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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
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
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
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(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification Number)
14785 Preston Road, Suite 860
Dallas, Texas 75240
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:
(972) 774-8300
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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
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Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
As of March 23, 1998, 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 $178.9 million based upon the closing price on the Nasdaq
Stock Market on such date. The officers and directors of the registrant are
considered affiliates for purposes of this calculation.
DOCUMENTS INCORPORATED BY REFERENCE
There is incorporated by reference in Part III of this Annual Report on
Form 10-K certain information contained under the headings "Directors and
Executive Officers of the Registrant", "Executive Compensation", "Certain
Relationships and Related Transactions" and "Security Ownership of Certain
Beneficial Owners and Management" in the registrant's Proxy Statement for the
Company's Annual Meeting of Shareholders proposed to be held May 12, 1998 which
Proxy Statement shall be filed within 120 days of the end of the Registrant's
fiscal year.
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TABLE OF CONTENTS
PAGE
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PART I
Item 1. Business .................................................................................. 3
Item 2. Properties ................................................................................ 18
Item 3. Legal Proceedings ......................................................................... 18
Item 4. Submission of Matters to a Vote of Security Holders ....................................... 19
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters ..................... 20
Item 6. Selected Financial Data ................................................................... 21
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations ................................................................. 22
Item 8. Consolidated Financial Statements ......................................................... 32
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure .................................................................. 53
PART III
Item 10. Directors and Executive Officers of the Registrant ........................................ 53
Item 11. Executive Compensation .................................................................... 53
Item 12. Security Ownership and Certain Beneficial Owners and Management ........................... 53
Item 13. Certain Relationships and Related Transactions ............................................ 53
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K ........................... 54
FORWARD-LOOKING STATEMENTS
This Form 10-K includes certain statements that may be deemed to be
"forward-looking statements" within the meaning of Section 27A of the Securities
Act of 1933, as amended (the "Securities Act"), and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements, other than
statements of historical facts, included in this Form 10-K that address
activities, events or developments that the Company expects, projects, believes
or anticipates will or may occur in the future, including such matters as crude
oil and natural gas reserves, future acquisitions, future drilling and
operations, future capital expenditures, future production of crude oil and
natural gas and future net cash flow are forward-looking statements. These
statements are based on certain assumptions and analyses made by management of
the Company in light of its experience and its perception of historical trends,
current conditions, expected future developments and other factors it believes
are appropriate in the circumstances. Such statements are subject to a number of
assumptions, risks and uncertainties, including those related to competition,
general economic and business conditions, prices of crude oil and natural gas,
the business opportunities (or lack thereof) that may be presented to and
pursued by the Company, changes in laws or regulations and other factors, many
of which are beyond the control of the Company.
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PART I
ITEM 1. BUSINESS AND PROPERTIES
GENERAL
Coho Energy, Inc. (the "Company") 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. The Company's
crude oil activities are concentrated principally in Mississippi and Oklahoma,
where, to the Company's knowledge, it is each state's largest producer of crude
oil. The Company's natural gas activities are concentrated principally in
Louisiana, where it has a stable reserve base and production that should be
sustainable with minimal incremental capital expenditures. At December 31, 1997,
the Company's total proved reserves were 119.7 MMBOE with a Present Value of
Proved Reserves of $526.3 million, approximately 65% of which were proved
developed reserves. At December 31, 1997, approximately 79% of Coho's total
proved reserves were comprised of crude oil. At December 31, 1997, the Company
owned an average working interest of 85% in and operated over 90% of its
producing properties.
The Company commenced operations in Mississippi in the early 1980s and
to date has focused most of its development efforts in that area. Coho believes
that the salt basin in central Mississippi offers significant long-term
potential due to the basin's large number of mature fields with multiple
hydrocarbon bearing horizons. 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 the Company's experience in exploiting fields in the area, Coho has
accumulated a large inventory of potential development drilling, secondary
recovery and exploration projects in this basin.
In December 1997, the Company acquired interests in 14 principal
producing fields located primarily in southern Oklahoma. These properties are
very similar to the Company's Mississippi properties and the Company believes
that it will be able to apply its proven knowledge base and experience in the
development of these properties. The Company believes that its concentration in
the onshore Gulf Coast region provides it with important competitive advantages
such as its extensive databases, operational infrastructure and economies of
scale.
The Company's focus in the onshore Gulf Coast region has resulted in
significant production, reserve and EBITDA growth. The Company's average net
daily production has increased in each of the last five years from 4,819 BOE in
1992 to 11,227 BOE in 1997, representing a compound annual growth rate of 18.4%.
Over the five-year period ended December 31, 1997, the Company discovered or
acquired approximately 102.3 MMBOE of proved reserves at an average finding cost
of $5.07 per BOE. Over the same period, the Company has replaced over 500% of
its production. This increase in reserves from 32.4 MMBOE at year end 1992 to
119.7 MMBOE at year-end 1997 represents a five-year compound annual growth rate
of 30%. Concurrent with the increase in production, EBITDA has increased from
$16.9 million in 1992 to $40.0 million in 1997.
BUSINESS STRATEGY
The Company pursues a multifaceted growth strategy, as follows:
Relatively Low-Risk Field Development. The Company intends to maximize
production and continue to increase reserves through relatively low-risk
activities such as development/delineation drilling, including high-angle and
horizontal drilling, multi-zone completions, recompletions, enhancement of
production facilities and secondary recovery projects. Since 1994, the Company
has drilled 62 development wells, of which 90% were completed successfully. The
Company anticipates that approximately 74% of its total 1998 capital expenditure
budget will be allocated to such relatively low-risk, high-return projects,
including secondary recovery projects which will comprise approximately 35% of
the total 1998 capital expenditure budget.
Use of Technology. The Company intends to identify exploration
prospects and develop reserves in the vicinity of its existing fields using
technologies that include 3-D seismic technology. The Company first began using
3-D seismic technology in the Laurel field in Mississippi in 1983, and has
recently shot two large 3-D seismic programs in
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and around its existing properties. These programs have produced an attractive
inventory of exploration projects that the Company plans to pursue.
Acquire Properties with Underdeveloped Reserves. The Company acquires
underdeveloped crude oil and natural gas properties which have geological
complexity and multiple producing horizons. Management believes that the
Company's extensive experience in Mississippi developed over the past 14 years
should enable it to efficiently increase reserves and improve production rates
in similar geologically complex environments. Additionally, management believes
that this experience gives the Company a competitive advantage in evaluating
similarly situated acquisition prospects. See "Oil and Gas Operations -
Principal Areas of Activity - Oklahoma".
Significant Control of Operations. Coho's strategy of increasing
production and reserves through acquiring and developing multiple-zone fields
requires the Company to develop a thorough understanding of the complex
geological structures and maintain operational control of field development.
Therefore, the Company strives to operate and obtain high working interests in
all its properties. As of December 31, 1997, Coho operated over 90% and had an
average working interest of 85% in its producing properties. Operating
Control, combined with the Company's significant technical and geological
expertise, enables the Company to control the magnitude and timing of capital
expenditures and field development.
Geographic Focus. The Company has been able to maintain a low cost
structure through asset concentration. At December 31, 1997, approximately 94%
of the Company's Mississippi reserves were concentrated in five fields, and 76%
of the Company's Oklahoma reserves were concentrated in six fields. Asset
concentration permits operating economies of scale and leverages operational,
technical and marketing capabilities. As a result, the Company has been able to
achieve favorable average production costs of $3.90 per BOE and favorable cash
margins of $9.81 per BOE for 1997.
OTHER ACTIVITIES. Effective December 31, 1997, the Company acquired
approximately 50 MMBbls of crude oil and natural gas liquid reserves and
approximately 33 BCF of natural gas reserves as well as interests in more than
25,000 gross acres concentrated primarily in southern Oklahoma, including 14
principal producing fields, from Amoco Production Company. Daily net production
from the properties during December 1997 was approximately 7,300 BOE.
Consideration paid by the Company for the acquisition of these properties was
$257.5 million cash and warrants to purchase one million common shares of the
Company at $10.425 per share for a period of five years.
On April 3, 1996, Interstate Natural Gas Company ("ING"), a wholly
owned subsidiary of the Company, sold all of the stock of three wholly-owned
subsidiaries that comprised its natural gas marketing and transportation segment
to an unrelated third party for cash of $19.5 million, the assumption of net
liabilities of approximately $2.3 million and the payment of taxes of $1.2
million generated as a result of the tax treatment of the transaction.
Accordingly, the marketing and transportation segment is accounted for as
discontinued operations herein.
THE COMPANY. The Company was incorporated in June 1993 under the laws
of the State of Texas and conducts a majority of its operations through its
subsidiary Coho Resources, Inc. ("CRI"). Prior to September 29, 1993, CRI was a
publicly held company of which Coho Resources Limited, a publicly held Alberta,
Canada company ("CRL"), held a 68% ownership interest. As a result of a
reorganization of the Company effective on September 29, 1993, CRI and CRL
became wholly-owned subsidiaries of Coho Energy, Inc.
References herein to "Coho" or the "Company", except as otherwise
indicated, refer to Coho Energy, Inc. and its subsidiaries, including CRI, CRL
and ING. The Company's principal executive office is located at 14785 Preston
Road, Suite 860, Dallas, Texas 75240, and its telephone number is (972)
774-8300.
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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 shall apply to the technical terms
used herein:
"Bbls" means barrels of crude oil, condensate or natural gas liquids,
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 the Company has 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 the
Company's 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
reserves that exist behind the casing of existing wells when the cost of making
such reserves available for production is relatively small relative to the cost
of a new well.
"Proved reserves or 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.
"Secondary recovery" means a method of oil and natural gas extraction
in which energy sources extrinsic to the reservoir are utilized.
"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 such
acreage contains proved reserves.
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OIL AND GAS OPERATIONS
Coho has focused its operations on three main activities: conventional
exploitation, secondary recovery and exploration. Each of these interrelated
activities plays an important role in the Company's continuing production and
reserve growth. Coho's 1997 operations have been conducted primarily in the
Brookhaven, Laurel, Martinville, Soso and Summerland fields in Mississippi, and
the Monroe field in Louisiana. In addition, in December 1997, the Company
acquired interests in 14 producing fields located primarily in southern
Oklahoma.
Conventional Exploitation. The Mississippi salt basin is 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. In 1997, Coho spent approximately $53
million of its total capital expenditures of $73 million, excluding the Oklahoma
property acquisition, on exploitation projects. At December 31, 1997, Coho had
ongoing exploitation projects in the Brookhaven, Laurel, Martinville, Soso and
Summerland fields in Mississippi. Coho has been able to achieve significant
production and reserve increases in these fields as a result of these efforts.
Acquisition of mature underdeveloped and underexplored fields has been
one of the key elements to the Company's strategy of building reserves and
creating shareholder value. By capitalizing on its operating knowledge and
technical expertise, the Company has been able to acquire properties and develop
substantial additional low-cost reserves through conventional development
drilling and exploration opportunities. This strategy is illustrated in the
Company's 1995 acquisition of the Brookhaven field in Mississippi. Since
acquiring this property, the Company has increased total daily field production
from successful exploitation and exploration to approximately 1,100 net BOE at
December 31, 1997, from approximately 230 net BOE at the time of acquisition.
The Company believes it will be able to apply its experience in the Mississippi
salt basin to the newly acquired properties in Oklahoma and significantly
increase production and reserves from these properties.
Secondary Recovery. Over the last four years, Coho has 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. In 1997, Coho spent approximately $21 million of its total
capital expenditure budget on secondary recovery projects. 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. Coho's secondary recovery projects in general produce higher gravity
crude oil which is then blended with heavier crude oils from other reservoirs to
yield higher price realizations. The Company believes opportunities exist for
adding secondary recovery projects throughout the Company's current field
inventory.
Exploration. Because of the many productive formations in the
Mississippi salt basin, dry hole risks are substantially reduced, improving
exploration economics. The Company has drilled several successful exploration
wells in the currently defined Brookhaven, Laurel and Martinville fields. Coho
has recently expanded its exploration program and plans to allocate 25% of its
1998 capital budget to exploration. In 1995, Coho 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. Two additional
exploration wells are planned for Martinville in 1998. In 1996, Coho completed a
37-square mile 3-D seismic survey encompassing the Laurel field, Coho's 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 for 1998, and a
"look-alike" prospect west of the Laurel field has been identified. The Company
recognizes deep exploration potential in the Smackover formation at the Soso
field and is currently permitting for a 2-D seismic program in the second
quarter of 1998. In addition to the exploratory success in Brookhaven mentioned
above, the Company believes each of these fields has significant exploration
reserve potential relative to the Company's reserve base.
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Principal Areas of Activity
The following table sets forth, for Coho's major producing fields,
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, 1997, and the
number of productive wells producing at December 31, 1997, all of which are
crude oil wells unless otherwise indicated:
Year Ended December 31, At December 31, 1997
---------------------------- -----------------------------------
1995 1996 1997
---- ---- ---- Net Average
BOE/ BOE/ BOE/ Productive Percentage Working
Field day day day Wells Operated Interest
----- ---- ---- ---- ---------- ---------- --------
Brookhaven, Mississippi ... 130(a) 416 952 21 100% 94%
Laurel, Mississippi ....... 3,470 3,317 3,248 36 100 92
Martinville, Mississippi .. 343 580 1,349 23 100 94
Monroe, Louisiana (b) ..... 3,097 2,892 2,848 2,670 100 98
Soso, Mississippi ......... 470 772 1,197 25 100 93
Summerland, Mississippi ... 1,242 1,451 1,125 20 100 90
Oklahoma properties (c) ... -- -- -- 545 69 58
Other (d) ................. 453 341 508 10 42 53
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Total ........... 9,205 9,769 11,227 3,350 92 85
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(a) Calculated as a 365 day average, although the effective acquisition date was
July 1, 1995.
(b) All gross and net wells located in Monroe, Louisiana, are productive natural
gas wells.
(c) These properties were acquired effective December 31, 1997. No production
was recorded in 1997.
(d) Of the wells indicated, two wells are productive natural gas wells.
Brookhaven Field, Mississippi. In 1995, the Company purchased a 93%
working interest in the unitized Brookhaven field covering more than 13,000
acres. 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.
Like other fields, Coho made the acquisition anticipating additional
field-wide recoveries through development drilling, recompletions, secondary
recovery and exploration. During its first year of ownership, the Company
focused its efforts on expanding its understanding of the Tuscaloosa reservoir.
Company mapping suggested less than 25% of the oil in place from the Tuscaloosa
reservoir had been recovered. As a result of its study, the Company identified
and drilled six new Tuscaloosa well bores in the field in 1996 and 1997. The six
penetrations found unswept crude oil reserves associated with structural and
stratigraphic complexity. Four of these penetrations were completed as
commercial producers and two wells will be used as injectors to aid the
secondary recovery operations.
In addition to its exploitation success, the Company has had
significant exploration success. In June 1997, the Company announced successful
deep exploratory test results in the Washita Fredricksburg at 11,500 feet, the
Paluxy at 12,500 feet and the Rodessa at 15,000 feet. Delineation drilling for
the Washita Fredricksburg and Paluxy continued during the second half of 1997,
and current production from these horizons is in excess of 1,200 gross BOPD. A
delineation well to the discovery Rodessa well is currently drilling.
Delineation drilling on this 23-square mile structure will continue throughout
1998.
As a result of the exploration success at Brookhaven, the Company has
leased approximately 6,500 net acres on a similar geologic structure near the
Brookhaven field. Exploration drilling will commence on this structure during
1998. Production in Brookhaven in 1997 averaged 952 BOE per day and proved
reserves at December 31, 1997 were 5.6 MMBOE, a 96% increase over 1996.
Laurel Field, Mississippi. The Laurel field is a multi-pay geological
setting with producing horizons from the Eutaw formation (approximately 7,500
feet) to the Hosston formation (approximately 13,500 feet). It is the Company's
largest oil producing property and represented approximately 29% of Coho's total
production on a BOE basis during
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1997. At December 31, 1997, the field contained 39 wells producing from the
Stanley, Christmas, Tuscaloosa, Washita Fredricksburg, Paluxy, Mooringsport,
Rodessa, Sligo and Hosston reservoirs. Proved reserves at Laurel totaled 15.3
MMBbls at December 31, 1997.
The Company considers 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 only producing 47 BOPD. Coho then proceeded to employ 3-D seismic
technology to assist in defining the multi-pay zones in the field and commenced
an extensive drilling program to increase primary production, utilizing a
combination of vertical, high-angle and horizontal drilling techniques.
