expect the
effective date will be March 31, 2000.
Debt under the standby loan agreement will be evidenced by notes,
maturing seven years after the effective date, and bearing interest at a minimum
annual rate of 15% 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 BOE 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 BOE 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 will be expressly subordinate to
payments in full in cash of all obligations arising in connection with the new
credit facility. Subject to a final agreement between Chase and the standby
lenders, after the initial twelve-month period, cash interest payments may be
made only to the extent by which earnings before interest, tax, depreciation and
amortization expense on a trailing four-quarter basis exceed $65 million. The
new credit facility may also prohibit 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 earnings before
interest, tax, depreciation and amortization expense 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 "Treasury Rate" for the first four
years, or beginning in the fifth year, a premium equal to one- half the 15% base
interest rate declining annually, and ratably to par. "Treasury Rate" is the
yield of U.S. Treasury securities with a term equal to the then-remaining term
of standby loan notes that has become publicly available on the third business
day before the date fixed for repayment.
Cash on hand as of the effective date, together with borrowings under the
new credit facility and, if necessary, borrowings under the standby loan will be
used to:
o repay amounts due under the existing bank group loan, including
accrued interest and reasonable fees and expenses,
o pay administrative expenses associated with the bankruptcy
proceeding, and
o provide working capital for future operations.
38
<PAGE> 39
Proceeds from the rights offering will be used to provide working capital and
for general corporate purposes. 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.
The holders of the our existing bonds will receive shares representing
96% of our new common stock as of the effective date without giving effect to
dilution from shares issued under the rights offering or the standby loan.
Existing shareholders will receive shares representing 4% of our new
common stock on a basis of one share of new common stock for 40 shares of
existing common stock as of the effective date without giving effect to dilution
from shares issued under the rights offering or the standby loan and rights to
purchase additional shares of our new common stock at $10.40 per share.
Additionally, existing shareholders will 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.
Dividends. While we are restricted on the payment of dividends under the
existing bank group loan, dividends are permitted on our equity securities
provided:
o we are not in default under the existing bank group loan; and
o (a) the aggregate sum of the proposed dividend, plus all other
dividends or distributions made since February 8, 1994 do
not exceed 50% of cumulative consolidated net income during
the period from January 1, 1994 to the date of the proposed
dividend, or
(b) the ratio of total consolidated indebtedness, excluding
accounts payable and accrued liabilities to shareholders'
equity does not exceed 1.6 to 1.0 after giving effect to the
proposed dividend or
(c) the aggregate amount of the proposed dividend, plus all
other dividends or distributions made since February 8,
1994, do not exceed 100% of cumulative consolidated net
income for the three fiscal years immediately preceding the
date of payment of the proposed dividend.
The existing bond indenture limits our ability to pay dividends, based on our
ability to incur additional indebtedness and primarily limited to 50% of
consolidated net income earned, excluding any write down of property, plant and
equipment after the date the existing bonds were issued plus the net proceeds
from any future sales of our capital stock. Due to our default under the
existing bank group loan and due to our current and expected capital needs as
discussed above, it is unlikely that we will pay dividends in the foreseeable
future. Additionally, the terms of the new credit facility and the standby loan
will 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 have 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:
o Brookhaven o Tatums
o Laurel o East Fitts
o Martinville o North Alma Deese and
o Summerland o Sholem Alechem.
o Bumpass
39
<PAGE> 40
In addition, during 1998, we drilled 42 wells which include the following:
<TABLE>
<S> <C> <C>
o Mississippi fields o Oklahoma fields o Louisiana fields
-- 16 producing oil wells, -- 11 producing oil wells, -- 2 producing gas wells, and
-- 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 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.
YEAR 2000 ISSUE
We, like other businesses, faced the Year 2000 issue. Many computer
systems and equipment with embedded chips or processors use only two digits to
represent the calendar year. This could result in computational or operational
errors because date sensitive systems will recognize the year 2000 as 1900 or
not at all. This inability to recognize or properly treat the year 2000 may
cause systems to process critical financial and operational information
incorrectly.
State of Readiness. We divided our Year 2000 review into five separate
elements: accounting computer systems, network infrastructure, desktop computers
at corporate headquarters, field operational systems and major suppliers and
purchasers. We completed our Year 2000 review and remediation in December 1999.
We concurrently reviewed Year 2000 compliance of major suppliers and
purchasers. We have contacted our major suppliers and purchasers by letter and
have asked for a written response from them describing their Year 2000 readiness
efforts. To date, we have not identified any material problems associated with
the Year 2000 readiness efforts of our major suppliers and purchasers.
In addition, we created a contingency plan to mitigate potential Year
2000 problems both within Coho and with our major suppliers and purchasers.
Cost. We began our Year 2000 Program in 1997, and have incorporated our
preparations into our normal equipment upgrade cycle. As a result, the
historical cost of our Year 2000 efforts to date has not been material. We do
not estimate future expenditures related to the Year 2000 to be material.
Risks. We believe that we have taken and are taking all reasonable
steps to ensure Year 2000 readiness. Although other unanticipated Year 2000
issues could yet have an adverse effect on our results of operations or our
financial condition, it is not possible to estimate the extent of impact at this
time, though it is unlikely that any effect will be material.
ALL STATEMENTS REGARDING YEAR 2000 MATTERS CONTAINED IN THIS ANNUAL
REPORT ON FORM 10-K ARE "YEAR 2000 READINESS DISCLOSURES" WITHIN THE MEANING OF
THE YEAR 2000 INFORMATION AND READINESS DISCLOSURE ACT.
40
<PAGE> 41
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
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 "Item 7.
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 existing 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 existing bank group
loan discussed under "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations," the existing 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 existing bonds
with an estimated fair market value of $83 million based on quoted prices from
market sources.
We are in default under our existing bank group loan and our existing
bonds. For more information see "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations."
On the effective date of the plan of reorganization, the existing bank
group loan is expected to be paid in full in cash and the existing bonds will be
converted to our new common stock. A new line of credit will be established with
the new lenders and Chase, as agent for the new lenders. If necessary, we may
also obtain additional funds under the standby loan with a maximum commitment of
$90 million. The establishment of the new debt instruments, as discussed above,
is expected to change our interest rate risk.
41
<PAGE> 42
ITEM 8. FINANCIAL STATEMENTS
<TABLE>
<S> <C>
Report of Independent Public Accountants........................................................................ 43
Consolidated Balance Sheets, December 31, 1998 and 1999......................................................... 44
Consolidated Statements of Operations, Years Ended December 31, 1997, 1998 and 1999............................. 45
Consolidated Statements of Shareholders' Equity, Years Ended December 31, 1997, 1998 and 1999................... 46
Consolidated Statements of Cash Flows, Years Ended December 31, 1997, 1998 and 1999............................. 47
Notes to Consolidated Financial Statements, Years Ended December 31, 1997, 1998 and 1999........................ 48
</TABLE>
42
<PAGE> 43
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 operations
and 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 March 20, 2000.)
43
<PAGE> 44
COHO ENERGY, INC.
AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
DECEMBER 31
------------------------
1998 1999
--------- ---------
<S> <C> <C>
ASSETS
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
44
<PAGE> 45
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
45
<PAGE> 46
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
46
<PAGE> 47
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
47
<PAGE> 48
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 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.
48
<PAGE> 49
COHO ENERGY, INC.
AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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 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 EPS
---------- ---------- ---- ---------- ---------- ------ ---------- ---------- ------
(in thousands) (in thousands) (in thousands)
<S> <C> <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 $(1.20)
==== ====== ======
Stock Options 641,099 -- --
---------- ---------- ---------- ---------- ---------- ----------
DILUTED EARNINGS PER $ 6,288 22,333,903 $.28 $ (203,346) 25,603,512 $(7.94) $ (30,715) 25,603,512 $(1.20)
========== ========== ==== ========== ========== ====== ========== ========== ======
SHARE
</TABLE>
49
<PAGE> 50
COHO ENERGY, INC.
AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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
basis. 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 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.
50
<PAGE> 51
COHO ENERGY, INC.
AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
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.
51
<PAGE> 52
COHO ENERGY, INC.
AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
<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. 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.
52
<PAGE> 53
COHO ENERGY, INC.
AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
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
53
<PAGE> 54
COHO ENERGY, INC.
AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
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.
54
<PAGE> 55
COHO ENERGY, INC.
AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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>
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.
55
<PAGE> 56
COHO ENERGY, INC.
AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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 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.
56
<PAGE> 57
COHO ENERGY, INC.
AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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>
57
<PAGE> 58
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>
58
<PAGE> 59
COHO ENERGY, INC.
AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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>
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.
59
<PAGE> 60
COHO ENERGY, INC.
AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
(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
60
<PAGE> 61
COHO ENERGY, INC.
AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
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.
(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
61
<PAGE> 62
COHO ENERGY, INC.
AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
(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.
62
<PAGE> 63
COHO ENERGY, INC.
AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
63
<PAGE> 64
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>
64
<PAGE> 65
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.
65
<PAGE> 66
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. We
anticipate that the effective date of confirmation of our plan of reorganization
will be March 31, 2000.
On 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.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
NONE
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<PAGE> 67
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
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>
Jeffrey Clarke 54 1982
Louis F. Crane (a) 57 1993
Alan Edgar (b) 53 1998
Kenneth H. Lambert (a) 55 1980
Douglas R. Martin (b) 54 1990
Jake Taylor (b) 54 1993
</TABLE>
- ---------------
* Represents the year each individual became a director of us or Coho
Resources, Inc.
(a) Member of the Audit Committee.
(b) Member of the Compensation Committee.
Jeffrey Clarke has served as our Chairman since October 1993 and our
President and Chief Executive Officer since September 1993. Mr. Clarke served as
Executive Vice President and Chief Operating Officer of Coho Resources, Inc.
from May 1982 until May 1990, as President and Chief Operating Officer of Coho
Resources, Inc. from May 1990 to October 1992 and as President and Chief
Executive Officer of Coho Resources, Inc. since October 1992. He served as
Senior Vice President, Chief Operating Officer and a director of Coho Resources
Limited from 1984 to October 1992 and as President and Chief Executive Officer
of Coho Resources Limited since October 1992 and has been engaged by Coho
Resources Limited in various capacities since 1980.
Louis F. Crane has served as President and Chief Executive Officer of
Orleans Capital, an investment portfolio management firm, since November 1991.
Mr. Crane is Chairman of the Board of Offshore Logistics Inc.
Alan Edgar has been an independent financial consultant since January
1999. He served as Managing Director, Co-head Energy Group with Donaldson,
Lufkin & Jenrette Securities Corporation, an investment banking firm, from 1990
until his retirement in December 1998.
Kenneth H. Lambert served as Chairman of the Board of Directors of Coho
Resources, Inc. from 1980 until September 1993, as Chief Executive Officer of
Coho Resources, Inc. from 1980 to 1992 and as President of Coho Resources, Inc.
from 1980 to 1990. Mr. Lambert served as President and Chief Executive Officer
of Coho Resources Limited from 1980 to June 1992, and as Chairman of the Board
of Coho Resources Limited from June 1992 until September 1993. Mr. Lambert has
served as President and Chief Executive Officer of Nugold Technology Ltd., a
private company dealing in the recovery of precious metals, since April 1993.
Mr. Lambert is chairman of the board, president, chief executive officer and
director of Edmonton International Industries Ltd., a Canadian public investment
holding company, the Chairman of the Board of Destination Resorts, Inc., a
Canadian public resort development corporation, and Chairman of the Board of Oz
New Media, a Canadian public educational network, multimedia and digital content
company.
Douglas R. Martin has served as Chairman of Pursuit Resources Corp., a
Canadian public oil and gas company, since September 1993. Mr. Martin served as
Senior Vice President and Chief Financial Officer of Coho Resources, Inc. from
May 1990 to August 1993. He served as the Senior Vice President and Chief
Financial Officer of Coho Resources Limited from April 1990 to August 1993.
Jake Taylor has been an independent financial consultant since 1989.
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<PAGE> 68
Under the terms of the Registration Rights and Shareholder Agreement
dated May 12, 1998, between Energy Investment Partnership No. 1, L.P. and us, we
have agreed to nominate two persons designated by EIP for election to our board
of directors at each annual meeting of our shareholders. Currently, no EIP
designee serves on our board of directors, and EIP has not made any nominations.
If the shares of common stock owned by EIP decreases to both less than one
million shares and less than 4% of the outstanding shares of common stock, our
obligation under the registration rights agreement to nominate any designees of
EIP to our board ceases. The registration rights agreement further provides
that, if our proxy statement for any annual meeting includes a recommendation
regarding the election of any other nominees to our board of directors, we must
include a recommendation that the shareholders also vote in favor of the
nominees of EIP. So long as any designee of EIP serves as one of our directors,
we have agreed to appoint one of those designees to be a member of the
Compensation Committee of the board and, if our board of directors establishes
an Executive Committee, the Executive Committee of the board.
Jeffrey Clarke, our Chairman, President and Chief Executive Officer, and
Keri Clarke, our Vice President, Land and Environmental/Regulatory Affairs, are
brothers. There is no other 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>
Jeffrey Clarke 54 Chairman, President, Chief Executive Officer and Director
R. M. Pearce 48 Executive Vice President and Chief Operating Officer
Anne Marie O'Gorman 41 Senior Vice President, Corporate Development and
Corporate Secretary
Keri Clarke 43 Vice President, Land and Environmental/Regulatory Affairs
R. Lynn Guillory 53 Vice President, Human Resources and Administration
Gary Hoge 56 Vice President, Exploration
Larry L. Keller 41 Vice President, Mid-Continent Division
Susan J. McAden 42 Vice President & Controller
Patrick S. Wright 43 Vice President, Gulf Coast Division
Joseph F. Ragusa 46 Treasurer
</TABLE>
For information concerning Jeffrey Clarke, see the table under the caption
"Directors," above.
R. M. Pearce has served as our Executive Vice President and Chief Operating
Officer since August 1995 and has been an officer of us since November 1993.
From July 1991 to October 1993, Mr. Pearce served as President of GRL Production
Services Company.
Anne Marie O'Gorman was appointed as our Senior Vice President, Corporate
Development, in March 1996 and was Vice President, Corporate Development, of us
from August 1993 and for Coho Resources, Inc. before then. Ms. O'Gorman had been
employed by Coho Resources, Inc. or Coho Resources Limited in various capacities
since 1985. Ms. O'Gorman has served as our Secretary since September 1993.
Keri Clarke has served as Vice President, Land and Environmental/Regulatory
Affairs, of us from August 1993 and for Coho Resources, Inc. before then. He has
also been employed by Coho Resources Limited in various positions since 1981.
R. Lynn Guillory joined us as our Vice President, Human Resources and
Administration, when we acquired Interstate Natural Gas on December 8, 1994. Mr.
Guillory held that same position with Interstate Natural Gas since its inception
in March 1992.
Gary Hoge joined us as Vice President, Exploration in April 1998. From 1994
until he joined us, Mr. Hoge served as Vice President, Exploration for Greenhill
Petroleum. From 1992 until 1994 Mr. Hoge served in several senior positions with
Coffman Exploration and Cielo Energy.