The Company has also implemented a successful secondary recovery
program 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 response from the secondary recovery
projects has been strong.
In addition to the continued exploitation program, the Company is
continuing an active exploration program at Laurel. In 1996 and 1997, much of
the Company's focus at Laurel was directed toward a mineral leasing program,
permitting and surveying associated with shooting a 37-square mile 3-D seismic
program. The results from this study will allow the Company to better evaluate
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 Company plans to drill several exploration wells at Laurel in 1998.
The average net daily production for 1997 from Laurel was 3,248 BOE,
which was down approximately 2% compared to 1996 net daily production, as a
result of the Company's redirection of water injection activity to optimize
ultimate recoverable reserves from the multiple sands of the Rodessa reservoir.
It is expected that production will continue to fluctuate as water breakthrough
occurs in one sand layer and another sand layer is pressurized. Coho's average
working interest is 92% in the 39 producing wells it operated in the Laurel
field at December 31, 1997.
Martinville Field, Mississippi. The Martinville field was originally
discovered in 1957, and was acquired by Coho in April 1989. At the time of
acquisition, Martinville was only producing 80 BOEPD, while the average
production in 1997 was 1,349 BOEPD. The field covers more than 7,400 acres, and
currently has 24 producing wellbores. Like Laurel, the field is characterized by
highly complex faulting and produces from multiple horizons. Coho currently has
an average 94% working interest in the field.
In late 1995, the Company conducted a 3-D seismic shoot over a
24-square mile area to enhance the Company's ability to exploit primary reserves
through continued reservoir delineation and to develop secondary recovery
projects in the Mooringsport, Rodessa and Sligo formations. In 1996, drilling
commenced in the Rodessa and Sligo reservoirs and a full scale secondary
recovery project was initiated in the Rodessa formation. A successful Hosston
exploratory well was drilled in late 1996.
In 1997, the Company continued the development of secondary recovery
projects in the Mooringsport, Rodessa and Sligo formation. One successful
Mooringsport response well was drilled and is currently producing 500 gross BOPD
and one successful Rodessa response well was drilled and is currently producing
250 gross BOPD. In addition, a successful Washita Fredricksburg exploratory well
was drilled in late 1997. This well produces 250 gross BOPD from 8,500 feet.
Four development wells from this Washita Fredricksburg discovery are planned for
1998. Following up on the 1996 and 1997 exploratory success, the Company plans
to drill at least two exploratory tests at Martinville in 1998. Reserves at the
end of 1997 totaled 6.9 MMBOE, a 49% increase over proved reserves in 1996, and
average daily production during 1997 showed a 133% increase from 1996 average
daily production.
Monroe Field, Louisiana. The Monroe field was discovered in 1916, and
encompasses 25 townships, covering approximately 105,000 acres of fee mineral
and leasehold acreage. The primary producing horizon is at a depth of
approximately 2,900 feet. Average daily production during 1997 was 2,848 BOE,
down slightly from 1996 average daily production primarily due to operational
problems associated with seasonal but unusually high levels of flooding. In
1997, the Company continued its shallow Sparta sand natural gas drilling program
initiated in 1996, and drilled 9 new shallow natural gas wells at a depth of 250
to 900 feet each. This Sparta program, coupled with continued operating
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efficiencies, resulted in December 31, 1997 net proved reserves of 99.5 Bcf of
natural gas in the Monroe field, a 2% increase over December 31, 1996 proved
reserves. Plans in 1998 include continuation of the Sparta drilling program.
In addition to production from the Monroe field, the Company also
operates a natural gas gathering system located in the Monroe field in
Louisiana, as well as certain other natural gas gathering systems in the Gulf
Coast region. These gathering systems, which are all Company-operated, consist
of over 1,000 miles of varying diameter pipe. In 1997, these systems gathered
approximately 26.4 MMcf per day of Company-owned and third party natural gas.
These gathering systems are operated through the Company's wholly owned
subsidiaries, Coho Louisiana Gathering Company ("CLGC") and Coho Fairbanks
Gathering Company ("CFGC").
Soso Field, Mississippi. In mid-1990, the Company acquired a 90%
working interest in the Soso field, which was originally discovered in 1945, and
covers approximately 6,461 acres. At the time of acquisition by the Company, the
field produced 225 BOPD. In 1997, the average daily production was 1,197 BOE, an
increase of 55% over 1996 average daily production. Reserves at December 31,
1997 totaled 6.1 MMBOE, an 8% increase over year-end 1996.
Soso is a large, geologically complex field which had already produced
over 75 MMBOE at the time Coho acquired it. Also, like Brookhaven, Coho's
detailed mapping of the field suggested that less than 25% of the total in-place
crude oil had been recovered. Soso was acquired primarily for the opportunity to
increase total recoverable reserves by another 5% to 15% through recompletions
in existing wellbores, development drilling and secondary recovery projects.
Most of the Company's early production growth at Soso was associated
with workovers and recompletions on existing wells, and some development
drilling; however, with the success of secondary recovery projects at Laurel and
Martinville, the Company took a fresh look at the field, and since then,
secondary recovery projects have been initiated in the Cotton Valley, Sligo and
Rodessa formations. These projects have played a significant role in the
fivefold increase in daily production since 1990.
Coho believes many more exploitation opportunities exist for primary as
well as secondary reserves in this multi-reservoir field. Since the Soso field
is associated with a deep salt feature like Laurel, Martinville and Brookhaven,
deep exploration potential exists at the Smackover and Haynesville levels. The
Company is currently permitting for an exploratory seismic program in the second
quarter of 1998.
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, 1997, the Company operated 22
producing wells and has an average working interest of 90% in this unitized
field.
The Company assumed operating control in November 1989. Recompletions,
development drilling and the installation of higher volume artificial lift
equipment increased net daily crude oil production from 415 BOEPD (of which only
200 BOEPD were economic) in 1989 at the date of acquisition, to 1,125 BOEPD in
1997. Average daily production during 1997 was down 22% from 1996 average daily
production as a result of the natural decline of the reservoirs and low capital
expenditures during the year. Due to recent horizontal drilling success, the
Company expects 1998 production levels to be at least equal to 1996 production
levels.
At December 31, 1997, the Summerland field had proved reserves of 7.0
MMBOE reflecting a 20% increase in reserves from year-end 1996. This reserve
growth is primarily associated with the application of horizontal drilling in
the Tuscaloosa formation in late 1997. The Company believes Summerland has some
additional exploration possibilities from deep drilling in the Cotton Valley and
Smackover formations.
Oklahoma. Effective December 31, 1997, the Company acquired from Amoco
Production Company interests in more than 25,000 gross acres concentrated in
southern Oklahoma, including 14 principal producing fields. The Company will
operate all but two of these fields and currently has an average working
interest in these fields of approximately 66%.
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These properties are very similar to the Company's Mississippi salt
basin operations and the Company believes that the application of its
substantial knowledge base should benefit in the development of these
properties. The Company anticipates adding substantially to its reserves and
production from these properties through an active operations and exploitation
program beginning in 1998. At December 31, 1997, net production from the more
than 1,700 producing wells located on these properties was approximately 7,300
BOE per day and proved reserves totaled 58.8 MMBOE, of which 91% was oil. Of the
reserves at December 31, 1997, 76% were accounted for by only six fields: East
Fitts, East Velma Middle Block, North Alma Deese, Sholem Alechem, Bumpass and
Tatums, all of which will be operated by the Company.
Other Domestic Properties. The Company also has working interests in
other producing properties in Mississippi and Texas. Coho operates the Bentonia
and Frio properties in Mississippi and owns non-operated working interests in
the Glazier property in Mississippi, and a field in state waters offshore North
Padre Island, Texas. As of December 31, 1997, these fields had combined net
proved reserves of 3.4 MMBOE.
Tunisia, North Africa. Coho has a 50% interest in a permit covering 1.4
million gross acres in Tunisia, North Africa that it acquired from its former
Canadian parent company. During 1994, Coho and its joint interest partners
conducted a seismic survey on the Anaguid permit in Tunisia. In October 1995,
Coho and its partners drilled an unsuccessful, exploratory well on its Anaguid
permit in southern Tunisia. In early 1997, the Company and its partners
conducted a 465 kilometer 2-D seismic program in a new area of the Anaguid
permit. Coho is currently evaluating potential opportunities in the permit area
and intends to drill a well in 1998. Coho's estimated net cost to drill this
well is approximately $1.8 million.
Production
The following table sets forth certain information regarding Coho's
production volumes, average prices received and average production costs
associated with its sales of crude oil and natural gas for each of the years in
the three-year period ended December 31, 1997:
Year Ended December 31,
--------------------------------
1995 1996 1997
---- ---- ----
CRUDE OIL:
Volumes (MBbls) ..................... 2,178 2,468 2,820
Average sales price (per Bbl) (a) ... $ 13.62 $ 16.42 $ 16.31
NATURAL GAS:
Volumes (MMcf) ...................... 7,092 6,646 7,666
Average sales price (per Mcf) (b) ... $ 1.59 $ 2.07 $ 2.23
AVERAGE PRODUCTION COST (PER BOE) (c) .. $ 3.71 $ 3.88 $ 3.90
- --------------
(a) Includes the effects of crude oil price hedging contracts. Price per
Bbl before the effect of hedging was $13.89, $18.34 and $16.42 for the
years ended December 31, 1995, 1996 and 1997, respectively.
(b) Includes the effects of natural gas price hedging contracts. Price per
Mcf before the effect of hedging was $1.44, $2.24 and $2.22 for the
years ended December 31, 1995, 1996 and 1997, respectively.
(c) Includes lease operating expenses and production taxes.
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Drilling Activities
During the periods indicated, the Company drilled or participated in
the drilling of the following wells, all of which were in the United States,
except as otherwise indicated.
Year Ended December 31,
--------------------------------------------
1995 1996 1997
----------- ------------ ----------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
EXPLORATORY:
Crude oil ...... -- -- 1 1.0 3 2.8
Natural gas .... -- -- -- -- 1 .8
Dry holes ...... 1* .5* 1 1.0 1 1.0
DEVELOPMENT:
Crude oil ...... 6 5.4 13 12.0 10 9.3
Natural gas .... 1 1.0 6 6.0 11 9.8
Dry holes ...... -- -- 4 3.7 2 2.0
Service wells .. 1 .9 8 7.5 -- --
--- --- --- ---- --- ----
Total ............. 9 7.8 33 31.2 28 25.7
=== === === ==== === ====
- --------
* Well drilled in Tunisia
At December 31, 1997, the Company was participating in 6 gross wells
(5.6 net) that were in various stages of drilling or completion.
Reserves
The following table summarizes the Company's net proved crude oil and
natural gas reserves as of December 31, 1997, which have been reviewed by Ryder
Scott with regard to the Company's Mississippi and Louisiana properties and
Sproule Associates, Inc. with regard to the Company's Oklahoma properties.
Crude Natural Net Proved
Oil Gas Reserves
(MBbls) (MMcf) (MBOE)
------- -------- ----------
Mississippi ............... 41,624 1,807 41,925
Oklahoma .................. 53,358 32,616 58,794
Louisiana ................. -- 99,475 16,579
Other ..................... 102 13,607 2,370
------ ------- -------
Total ................. 95,084 147,505 119,668
====== ======= =======
At December 31, 1997, the Company had net proved developed reserves of
84,228 MBOE and net proved undeveloped reserves of 35,440 MBOE. The Present
Value of Proved Reserves was $526.3 million, which represented $386.4 million
for the proved developed and $139.9 million for the proved undeveloped reserves.
At December 31, 1996, the Company reported total proved reserves of 53,678 MBOE
and the Present Value of Proved Reserves was $417.1 million. This total
represents an increase of 65,990 MBOE and $109.2 million in reserves and Present
Value of Proved Reserves, respectively, at December 31, 1997. The increase was
attributable to extensions and discoveries associated with the Company's efforts
in Mississippi, as well as the recent Oklahoma property acquisition.
There are numerous uncertainties inherent in estimating quantities of
proved oil and natural gas reserves, including many factors beyond the control
of the Company. The estimates of the reserve engineers are based on several
assumptions, all of which are to some degree speculative. Actual future
production, revenues, taxes, production costs, development expenditures and
quantities of recoverable crude oil and natural gas reserves might vary
substantially from those assumed in the estimates. Any significant variance in
these assumptions could materially affect the estimated
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quantity and value of reserves set forth herein. In addition, the Company's
reserves might be subject to revision based upon actual production, results of
future development, prevailing crude oil and natural gas prices and other
factors.
In general, the volumes of production from crude oil and natural gas
properties declines as reserves are depleted. Except to the extent Coho acquires
additional properties containing proved reserves or conducts successful
exploration and development activities, or both, the proved reserves of Coho
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
15 to the Consolidated Financial Statements of the Company included elsewhere
herein.
Acreage
The following table summarizes the developed and undeveloped acreage
owned or leased by Coho at December 31, 1997:
Developed Undeveloped
------------------- ------------------
Gross Net Gross Net
------- ------- ------ ------
Mississippi .............. 24,851 23,122 22,821 20,274
Louisiana ................ 125,770 105,496 1,598 1,419
Oklahoma (a) ............. 40,830 25,969 -- --
Texas .................... 2,796 2,796 1,626 1,626
Offshore Gulf of Mexico .. 5,760 2,269 -- --
------- ------- ------ ------
Total ................ 200,007 159,652 26,045 23,319
======= ======= ====== ======
At December 31, 1997, the Company also held a 50% working interest in
an exploratory permit in Tunisia, North Africa, covering 1,412,000 gross acres.
Additionally, the Company held a 100% working interest in an offshore permit in
Tunisia covering approximately 115,000 gross acres, which the Company has
subsequently released.
(a) The Company is currently conducting due-diligence on the acreage
acquired and is unable to determine the undeveloped acreage at this
time. The Company does not believe a significant amount of acreage will
be considered undeveloped.
TITLE TO PROPERTIES
As is customary in the oil and gas industry, in certain circumstances,
the Company makes only a limited review of title to undeveloped crude oil and
natural gas leases at the time they are acquired by Coho. However, before the
Company acquires crude oil and natural gas properties, and before drilling
commences on any leases, the Company causes 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, the Company, rather than the seller of the undeveloped property, is
typically obligated to cure any such title defects at its expense. If Coho were
unable to remedy or cure any title defect of a nature such that it would be
prudent to commence drilling operations on the property, the Company could
suffer a loss of its entire investment in the property. The Company believes
that it has good title to its crude oil and natural gas properties, some of
which are subject to immaterial encumbrances, easements and restrictions. The
crude oil and natural gas properties owned by the Company are also typically
subject to royalty and other similar non-cost bearing interests customary in the
industry. The Company does not believe that any of these encumbrances or burdens
will materially affect Coho's ownership or use of its properties.
COMPETITION
The crude oil and natural gas industry is highly competitive. A large
number of companies and individuals engage in drilling for crude oil and natural
gas, and there is a high degree of competition for desirable crude oil and
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natural gas properties suitable for drilling, for materials and third-party
services essential for their exploration and development and for attracting and
retaining quality personnel. The principal competitive factors in the
acquisition of crude oil and natural gas properties include the staff and data
necessary to identify, investigate and purchase such properties and the
financial resources necessary to acquire and develop them. Many of Coho's
competitors are substantially larger and have greater financial and other
resources than does Coho.
The principal resources necessary for the exploration for, and the
acquisition, exploitation, production and sale of, crude oil and natural gas are
leasehold or freehold prospects under which crude oil and natural gas reserves
may be discovered, drilling rigs and related equipment to explore for and
develop such reserves and capital assets required for the exploitation and
production of the reserves and knowledgeable personnel to conduct all phases of
crude oil and natural gas operations. Coho must compete for such resources with
both major oil companies and independent operators and also with other
industries for certain personnel and materials. Although Coho believes its
current resources are adequate to preclude any significant disruption of
operations in the immediate future, the continued availability of such materials
and resources to Coho cannot be assured.
CUSTOMERS AND MARKETS
Substantially all of Coho's crude oil is sold at the wellhead at posted
prices, as is customary in the industry. In certain circumstances, natural gas
liquids are removed from the natural gas produced by Coho and are sold by Coho
at posted prices. During 1997, two purchasers of Coho's crude oil and natural
gas, EOTT Energy Corp. ("EOTT") and Mid Louisiana Marketing Company, accounted
for 75% and 21%, respectively, of Coho's receipt of operating revenues. In 1995,
Amerada Hess Corporation ("Amerada") accounted for 66% of Coho's receipt of
operating revenues. Subsequent to December 31, 1995, Amerada sold its
Mississippi pipeline transportation and marketing assets to EOTT. Coho consented
to Amerada's assignment of its short-term contract to EOTT and entered into a
new three-year crude oil purchase agreement with EOTT effective March 1, 1996.
Under the crude oil purchase agreement, Coho has committed the majority of its
crude oil production in Mississippi to EOTT for a period of three years on a
pricing basis of posting plus a premium.
The majority of crude oil production in Oklahoma will be sold to Amoco
Production Company, initially for a one year term beginning January 1, 1998 on a
pricing basis of posting plus a premium. Subsequent to the first year and for a
nine year period thereafter, Amoco will have a right of first refusal to match,
in all respects, a competitive bid. The crude contract was a component of the
purchase and sale agreement and provides for a competitive annual review of the
pricing mechanism.
The natural gas produced in the Monroe field (approximately 17.1 MMcf
per day in 1997) is sold either to industrial or jurisdictional customers along
the interstate pipeline formerly owned by the Company or to industrial customers
in the field that are connected to the gathering system. Generally, the Company
sells its natural gas at prices based on regional price indices, set on a
month-to-month basis. Effective with the sale of the natural gas marketing and
transportation companies in 1996, the Company entered into a long-term natural
gas sales contract for its Monroe field natural gas to Mid Louisiana Marketing
Company based on regional price indices set on a month-to-month basis,
consistent with past operations.
The price received by the Company for crude oil and natural gas may
vary significantly during certain times of 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, the Company periodically enters into forward sale
agreements or other arrangements for a portion of its crude oil and natural gas
production to hedge its 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, such hedging transactions may limit potential gains by the Company
if crude oil and natural gas prices were to rise substantially over the price
established by the hedge. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- General" and Note 1 to the Consolidated
Financial Statements included elsewhere herein.
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OFFICE AND FIELD FACILITIES
The Company currently leases its executive and administrative offices
in Dallas, Texas, consisting of 47,942 square feet, under a lease that continues
through October 2000. The Company also leases field offices in Laurel,
Mississippi, covering approximately 5,000 square feet under a non-cancelable
lease extending through June 2000, and Ratliff City, Oklahoma, covering
approximately 10,000 square feet through January 2003. The field office
facilities in Fairbanks, Louisiana and Brookhaven, Mississippi are owned by the
Company.
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. Such
regulations include requiring permits for the drilling of wells, maintaining
bonding requirements in order to drill or operate wells, and regulating the
location of wells, the method of drilling and casing wells, the surface use and
restoration of properties upon which wells are drilled, and the plugging and
abandonment of wells. The Company's operations are also subject to various
conservation laws and regulations, including those of Mississippi, Louisiana,
Oklahoma and Texas wherein the Company's properties are located. These laws and
regulations include the regulation of the size of drilling and spacing units or
proration units, the density of wells that may be drilled, and unitization or
pooling of crude oil and natural gas properties. In this regard, some states
allow the forced pooling or integration of tracts to facilitate exploration
while other states rely on voluntary pooling of land and leases. In addition,
state conservation laws establish maximum rates of production from crude oil and
natural gas wells, generally restrict the venting or flaring of natural gas, and
impose certain requirements regarding the ratability of production. The effect
of these regulations is to limit the amount of crude oil and natural gas the
Company can produce from its wells and to limit the number of wells or the
locations at which the Company 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, the Company is subject to production tax rates of up to 6%
in Mississippi, $.02 per Mcf in Louisiana, and 7% in Oklahoma. In addition, the
Company has been active in the adoption of legislation dealing with production
and severance tax relief in Mississippi.
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 which carry substantial penalties for
failure to comply. The regulatory burden on the crude oil and natural gas
industry increases the Company's cost of doing business and, consequently,
affects its profitability.
Offshore Leasing. Certain of the Company's operations are located on
federal crude oil and natural gas leases, which are administered by the United
States Minerals Management Service (the "MMS"). Such leases are issued through
competitive bidding, contain relatively standardized terms and require
compliance with detailed MMS regulations and orders (which are subject to change
by the MMS). For offshore operations, lessees must obtain MMS approval for
exploration plans and development and production plans prior to the commencement
of such 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 MMS prior to the commencement of
drilling. The MMS has promulgated regulations requiring offshore production
facilities located on the Outer Continental Shelf ("OCS") to meet stringent
engineering and construction specifications. Similarly, the MMS has promulgated
other regulations governing the plugging and abandonment of wells located
offshore and the removal of all production facilities. Under certain
circumstances, the MMS may require any Company operations of federal leases to
be suspended or terminated. To cover the various obligations of lessees on the
OCS, the MMS generally requires that lessees or operators post substantial bonds
or other acceptable assurances that such obligations will be met. The cost of
such bonds or other surety can be substantial and there is no assurance that the
Company can obtain bonds or other surety in all cases.
Gas Royalty Valuation Regulations. In December 1997, the MMS published
a final rule amending its regulations governing valuation for royalty purposes
of gas produced from federal and Indian leases. The rule primarily addresses
allowances for transportation of gas and purports to clarify the methods by
which gas royalties and deductions
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for gas transportation are calculated. The final rule became effective February
1, 1998. The rule purports to continue the commitment of the MMS to assure that
lessees deduct only the actual, reasonable costs of transportation and not any
costs of marketing. The rule identifies certain specifically allowable and
certain specifically nonallowable costs of transportation.
Crude Oil Sales and Transportation Rates. Sales of crude oil and
condensate can be made by Coho at market prices not subject at this time to
price controls. In January 1997, the MMS published a proposed rulemaking to
amend the current federal crude oil royalty valuation regulations. In July 1997,
the MMS published a supplementary proposed rulemaking concerning such
regulations. In February 1998, the MMS published another supplementary proposed
rulemaking. The intent of the rule is to decrease reliance on posted prices and
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. Comments on the second supplementary
proposed rule are due on March 23, 1998. In February 1998, the MMS also
published a notice of proposed rulemaking 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. Comments on the proposed rulemaking are due on April 13, 1998. The
Company cannot predict what action the MMS will take on these matters, nor can
it predict at this stage of the rulemaking proceedings how the Company might be
affected by amendments to these regulations.
The price that the Company receives 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 FERC to establish a "simplified and generally
applicable" rate making methodology for crude oil pipeline rates. Effective as
of January 1, 1995, the FERC implemented regulations establishing an indexing
system for transportation rates for crude oil pipelines, which would generally
index such rates to inflation, subject to certain conditions and limitations.
The Company is not able to predict with certainty what effect, if any, these
regulations will have on it, but other factors being equal under certain
conditions, the regulations may tend to increase transportation costs or reduce
wellhead prices for such commodities.
Gathering Regulation. Under the Natural Gas Act (the "NGA"), facilities
used for and operations involving the production and gathering of natural gas
are exempt from FERC jurisdiction, while facilities used for and operations
involving interstate transmission are not. The FERC's determination of what
constitutes exempt gathering facilities, as opposed to jurisdictional
transmission facilities, has evolved over time. Under current law even
facilities which otherwise would have been classified as gathering may be
subject to the FERC's rates and service jurisdiction when owned by an interstate
pipeline company and when such regulation is necessary in order to effectuate
FERC's Order No. 636 open-access initiatives. Respecting facilities owned by
noninterstate pipeline companies, such as Coho Fairbanks Gathering Company
("CFGC") and Coho Louisiana Gathering Company ("CLGC"), the Company's gathering
facilities, the FERC has historically distinguished between these types of
activities on a very fact-specific basis which makes it difficult to predict
with certainty the status of gathering facilities. On November 1, 1993, in
Docket No. CP93-79-000, this uncertainty was settled by FERC with respect to the
gathering facilities transferred from Mid Louisiana Gas Company , the Company's
former interstate pipeline, to CFGC effective January 1, 1994, when FERC issued
an order declaring the facilities to be nonjurisdictional gathering. On May 27,
1994, FERC affirmed its November 1, 1993 order in all material respects. On June
27, 1994, the Producer-Marketer Transportation Group Gathering Coalition and the
Independent Petroleum Association of America (IPAA) filed a request for a
rehearing of the May 27, 1994 order. On December 6, 1994, FERC issued a final
order disallowing IPAA's request for rehearing. On December 9, 1994, IPAA filed
a petition for review of the FERC orders in the U.S. Court of Appeals for the
D.C. Circuit. This case is one in a series of cases that has delineated the
FERC's gathering policy. Among other matters, the FERC slightly narrowed its
statutory tests for establishing gathering status and reaffirmed that it does
not have jurisdiction over natural gas gathering facilities and services and
that such facilities and services are properly regulated by state authorities.
As a result, natural gas gathering may receive greater regulatory scrutiny by
state agencies. In addition, the FERC has approved several transfers by
interstate pipelines of gathering facilities to unregulated gathering companies,
including affiliates. This could allow such companies to compete more
effectively with independent gatherers. Although the FERC orders delineating its
new gathering policy are subject to court appeals, there has been only one
definitive court decision to date. The U.S. Court of Appeals for the D.C.
Circuit upheld the FERC's decision to not regulate gathering rates but found
that its "default" contract requirement was unlawful as outside the FERC's
jurisdiction. The U.S. Supreme Court declined to review the D.C. Circuit's
decision. On remand from the D.C. Circuit's decision, the FERC found that the
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issue concerning its jurisdiction to require default contracts was effectively
moot. The FERC stated, however, that it would consider what, if any,
transitional protection it might provide, consistent with the D.C. Circuit's
decision, if the issue arises in future cases. Management does not believe the
ultimate resolution of these proceedings will have a material adverse effect on
the financial condition of the Company.
State regulation of gathering facilities generally includes various
safety, environmental and, in some circumstances, nondiscriminatory take
requirements. While some states provide for the rate regulation of pipelines
engaged in the intrastate transportation of natural gas, such regulation has not
generally been applied against gatherers of natural gas. For historical reasons,
however, certain of the gathering facilities owned by CLGC are subject to the
jurisdiction of the Louisiana Department of Natural Resources ("LDNR") pursuant
to its authority to regulate intrastate pipelines. Further, natural gas
gathering may receive greater regulatory scrutiny following the pipeline
industry restructuring under Order No. 636. Thus the Company's gathering
operations could be adversely affected should they be subject in the future to
the application of state or federal regulation of rates and services.
Future Legislation and Regulation. The Company's operations will be
affected from time to time in varying degrees by political developments and
federal and state laws and regulations. In particular, crude oil and natural gas
production operations and economics are affected by tax and other laws relating
to the petroleum industry, by changes in such laws and by constantly changing
administrative regulations. For example, the price at which natural gas may
lawfully be sold has historically been regulated under the NGA. Only recently,
with the deregulation of the last regulated price categories of natural gas on
January 1, 1993, have free market forces been allowed to control the sales price
of natural gas. Given the right set of circumstances, there is no guarantee that
new regulations, similar or otherwise, would not be imposed on the production of
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 such legislation or regulations on the Company.
ENVIRONMENTAL REGULATIONS
The Company's operations are subject to numerous laws and regulations
governing the discharge of materials into the environment or otherwise relating
to environmental protection. These laws and regulations may require the
acquisition of a permit before drilling commences, restrict the types,
quantities and concentration of various substances that can be released into the
environment in connection with drilling and production activities, limit or
prohibit drilling activities on certain lands lying within wilderness, wildlife
refuges or preserves, wetlands and other protected areas, and impose substantial
liabilities for pollution resulting from the Company's 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
could have a significant impact on the operating costs of the Company, as well
as the oil and gas industry in general. Management believes that the Company is
in substantial compliance with current applicable environmental laws and
regulations and that continued compliance with existing requirements will not
have a material adverse impact on the Company.
The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder
impose a variety of regulations on "responsible parties" related to the
prevention of crude oil spills and liability for damages resulting from such
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, or the lessee or permittee of the
area in which an offshore facility is located. The OPA, as recently amended,
requires the lessee or permittee of the offshore area in which a covered
offshore facility is located to establish and maintain evidence of financial
responsibility in the amount of $35.0 million to cover liabilities related to a
crude oil spill for which such person is statutorily responsible. Prior to the
amendment, the OPA required such lessee or permittee to maintain evidence of
financial responsibility in the amount of $150.0 million, and the amended
statute authorizes the President of the United States to increase the amount of
financial responsibility to $150.0 million depending on the risks posed by the
quantity of crude oil that is handled by the facility. On March 25, 1997, the
MMS proposed regulations to implement the financial responsibility requirements
under the OPA. The proposed regulations would use an offshore facility's worst
case oil-spill discharge volume to determine if the responsible party must
demonstrate increased financial responsibility. Because the Company's only
offshore well is a natural gas well, it does not believe that it will be subject
to the financial responsibility requirements, if such requirements are
implemented in the manner proposed by the MMS. The Company cannot predict the
final form
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of any financial responsibility regulations that will be adopted by the MMS, but
the impact of any such regulations should not be any more adverse to the Company
that it will be to other similarly situated companies.
The OPA subjects responsible parties to strict, joint and several and
potentially unlimited liability for removal costs and certain other damages
caused by an oil spill covered by the statute. It also imposes other
requirements on responsible parties, such as the preparation of a crude oil
spill contingency plan. The Company has such a plan in place. Failure to comply
with the OPA's ongoing requirements or inadequate cooperation during a spill
event may subject a responsible party to civil or criminal enforcement actions.
As of this date, the Company is not the subject of any civil or criminal
enforcement actions under the OPA.
The Federal Water Pollution Control Act of 1972, as amended (the
"FWPCA"), 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. Permits must be obtained
to discharge pollutants into state and federal waters. Certain state discharge
regulations and the Federal National Pollutant Discharge Elimination System
general permits prohibit the discharge of produced water and sand, drilling
fluids, drill cuttings and certain other substances related to the oil and gas
industry into coastal waters. The FWPCA provides for civil, criminal and
administrative penalties for any unauthorized discharges of oil and other
hazardous substances in reportable quantities and, along with the OPA, imposes
substantial potential liability for the costs of removal, remediation and
damages. State laws for the control of water pollution also provide varying
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 ("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons that are 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 companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. Persons who are or were responsible for releases of hazardous substance
under CERCLA 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.
Currently, the Company does not own or operate CERCLA identified sites.
The Resource Conservation and Recovery Act ("RCRA") is the principal
federal statute governing the treatment, storage and disposal of hazardous
wastes. RCRA imposes stringent operating requirements (and liability for failure
to meet such 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, RCRA 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 RCRA. At various times in the
past, proposals have been made to amend RCRA and various state statutes to
rescind the exemption that excludes crude oil and natural gas exploration and
production wastes from regulation as hazardous waste under such statutes. Repeal
or modification of this exemption by administrative, legislative or judicial
process, or through changes in applicable state statutes, would increase the
volume of hazardous waste to be managed and disposed of by the Company.
Hazardous wastes are subject to more rigorous and costly disposal requirements
than are non-hazardous wastes. Any such change in the applicable statutes may
require the Company to make additional capital expenditures or incur increased
operating expenses.
A sizable portion of the Company's operations in Mississippi is
conducted within city limits. On an annual basis in order to obtain permits to
conduct new drilling operations, the Company is required to meet certain tests
of financial responsibility. The Company is conducting a voluntary program to
remove inactive aboveground storage tanks from its well sites. Inactive tanks
are replaced, as necessary, with newer aboveground storage tanks.
Some states have enacted statutes governing the handling, treatment,
storage and disposal of naturally occurring radioactive material ("NORM"). NORM
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
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and natural gas production and processing streams. Mississippi legislation
prohibits the transfer of property for residential or other unrestricted use if
the property contains NORM above prescribed levels. The Company is voluntarily
remediating NORM concentrations identified at the Brookhaven field in
Mississippi. In addition, the Company is a defendant in several lawsuits brought
in 1994 and 1996 by landowners alleging personal injury and property damage from
NORM at various wellsite locations.
Certain governmental agencies are presently studying whether the crude
oil and natural gas industry's practice of utilizing mercury meters poses any
potential problems that require more stringent regulation. Operators in the
Monroe field have been asked to monitor their operations and assist in gathering
data. During 1995, the Company voluntarily negotiated a remediation plan with
the governmental agencies responsible for the two wildlife refuges in the Monroe
field. Under the plan, the company began removal of the mercury meters within
the wildlife refugees in 1996. The Company continues to cooperate with the other
various agencies in their studies. At this time, the Company believes that such
spillages and leaks may have occurred in the past. However, the Company believes
that such spillage and leaks are less than the amounts reportable under prior or
existing statutes and laws.