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<PAGE> 69
Larry L. Keller has served as our Vice President, Mid-Continent Division
since August 1998 and Vice President, Exploitation, of us from August 1993 and
for Coho Resources, Inc. before then. He had been employed in various
engineering positions with Coho Resources, Inc. since July 1990.
Susan J. McAden was appointed as our Vice President and Controller in
January 1998 and joined us as Controller in February 1995. From September 1993
to February 1995, Ms. McAden was Vice President and Controller of Lincoln
Property Company, a property development and management company. From November
1990 to September 1993, Ms. McAden was Chief Accounting Officer and Treasurer of
Concap Equities, Inc., the acting general partner for sixteen public real estate
partnerships.
Patrick S. Wright has served as our Vice President, Gulf Coast Division,
since August 1998 and joined us as Vice President, Operations, in January 1996.
From January 1991 until he joined us, Mr. Wright served in several managerial
positions with Snyder Oil Corporation, an international oil and gas exploration
and production company.
Joseph F. Ragusa was appointed Treasurer in January 1998 and joined us as
Assistant Treasurer when we acquired Interstate Natural Gas on December 8, 1994.
Mr. Ragusa held that same position with Interstate Natural Gas since January
1993.
In late 1999, we proposed a work force reduction. In connection with the
proposed work force reduction, Eddie M. LeBlanc, III, is no longer employed by
us. Mr. LeBlanc was our Senior Vice President and Chief Financial Officer.
On February 29, 2000, the majority holders of our existing bonds informed
us that, on the effective date of the plan of reorganization, they would cause a
new chief executive officer to be appointed. Any action to elect a new chief
executive officer has not been taken, and is not expected to be taken, by our
current board of directors, but rather will be taken by our board of directors
as it will exist after the effective date. As a result of the announcement of
the majority bondholders, on the effective date, Mr. Clarke is expected to
resign as our Chairman, President and Chief Executive Officer and as one of our
directors. The majority bondholders have named Mr. Michael McGovern as the
designated future chief executive officer. Mr. McGovern has 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) .
Additionally, Mr. Gary L. Pittman and Mr. Gerald E. Ruley have been named
as the designated future Chief Financial Officer and Vice President of
Operations, respectively, as of the effective date. 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, since
1999. 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. Mr. Ruley has served 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.
With the exception of Mr. Clarke, we expect the above directors and
officers to be our directors and officers after the consummation of our plan of
reorganization, subject to the provisions of this paragraph. Mr. McGovern, the
designated future chief executive officer, has indicated that changes will be
made with respect to certain officers discussed above subsequent to the
consummation of the plan of reorganization. Under our plan of reorganization,
for the first year after the effective date of 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 existing 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.
The four members of the board of directors selected by the principal
holders of existing bonds are set forth below:
Michael McGovern. For information concerning Mr. McGovern, see above.
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<PAGE> 70
Eugene L. 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.
James E. Bolin. Mr. Bolin has served as Vice President and Secretary of
Appaloosa Partners, Inc., and investment firm, 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.
We are not currently aware of the identities of the remaining board members for
the one-year period after confirmation that will be nominated in accordance with
our plan of reorganization.
ITEM 11. 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 Exploitation 1998 $163,000 $ 0 -- $ 83,685
(5)(6) 1997 $143,100 $ 65,000 45,000 $ 10,050
</TABLE>
- -----------
(see notes on following page)
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<PAGE> 71
(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.
(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.
(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.
(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.
(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 October 1997. For more information, see "Item 13. Certain Relationships
and Related Transactions."
(7) Upon consummation of our plan of reorganization, all options will be
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 -- $-- 482,023 0 $ 0 $ 0
R.M. Pearce -- $-- 380,000 0 $ 0 $ 0
Eddie M. LeBlanc, III(3) -- $-- 250,000 0 $ 0 $ 0
Anne Marie O'Gorman -- $-- 203,432 0 $ 0 $ 0
Larry L. Keller -- $-- 78,333 15,000 $ 0 $ 0
</TABLE>
(1) Upon consummation of our plan of reorganization, all options will be
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) 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.
EMPLOYMENT AGREEMENTS
We have entered into employment agreements with each of Messrs. Clarke and
Pearce and Ms. O'Gorman, which provide for minimum annual compensation in the
amount of $300,000, $225,000, and $175,000, respectively, in each case to be
reviewed annually by our board of directors for possible increases. Each
employment agreement is for a term of three years, renewable annually for a term
to extend two years from the renewal date unless either party gives notice. 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. Clarke or Pearce or Ms. O'Gorman terminates his or her
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<PAGE> 72
employment for "Good Reason" (as defined below) or is terminated by Coho for
other than "Cause" (as defined below), Coho would:
o pay that individual a cash lump sum payment equal to two times the
executive's then-current annual rate of total compensation, and
o continue, until the first anniversary of the employment termination,
health and medical benefits under our plans or the equivalent thereof.
If any of Messrs. Clarke or Pearce or Ms. O'Gorman terminates his or her
employment for Good Reason or is terminated by Coho for other than Cause within
three years of a "Change of Control" (as defined below), we will pay the
executive an additional lump sum equal to 0.99 times his or her then-current
annual rate of total compensation and continue health benefits until the third
anniversary of the employment termination. If any of Messrs. Clarke or Pearce or
Ms. O'Gorman becomes disabled or dies during the term of the respective
employment agreement, we will pay the executive or his or her estate
compensation under the employment agreement for a six-month period following
death or disability. Under the Deficit Reduction Act of 1984, severance payments
contingent upon a "change of control" that exceeded a specified amount subject
both us and the officer to adverse U.S. federal income tax consequences. Each of
the employment agreements was amended on March 17, 1997 to provide that we shall
pay the officer a "gross-up" payment to insure that the officer receives the
total benefit intended by the employment agreement.
The term "Good Reason" is defined in each employment agreement generally to
mean:
o the failure by Coho to elect or re-elect the executive to his or her
existing office with Coho without Cause,
o a material change by Coho of the executive's function, duties or
responsibilities that would cause his or her position with Coho to
become of less dignity, responsibility, importance or scope,
o we require the executive to relocate his or her primary office to a
location that is greater than 50 miles from our current location, or
o any other material breach of the employment agreement by Coho.
The term "Cause" is defined in each employment agreement generally to
mean:
o any material failure of the executive after written notice to perform
his or her duties,
o commission of fraud by the executive against Coho, our affiliates or
customers,
o a material breach by the executive of the confidentiality or
non-competition provisions in the employment agreement, or
o 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:
o any person or group of persons acting in concert becomes the
beneficial owner of 20 percent or more of the outstanding shares of
our common stock or the combined voting power of our voting
securities, with specified exceptions,
o individuals who as of the date of the employment agreement constitute
our board of directors or their designated successors cease for any
reason to constitute at least a majority of our board of directors, or
o there occurs a reorganization, merger or consolidation or sale or
other disposition of all or substantially all of our assets unless,
after the transaction:
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<PAGE> 73
-- all or substantially all of those persons who were the beneficial
owners of our common stock before the transaction beneficially
own more than 60 percent of the then-outstanding common stock of
the resulting corporation,
-- only people who owned our common stock before the transaction
beneficially owns 40 percent or more of the then-outstanding
common stock of the resulting corporation, and
-- at least a majority of the board of directors of the corporation
resulting from the transaction were members of our board of
directors at the time of the execution of the initial agreement
or of the action by our board of directors providing for the
corporate transaction.
We currently have an executive severance agreement with Larry L. Keller.