Because the Company's strategy is to acquire interests in
underdeveloped crude oil and natural gas properties many of which have been
operated by others for many year, the Company may be liable for damage or
pollution caused by the former operators of such crude oil and natural gas
properties. The Company makes a provision for future site restoration charges on
a unit-of-production basis which is included in depletion and depreciation
expense. The Company's operations are also subject to all the risks normally
incident to the operation and development of crude oil and natural gas
properties and the drilling of crude oil and natural gas wells, including
encountering unexpected formations or pressures, blowouts, cratering and fires,
which could result in personal injuries, loss of life, pollution damage and
other damage to the properties of the Company and 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, to more
extensive governmental regulation, including regulations that may, in certain
circumstances, impose strict liability for pollution damage, and to interruption
or termination of operations by governmental authorities based on environmental
or other considerations. The Company maintains insurance against certain losses
or liabilities arising from its operations in accordance with customary industry
practices and in amounts that management believes to be reasonable. However,
insurance is either not available to the Company against all operational risks
or is not economically feasible for the Company to obtain. The occurrence of a
significant event that would impose liability on the Company that is either not
insured or not fully insured could have a material adverse effect on the
Company's financial condition and results of operations.
EMPLOYEES
At February 15, 1998, Coho had 166 employees associated with its
operations, including 26 field personnel in Mississippi, 26 field personnel in
Oklahoma and 39 field personnel in Louisiana. None of the Company's employees is
represented by a union. The Company considers its employee relations to be
satisfactory.
ITEM 2. PROPERTIES
For information with respect to the Company's properties, see "Business
and Properties".
ITEM 3. LEGAL PROCEEDINGS
In July 1994, the Company, together with several other companies, was
named as a defendant in a lawsuit filed in Jones County, Mississippi. The
lawsuit involves claims by a landowner for purported damages caused by naturally
occurring radioactive materials at various wellsite locations on land leased by
the Company in Mississippi. The plaintiff is seeking significant compensatory
and punitive damages, including damages for "emotional distress". This lawsuit
has been dormant for two years and the land involved has been remediated.
Additionally, in 1996 and 1997, the Company, together with several
other companies, was named as a defendant in a number of lawsuits of the same
nature as the July 1994 lawsuit. All of the suits are principally identical and
seek damages for land damage, health hazard, mental and emotional distress, etc.
None of the suits seek specific award amounts, but all seek punitive damages.
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While the Company is not able to determine its exposure in the
remaining suits at this time, the Company believes that the claims will have no
material adverse effect on its financial position or results of operations.
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 aggregate, on the Company's financial position or results of
operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the
fourth quarter of 1997.
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock is traded on the Nasdaq Stock Market under the
symbol "COHO". The following table sets forth the range of high and low sale
prices for the Common Stock as reported on the Nasdaq Stock Market.
HIGH LOW
---- ---
1996
1st Quarter .................................. $ 6 5/8 $ 4 5/8
2nd Quarter .................................. 7 1/8 5 15/16
3rd Quarter .................................. 7 1/2 6 1/8
4th Quarter .................................. 8 1/4 6 3/4
1997
1st Quarter .................................. $ 9 1/4 $ 6 7/8
2nd Quarter .................................. 11 1/2 6 7/8
3rd Quarter .................................. 11 5/8 9
4th Quarter .................................. 13 8 1/4
The last reported sale price of the Common Stock as reported on the
Nasdaq Stock Market on March 23, 1998 was $7 3/4 per share. At March 23, 1998,
there were 196 holders of record of the Common Stock. The Company believes it
has in excess of 35 beneficial holders of its Common Stock.
The Company has never paid cash dividends on its Common Stock and does
not intend to pay cash dividends on its Common Stock in the foreseeable future.
In the past, the Company has used its available cash flow to conduct exploration
and development activities or to make acquisitions, and expects to continue to
do so in the future. In addition, the terms of the Company's revolving credit
facility and Senior Notes indenture restrict the payment of dividends by the
Company and CRI. Coho Energy, Inc. currently is a holding company with no
independent operations. Accordingly, any amounts available for dividends will be
dependent on the prior declaration of dividends by CRI or CRL to Coho Energy,
Inc. Any declaration of dividends by CRI or CRL would be subject to Canadian or
U.S. withholding tax at applicable tax rates.
On December 9, 1996, the Company issued 100,000 shares of Common Stock to
Churchill Resource Investments, Inc., a Colorado corporation, in consideration
for certain oil and gas properties and interests in the Laurel and Glazier,
Mississippi fields. The shares were issued without registration under the
Securities Act in reliance on the exemption therefrom set forth in Section 4(2)
of the Securities Act.
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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, 1997 are derived from, and qualified by
reference to, the Company's audited consolidated financial statements included
at Item 8 hereof. The information presented below should be read in conjunction
with Coho's Consolidated Financial Statements and the notes thereto and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" included elsewhere herein. The selected consolidated financial data
presented below are not necessarily indicative of the future results of
operations or financial performance of the Company.
1993 1994(1) 1995 1996 1997
---- ------- ---- ---- ----
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
STATEMENT OF EARNINGS DATA: (2)
Operating revenues ........................... $ 28,263 $ 26,464 $ 40,903 $ 54,272 $ 63,130
Operating costs .............................. 8,773 9,372 12,457 13,875 15,970
General and administrative expenses .......... 2,997 3,435 5,400 7,264 7,163
Depletion and depreciation ................... 10,677 9,989 14,717 16,280 19,214
Net interest expense ......................... 3,484 3,972 8,048 7,464 10,474
Other expense(3) ............................. 21,000 973 -- -- --
Income tax expense (benefit) ................. (5,219) (303) 112 3,483 4,020
Earnings (loss) from continuing operations ... (13,449) (974) 169 5,906 6,288
Net earnings (loss) .......................... (13,449) (1,654) 1,780 5,906 6,288
Basic earnings (loss) from continuing
operations per common share(4) ......... $ (1.12) $ (0.07) $ (0.02) $ 0.29 $ 0.29
Diluted earnings (loss) from continuing
operations per common share(5) ......... $ (1.12) $ (0.07) $ (0.02) $ 0.29 $ 0.28
Basic earnings (loss) per common share(4) .... $ (1.12) $ (0.12) $ 0.05 $ 0.29 $ 0.29
Diluted earnings (loss) per common share(5) .. $ (1.12) $ (0.12) $ 0.05 $ 0.29 $ 0.28
OTHER FINANCIAL DATA:
Capital expenditures ......................... $ 24,122 $ 19,503 $ 29,970 $ 52,384 $ 72,667
BALANCE SHEET DATA: (2)
Working capital (deficit)(6) ................. $ 871 $ (2,379) $ 14,433 $ 6,662 $ (2,021)
Net property and equipment ................... 96,871 171,524 175,899 210,212 531,409
Total assets ................................. 104,286 196,970 204,042 230,041 555,128
Long-term debt, excluding current portion .... 54,000 86,311 107,403 122,777 369,924
Redeemable preferred stock ................... -- 16,125 -- -- --
Total shareholders' equity ................... 44,279 56,416 74,321 81,466 142,103
(1) In December 1994, the Company acquired all of the outstanding common
stock of ING.
(2) Amounts for 1994 and 1995 exclude discontinued operations representing
the Company's natural gas marketing and transportation segment.
(3) Amount for 1993 reflects the writedown in carrying value of crude oil
and natural gas properties ($20,000) and reorganization costs ($1,000).
(4) Basic per share amounts have been computed by dividing net earnings after
preferred dividends by the weighted average number of shares outstanding:
12,013 in 1993; 14,190 in 1994; 17,932 in 1995; 20,179 in 1996; and
21,693 in 1997, respectively.
(5) 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: 12,013 in 1993;
14,190 in 1994; 17,932 in 1995; 20,342 in 1996; and 22,334 in 1997,
respectively.
(6) Amount for 1995 includes $17,421 related to net assets of discontinued
operations.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion should be read in conjunction with the Company's
Consolidated Financial Statements included elsewhere herein. Certain information
contained herein, including information with respect to the Company's plans and
strategy for its business, are forward-looking statements. These statements are
based on certain assumptions and analyses made by management of the Company in
light of its experience and its perception of historical trends, current
conditions, expected future developments and other factors it believes are
appropriate. Such statements are subject to a number of assumptions, risks and
uncertainties, general economic and business conditions, prices of crude oil and
natural gas, the business opportunities (or lack thereof) that may be presented
to and pursued by the Company, changes in laws or regulations and other factors,
many of which are beyond the control of the Company. Such statements are not
guarantees of future performance and actual results or developments may differ
materially from those projected in the forward-looking statements.
COMPANY HISTORY
The Company was incorporated in June 1993 under the laws of the State of
Texas and conducts a majority of its operations through CRI. Prior to September
29, 1993, CRI was a publicly held company of which CRL, a publicly held Alberta,
Canada company, held a 68% ownership interest. As a result of a reorganization
of the Company effective on September 29, 1993, CRI and CRL became wholly owned
subsidiaries of Coho Energy, Inc.
In December 1994, the Company acquired all of the capital stock of
Interstate Natural Gas Company ("ING"). ING, through its subsidiaries, was a
privately held natural gas producer, gatherer and pipeline company operating in
Louisiana and Mississippi. As a result of the acquisition of ING, Coho acquired
approximately 86 Bcf of natural gas reserves, with natural gas production in
December 1994 of 20 Mmcf per day primarily from the Monroe field in north
Louisiana. Additionally, the ING acquisition included approximately 1,000 miles
of gathering systems in the Monroe field and a 167 mile long interstate pipeline
(operating as the Mid Louisiana Gas Company) and certain intrastate pipeline
facilities. Consideration paid by the Company for the acquisition of ING was $20
million cash, the assumption of net liabilities of $3.3 million (excluding
deferred taxes), 2,775,000 shares of the Common Stock and 161,250 shares of
redeemable preferred stock (which preferred shares were exchanged on August 30,
1995 for 3,225,000 shares of Common Stock), having an aggregate stated value of
$16.1 million. The acquisition of ING was accounted for using the purchase
method.
In April 1996, ING sold all of the stock of three wholly owned
subsidiaries that comprised its natural gas marketing and transportation segment
to an unrelated third party for cash of $19.5 million, the assumption of net
liabilities of approximately $2.3 million and the payment of taxes of up to $1.2
million generated as a result of the tax treatment of the transaction. The
marketing and transportation segment is accounted for as discontinued operations
herein.
Effective December 31, 1997, the Company acquired from Amoco Production
Company ("Amoco") interests in certain crude oil and natural gas properties
("Amoco 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 Amoco Properties are in more than 25,000 gross acres
concentrated in southern Oklahoma, including 14 major producing oil fields. As a
result of the acquisition, the Company's total proved reserves increased 103%
and daily net production is expected to increase 63%. The Company will operate
all but two of these fields and have an average working interest in these fields
of approximately 66%.
GENERAL
The Company seeks to acquire controlling interests in underdeveloped
crude oil and natural gas properties and attempts to maximize reserves and
production from such properties through relatively low-risk activities such as
development drilling, multiple completions, recompletions, workovers,
enhancement of production facilities and secondary recovery projects. The
Company's only operating revenues are crude oil and natural gas sales with crude
oil sales representing approximately 75% of production revenues and natural gas
sales representing approximately 25% of production revenues during 1995, 1996
and 1997. Operating revenues increased from $26.9 million in 1992 to $63.1
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million in 1997 primarily due to an increase in production volumes from
successful development and exploration activities in the Company's existing
Mississippi fields and due to the December 1994 acquisition of the Monroe
natural gas field and the August 1995 acquisition of the Brookhaven field. The
Company has a two year inventory of lower risk exploitation projects including
development drilling, recompletions and secondary recovery projects identified
for its Mississippi properties. This exploitation inventory coupled with the
Company's recent exploration success in the Brookhaven field and the exploration
opportunities identified at Laurel, Martinville and Soso fields should provide
development and exploration opportunities and continued growth in production and
reserves.
The Company also strives to maintain a low cost structure through asset
concentration, such as in the interior salt basin of Mississippi. Asset
concentration permits operating economies of scale and leverages operational,
technical and marketing capabilities. Production costs (including lease
operating expenses and production taxes) per BOE have decreased from $4.11 in
1992 to $3.90 in 1997.
The price received by the Company for crude oil and natural gas may vary
significantly during certain times of 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, the Company has entered, and expects to continue to
enter, into forward sale agreements or other arrangements for a portion of its
crude oil and natural gas production to hedge its exposure to price
fluctuations. While the Company's hedging program is intended to stabilize cash
flow and thus allow the Company to plan its capital expenditure program with
greater certainty, such hedging transactions may limit potential gains by the
Company if crude oil and natural gas prices were to rise substantially over the
price established by the hedge. Because all hedging transactions are tied
directly to the Company's crude oil and natural gas production and natural gas
marketing operations, the Company does not believe that such 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 the Company's crude oil hedging
transactions is determined as the difference between the contract price and the
average closing price for West Texas Intermediate ("WTI") crude oil on the New
York Mercantile Exchange ("NYMEX") for the contract period. Any gain or loss on
the Company's 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 the
Company's crude oil and natural gas.
The Company also controls the magnitude and timing of its capital
expenditures by obtaining high working interests in and operating its
properties. At December 31, 1997, the Company owned an average working interest
of 85% in and operated over 90% of its producing properties.
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RESULTS OF OPERATIONS
SELECTED OPERATING DATA
YEAR ENDED DECEMBER 31,
-------------------------------
1995 1996 1997
------- ------- -------
PRODUCTION:
Crude oil (Bbl/day) ............... 5,966 6,742 7,726
Natural gas (Mcf/day) ............. 19,431 18,160 21,003
BOE (Bbl/day) ................ 9,205 9,769 11,227
AVERAGE SALES PRICES:
Crude oil (per Bbl) ............... $ 13.62 $ 16.42 $ 16.31
Natural gas (per Mcf) (a) ......... 1.59 2.07 2.23
PER BOE DATA:
Production costs (b) .............. $ 3.71 $ 3.88 $ 3.90
Depletion ......................... 4.38 4.55 4.69
PRODUCTION REVENUES (IN THOUSANDS):
Crude oil ......................... $29,654 $40,527 $45,991
Natural gas ....................... 11,249 13,745 17,139
------- ------- -------
Total production revenues .... $40,903 $54,272 $63,130
======= ======= =======
- --------------
(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.
YEAR ENDED DECEMBER 31, 1997 COMPARED WITH YEAR ENDED DECEMBER 31, 1996
Operating Revenues. During 1997, production revenues increased 16% to
$63.1 million as compared to $54.3 million in 1996. This increase was
principally due to a 15% increase in crude oil production, a 16% increase in
natural gas production and an increase in the price received for natural gas
(including hedging gains and losses discussed below) of 8%.
The 16% increase in daily natural gas production is primarily a result of
the continued positive response from the Company's development efforts in the
North Padre, Martinville and Brookhaven fields. The 15% increase in daily crude
oil production during 1997 is due to significant production increases made in
the Martinville, Soso and Brookhaven fields, with production increasing by 125%,
51% and 87%, respectively, in such fields. These production increases were
partially offset by a production decrease in the Summerland field due to the
unusually high frequency of weather-related power outages and mechanical
problems during the first quarter of 1997 and normal production declines due to
the maturity of the field.
Average crude oil prices realized in 1997, including hedging gains and
losses discussed below, remained comparable to 1996. Even though posted crude
oil prices received in 1997 declined from 1996 prices, the average prices
realized in 1996 and 1997 were comparable due to crude oil hedging losses
experienced in 1996. The posted price for the Company's crude oil averaged
$18.34 per Bbl in 1997, a 9% decrease over the average posted price of $20.23
per Bbl experienced in 1996. The price per Bbl received by the Company is
adjusted for the quality and gravity of the crude oil and is generally lower
than the posted price.
The realized price for the Company's natural gas, including hedging gains
and losses discussed below, increased 8% from $2.07 per Mcf in 1996 to $2.23 per
Mcf in 1997. Although the average natural gas prices received, net of fuel used
in gathering, in 1996 and 1997 were comparable at $2.25 per Mcf and $2.22 per
Mcf, respectively, the natural gas hedging losses in 1996 reduced the realized
price in 1996 by $.18 per Mcf while 1997 hedging gains increased the realized
price in 1997 by $.01 per Mcf.