The purpose of the severance agreement is to encourage the executive officer to
continue to carry out his duties with Coho in the event of a "change of control"
of Coho. Under the severance agreement, a "change of control" of Coho is
generally deemed to have occurred if:
o any person or group of persons acting in concert becomes the
beneficial owner of 20 percent or more of the outstanding shares of
our common stock or the combined voting power of our voting
securities, with specified exceptions,
o individuals who as of the date of the severance agreement constitute
our board of directors or their designated successors cease for any
reason to constitute at least a majority of our board of directors,
o our shareholders approve a complete liquidation or dissolution of
Coho, or
o there occurs a reorganization, merger or consolidation or sale or
other disposition of all or substantially all of our assets unless,
after the transaction:
-- all or substantially all of those persons who were the beneficial
owners of our common stock before the transaction beneficially
own more than 60 percent of the then-outstanding common stock of
the resulting corporation, except to the extent their ownership
existed before the corporate transaction,
-- no person, with specified exceptions, beneficially owns 20
percent or more of the then-outstanding common stock of the
resulting corporation, and
-- at least a majority of the board of directors of the corporation
resulting from the transaction were members of our board of
directors at the time of the execution of the initial agreement
or of the action by our board of directors providing for the
corporate transaction.
The severance agreement provides for severance payments in the event of
termination of the executive officer's employment within two years after a
change of control of Coho, unless the executive's employment is terminated by
Coho or our successor for "cause" or because of the executive's death,
"disability" or "retirement" or by the executive's voluntary termination for
other than "good reason," in each case as these terms are defined in the
severance agreement. The benefits include:
o a lump sum payment equal to 1.5 times the highest salary plus bonus
paid to the executive in any of the five years preceding the year of
termination of employment,
o salary to the date of termination, and
o immediate vesting of all stock options or restricted stock awards that
may have been granted to the executive under our employee benefit
plans, except that those options or restricted stock awards shall vest
only to the extent the total payments to the executive under the
severance agreement or otherwise would not be subject to excise taxes
imposed under Section 4999 of the Internal Revenue Code of 1986.
The employment agreements and the severance agreement described above have
been rejected in our plan of reorganization. Settlements associated with these
rejected contracts will be recognized in connection with the reorganization.
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<PAGE> 74
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. If our plan of reorganization is confirmed and consummated, the
total amount of cash awards that will be granted under the retention plan is
$1,472,507, 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.
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 of Coho at any time during 1999.
During 1999 no executive officer of Coho served as:
o 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,
o a director of another entity, one of whose executive officers served
on the compensation committee of our board of directors, or
o 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.
COMPENSATION OF DIRECTORS
DIRECTOR FEES
Directors who are not our employees receive a semi-annual retainer of
$7,000 plus a fee of $500 for each meeting of our board of directors or meeting
of a committee of our board of directors attended in person. If attendance is by
telephone, directors who are not our employees receive a fee of $250 for each
meeting in which he participated. 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.
NON-EMPLOYEE DIRECTOR STOCK OPTION PLAN
Under our 1993 Non-Employee Director Stock Option Plan, for so long as
there is an adequate number of shares available for grant, each person who
becomes a non-employee director of Coho is entitled to receive an option to
purchase 5,000 shares of our common stock at a price per share equal to the
closing sale price of our common stock on the date of his appointment or
election. In addition, and for so long as there is then an adequate number of
shares available for grant under the Non-Employee Director Plan, each
non-employee director is entitled to receive, on the date of each annual meeting
of our shareholders at which he is re-elected as a director, an option to
purchase an additional 1,000 shares of our common stock at the closing sale
price on the date of grant. However, until a non-employee director has received
options under the Non-Employee Director Plan for an aggregate of 15,000 shares
of our common stock, he shall receive an option to purchase 5,000 shares on the
date of each annual meeting of our shareholders at which he is re-elected as
director.
Options granted under the Non-Employee Director Plan are exercisable one
year after the date of grant and must be exercised within five years from the
date the option becomes exercisable. The options terminate on the earlier of the
date of the expiration of the option or one day less than one month after the
date the optionee ceases to serve as a director of Coho for any reason other
than death, disability or retirement of the director. If an optionee retires
from our board of directors or dies while serving as a director of Coho, the
option terminates on the earlier of the date of expiration of the option or one
year following the date of retirement or death.
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<PAGE> 75
During the year ended December 31, 1999, no director was granted options
under the Non-Employee Director Plan. Upon consummation of our plan of
reorganization, we anticipate that the Non-Employee Director Plan will be
terminated.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN 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 March 23, 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>
President and Fellows of Harvard College 3,245,000(2) 12.70%
c/o Harvard Management Company, Inc.
600 Atlantic Avenue
Boston, Massachusetts 02210
Energy Investment Partnership No. 1 2,182,084(3) 8.52%
200 Crescent Court, Suite 1600
Dallas, Texas 75201
</TABLE>
(1) Based on 25,603,512 shares issued and outstanding as of March 1, 2000.
(2) Based solely on information contained in a Schedule 13G dated February
14, 2000 filed with the Commission. President and Fellows of Harvard
College is an employee benefit plan or endowment fund in accordance
with Rule 13d-1(6)(l)(ii)(F) and has sole voting and dispositive power
with respect to 3,245,000 shares of common stock that are owned by it.
(3) Based solely on information contained in a Schedule 13G dated May 20,
1998 filed with the Commission. Energy Investment Partnership No. 1 is
a general partnership and has shared voting and dispositive power with
respect to 2,182,084 shares of common stock that are owned by the
partnership.
75
<PAGE> 76
The following table sets forth information with respect to common stock
beneficially owned as of December 31, 1999 by each of our directors, by each
executive officer named in the Summary Compensation Table and by all directors
and officers as a group. 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(1) OF CLASS
----------------------- --------
<S> <C> <C>
Jeffrey Clarke........................... 551,811 2.2%
Louis F. Crane........................... 27,000 *
Alan E. Edgar............................ 480,000 1.9%
Larry L. Keller 93,505 *
Eddie M. LeBlanc, III**.................. 251,000 *
Kenneth H. Lambert....................... 398,191(2) 1.6%
Douglas R. Martin........................ 6,000 *
Anne Marie O'Gorman...................... 219,766 *
R. M. Pearce............................. 385,000 1.5%
Jake Taylor.............................. 67,400 *
All directors and executive officers as
a group (16 persons)..................... 2,738,315 10.7%
</TABLE>
- ---------------
* Less than 1%
** 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.
(1) Includes 482,023; 13,000; 78,333; 250,000; 5,000; 380,000; 13,000;
203,432 and 1,699,453 shares that may be acquired within 60 days upon
the exercise of stock options held by Messrs. Clarke, Crane, Keller,
LeBlanc, Martin, Pearce and Taylor, Ms. O'Gorman and all directors and
executive officers as a group, respectively. If our plan of
reorganization is consummated, all options will be canceled.
(2) Mr. Lambert is the beneficial owner of the shares held by Lambert
Management Ltd., Lambert Holdings, Ltd., Edmonton International
Industries Ltd., 372268 Alberta Ltd., 249172 Alberta Ltd. and 297139
Alberta Ltd. The number of shares shown as beneficially owned by Mr.
Lambert include the shares owned by these entities and also include
17,523 shares that may be acquired by Mr. Lambert within 60 days upon
the exercise of stock options. Included in Mr. Lambert's total shares
are 31,984 which are held by family members; Mr. Lambert claims no
beneficial interest in these shares.
In addition to the foregoing options, Mr. Keller and all executive officers
and directors as a group held options to acquire 15,000 and 58,498 shares of
existing common stock, respectively, which options were not exercisable within
60 days. If our plan of reorganization is consummated, all options will be
canceled.
ITEM 13. 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 "Item 10. Directors and Executive
Officers of the Registrant." On March 18, 1999, Messrs. Muse and Stuart resigned
from our board of directors.