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Production revenues for 1997 included crude oil hedging losses of $.3
million ($.11 per Bbl) compared to crude oil hedging losses of $4.7 million
($1.92 per Bbl) in 1996. Production revenues in 1997 also included natural gas
hedging gains of $.1 million ($.01 per Mcf) compared with natural gas hedging
losses of $1.2 million ($.18 per Mcf) for 1996. The Company has 10,000 Mmbtu of
natural gas production per day hedged from January through March 1998 at a
minimum price of $2.70 per Mmbtu and a maximum price of $3.28 per Mmbtu. In
March 1998, the Company hedged an additional 15,000 Mmbtu per day of natural gas
production over the period from April to August 1998, at a minimum price of
$2.00 per Mmbtu and a maximum price of $2.54 per Mmbtu.
Interest and other income decreased to $646,000 in 1997 from $1 million
in 1996 primarily due to $472,000 of interest earned during 1996 on the
receivable from the sale of the marketing and pipeline segment of operations and
due to an unrealized gain of $450,000 on marketable securities in 1996,
partially offset by $137,000 of interest received in the first quarter of 1997
on a federal tax refund and $465,000 of interest earned in the fourth quarter of
1997 on cash investments.
Expenses. Production expenses (including production taxes) were $16
million for 1997 compared to $13.9 million for 1996. This increase primarily
reflects additional production volumes. On a BOE basis, production costs
increased to $3.90 per BOE in 1997 compared to $3.88 per BOE in 1996.
General and administrative costs decreased 1% between years from $7.3
million in 1996 to $7.2 million in 1997. General and administrative costs
expensed in 1997 were less than such costs expensed in 1996, even though total
general and administrative costs increased, due to an increase in the
capitalization of salaries and other general and administrative costs directly
associated with the Company's increased exploration and development activities.
Total general and administrative cost increased due to higher compensation and
employee related costs attributable to staff additions and higher professional
fees.
Interest expense increased 31% in 1997 compared to 1996, due to higher
borrowing levels during 1997 as compared to 1996 and due to the sale of $150
million of 8 f% Senior Subordinated Notes ("Senior Notes") on October 3, 1997
which bear a higher interest rate than the Company's revolving credit facility.
The average interest rate paid on outstanding indebtedness was 7.84% in 1997,
compared to 7.6% in 1996.
Depletion and depreciation expense increased 18% to $19.2 million in 1997
from $16.3 million in 1996. These increases are primarily the result of
increased production volumes and an increased rate per BOE, which increased to
$4.69 in 1997, compared with $4.55 in 1996.
In accordance with generally accepted accounting principles, at a point
in time coinciding with the quarterly and annual reporting periods, the Company
must test the carrying value of its crude oil and natural gas properties, net of
related deferred taxes, against 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 (the "cost center ceiling"). If the carrying value
exceeds the cost center ceiling, the excess must be expensed in such period and
the carrying value of the oil and gas lowered accordingly. Amounts required to
be written off may not be reinstated for any subsequent increase in the cost
center ceiling.
Based on this test at December 31, 1997, using the year end WTI posted
reference price of $16.17 per Bbl of crude oil and a year end price of $2.26 per
Mcf of natural gas, the carrying value of the crude oil and natural gas
properties were lower than the cost center ceiling therefore no writeoff was
required. Assuming the price of natural gas remains constant and the ratio of
crude oil reserves to total reserves and the crude oil components of such
reserves do not change significantly from such quantities estimated in the year
end reserve report used in the December 31, 1997 test, the Company's carrying
value of its crude oil and natural gas properties would not exceed the cost
center ceiling at any WTI posted reference price above $14.72 per Bbl of crude
oil. The Company's capital expenditure program is, in large measure, designed to
increase production of both crude oil and natural gas from its proved reserves.
Such increases have the effect of increasing the present value of the discounted
future cash flows, thus increasing the cost center ceiling. The Company has
experienced increases in its daily rate of production during the first quarter
of 1998.
The Company's net operating loss carryforwards ("NOLs") for United States
and Canadian federal income tax purposes were approximately $67.5 million at
December 31, 1997 and expire between 1998 and 2011. Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS 109")
requires that the tax benefit
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of such NOLs be recorded as an asset to the extent that management assesses the
utilization of such NOLs to be "more likely than not." It is expected that
future reversals of existing taxable temporary differences will generate taxable
amounts sufficient to utilize the majority of the NOL carryforwards prior to
their expiration. A valuation allowance has been established with respect to
approximately $10.4 million of these NOLs as it is uncertain whether they will
be utilized before they expire.
The Company's net earnings for 1997 were $6.3 million, as compared to net
earnings of $5.9 million for 1996 for the reasons discussed above.
YEAR ENDED DECEMBER 31, 1996 COMPARED WITH YEAR ENDED DECEMBER 31, 1995
Operating Revenues. During 1996, production revenues increased 33% to
$54.3 million as compared to $40.9 million in 1995 (including hedging gains and
losses discussed below). This increase was principally due to increases of 13%
in crude oil production, 21% in crude oil prices and 30% in natural gas prices
which were slightly offset by a 6% decrease in natural gas production.
The 13% increase in daily crude oil production for 1996 to 6,742 Bbls is
primarily a result of continued development activity, including recompletions
and workovers on existing wells and drilling new wells and waterflood operations
in the Martinville, Soso and Summerland fields and waterflooding and exploration
success in Martinville. In addition, 1996 includes crude oil production from the
Brookhaven field for the entire year as compared to only five months in 1995.
Natural gas production for 1996 was 6% lower than 1995, primarily due to
operational problems associated with the natural gas gathering system caused by
unusually cold, wet weather during the winter months of 1996. Although the
Monroe gas field (the Company's primary gas field) is experiencing normal
production declines, production from new development wells in the field should
offset such declines absent the operational problems discussed above.
In 1996, the posted price for the Company's crude oil averaged $20.23 per
Bbl, a 21% increase over the average posted price of $16.73 experienced in 1995.
The crude oil prices received by the Company during 1996 increased more
significantly than the average posted price because the Company amended its
marketing arrangements for the sale of substantially all of its crude oil during
1995 and again in March 1996, to improve the price and resultant revenues it
receives for its crude oil.
The price for the Company's natural gas, including hedging gains and
losses, increased 30% in 1996 compared to 1995 due to increased demands for
natural gas.
Production revenues for 1996 included crude oil hedging losses of $4.7
million ($1.92 per Bbl) compared to crude oil hedging losses of $.6 million
($.27 per Bbl) in 1995. Production revenues in 1996 also included natural gas
hedging losses of $1.2 million ($.18 per Mcf) compared with natural gas hedging
gains of $1.0 million ($.15 per Mcf) in 1995.
Interest and other income increased to $1.0 million in 1996 from $92,000
in 1995 due to $472,000 of interest earned during 1996 on the receivable from
the sale of the marketing and pipeline segment of operations and due to an
unrealized gain of $450,000 on marketable securities.
Expenses. Production expenses were $13.9 million for 1996 compared to
$12.5 million for 1995. This increase primarily reflects additional production
volumes. On a BOE basis, production costs increased to $3.88 per BOE in 1996
compared to $3.71 per BOE in 1995, primarily due to an increase of $.15 per BOE
in production taxes as a result of higher crude oil and natural gas prices.
General and administrative costs increased 35% in 1996 to $7.3 million,
primarily due to increased compensation and employee related costs attributable
to staff additions made during the last half of 1995 and during 1996 to handle
the increased drilling and recompletion activity. Additionally, 1996 expenses
include an estimated bonus accrual of approximately $812,000 associated with the
Company's 1996 bonus plan, which is awarded based on the Company's after tax
return on equity for the year. As a result of these increases, general and
administrative expenses per BOE increased 26% from $1.61 in 1995 to $2.03 in
1996.
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Depletion and depreciation expense increased 11% to $16.3 million in
1996. This increase is primarily the result of increased production volumes. The
depletion rate per BOE in 1996 increased 4% to $4.55 compared with $4.38 for
1995.
Interest expense increased 5% to $8.5 million in 1996 from $8.1 million
in 1995 due to higher borrowing levels, which were partially offset by a
decrease in interest rates. Borrowing levels increased by $2.0 million to $105.4
million prior to the paydown of $20.5 million on April 3, 1996 from the proceeds
of the natural gas pipeline sale discussed under "Liquidity and Capital
Resources". Borrowing levels during the remainder of 1996 increased by $35.6
million to $120.5 million to fund increased drilling activities. The average
interest rate paid on outstanding indebtedness under the Company's Revolving
Credit Facility was 7.6% in 1996, compared to 8.4% in 1995.
The Company's net earnings in 1996 were $5.9 million, as compared to $1.8
million in 1995 (including $1.6 million of income from discontinued operations)
for the reasons discussed above.
LIQUIDITY AND CAPITAL RESOURCES
Capital Sources. Cash flow generated from operating activities was $16.8
million and $37.1 million for the years ended December 31, 1996 and 1997,
respectively. Cash flow generated from operating activities before changes in
operating assets and liabilities improved $3.6 million from 1996 to 1997
primarily due to production and gas price increase. Changes in operating assets
and liabilities provided additional cash flow of $7.1 million in 1997 as
compared to a use of cash flow of $9.5 million in 1996.
At December 31, 1997, the Company had a working capital deficit of $2.0
million primarily due to current payables associated with drilling and
recompletion activity which will be funded with cash flow from operations and
borrowings under the Revolving Credit Facility.
In April 1996, the Company's wholly owned subsidiary, ING, sold all of
the stock of its wholly owned subsidiaries that comprised the Company's
Louisiana natural gas marketing and transportation segment to an unrelated third
party, for total consideration of approximately $23 million. The total
consideration was comprised of $19.5 million in cash, the assumption of net
liabilities of approximately $2.3 million (excluding deferred taxes) and the
reimbursement for the payment of certain taxes of up to $1.2 million generated
as a result of the tax treatment of the transaction. The cash proceeds from the
sale were used to reduce amounts outstanding under the Company's Revolving
Credit Facility.
On October 3, 1997, the Company issued 5,000,000 shares of common stock
at $10.50 per share and issued $150 million of 8 7/8% Senior Subordinated Notes
due 2007 ("Senior Notes") pursuant to two public offerings with combined net
proceeds of $193.7 million. The proceeds from these offerings were used to repay
$144.8 million of indebtedness outstanding under the Company's Revolving Credit
Facility, for general corporate purposes and to fund a portion of the December
1997 Oklahoma property acquisition discussed under "Property Acquisitions".
Under the Revolving Credit Facility, the amount available to the Company
in borrowing capacity for general corporate purposes ("Borrowing Base") is $300
million, which terminates on January 2, 2003. The margin premium charged in
excess of LIBOR for revolving Eurodollar advances is based on a ratio calculated
on a rolling four-quarter basis of consolidated indebtedness to EBITDA. The
margin is currently 1.50%. CRI, and its wholly owned subsidiaries, Coho
Louisiana Production Company, Coho Exploration, Inc. and Coho Oil & Gas, Inc.,
are the borrowers under the Revolving Credit Facility and 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. At December 31, 1997,
outstanding advances under the Company's Revolving Credit Facility were $221
million, all of which were classified as long term, leaving $79 million
available thereafter.
The Revolving Credit Facility contains certain financial and other
covenants including (i) the maintenance of minimum amounts of shareholders'
equity ($108 million plus 50% of the accumulated consolidated net income
beginning in 1998 for the cumulative period excluding adjustments for any write
down of property, plant and equipment, plus 75% of the cash proceeds of any
sales of capital stock of the Company), (ii) maintenance of minimum ratios of
cash flow to interest expense (2.5 to 1) as well as current assets (including
unused borrowing base) to current liabilities (1 to 1), (iii) limitations on the
Company's ability to incur additional debt and (iv) restrictions on the payment
of dividends.
27
28
At December 31, 1997, shareholders' equity exceeded the minimum required under
the Revolving Credit Facility by approximately $34 million and the ratio of
current assets to current liabilities was 5.0 to 1. For the year ended December
31, 1997, the ratio of EBITDA to interest expense was 3.7 to 1.
The Senior Notes are unsecured senior subordinated obligations of the
Company and rank pari passu in right of payment to all existing and future
senior subordinated indebtedness of the Company. The Senior Notes 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 Senior Notes on a senior
subordinated basis.
The indenture issued in conjunction with the Senior Notes (the
"Indenture") contains certain covenants, including 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.
Property Acquisition. Effective December 31, 1997, the Company acquired
the Amoco Properties located primarily in southern Oklahoma for cash
consideration of approximately $257.5 million and warrants to purchase one
million shares of common stock of the Company at $10.425 per share for a period
of five years valued at $3.4 million. The aggregate purchase price was $267.8
million, including transaction costs of approximately $1.9 million and assumed
liabilities of $5 million. $221 million of the cash consideration was financed
under the Revolving Credit Facility and the remaining $36.5 million was funded
from working capital.
Dividends. While the Company is restricted on the payment of dividends
under the Revolving Credit Facility, dividends are permitted on Company equity
securities provided (i) the Company is not in default under the Revolving Credit
Facility; and (ii) (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 after giving effect to such
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 Indenture will limit
the Company's ability to pay dividends, based on the Company's 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 Senior Notes were issued plus the net proceeds from any future sales of
capital stock of the Company. Although the Company has never paid a dividend on
its Common Stock and has no plan to do so in the foreseeable future, the Company
does not believe that the Revolving Credit Facility or the Indenture imposes an
undue burden on the Company's ability to pay dividends.
Capital Expenditures. During 1997, the Company incurred capital
expenditures of $72.7 million (excluding the acquisition cost of the recently
acquired Oklahoma properties) compared with $52.3 million in 1996. The capital
expenditures incurred during 1997 were largely in connection with the continuing
development efforts, including recompletions, workovers and waterfloods, on
existing wells in the Company's Brookhaven, Laurel, Martinville and Soso fields.
In addition during 1997, the Company drilled 28 wells as follows: four producing
crude oil wells in the Laurel field, three producing crude oil wells and one dry
hole in the Martinville field, two producing crude oil wells in the Soso field,
four producing crude oil wells and one producing natural gas well in the
Brookhaven field, nine producing natural gas wells and two dry holes in the
Monroe field and two producing offshore natural gas wells in the North Padre
field. The Company was in the process of drilling six wells at December 31,
1997: one in the Summerland field, two in the Martinville field and three in the
Brookhaven field.
General and administrative costs directly associated with the Company's
exploration and development activities were $2.5 million and $4.1 million for
the years ended December 31, 1996 and 1997, respectively, and were included in
total capital expenditures.
The Company initially budgeted expenditures of approximately $90 million
to continue the exploration and exploitation of the Company's properties in the
Mississippi salt basin and exploitation of the newly acquired Oklahoma
properties. With the fall in oil prices, during the first quarter the Company
has reviewed its 1998 projects and has
28
29
decided to postpone approximately $20 million of capital expenditures. Coho is
in a unique position to increase or decrease its capital budget because it
operates and has a high working interest in the majority of its fields.
Management believes that, barring any significant acquisitions or other
unforeseen capital requirements, borrowings under the Revolving Credit Facility
and cash flow from operations will be adequate to fund the anticipated capital
expenditures and working capital needs of the Company through 1998.
Year 2000 Issue. The Company has assessed and continues to assess the
impact of the "year 2000" issue on its reporting systems and operations. The
"year 2000" issue exists because many computer systems and applications
currently use two-digit date fields to designate a year. As the century date
occurs, 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.
The Company projects all computer systems and software will be year 2000
compliant during 1998. Management does not estimate future expenditures related
to the year 2000 exposure to be material.
29
30
ITEM 8. FINANCIAL STATEMENTS
Report of Independent Public Accountants ........................................................ 31
Consolidated Balance Sheets, December 31, 1996 and 1997 ......................................... 32
Consolidated Statements of Earnings, Years Ended December 31, 1995, 1996 and 1997 ............... 33
Consolidated Statements of Shareholders' Equity, Years Ended December 31, 1995, 1996 and 1997 ... 34
Consolidated Statements of Cash Flows, Years Ended December 31, 1995, 1996 and 1997 ............. 35
Notes to Consolidated Financial Statements, Years Ended December 31, 1995, 1996 and 1997 ........ 36
30
31
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Shareholders of
Coho Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Coho
Energy, Inc. (a Texas corporation) and subsidiaries for the years ended December
31, 1997 and 1996, and the related consolidated statements of earnings,
shareholders' equity, and cash flows for each of the three years in the period
ended December 31, 1997. 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 for the years ended December 31, 1997 and 1996, and results of
their operations and their cash flows for each of the three years in the period
ended December 31, 1997 in conformity with generally accepted accounting
principles.