76
<PAGE> 77
In May 1990 we made a non-interest bearing loan in the amount of $205,000
to Mr. Jeffrey Clarke, our Chairman, President and Chief Executive Officer, to
assist him in the purchase of a house in Dallas, Texas. The loan is unsecured
and repayable when Mr. Clarke ceases to be employed by us, unless Mr. Clarke's
employment is terminated as a result of our current restructuring process, at
which time the loan will be forgiven.
In October 1997 we made non-interest bearing sole recourse loans to Jeffrey
Clarke, our Chairman, President and Chief Executive Officer; Anne Marie
O'Gorman, our Senior Vice President, Corporate Development; Larry Keller, our
Vice President Exploitation; and Kenneth Lambert, one or our 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.
In 1999, we entered into an agreement with Alan Edgar, one of our
directors, that provides 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. If the plan of reorganization is consummated, this agreement will be
rejected.
77
<PAGE> 78
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Documents Filed as a Part of this Report
1. FINANCIAL STATEMENTS
Reference is made to the Index to Financial Statements under Item 8 on page
42.
2. FINANCIAL STATEMENT SCHEDULES
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Report of Independent Public Accountants................................... 82
Schedule III -- Condensed Financial Information - Parent Only.............. 83
</TABLE>
All other schedules and financial statements are omitted because they are
not applicable or the required information is shown in the financial statements
or notes thereto listed above in Item 14(a) 1.
3. EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- -----------
2.1 - Company'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
(incorporated by reference to Exhibit 2.1 to the Company's
Registration Statement on Form S-1 (Registration Number
333-96331)).
2.2 - 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 (incorporated by reference to Exhibit 2.2 to
the Company's Registration Statement on Form S-1 (Registration
Number 333-96331)).
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 Registration
Statement on Form S-1 (Registration Number 333-96331).
3.1 - Articles of Incorporation of the Company (incorporated by
reference to Exhibit 3.1 to the Company's Registration
Statement on Form S-4 (Registration No. 33-65620)).
3.2 - Bylaws of the Company, (incorporated by reference to Exhibit
3.2 to the Company's Registration Statement on Form S-4
(Registration No. 33-65620)).
3.3 - Form of Amended and Restated Articles of Incorporation of
the Company (incorporated by reference to the Company's
Registration Statement on Form S-1 (Registration Number
333-96331)).
3.4 - Form of Amended and Restated Bylaws of the Company
(incorporated by reference to the Company's Registration
Statement on Form S-1 (Registration Number 333-96331)).
4.1 - Articles of Incorporation (included as Exhibit 3.1 above).
4.2 - Bylaws of the Company (included as Exhibit 3.2 above).
4.3 - Rights Agreement dated September 13, 1994 between Coho Energy,
Inc. and Chemical Bank (incorporated by reference to Exhibit 1
to the Company's Form 8-A dated September 13, 1994).
78
<PAGE> 79
4.4 - First Amendment to Rights Agreement made as of December 8,
1994 between Coho Energy, Inc. and Chemical Bank (incorporated
by reference to Exhibit 4.5 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1994).
4.5 - Second Amendment to Rights Agreement as of August 30, 1995
between Coho Energy, Inc. and Chemical Bank (incorporated by
reference to Exhibit 4.1 to the Company's Quarterly Report on
Form 10-Q for the quarter ended September 30, 1995).
4.6 - Third Amendment to Rights Agreement as of August 19, 1998
between Coho Energy, Inc. and Chase Manhattan Bank
(incorporated by reference to Exhibit 4.6 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1998).
4.7 - Indenture dated as of October 1, 1997 for the 8 7/8% Senior
Subordinated Notes due 2007 (incorporated by reference to
Exhibit 4.7 to the Company's Second Amendment dated September
9, 1997 to its Registration Statement on Form S-3
(Registration No. 333-33979)).
4.8 - First Supplemental Indenture dated as of September 2, 1998 for
the 8 7/8% Senior Subordinated Notes due 2007 (incorporated by
reference to Exhibit 4.8 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1998).
4.9 - Form of Amended and Restated Articles of Incorporation of the
Company (included as Exhibit 3.3 above).
4.10 - Form of Amended and Restated Bylaws of the Company (included
as Exhibit 3.4 above).
10.1 - Amended and Restated Registration Rights Agreement dated
December 8, 1994 among Coho Energy, Inc., Kenneth H. Lambert
and Frederick K. Campbell (incorporated by reference to
Exhibit 10.3 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1994).
*10.2 - 1993 Stock Option Plan (incorporated by reference to Exhibit
10.1 to the Company's Registration Statement on Form S-4 (Reg.
No. 33-65620)).
*10.3 - First Amendment to 1993 Stock Option Plan (incorporated by
reference to Exhibit 10.6 to the Company's Quarterly Report on
Form 10-Q for the quarter ended September 30, 1993).
*10.4 - Second Amendment to 1993 Stock Option Plan (incorporated by
reference to Exhibit 10.6 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1994).
*10.5 - Third Amendment to 1993 Stock Option Plan (incorporated by
reference to Exhibit 10.2 to the Company's Quarterly Report on
Form 10-Q for the quarter ended June 30, 1996).
*10.6 - Employment Agreement dated as of November 11, 1994 by and
between Coho Energy, Inc. and Jeffrey Clarke (incorporated by
reference to Exhibit 10.7 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1994).
*10.7 - Employment Agreement dated as of November 11, 1994 by and
between Coho Energy, Inc. and R. M. Pearce (incorporated by
reference to Exhibit 10.8 to the Company's Annual Report Form
10-K for the year ended December 31, 1994).
*10.8 - Employment Agreement dated as of June 25, 1995 by and between
Eddie M. LeBlanc, III and Coho Energy, Inc. (incorporated by
reference to Exhibit 10.1 to the Company's Quarterly Report on
Form 10-Q for the quarterly period ended June 30, 1995).
*10.9 - Employment Agreement dated as of August 19, 1996 by and
between Anne Marie O'Gorman and Coho Energy, Inc.
(incorporated by reference to Exhibit 10.10 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1996).
79
<PAGE> 80
*10.10 - First Amendment to Employment Agreement dated as of August 19,
1996 by and among Jeffrey Clarke and Coho Energy, Inc.
(incorporated by reference to Exhibit 10.11 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1996).
*10.11 - First Amendment to Employment Agreement dated as of August 19,
1996 by and among R. M. Pearce and Coho Energy, Inc.
(incorporated by reference to Exhibit 10.12 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1996).
*10.12 - First Amendment to Employment Agreement dated as of August 19,
1996 by and among Eddie M. LeBlanc and Coho Energy, Inc.
(incorporated by reference to Exhibit 10.13 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1996).
*10.13 - 1993 Non Employee Director Stock Option Plan (incorporated by
reference to Exhibit 10.2 to the Company's Registration
Statement on Form S-4 (Reg. No. 33-65620)).
*10.14 - First Amendment to 1993 Non-Employee Director Stock Option
Plan (incorporated by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the quarter ended
June 30, 1996).
*10.15 - Form of Executive Severance Agreement entered into with each
of Keri Clarke, R. Lynn Guillory, Larry L. Keller, Susan J.
McAden, Joseph Ragusa, Gary Hoge and Patrick S. Wright
(incorporated by reference to Exhibit 10.15 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1995).
10.16 - 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).
10.17 - Fourth Amended and Restated Credit Agreement among Coho
Resources, Inc., Coho Louisiana Production Company, Coho
Exploration, Inc., Coho Acquisitions Company, Coho Energy,
Inc., Banque Paribas, Houston Agency, Bank One, Texas, N.A.,
and MeesPierson N.V. dated as of December 18, 1997
(incorporated by reference to Exhibit 10.23 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1997).
10.18 - First Amendment to the Fourth Amended and Restated Credit
Agreement dated July 7, 1998 among Coho Resources, Inc., Coho
Louisiana Production Company, Coho Exploration, Inc., Coho Oil
& Gas, Inc. (formerly Coho Acquisitions Company), Coho Energy,
Inc., Banque Paribas, Houston Agency, Bank One, Texas, N.A.,
and MeesPierson N.V. (incorporated by reference to Exhibit
10.19 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1998).
10.19 - Second Amendment to the Fourth Amended and Restated Credit
Agreement dated November 13, 1998 among Coho Resources, Inc.,
Coho Louisiana Production Company, Coho Exploration, Inc.,
Coho Oil & Gas, Inc. (formerly Coho Acquisitions Company),
Coho Energy, Inc., Banque Paribas, Houston Agency, Bank One,
Texas, N.A., and MeesPierson N.V. (incorporated by reference
to Exhibit 10.20 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1998).
10.20 - Third Amendment to the Fourth Amended and Restated Credit
Agreement dated November 30, 1998 among Coho Resources, Inc.,
Coho Louisiana Production Company, Coho Exploration, Inc.,
Coho Oil & Gas, Inc. (formerly Coho Acquisitions Company),
Coho Energy, Inc., Banque Paribas, Houston Agency, Bank One,
Texas, N.A., and MeesPierson N.V. (incorporated by reference
to Exhibit 10.21 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1998).
10.21 - Fourth Amendment to the Fourth Amended and Restated Credit
Agreement dated January 29, 1999 among Coho Resources, Inc.,
Coho Louisiana Production Company, Coho Exploration, Inc.,
Coho Oil & Gas, Inc. (formerly Coho Acquisitions Company),
Coho Energy, Inc., Banque Paribas, Houston
80
<PAGE> 81
Agency, Bank One, Texas, N.A., and MeesPierson N.V.
(incorporated by reference to Exhibit 10.22 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1998).
10.22 - 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).
10.23 - Purchase and Sale Agreement 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 31,1997).
10.24 - Shareholder Agreement (incorporated by reference to Item 7(1)
of the Exhibits to the Schedule 13D dated May 18, 1998,
relating to the Company and filed by Energy Investment
Partnership No. 1, Thomas O. Hicks, John R. Muse, Charles W.
Tate, Jack D. Furst, Lawrence D. Stuart, Jr., Michael J.
Levitt, Dan H. Blanks, and David B. Deniger).
10.25 - Amended and Restated Stock Purchase Agreement dated November
4, 1998, by and between Coho Energy, Inc. and HM4 Coho, L.P.
(incorporated by reference to Exhibit 99.1 to the Report on
Form 8-K dated November 18, 1998).
*10.26 - 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).
10.27 - 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 (incorporated by reference to Exhibit 10.27 to the
Company's Registration Statement on Form S-1 (Registration
Statement No. 333-96331)).
21.1 - List of Subsidiaries of the Company (filed herewith).
- --------------
* Represents management contract or compensatory plan or arrangement.
The Company will furnish a copy of any exhibit described above to any
beneficial holder of its securities upon receipt of a written request therefor,
provided that such request sets forth a good faith representation that as of the
record date for the Company's 2000 Annual Meeting of Shareholders, such
beneficial holder is entitled to vote at such meeting, and upon payment to the
Company of a fee compensating the Company for its reasonable expenses in
furnishing such exhibits.
(b) Reports on Form 8-K
None.
81
<PAGE> 82
REPORT FOR INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Shareholders
of Coho Energy, Inc.
Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The information contained in Schedule III
is not a required part of the basic financial statements but is supplementary
information required by the Securities and Exchange Commission. This information
has been subjected to the auditing procedures applied in the audit of the basic
financial statements and, in our opinion, is fairly stated in all material
respects in relation to the basic financial statements taken as a whole.
The basic 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 "Bankruptcy Proceedings,"
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 6, as to which
the date is March 20, 2000.)
82
<PAGE> 83
COHO ENERGY, INC.
AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)
SCHEDULE III
CONDENSED FINANCIAL INFORMATION - PARENT ONLY
The following presents the condensed balance sheets as of December 31, 1998
and 1999 and statements of operations and statements of cash flows for Coho
Energy, Inc., the parent company, for the years ended December 31, 1997, 1998
and 1999.
COHO ENERGY, INC.
(PARENT)
(DEBTOR-IN-POSSESSION)
CONDENSED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
DECEMBER 31
------------------------
1998 1999
--------- ---------
<S> <C> <C>
ASSETS
Current assets
Cash and cash equivalents ........................................... $ 6 $ 5
Accounts receivable ................................................. -- 2
Due from subsidiaries ............................................... 158,913 168,961
--------- ---------
158,919 168,968
Investments in subsidiaries, at equity ................................. (72,179) (102,875)
Other assets ........................................................... 3,871 3,584
--------- ---------
$ 90,611 $ 69,677
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities not subject to compromise:
Current liabilities
Accounts payable, principally trade ................................. $ 36 $ --
Accrued interest .................................................... 2,811 --
Current portion of long term debt (note 4) .......................... 149,007 --
--------- ---------
Total current liabilities ............................ 151,854 --
Liabilities subject to compromise:
Accounts payable, principally trade ................................. -- 30
Accrued liabilities ................................................. -- 510
Accrued interest .................................................... -- 12,014
Current portion of long term debt (note 4) .......................... -- 149,081
--------- ---------
Total liabilities subject to compromise .............. -- 161,635
--------- ---------
151,854 161,635
Shareholders' equity
Preferred stock, par value $0.01 Per share
Authorized 10,000,000 shares, none issued
Common stock, par value $0.01 Per share
Authorized 100,000,000 shares
Issued 25,603,512 shares at december 31, 1998 and 1999 .......... 256 256
Additional paid-in capital .......................................... 137,812 137,812
Retained deficit .................................................... (199,311) (230,026)
--------- ---------
Total shareholders' equity ...................................... (61,243) (91,958)
--------- ---------
$ 90,611 $ 69,677
========= =========
</TABLE>
SEE ACCOMPANYING NOTES TO CONDENSED FINANCIAL INFORMATION
83
<PAGE> 84
SCHEDULE III
COHO ENERGY, INC.
(PARENT)
(DEBTOR-IN-POSSESSION)
CONDENSED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
December 31
---------------------------------------
1997 1998 1999
--------- --------- ---------
<S> <C> <C> <C>
Operating expenses
General and administrative .................... $ 471 $ 666 $ 213
--------- --------- ---------
Other (income) expenses
Interest income from subsidiaries ............. (4,320) (14,519) (9,753)
Interest expense .............................. 3,389 13,864 9,560
Equity in (income) loss of subsidiaries ....... (5,828) 203,326 30,697
--------- --------- ---------
(6,759) 202,671 30,504
--------- --------- ---------
Earnings (loss) before income taxes .............. 6,288 (203,337) (30,717)
Income taxes expense (benefit)
Current expense ............................... -- -- (2)
Deferred expense .............................. -- 9 --
--------- --------- ---------
Net earnings (loss) .............................. $ 6,288 $(203,346) $ (30,715)
========= ========= =========
Basic earnings (loss)per common share ............ $ .29 $ (7.94) $ (1.20)
========= ========= =========
Diluted earnings (loss) per common share ......... $ .28 $ (7.94) $ (1.20)
========= ========= =========
</TABLE>
See accompanying Notes to Condensed Financial Information
84
<PAGE> 85
SCHEDULE III
COHO ENERGY, INC.