Arthur Andersen LLP
Dallas, Texas
March 20, 1998
31
32
COHO ENERGY, INC.
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
ASSETS
DECEMBER 31
-----------------------
1996 1997
--------- ---------
Current assets
Cash and cash equivalents
Account receivable, principally trade ...................................... $ 1,864 $ 3,817
Deferred income taxes ...................................................... 11,884 10,724
Investment in marketable securities ........................................ 913 1,818
Other current assets ....................................................... 1,962 --
995 715
--------- ---------
17,618 17,074
Property and equipment, at cost net of accumulated depletion and
depreciation, based on full cost accounting method (note 3) ................ 210,212 531,409
Other assets ............................................................... 2,211 6,645
--------- ---------
$ 230,041 $ 555,128
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable, principally trade ........................................ $ 5,752 $ 4,888
Accrued liabilities and other payables ..................................... 5,043 14,169
Current portion of long term debt (note 4).................................. 161 38
--------- ---------
10,956 19,095
Long term debt, excluding current portion (note ............................. 122,777 369,924
Deferred income taxes (note 5) .............................................. 14,842 20,306
--------- ---------
148,575 409,325
--------- ---------
Commitments and contingencies (note 9) -- 3,700
Shareholders' equity (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 20,347,126 and 25,603,512 shares at December 31, 1996 and 1997,
respectively .............................................................. 203 256
Additional paid-in capital .................................................. 83,516 137,812
Retained earnings (deficit).................................................. (2,253) 4,035
--------- ---------
Total shareholders' equity ............................................. 81,466 142,103
--------- ---------
$ 230,041 $ 555,128
========= =========
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
32
33
COHO ENERGY, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EARNINGS
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31
-------------------------------------
1995 1996 1997
---------- ---------- ----------
Operating revenues
Crude oil and natural gas production (note 10) ......................... $ 40,903 $ 54,272 $ 63,130
-------- -------- --------
Operating expenses
Crude oil and natural gas production .................................. 10,514 11,277 13,747
Taxes on oil and gas production ....................................... 1,943 2,598 2,223
General and administrative ............................................ 5,400 7,264 7,163
Depletion and depreciation ............................................ 14,717 16,280 19,214
-------- -------- --------
Total operating expenses .......................................... 32,574 37,419 42,347
-------- -------- --------
Operating income (loss) ................................................ 8,329 16,853 20,783
-------- -------- --------
Other income and expenses
Interest and other income ............................................. 92 1,012 646
Interest expense ...................................................... (8,140) (8,476) (11,120)
-------- -------- --------
(8,048) (7,464) (10,474)
-------- -------- --------
Earnings from continuing operations before income taxes ................ 281 9,389 10,309
-------- -------- --------
Income taxes (note 5)
Current (recovery) expense ............................................ 457 (411) 163
Deferred (reduction) expense .......................................... (345) 3,894 3,858
-------- -------- --------
112 3,483 4,021
-------- -------- --------
Net earnings from continuing operations ................................ 169 5,906 6,288
Discontinued operations (note 2)
Income (loss) from discontinued marketing and transportation operations
(less applicable income tax expense (benefit) of $1,384 in 1995) .... 1,611 -- --
-------- -------- --------
Net earnings ........................................................... 1,780 5,906 6,288
Dividends on preferred stock ........................................... (944) -- --
-------- -------- --------
Net earnings applicable to common stock ................................ $ 836 $ 5,906 $ 6,288
======== ======== ========
Basic earnings (loss) from continuing operations per common share ...... $ (.02) $ .29 $ .29
======== ======== ========
Diluted earnings (loss) from continuing operations per common share .... $ (.02) $ .29 $ .28
======== ======== ========
Basic earnings per common share ........................................ $ .05 $ .29 $ .29
======== ======== ========
Diluted earnings per common share ...................................... $ .05 $ .29 $ .28
======== ======== ========
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
33
34
COHO ENERGY, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
NUMBER OF
COMMON ADDITIONAL RETAINED
SHARES COMMON PAID-IN EARNINGS
OUTSTANDING STOCK CAPITAL (DEFICIT) TOTAL
----------- ------ ---------- --------- -----
Balance at December 31, 1994 ..................... 16,782,925 $ 168 $ 65,243 $ (8,995) $ 56,416
Issued on
(i) Exchange of preferred stock (note 7)...... 3,225,000 32 16,093 -- 16,125
(ii) Satisfaction of accrued preferred
dividends (note 7) ....................... 157,338 2 942 -- 944
Net earnings .................................... -- -- -- 1,780 1,780
Dividends on preferred stock .................... -- -- -- (944) (944)
---------- ---------- ---------- ---------- ----------
Balance at December 31, 1995 ..................... 20,165,263 202 82,278 (8,159) 74,321
Issued on
(i) Exercise of Employee Stock Options ........ 81,863 -- 414 -- 414
(ii) Acquisition of working interest .......... 100,000 1 824 -- 825
Net earnings ..................................... -- -- -- 5,906 5,906
---------- ---------- ---------- ---------- ----------
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
========== ========== ========== ========== ==========
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
34
35
COHO ENERGY, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31
-------------------------------------
1995 1996 1997
---------- ---------- ----------
Cash flows from operating activities
Net earnings ................................................... $ 1,780 $ 5,906 $ 6,288
Adjustments to reconcile net earnings to net cash provided
(used) by operating activities:
Depletion and depreciation ..................................... 15,876 16,280 19,214
Deferred income taxes .......................................... 653 3,894 3,858
Amortization of debt issue costs and other...................... 918 271 591
Changes in:
Accounts receivable............................................. (4,696) (6,983) 1,160
Other assets ................................................... 1,188 (489) (351)
Accounts payable and accrued liabilities ....................... (3,221) 40 4,346
Investment in marketable securities ............................ -- (1,512) 1,962
Deferred income taxes and other current liabilities ............ 337 (560) --
--------- --------- --------
Net cash provided (used) by operating activities ................ 12,835 16,847 37,068
--------- --------- --------
Cash flows from investing activities
Acquisitions ................................................... -- -- (259,355)
Property and equipment ......................................... (29,970) (52,384) (72,667)
Changes in accounts payable and accrued liabilities related to
exploration and development ................................... 986 (902) 3,559
Cash included in net assets of discontinued operations ......... (352) -- --
Proceeds on sale of property and equipment...................... -- 21,476 --
--------- --------- --------
Net cash used in investing activities ........................... (29,336) (31,810) (328,463)
--------- --------- --------
Cash flows from financing activities
Increase in long term debt ..................................... 19,140 52,600 402,894
Debt issuance costs ............................................ -- -- (4,275)
Repayment of long term debt .................................... (1,822) (37,617) (155,989)
Increase in gas storage loan ................................... 4,000 -- --
Repayment of gas storage loan .................................. (5,000) -- --
Proceeds from exercised stock options .......................... -- 414 1,495
Issuance of common stock ....................................... -- -- 49,223
--------- --------- --------
Net cash provided by financing activities ....................... 16,318 15,397 293,348
--------- --------- --------
Net increase (decrease) in cash and cash equivalents ............ (183) 434 1,953
Cash and cash equivalents at beginning of year .................. 1,613 1,430 1,864
--------- --------- --------
Cash and cash equivalents at end of year ........................ $ 1,430 $ 1,864 $ 3,817
========= ========= ========
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
35
36
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1995, 1996 AND 1997
(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").
Prior to September 29, 1993, CRI was a publicly held company of which Coho
Resources Limited, a publicly held Alberta, Canada Company ("CRL"), held a 68%
ownership interest. As a result of the reorganization effective on September 29,
1993 (the "1993 Reorganization"), CRI and CRL became wholly-owned subsidiaries
of CEI.
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.
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.
Marketable Securities
In accordance with Statement of Financial Accounting Standards No. 115,
"Accounting for Certain Instruments in Debt and Equity Securities", the Company
has classified all equity securities as trading securities and adjusted such
securities to market value at the end of each period. Unrealized gains and
losses on trading securities are reported in earnings. Trading securities, as of
December 31, 1996, had a fair value of $1,962,000 and gross unrealized gains of
$722,000.
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.
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
36
37
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
Estimates
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.
Impairment of Long-Lived Assets
During fiscal year 1996, the Company adopted SFAS No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived-Assets To Be Disposed
Of." The Company has no assets which meet the requirement for impairment.
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
Statement of Financial Accounting Standards 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
FASB-Statement No. 128 "Earnings Per Share." Under Statement 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. Previously reported EPS
were equivalent to the diluted EPS calculated under Statement 128.
37
38
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
1995 1996 1997
----------------------------- ---------------------------- ---------------------------
Income Common Income Common Income Common
(in 000's) Shares EPS (in 000's) Shares EPS (in 000's) Shares EPS
---------- ---------- --- ---------- ---------- ---- ---------- ---------- ---
Net earnings $ 1,780 $ 5,906 $ 6,288
Less preferred dividend (944) -- --
------- ------- -------
BASIC EARNINGS PER SHARE 836 17,931,933 $.05 5,906 20,178,917 $.29 6,288 21,692,804 $.29
==== ==== ====
Stock Options 162,651 641,099
------- ---------- ---- ------- ---------- ---- ------- ---------- ----
DILUTED EARNINGS PER SHARE $ 836 17,931,933 $.05 $ 5,906 20,341,568 $.29 $ 6,288 22,333,903 $.28
======= ========== ==== ======= ========== ==== ======= ========== ====
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 number of common shares outstanding during
the year including common stock equivalents, consisting of stock options for the
three years and warrants for 1997, when their effect is dilutive. In 1995,
conversion of the stock options would have been anti-dilutive and, therefore,
was not considered in diluted EPS. In 1997, conversion of the warrants would
have been anti-dilutive and, therefore, was not considered in diluted EPS.
Income Taxes
The Company accounts for income taxes in accordance with FASB Statement
of Financial Accounting Standards No. 109, "Accounting for Income Taxes." Under
the asset and liability method of Statement 109, deferred tax assets and
liabilities are recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of existing assets
and liabilities and their respective tax bases. Deferred tax assets and
liabilities are measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are expected to be
recovered or settled.
Hedging Activities
Periodically, the Company enters into futures contracts which are
traded on the stock exchanges in order to fix the price on a portion of its
crude oil and natural gas production. Changes in the market value of crude oil
and natural gas futures contracts are reported as an adjustment to revenues in
the period in which the hedged production or inventory is sold. The gain or loss
on the Company's hedging transactions is determined as the difference between
the contract price and a reference price, generally closing prices on the New
York Mercantile Exchange.
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.
38
39
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Business Segments
In June 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards 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. DISCONTINUED OPERATIONS
On April 3, 1996, the Company's wholly owned subsidiary, Interstate
Natural Gas Company ("ING"), sold the stock of three wholly owned subsidiaries
that comprised its natural gas marketing and transportation segment to an
unrelated third party for cash of $19.5 million, the assumption of net
liabilities of approximately $2.3 million and the payment of taxes of $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, and accordingly, its operations are segregated in the accompanying
statements of operations.
Revenues of the marketing and transportation segment were $71,773,000
for 1995. Certain expenses have been allocated to discontinued operations,
including interest expense, which was allocated on the ratio of net assets
discontinued to the total net assets acquired from ING applied to the $20
million of cash borrowed to acquire ING.
3. PROPERTY AND EQUIPMENT
December 31
-------------------------
1996 1997
--------- ---------
Crude oil and natural gas leases and rights including exploration,
development and equipment thereon, at cost ................... $ 328,836 $ 669,247
Accumulated depletion and depreciation ........................... (118,624) (137,838)
--------- ---------
$ 210,212 $ 531,409
========= =========
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 totalled
$1,788,000, $2,452,000 and $4,081,000 in 1995, 1996 and 1997, respectively.
During 1995, 1996 and 1997, 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 totalling $8,284,000 and
$82,872,000 (including $70,000,000 for the recently acquired Oklahoma
properties) at December 31, 1996 and 1997, 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 $4.38, $4.55 and $4.69 in 1995, 1996 and 1997, respectively.
39
40
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
4. LONG-TERM DEBT
1996 1997
--------- ---------
Revolving credit facility ...................................... $ 120,500 $ 221,000
8 7/8% Senior Subordinated Notes Due 2007 ...................... -- 150,000
Promissory notes ............................................... 2,323 --
Other ......................................................... 234 68
--------- ---------
123,057 371,068
Unamortized original issue discount on senior subordinated
notes......................................................... -- (1,106)
Unamortized discount on promissory notes ....................... (119) --
Current maturities on long term debt ........................... (161) (38)
--------- ---------
$ 122,777 $ 369,924
========= =========
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 Restated Credit Agreement"), provides a
maximum commitment amount available to the Company ("Borrowing Base") of $300
million for general corporate purposes. Outstanding advances as of December 31,
1997, were $221 million, leaving $79 million in available borrowing under the
credit facility for general corporate purposes. The Restated Credit 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 Restated Credit Agreement 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%) and 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 provide collateral
with value equal to such excess or 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.
The Restated Credit 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 and CRI's ability to incur additional debt, and (iv) restrictions on
the payment of dividends.
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 ("Senior Notes"). 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 Restated Credit Agreement and for general corporate purposes.
The Senior Notes 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 Senior Notes 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 Senior Notes on a senior
subordinated basis.
40
41
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The Indenture issued in conjunction with the Senior Notes (the
"Indenture") contains certain covenants, including 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.
Promissory Notes
In August 1995, the Company entered into noninterest bearing promissory
notes aggregating $4.2 million ($3.8 million net of discount based on an imputed
interest rate of 8.13%) which were paid in two installments of $1.9 million in
August 1996 and $2.3 million in August 1997 in connection with the Brookhaven
Acquisition (Note 6).
Debt Repayments
Based on the balances outstanding and current terms under the Restated
Credit Agreement and the Senior Notes indenture, estimated aggregate principal
repayments for each of the next five years are as follows: ; 1998 - $52,000;
1999 - $16,000; 2000- $0; 2001 - $0; 2002 - $0 and $371,000,000 thereafter.
5. INCOME TAXES
Deferred income taxes are recorded based upon differences between
financial statement and income tax basis of assets and liabilities. The tax
effects of these differences which give rise to deferred income tax assets and
liabilities at December 31, 1996 and 1997, were as follows:
1996 1997
---------- ----------
DEFERRED TAX ASSETS
Net operating loss carryforwards...................... $ 26,087 $ 25,176
Alternative minimum tax credit carryforwards.......... 1,866 1,095
Employee benefits..................................... 46 565
Other................................................. (46) 165
Total gross deferred tax assets....................... ---------- ---------
27,953 27,001
Less valuation allowance.............................. (4,150) (4,594)
---------- ---------
Net deferred tax assets............................... 23,803 22,407
---------- ---------
DEFERRED TAX LIABILITIES
Property and equipment, due to differences in
depletion and depreciation........................ 37,732 40,895
---------- ---------
NET DEFERRED TAX LIABILITY................................ $ 13,929 $ 18,488
========== =========
The valuation allowance for deferred tax assets as of December 31, 1996
and 1997 includes $2,052,000 and $2,051,000, 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.
41
42
COHO ENERGY, INC.
AND SUBSIDIARIES
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:
1995 1996 1997
------- -------- --------
Earnings (loss) before income taxes from continuing
operations.................................................. $ 281 $ 9,389 $ 10,309
======== ======== ========
Expected income tax expense (recovery) (statutory
rate - 34%)................................................ $ 95 $ 3,192 $ 3,505
State taxes - deferred ....................................... 232 (353) 552
Federal benefit of state taxes ............................... (78) 120 (188)
Change in valuation allowance ................................ (168) 471 444
Other ........................................................ 31 53 (293)
-------- -------- --------
$ 112 $ 3,483 $ 4,020
======== ======== ========
At December 31, 1997, the Company had the following income tax
carryforwards available to reduce future years' income for tax purposes:
Expires Amount
------- ------
Net operating loss carryforwards for federal income tax purposes ...................... 1998 $ 5,043
1999 1,727
2000 4,253
2001 3,016
2002 211
2003-2011 49,252
--------
$ 63,502
========
Operating loss carryforwards for Canadian income tax purposes ......................... 1999-2003 $ 4,046
========
Operating loss carryforwards for federal alternative minimum tax
purposes .......................................................................... 2009-2010 $ 12,832
========
Federal alternative minimum tax credit carryforwards .................................. -- $ 1,095
========
Operating loss carryforwards for Mississippi income tax purposes ...................... 2010-2012 $ 14,440
========
Operating loss carryforwards for Louisiana income tax purposes ........................ 2004-2012 $ 10,161
========
6. ACQUISITIONS
Effective December 31, 1997, the Company acquired from Amoco Production
Company ("Amoco") interests in certain crude oil and natural gas properties
("Amoco 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 Amoco 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.