(PARENT)
(DEBTOR-IN-POSSESSION)
CONDENSED 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
by operating activities:
Equity in loss (income) of subsidiaries ................................... (5,828) 203,346 30,697
Amortization of debt issue costs and other ................................ -- 552 339
Deferred income taxes ..................................................... -- 9 --
Changes in:
Other assets .............................................................. (22) (12) 20
Accounts payable .......................................................... 3,312 (480) 9,707
--------- --------- ---------
Net cash provided by operating activities .................................... 3,750 49 10,048
--------- --------- ---------
Cash flows from investing activities
Investments in subsidiaries ............................................... (26,397) (21,900) --
Advances from (to) subsidiaries ........................................... (172,967) 21,830 (10,048)
--------- --------- ---------
Net cash used in investing activities ........................................ (199,364) (70) --
--------- --------- ---------
Cash flows from financing activities
Increase in long term debt ................................................ 148,894 -- --
Debt issuance cost ........................................................ (4,275) -- --
Issuance of common stock .................................................. 49,223 -- --
Proceeds from stock options exercised ..................................... 1,495 -- --
--------- --------- ---------
Net cash provided by financing activities .................................... 195,337 -- --
--------- --------- ---------
Decrease in cash ............................................................. (277) (21) --
Cash and cash equivalents at beginning of period ............................. 304 27 6
--------- --------- ---------
Cash and cash equivalents at end of period ................................... $ 27 $ 6 $ 6
========= ========= =========
</TABLE>
See accompanying Notes to Condensed Financial Information
85
<PAGE> 86
SCHEDULE III
COHO ENERGY, INC.
(PARENT)
(DEBTOR-IN-POSSESSION)
NOTES TO CONDENSED FINANCIAL INFORMATION
FOR THE YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999
1. GENERAL
The accompanying condensed financial information of Coho Energy, Inc.
(the "Company") should be read in conjunction with the consolidated financial
statements of the Company and its subsidiaries included in the Company's Annual
Report on Form 10-K for the year ended December 31, 1999.
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 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 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.
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As a result of the Chapter 11 filing, the Company's wholly owned
subsidiaries have incurred and will continue to incur significant costs for
professional fees as the Plan of Reorganization is developed. Approximately $3.1
million in reorganization costs have been incurred 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.
3. COMMITMENTS AND CONTINGENCIES
The Company has guaranteed $239.6 million of debt related to
unconsolidated subsidiaries under the existing revolving credit facility (the
"Existing Bank Group Loan Agreement"). Currently, the subsidiaries are in
default on such debt as discussed in Note 4 to the Consolidated Financial
Statements of the Company.
The Existing Bank Group Loan Agreement contains certain financial and
other covenants including (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 ability to incur additional debt, and (iv)
restrictions on the payment of dividends. At December 31, 1999, the Company was
not in compliance with shareholder's equity, cash flow to interest expense and
current assets to current liabilities covenants.
4. LONG -TERM DEBT
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 5, 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.
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.
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5. 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 Bonds 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 $3.4 million, 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. This noncash transaction is not
reflected in the statement of cash flows for the year ended December 31, 1997.
6. 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. We
anticipate the effective date of confirmation of our plan of reorganization will
be March 31, 2000.
On 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.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities and
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Coho Energy, Inc.
Date: March 29, 2000 By: /s/ JEFFREY CLARKE
------------------------------------------------
Jeffrey Clarke
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities and Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
/s/ JEFFREY CLARKE Chairman, President March 29, 2000
- ---------------------------------------- Chief Executive Officer
Jeffrey Clarke and Director (Principal
Executive Officer and
Principal Financial Officer)
/s/ SUSAN J. MCADEN Vice President and Controller March 29, 2000
- ---------------------------------------- (Principal Accounting Officer)
Susan J. McAden
/s/ LOUIS F. CRANE Director March 29, 2000
- ----------------------------------------
Louis F. Crane
/s/ ALAN EDGAR Director March 29, 2000
- ----------------------------------------
Alan Edgar
/s/ KENNETH H. LAMBERT Director March 29, 2000
- ----------------------------------------
Kenneth H. Lambert
/s/ DOUGLAS R. MARTIN Director March 29, 2000
- ----------------------------------------
Douglas R. Martin
/s/ JAKE TAYLOR Director March 29, 2000
- ----------------------------------------
Jake Taylor
</TABLE>
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<PAGE> 90
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C>
2.1 - Company'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
(incorporated by reference to Exhibit 2.1 to the Company's
Registration Statement on Form S-1 (Registration Number
333-96331)).
2.2 - 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 (incorporated by reference to Exhibit 2.2 to
the Company's Registration Statement on Form S-1 (Registration
Number 333-96331)).
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 Registration
Statement on Form S-1 (Registration Number 333-96331).
3.1 - Articles of Incorporation of the Company (incorporated by
reference to Exhibit 3.1 to the Company's Registration
Statement on Form S-4 (Registration No. 33-65620)).
3.2 - Bylaws of the Company, (incorporated by reference to Exhibit
3.2 to the Company's Registration Statement on Form S-4
(Registration No. 33-65620)).
3.3 - Form of Amended and Restated Articles of Incorporation of
the Company (incorporated by reference to the Company's
Registration Statement on Form S-1 (Registration Number
333-96331)).
3.4 - Form of Amended and Restated Bylaws of the Company
(incorporated by reference to the Company's Registration
Statement on Form S-1 (Registration Number 333-96331)).
4.1 - Articles of Incorporation (included as Exhibit 3.1 above).
4.2 - Bylaws of the Company (included as Exhibit 3.2 above).
4.3 - Rights Agreement dated September 13, 1994 between Coho Energy,
Inc. and Chemical Bank (incorporated by reference to Exhibit 1
to the Company's Form 8-A dated September 13, 1994).
</TABLE>
<PAGE> 91
<TABLE>
<S> <C>
4.4 - First Amendment to Rights Agreement made as of December 8,
1994 between Coho Energy, Inc. and Chemical Bank (incorporated
by reference to Exhibit 4.5 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1994).
4.5 - Second Amendment to Rights Agreement as of August 30, 1995
between Coho Energy, Inc. and Chemical Bank (incorporated by
reference to Exhibit 4.1 to the Company's Quarterly Report on
Form 10-Q for the quarter ended September 30, 1995).
4.6 - Third Amendment to Rights Agreement as of August 19, 1998
between Coho Energy, Inc. and Chase Manhattan Bank
(incorporated by reference to Exhibit 4.6 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1998).
4.7 - Indenture dated as of October 1, 1997 for the 8 7/8% Senior
Subordinated Notes due 2007 (incorporated by reference to
Exhibit 4.7 to the Company's Second Amendment dated September
9, 1997 to its Registration Statement on Form S-3
(Registration No. 333-33979)).
4.8 - First Supplemental Indenture dated as of September 2, 1998 for
the 8 7/8% Senior Subordinated Notes due 2007 (incorporated by
reference to Exhibit 4.8 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1998).
4.9 - Form of Amended and Restated Articles of Incorporation of the
Company (included as Exhibit 3.3 above).
4.10 - Form of Amended and Restated Bylaws of the Company (included
as Exhibit 3.4 above).
10.1 - Amended and Restated Registration Rights Agreement dated
December 8, 1994 among Coho Energy, Inc., Kenneth H. Lambert
and Frederick K. Campbell (incorporated by reference to
Exhibit 10.3 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1994).
*10.2 - 1993 Stock Option Plan (incorporated by reference to Exhibit
10.1 to the Company's Registration Statement on Form S-4 (Reg.
No. 33-65620)).
*10.3 - First Amendment to 1993 Stock Option Plan (incorporated by
reference to Exhibit 10.6 to the Company's Quarterly Report on
Form 10-Q for the quarter ended September 30, 1993).