The following unaudited proforma information of the Company for the
years ended December 31, 1996 and 1997 have been prepared assuming the
acquisition of the Amoco Properties occurred on January 1, 1996. Such proforma
42
43
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
information is not necessarily indicative of what actually could have occurred
had the acquisition taken place on January 1, 1996 or 1997.
1996 1997
---------- -----------
Revenues ................................... $ 99,150 $ 109,428
Net earnings ............................... 6,167 6,422
Basic earnings per share ................... .31 .30
Diluted earnings per share ................. .30 .29
On August 18, 1995, the Company acquired from a third party approximately
93% of the working interests in a unitized oil field containing 11 active wells
and 159 inactive wells located in the Brookhaven field in Mississippi (the
"Brookhaven Acquisition"). The total cost of the acquisition was $5.6 million in
cash as follows: $1.4 million paid on the acquisition date; $1.9 million due in
August 1996 and $2.3 million due in August 1997. The net cost was $5.1 million
net of discount based on an imputed interest rate of 8.13% for the promissory
notes due in 1996 and 1997. Only the $1.4 million cash portion of the
acquisition cost is reflected in the consolidated statement of cash flows for
the year ended December 31, 1995 (the year of acquisition).
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 Senior Notes offering discussed in
Note 4, were used to repay indebtedness outstanding under the Company's Restated
Credit 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.
In December 1996, the Company issued 100,000 shares of common stock,
valued at approximately $825,000, to Churchill Resource Investments Inc. as
consideration for the purchase of interest in certain crude oil properties.
The redeemable preferred stock issued in connection with the acquisition
of ING in 1994 was non-voting and entitled to receive cumulative quarterly
dividends at a coupon rate equal to the prime lending rate per annum (8.5% for
the first quarter of 1995 and 9% for the second and third quarters of 1995). If
the preferred stock were not redeemed by September 4, 1995, the coupon rate
increased 1/2% per quarter to a maximum rate of 18% per annum. On August 30,
1995, the Company exchanged 3,225,000 shares of Common Stock for the 161,250
shares of Series A Preferred Stock with a stated value of $16,125,000 and issued
157,338 shares of Common Stock to the holders of the preferred stock to satisfy
the accrued dividend obligation through August 30, 1995 of $944,000. These
noncash transactions are not reflected in the consolidated statement of cash
flows for the year ended December 31, 1995.
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 Company's subsidiaries in the 1993 Reorganization. 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. On December 2, 1997, the Company granted, subject to
shareholder approval, 407,500 stock options which will be voted on May 12,
43
44
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
1998 and are included in 1997 granted shares. A summary of the status of the
Company's stock option plans at December 31, 1995, 1996 and 1997 and changes
during the years then ended follows:
1995 1996 1997
------------------- ------------------- -------------------
WTD AVG WTD AVG WTD AVG
SHARES EX PRICE SHARES EX PRICE SHARES EX PRICE
------ -------- ------ -------- ------ --------
Outstanding at January 1 ......... 1,533,813 5.63 1,700,313 5.56 1,815,784 5.55
Granted ...................... 166,500 4.98 202,000 5.19 1,286,000 8.73
Exercised .................... -- -- (81,863) 5.05 (256,386) 5.82
Canceled ..................... -- -- (4,666) 5.43 (21,583) 6.50
---------- ---- --------- ---- --------- ----
Outstanding at December 31........ 1,700,313 5.56 1,815,784 5.55 2,823,815 6.96
---------- ---- --------- ---- --------- ----
Exercisable at December 31........ 1,048,402 5.75 1,390,118 5.69 2,250,903 6.31
Available for grant at
December 31 .................. 39,670 118,836 36,419
Significant option groups outstanding at December 31, 1997 and related
weighted average price and life information follows:
WTD AVG
OPTIONS OPTIONS EXERCISE REMAINING
GRANT DATE OUTSTANDING EXERCISABLE PRICE LIFE (YEARS)
---------- ----------- ----------- -------- ------------
December 2, 1997 .............................. 410,000 2,500 $ 10.50 7
August 22, 1997 ............................... 16,000 -- 9.38 7
May 12, 1997 .................................. 8,000 -- 8.13 5
March 3, 1997 ................................. 836,000 745,750 7.88 4
June 13, 1996 ................................. 12,000 12,000 6.63 4
February 22, 1996.............................. 150,000 150,000 5.13 5
January 8, 1996 ............................... 40,000 13,333 5.00 5
September 25, 1995............................. 50,000 50,000 5.00 4
September 12 ,1995............................. 38,666 25,003 5.00 5
August 3, 1995 ................................ 24,000 24,000 4.88 4
April 14, 1995 ................................ 32,500 21,668 5.00 4
December 4, 1994 .............................. 105,000 105,000 5.01 5
November 10, 1994.............................. 240,000 240,000 5.00 4
June 7, 1994 .................................. 79,883 79,883 5.49 3
March 28, 1994 ................................ 5,000 5,000 4.50 2
October 22, 1993 .............................. 378,089 378,089 6.00 3
September 29, 1993............................. 105,067 105,067 6.84 2
November 18, 1992.............................. 6,667 6,667 5.25 2
October 19, 1992 .............................. 286,943 286,943 5.52 2
44
45
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The weighted average fair value at date for options granted during 1995,
1996 and 1997 was $2.25, $2.21 and $4.02 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:
1995 1996 1997
-------- -------- --------
Expected life (years).............. 5 5 5
Interest rate...................... 6.28% 5.37% 6.44%
Volatility......................... 43.43% 38.79% 43.76%
Dividend yield..................... --- --- ---
Had compensation cost for these plans been determined consistent with
FASB Statement 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:
1995 1996 1997
-------- -------- --------
Net income (loss) As reported.................................... $ 169 $ 5,906 $6,288
Pro forma.................................... $ (67) $ 5,625 $4,385
Basic earnings (loss) per share As reported................................... $ .01 $ .29 $ .29
Pro forma.................................... $ --- $ .27 $ .20
Diluted earnings (loss) per share As reported................................... $. 01 $ .29 $ .28
Pro forma..................................... $ --- $ .27 $ .20
9. COMMITMENTS AND CONTINGENCIES
(a) In July, 1994, the Company, together with several other companies,
was named as a defendant in a lawsuit filed in Jones County, Mississippi. The
lawsuit, involves claims by a landowner for purported damages caused by
naturally occurring radioactive materials ("NORM") at various wellsite locations
on land leased by the Company in Mississippi. The plaintiff is seeking
significant compensatory and punitive damages, including damages for "emotional
distress." This lawsuit has been dormant for two years and the land involved has
been remediated.
Additionally, in 1996 and 1997, the Company, together with several other
companies, was named as a defendant in a number of lawsuits of the same nature
as the July, 1994 lawsuit. All of the suits are principally identical and seek
damages for land damage, health hazard, mental and emotional distress, etc. None
of the suits seek specific award amounts, but all seek punitive damages.
In connection with the acquisition of the Amoco Properties on December
18, 1997, the Company assumed the responsibility for costs and expenses
associated with the assessment, remediation, removal, transportation and
disposal of the asbestos or NORM associated with the Amoco Properties.
Additionally, the Company is responsible for all other environmental claims up
to approximately $10.3 million and all environmental claims not identified and
presented to Amoco by December 18, 1998. The Company is not currently aware of
any such claims and is performing due diligence to identify all potential
environmental claims.
While the Company is not able to determine its exposure in the remaining
suits at this time, the Company believes that the claims will have no material
adverse effect on its financial position or results of operations.
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
45
46
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
position or results of operations. The Company has accrued $5 million, including
$1.3 million which has been reflected in current accrued liabilities, for future
remediation costs.
(b) The Company has leased (i) 38,568 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, and (iii) various vehicles under
non-cancellable leases extending through February 2000. Rental expense totalled
$487,000, $694,000 and $799,000 in 1995, 1996 and 1997, respectively. Minimum
rentals payable under these leases for each of the next five years are as
follows: 1998 - $784,000; 1999 - $706,000; 2000 - $564,000; 2001 - $0 and 2002
- -$0. Total rentals payable over the remaining terms of the leases are
$2,054,000.
(c) 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 but excluding the Monroe gas field discussed below. A
total of $1,061,000 has been included in depletion and depreciation expense with
respect to such costs as of December 31, 1997.
Certain governmental agencies are presently studying whether the oil and
gas industry's practice of utilizing mercury meters poses any potential
environmental problems that require more stringent regulation. Operators in the
Monroe Field have been asked to monitor their operations and assist in gathering
data. During 1995, the Company voluntarily negotiated a remediation plan with
the governmental agencies responsible for the two wildlife refuges in the Monroe
Field. Under the plan, the Company began removal of the mercury meters within
the two wildlife refuges in 1996. The Company continues to cooperate with the
various agencies in their studies. At this time, the Company believes that minor
mercury spillages and leaks may have occurred in the past. However, the Company
believes that such spillages and leaks are less than the amounts reportable
under prior or existing statutes and laws. The Company makes a provision for
future site restoration charges on a unit-of-production basis for the Monroe
field gas which is included in depletion and depreciation expense; a total of
$1,030,000 has been included in depletion and depreciation expense with respect
to such costs as of December 31, 1997.
(d) 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 officers' aggregate base salary and bonus portion of total annual
compensation covered under such employment agreements is approximately $1.3
million.
(e) 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 of 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.
The highest salary plus bonus paid to the officers covered under such
severance agreements during the preceding five year period would aggregate
approximately $876.000.
46
47
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(f) In conjunction with the acquisition of the Amoco Properties, the
acquisition of ING and the 1993 reorganization (Note 1), 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, 1997, is approximately 3,324,287.
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 $441,000, $(5,908,000) and
$(232,000) for 1995, 1996 and 1997, respectively, resulting from these hedging
programs. At December 31, 1997, the Company has 10,000 Mmbtu per day of natural
gas production hedged over the period from January through March 1998, at a
minimum price of $2.70 per Mmbtu and a maximum price of $3.28 per Mmbtu. In
March 1998, the Company hedged an additional 15,000 Mmbtu per day of natural gas
production over the period from April through August 1998, at a minimum price of
$2.00 per Mmbtu and a maximum price of $2.54 per Mmbtu.
The stated value of long term debt approximates fair market value since
the interest applicable to each instrument approximates market rates.
During the years ended December 31, 1996 and 1997, EOTT Energy Corp.
("EOTT") accounted for 66% and 75%, respectively, of Coho's receipt of operating
revenues, and Mid Louisiana Marketing Company (formerly a wholly owned
subsidiary sold on April 3, 1996 - see Note 2), accounted for 15% and 21%,
respectively, of Coho's receipt of operating revenues. In 1995, Amerada Hess
Corporation ("Amerada") accounted for 66% of Coho's receipt of operating
revenues. Included in accounts receivable is $2,691,000, $7,222,491 and
$2,969,000 due from these customers at December 31, 1995, 1996 and 1997,
respectively.
11. RELATED PARTY TRANSACTIONS
(a) Corporations controlled by certain directors and shareholders of the
Company have participated with the Company in certain crude oil and natural gas
joint ventures on the same terms and conditions as other industry partners.
These transactions are summarized as follows:
1995 1996 1997
-------- -------- --------
Campco International Capital Ltd. (i)
Net crude oil and natural gas revenues............ $ 219 $ 243 $ 255
Capital expenditures ............................ 77 101 173
Payable to (receivable from) CRI at the balance
sheet date....................................... (3) (22) 16
(i) Campco International Capital Ltd. is a private company controlled by
Frederick K. Campbell, a director of the Company.
(b) 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, is repayable on the date Mr. Clarke ceases employment with the
Company and is included in other assets at December 31, 1997.
47
48
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(c) 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
non-interest bearing loans of $622,111, payable on demand, 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.
(d) Certain of the Company's hedging agreements are 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 it's 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.
12. CASH FLOW INFORMATION
Supplemental cash flow information is presented below:
1995 1996 1997
-------- -------- --------
Cash paid (received) during the period
Interest...................................... $ 7,574 $ 8,259 $ 7,774
Income taxes.................................. $ (1,131) $ 478 $ 603
13. 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:
Year Ended December 31
--------------------------------
1995 1996 1997
---------- --------- -----------
Net earnings (loss) based on US GAAP...................................... $ 1,780 $ 5,096 $ 6,288
Adjustment to depletion based on difference in carrying value of oil and
gas properties related to:
ING acquisition (i)................................................... 576 556 562
Business combination with Odyssey Exploration, Inc. in 1990........... (198) (178) (168)
Application of Canadian full cost ceiling test........................ (535) (482) (455)
Deferred tax effect of adjustment above .................................. 53 35 21
--------- --------- -------
Net earnings (loss) based on Canadian GAAP ............................... $ 1,676 $ 5,027 $ 6,248
========= ========= =======
Net earnings (loss) per common share based on Canadian GAAP .............. $ 0.09 $ 0.25 $ 0.29
========= ========= =======
- -------------
(i) Under FAS 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 (Note 6). Under Canadian GAAP this adjustment is not
required.
48
49
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The effect on the consolidated balance sheets of the differences between
United States and Canadian GAAP is as follows:
Under
As Increase Canadian
Reported (Decrease) GAAP
-------- -------- ---------
DECEMBER 31, 1997
Property and Equipment................................ $531,409 $ 2,131 $533,540
Deferred Income Taxes................................. 20,306 (4,790) 15,516
Long Term Debt........................................ 369,924 (1,106) 368,818
Deferred Charges...................................... --- 1,106 1,106
Shareholder's Equity.................................. 142,103 6,921 149,024
DECEMBER 31, 1996
Property and Equipment................................ $210,212 $ 2,191 $212,403
Deferred Income Taxes................................. 14,842 (4,769) 10,073
Shareholder's Equity.................................. 81,466 6,961 88,427
14. SUPPLEMENTARY QUARTERLY FINANCIAL DATA (UNAUDITED)
First Second Third Fourth Total
----- ------ ----- ------ -----
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
1996
Operating revenues ........................... $ 12,367 $ 12,938 $ 13,552 $ 15,415 $ 54,272
Operating income ............................. 3,576 3,738 4,182 5,357 16,853
Net earnings ................................. 1,035 1,103 1,326 2,442 5,906
Basic earnings per share ..................... $ 0.05 $ 0.06 $ 0.06 $ 0.12 $ 0.29
Diluted earnings per share ...................... $ 0.05 $ 0.06 $ 0.06 $ 0.12 $ 0.29
1995
Operating revenues ........................... $ 9,402 $ 10,000 $ 10,418 $ 11,083 $ 40,903
Operating income ............................. 1,574 1,321 1,913 3,521 8,329
Income (loss) from continuing operations ..... (140) (361) (147) 817 169
Income (loss) from discontinued operations.... 317 26 113 1,155 1,611
Net earnings (loss) .......................... 177 (335) (34) 1,972 1,780
Basic earnings (loss) per share:
Continuing operations ..................... $ (0.02) $ (0.03) $ (0.02) $ 0.04 $ (0.02)
Discontinued operations ................... 0.01 (0.01) 0.00 0.06 0.07
-------- -------- -------- -------- --------
Net income (loss) per share ............... $ (0.01) $ (0.04) $ (0.02) $ 0.10 $ 0.05
======== ======== ======== ======== ========
Diluted earnings (loss) per share:
Continuing operations ..................... $ (0.02) $ (0.03) $ (0.02) $ 0.04 $ (0.02)
Discontinued operations ................... 0.01 (0.01) 0.00 0.06 0.07
-------- -------- -------- -------- --------
Net income (loss) per share ............... $ (0.01) $ (0.04) $ (0.02) $ 0.10 $ 0.05
======== ======== ======== ======== ========
49
50
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
15. SUPPLEMENTARY INFORMATION RELATED TO OIL AND GAS ACTIVITIES
(a) COSTS INCURRED
Costs incurred for property acquisition, exploration and development
activities were as follows:
1995 1996 1997
--------- --------- ---------
Property acquisitions
Proved ............................................ $ 7,294 $ 1,139 $ 199,485
Unproved .......................................... 2,253 986 73,281
Exploration ........................................... 3,378 6,528 13,374
Development ........................................... 19,194 41,091 53,542
Other.................................................. 677 894 729
--------- --------- ---------
$ 32,796 $ 50,638 $ 340,411
========= ========= =========
Property and equipment, net of accumulated depletion... $ 175,899 $ 210,212 $ 531,409
========= ========= =========
50
51
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(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.