*10.4 - Second Amendment to 1993 Stock Option Plan (incorporated by
reference to Exhibit 10.6 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1994).
*10.5 - Third Amendment to 1993 Stock Option Plan (incorporated by
reference to Exhibit 10.2 to the Company's Quarterly Report on
Form 10-Q for the quarter ended June 30, 1996).
*10.6 - Employment Agreement dated as of November 11, 1994 by and
between Coho Energy, Inc. and Jeffrey Clarke (incorporated by
reference to Exhibit 10.7 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1994).
*10.7 - Employment Agreement dated as of November 11, 1994 by and
between Coho Energy, Inc. and R. M. Pearce (incorporated by
reference to Exhibit 10.8 to the Company's Annual Report Form
10-K for the year ended December 31, 1994).
*10.8 - Employment Agreement dated as of June 25, 1995 by and between
Eddie M. LeBlanc, III and Coho Energy, Inc. (incorporated by
reference to Exhibit 10.1 to the Company's Quarterly Report on
Form 10-Q for the quarterly period ended June 30, 1995).
*10.9 - Employment Agreement dated as of August 19, 1996 by and
between Anne Marie O'Gorman and Coho Energy, Inc.
(incorporated by reference to Exhibit 10.10 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1996).
</TABLE>
79
<PAGE> 92
<TABLE>
<S> <C>
*10.10 - First Amendment to Employment Agreement dated as of August 19,
1996 by and among Jeffrey Clarke and Coho Energy, Inc.
(incorporated by reference to Exhibit 10.11 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1996).
*10.11 - First Amendment to Employment Agreement dated as of August 19,
1996 by and among R. M. Pearce and Coho Energy, Inc.
(incorporated by reference to Exhibit 10.12 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1996).
*10.12 - First Amendment to Employment Agreement dated as of August 19,
1996 by and among Eddie M. LeBlanc and Coho Energy, Inc.
(incorporated by reference to Exhibit 10.13 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1996).
*10.13 - 1993 Non Employee Director Stock Option Plan (incorporated by
reference to Exhibit 10.2 to the Company's Registration
Statement on Form S-4 (Reg. No. 33-65620)).
*10.14 - First Amendment to 1993 Non-Employee Director Stock Option
Plan (incorporated by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the quarter ended
June 30, 1996).
*10.15 - Form of Executive Severance Agreement entered into with each
of Keri Clarke, R. Lynn Guillory, Larry L. Keller, Susan J.
McAden, Joseph Ragusa, Gary Hoge and Patrick S. Wright
(incorporated by reference to Exhibit 10.15 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1995).
10.16 - 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).
10.17 - Fourth Amended and Restated Credit Agreement among Coho
Resources, Inc., Coho Louisiana Production Company, Coho
Exploration, Inc., Coho Acquisitions Company, Coho Energy,
Inc., Banque Paribas, Houston Agency, Bank One, Texas, N.A.,
and MeesPierson N.V. dated as of December 18, 1997
(incorporated by reference to Exhibit 10.23 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1997).
10.18 - First Amendment to the Fourth Amended and Restated Credit
Agreement dated July 7, 1998 among Coho Resources, Inc., Coho
Louisiana Production Company, Coho Exploration, Inc., Coho Oil
& Gas, Inc. (formerly Coho Acquisitions Company), Coho Energy,
Inc., Banque Paribas, Houston Agency, Bank One, Texas, N.A.,
and MeesPierson N.V. (incorporated by reference to Exhibit
10.19 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1998).
10.19 - Second Amendment to the Fourth Amended and Restated Credit
Agreement dated November 13, 1998 among Coho Resources, Inc.,
Coho Louisiana Production Company, Coho Exploration, Inc.,
Coho Oil & Gas, Inc. (formerly Coho Acquisitions Company),
Coho Energy, Inc., Banque Paribas, Houston Agency, Bank One,
Texas, N.A., and MeesPierson N.V. (incorporated by reference
to Exhibit 10.20 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1998).
10.20 - Third Amendment to the Fourth Amended and Restated Credit
Agreement dated November 30, 1998 among Coho Resources, Inc.,
Coho Louisiana Production Company, Coho Exploration, Inc.,
Coho Oil & Gas, Inc. (formerly Coho Acquisitions Company),
Coho Energy, Inc., Banque Paribas, Houston Agency, Bank One,
Texas, N.A., and MeesPierson N.V. (incorporated by reference
to Exhibit 10.21 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1998).
10.21 - Fourth Amendment to the Fourth Amended and Restated Credit
Agreement dated January 29, 1999 among Coho Resources, Inc.,
Coho Louisiana Production Company, Coho Exploration, Inc.,
Coho Oil & Gas, Inc. (formerly Coho Acquisitions Company),
Coho Energy, Inc., Banque Paribas, Houston
</TABLE>
<PAGE> 93
<TABLE>
<S> <C>
Agency, Bank One, Texas, N.A., and MeesPierson N.V.
(incorporated by reference to Exhibit 10.22 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1998).
10.22 - 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).
10.23 - Purchase and Sale Agreement 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 31,1997).
10.24 - Shareholder Agreement (incorporated by reference to Item 7(1)
of the Exhibits to the Schedule 13D dated May 18, 1998,
relating to the Company and filed by Energy Investment
Partnership No. 1, Thomas O. Hicks, John R. Muse, Charles W.
Tate, Jack D. Furst, Lawrence D. Stuart, Jr., Michael J.
Levitt, Dan H. Blanks, and David B. Deniger).
10.25 - Amended and Restated Stock Purchase Agreement dated November
4, 1998, by and between Coho Energy, Inc. and HM4 Coho, L.P.
(incorporated by reference to Exhibit 99.1 to the Report on
Form 8-K dated November 18, 1998).
*10.26 - 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).
10.27 - 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 (incorporated by reference to Exhibit 10.27 to the
Company's Registration Statement on Form S-1 (Registration
Statement No. 333-96331)).
21.1 - List of Subsidiaries of the Company (filed herewith).
</TABLE>
- --------------
* Represents management contract or compensatory plan or arrangement.
The Company will furnish a copy of any exhibit described above to any
beneficial holder of its securities upon receipt of a written request therefor,
provided that such request sets forth a good faith representation that as of the
record date for the Company's 2000 Annual Meeting of Shareholders, such
beneficial holder is entitled to vote at such meeting, and upon payment to the
Company of a fee compensating the Company for its reasonable expenses in
furnishing such exhibits.
<PAGE> 1
EXHIBIT 21.1
COHO ENERGY, INC.
LIST OF SUBSIDIARIES
Coho Resources Limited, Alberta, Canada (100% subsidiary of Coho Energy, Inc.)
Coho Resources, Inc., Nevada (owned 41.14% by Coho Resources Limited and 58.86%
by Coho Energy, Inc.)
Coho Marketing & Transportation, Inc., Nevada (100% subsidiary of Coho
Resources, Inc.)
Coho Shell Company, Delaware (100% subsidiary of Coho Energy, Inc.)
Profile Petroleum Ltd., Alberta, Canada (100% subsidiary of Coho Resources
Limited)
Grayon Development Limited, Alberta, Canada (100% subsidiary of Coho Resources
Limited)
Coho International Limited, Bahamas (100% subsidiary of Coho Resources Limited)
Coho Anaguid, Inc., Delaware (100% subsidiary of Coho Resources, Inc.)
Interstate Natural Gas Company, Delaware (100% subsidiary of Coho Resources,
Inc.)
Coho Exploration, Inc., Delaware (100% subsidiary of Interstate Natural Gas
Company)
Coho Louisiana Production Company, Delaware (100% subsidiary of Interstate
Natural Gas Company)
Coho Oil & Gas, Inc., Delaware (100% subsidiary of Coho Resources, Inc.)