Reserve Quantities
--------------------
Oil Gas
(Mbbls) (Mmcf)
------- ----------
Estimated reserves at December 31, 1994 ........... 27,515 100,117
Revisions of previous estimates ................... (599) 14,639
Purchase of reserves in place ..................... 1,786 9
Extensions and discoveries ........................ 4,274 200
Production ........................................ (2,178) (7,093)
-------- --------
Estimated reserves at December 31, 1995 ........... 30,798 107,872
Revisions of previous estimates ................... (1,913) 10,335
Purchase of reserves in place ..................... 218 --
Extensions and discoveries ........................ 8,186 1,571
Production ........................................ (2,467) (6,646)
-------- --------
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
======== ========
Proved developed reserves at December 31,
1995.............................................. 23,478 94,878
1996.............................................. 24,089 98,936
1997.............................................. 62,663 129,392
(c) Costs Incurred
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 Financial Accounting Standards Board Statement 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 its simplistic use.
51
52
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The following tabulation reflects the Company's estimated discounted
future cash flows from crude oil and natural gas production:
1995 1996 1997
---- ----- ----
Future cash inflows ............................................ $ 766,196 $ 1,174,356 $ 1,764,924
Future production costs......................................... (234,309) (301,619) (607,114)
Future development costs........................................ (33,824) (52,769) (114,294)
----------- ----------- -----------
Future net cash flows before income taxes....................... 498,063 819,968 1,043,516
Annual discount at 10%.......................................... (229,445) (402,885) (517,239)
----------- ----------- -----------
Present value of future net cash flows before income taxes
("Present Value of Proved Reserves")......................... 268,618 417,083 526,277
Future income taxes discounted at 10%........................... (43,679) (79,864) (58,084)
----------- ----------- -----------
Standardized measure of discounted future net cash flows........ $ 224,939 $ 337,219 $ 468,193
=========== =========== ===========
West Texas Intermediate posted reference price ($ per Bbl)...... $ 18.00 $ 25.25 $ 16.17
Estimated December 31 Company average realized price
$/Bbl........................................................ $ 15.69 $ 22.02 $ 15.06
$/Mcf........................................................ $ 2.54 $ 3.53 $ 2.26
The following are the significant sources of changes in discounted future
net cash flows relating to proved reserves:
1995 1996 1997
---- ---- ----
Crude oil and natural gas sales, net of production costs ................ $ (28,446) $ (46,305) $ (47,392)
Net changes in anticipated prices and production costs .................. 93,551 128,960 (176,309)
Extensions and discoveries, less related costs .......................... 24,281 74,560 73,565
Changes in estimated future development costs ........................... (10,581) (2,580) (6,393)
Development costs incurred during the period ............................ 19,194 6,321 10,817
Net change due to sales and purchase of reserves in place ............... 10,409 1,108 224,579
Accretion of discount ................................................... 16,441 26,862 41,708
Revision of previous quantity estimates ................................. 11,768 (1,643) 11,737
Net changes in income taxes ............................................. (14,289) (36,185) 21,780
Changes in timing of production and other ............................... (32,408) (38,818) (23,118)
--------- --------- ---------
Net increase (decrease) ................................................. 89,920 112,280 130,974
Beginning of year ....................................................... 135,019 224,939 337,219
--------- --------- ---------
Standardized measure of discounted future net cash flows ................ $ 224,939 $ 337,219 $ 468,193
========= ========= =========
52
53
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
NONE
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item appears in the Company's proxy
statement for the Annual Meeting of Shareholders to be filed with the Securities
and Exchange Commission pursuant to Regulation 14A, which information is
incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item appears under the caption
"Executive Compensation" set forth in the Company's proxy statement for the
Annual Meeting of Shareholders to be filed with the Securities and Exchange
Commission pursuant to Regulation 14A, which information is incorporated herein
by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item appears under the caption
"Security Ownership of Certain Beneficial Owners and Management" set forth in
the Company's proxy statement for the Annual Meeting of Shareholders to be filed
with the Securities Commission pursuant to Regulation 14A, which information is
incorporated herein by references.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item appears under the caption "Certain
Relationships and Related Transactions" set forth in the Company's proxy
statement for the Annual Meeting of Shareholders to be filed with the Securities
and Exchange Commission pursuant to Regulation 14A, which information is
incorporated herein by reference.
53
54
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 30.
2. FINANCIAL STATEMENT SCHEDULES
PAGE
----
Report of Independent Public Accountants.................................. 58
Schedule III -- Condensed Financial Information - Parent Only............. 59
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 - Plan of Reorganization dated as of June 30, 1993, by
and among the Registrant, Coho Resources, Inc., a
Nevada corporation, and Coho Resources Limited, an
Alberta, Canada corporation (incorporated by
reference to Exhibit 2.1 to the Company's
Registration Statement on Form S-4 (Reg. No.
33-65620)).
3(i).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(i).2 - Statement of Resolution Establishing Series of Shares
of Series A Preferred Stock dated December 8, 1994
(incorporated by reference to the Company's Form 8-K
filed on December 16, 1984).
3(i).3 - First Amendment to Statement of Resolution
Establishing Series of Shares of Series A Preferred
Stock dated August 23, 1995 (incorporated by
reference to Exhibit 3(i).1 to the Company's
Quarterly Report on Form 10-Q for the quarter ended
September 30, 1995).
3(ii).1 - Bylaws of the Company, filed as Exhibit 3.2 to the
Company's Registration Statement on Form S-4
(Registration No. 33-65620) and incorporated by
reference herein.
4.1 - Articles of Incorporation (included as Exhibit 3(i).1
above).
4.2 - Statement of Resolution Establishing Series of Shares
(included as Exhibit 3(i).2 above).
4.3 - Bylaws of the Company (included as Exhibit 3(ii).1
above).
4.4 - 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).
54
55
4.5 - 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).
4.6 - 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).
10.1 - Registration Rights and Shareholder Agreement dated
December 8, 1994 by and among Coho Energy, Inc., The
Morgan Stanley Leveraged Equity Fund II, LP, and
Quinn Oil Company Ltd (incorporated by reference to
Exhibit 10.2 to the Company's Annual Report on Form
10-K for the year ended December 31, 1994).
10.2 - 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).
*10.3 - 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)).
*10.4 - 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).
*10.5 - Second Amendment and Third 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).
*10.6 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).
*10.7 - 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).
*10.8 - 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).
*10.9 - 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).
*10.10 - 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).
*10.11 - 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).
*10.12 - 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).
55
56
*10.13 - 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).
10.14 - Third Amended and Restated Credit Agreement among
Coho Resources, Inc., Coho Louisiana Production
Company, Coho Exploration, Inc., Coho Energy, Inc.,
Banque Paribas, Houston Agency, Bank One, Texas,
N.A., and Meespierson N.V. dated as of August 8, 1996
(incorporated by reference to the Company's Quarterly
Report on Form 10-Q for the quarter ended September
30, 1996).
*10.15 - 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).
*10.16 - 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).
*10.17 - Form of Executive Severance Agreement entered into
with each of Keri Clarke, R. Lynn Guillory, Larry L.
Keller, Susan J. McAden, 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).
*10.18 - Stock Purchase Agreement dated March 4, 1996 among
Coho Energy, Inc., Interstate Natural Gas Company,
and Republic Gas Partners, L. L. C. (incorporated by
reference to the Exhibit 10.16 to the Company's
Annual Report on Form 10-K for the year ended
December 31, 1995.
10.19 - 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 From 10-K for the year
ended December 31, 1995).
10.20 - Gas Purchase Contract dated January 1, 1996, by and
between Mid Louisiana Production Company and Mid
Louisiana Marketing Company (incorporated by
reference to Exhibit 99.1 to the Company's current
report on Form 8-K dated April 3, 1996).
10.21 - Gas Transportation Agreement dated January 1, 1996,
by and between Mid Louisiana Gathering Company and
Mid Louisiana Marketing Company (incorporated by
reference to Exhibit 99.2 to the Company's current
report on Form 8-K dated April 3, 1996).
10.22 - Gas Transportation Agreement dated January 1, 1996,
by and between Fairbanks Gathering Company and Mid
Louisiana Marketing Company (incorporated by
reference to Exhibit 99.3 to the Company's current
report on Form 8-K dated April 3, 1996).
10.23 - 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.
10.24 - 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).
11.1 - Statement re computation of per share earnings.
21.1 - List of Subsidiaries of the Company.
56
57
27 - Financial Data Schedule
- --------------
* 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 1997 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
The Company has filed with the Securities and Exchange Commission a
current report on Form 8-K dated December 18, 1997, related to the acquisition
of interests in certain crude oil and natural gas properties located primarily
in southern Oklahoma from Amoco Production Company.
57
58
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.
Arthur Andersen LLP
Dallas, Texas
March 20, 1998
58
59
COHO ENERGY, INC.
AND SUBSIDIARIES
SCHEDULE III
CONDENSED FINANCIAL INFORMATION - PARENT ONLY
The following presents the condensed balance sheets as of December 31,
1997 and 1996 and statements of earnings and statements of cash flows for Coho
Energy, Inc., the parent company, for the years ended December 31, 1997, 1996
and 1995.
COHO ENERGY, INC.
(PARENT)
CONDENSED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
ASSETS
DECEMBER 31
---------------------
1996 1997
-------- --------
Current assets
Cash and cash equivalents ........................................ $ 304 $ 27
Due from subsidiaries ............................................ 7,535 180,743
-------- --------
7,839 180,770
Investments in subsidiaries, at equity ............................. 73,632 109,247
Other assets ....................................................... -- 4,297
-------- --------
$ 81,471 $294,314
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable.................................................. 5 3,317
-------- --------
Long-term debt.................................................... --- 148,894
-------- --------
5 152,211
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 50,000,000 shares
Issued 20,347,126 and 25,603,512 shares at December 31, 1996 and
1997, respectively............................................... 203 256
Additional paid-in capital.......................................... 83,516 137,812
Retained earnings (deficit)......................................... (2,253) 4,035
-------- --------
Total shareholders' equity.......................................... 81,466 142,103
-------- --------
$ 81,471 $ 294,314
======== ========
See accompanying Notes to Condensed Financial Information
59
60
SCHEDULE III
COHO ENERGY, INC.
(PARENT)
CONDENSED STATEMENTS OF EARNINGS
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
December 31
------------------------------
1995 1996 1997
---------- --------- ---------
Operating expenses
General and administrative.............. $ 428 $ 423 $ 471
Other (income) expenses
Interest income from subsidiaries........ --- --- (4,320)
Interest expense......................... --- --- 3,389
Equity in income of subsidiaries......... (2,208) (6,329) (5,828)
------- ------- -------
(2,208) (6,329) (6,759)
------- ------- -------
Net earnings.............................. $ 1,780 $ 5,906 $ 6,288
Dividends on preferred stock.............. (944) --- ---
------- ------- -------
Net earnings applicable to common stock... $ 836 $ 5,906 $ 6,288
======= ======= =======
Basic earnings per common share........... $ .05 $ .29 $ .29
======= ======= =======
Diluted earnings per common share......... $ .05 $ .29 $ .28
======= ======= =======
See accompanying Notes to Condensed Financial Information
60
61
SCHEDULE III
COHO ENERGY, INC.
(PARENT)
CONDENSED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
Year Ended December 31
------------------------------
1995 1996 1997
---------- --------- ---------
Cash flows from operating activities
Net earnings........................................................ $ 1,780 $ 5,906 $ 6,288
Adjustments to reconcile net earnings (loss) to net cash provided
by operating activities:
Equity in income of subsidiaries.................................... (2,208) (6,329) (5,828)
Changes in:
Other assets........................................................ -- -- (22)
Accounts payable.................................................... (94) (15) 3,312
------- ------- -------
Net cash provided by (used in) operating activities.................. (522) (438) 3,750
------- ------- -------
Cash flows from investing activities
Investments in subsidiaries......................................... -- -- (26,397)
Advances from (to) subsidiaries..................................... 466 325 (172,967)
------- ------- -------
Net cash provided by (used in) investing activities.................. 466 325 (199,364)
------- ------- -------
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............................... -- 414 1,495
------- ------- -------
Net cash provided by (used in) financing activities.................. -- 414 195,337
------- ------- -------
Increase (decrease) in cash.......................................... (56) 301 (277)
Cash and cash equivalents at beginning of period..................... 59 3 304
------- ------- -------
Cash and cash equivalents at end of period........................... $ 3 $ 304 $ 27
======= ======= =======
See accompanying Notes to Condensed Financial Information
61
62
SCHEDULE III
COHO ENERGY, INC.
(PARENT)
NOTES TO CONDENSED FINANCIAL INFORMATION
FOR THE YEARS ENDED DECEMBER 31, 1995, 1996 AND 1997
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, 1997.
2. COMMITMENTS AND CONTINGENCIES
The Registrant has guaranteed $221,000,000 of debt related to
unconsolidated subsidiaries under the Restated Credit Agreement described in
note 4 to the consolidated financial statements of the Company.
The Restated Credit 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. In the event of a change of control of the Company, as defined in
the Restated Credit Agreement, at the discretion of the lenders, the loan may
become immediately due and payable. At December 31, 1997, the Company was in
compliance with all debt covenants.
3. 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 ("Senior Notes").
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 4, were used to repay indebtedness
outstanding under the Restated Credit Agreement and for general corporate
purposes.
The Senior Notes will be unsecured senior subordinated obligations of
the Company and will rank pari passu in right of payment with all existing and
future senior subordinated indebtedness of the Company. The Senior Notes 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 Senior Notes on a senior
subordinated basis.
The indenture issued in conjunction with the Senior Notes (the
"Indenture") will contain certain covenants, including 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.
4. 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 Senior Notes offering discussed in
Note 3, were used to repay indebtedness outstanding under the Company's Restated
Credit 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
62
63
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.
The redeemable preferred stock issued in connection with the acquisition
of a subsidiary corporation was non-voting and entitled to receive cumulative
quarterly dividends at a coupon rate equal to the prime lending rate per annum
(8.5% for the first quarter of 1995 and 9% for the second and third quarters of
1995). If the preferred stock were not redeemed by September 4, 1995, the coupon
rate increased 1/2% per quarter to a maximum rate of 18% per annum. On August
30, 1995, the Company exchanged 3,225,000 shares of Common Stock for the 161,250
shares of Series A Preferred Stock with a stated value of $16,125,000 and issued
157,338 shares of Common Stock to the holders of the preferred stock to satisfy
the accrued dividend obligation through August 30, 1995 of $944,000. These
noncash transactions are not reflected in the statement of cash flows for the
year ended December 31, 1995.
63
64
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 20, 1998 By: (Signed) 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.
SIGNATURE TITLE DATE
--------- ----- ----
(Signed) JEFFREY CLARKE Chairman, President March 20, 1998
- --------------------------------------------------- Chief Executive Officer
Jeffrey Clarke and Director
(Signed) EDDIE M. LEBLANC, III Sr. Vice President and March 20, 1998
- --------------------------------------------------- Chief Financial Officer
Eddie M. LeBlanc, III (principal financial
and accounting officer)
(Signed) ROBERT B. ANDERSON Director March 20, 1998
- --------------------------------------------------
Robert B. Anderson
(Signed) ROY R. BAKER Director March 20, 1998
- --------------------------------------------------
Roy R. Baker
(Signed) FREDERICK K. CAMPBELL Director March 20, 1998
- --------------------------------------------------
Frederick K. Campbell
(Signed) LOUIS F. CRANE Director March 20, 1998
- --------------------------------------------------
Louis F. Crane
(Signed) HOWARD I. HOFFEN Director March 20, 1998
- ---------------------------------------------------
Howard I. Hoffen
(Signed) KENNETH H. LAMBERT Director March 20, 1998
- ---------------------------------------------------
Kenneth H. Lambert
(Signed) DOUGLAS R. MARTIN Director March 20, 1998
- ----------------------------------------------------
Douglas R. Martin
(Signed) CARL S. QUINN Director March 20, 1998
- ----------------------------------------------------
Carl S. Quinn
(Signed) JAKE TAYLOR Director March 20, 1998
- ----------------------------------------------------
Jake Taylor
64
65
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------- -----------
2.1 - Plan of Reorganization dated as of June 30, 1993, by
and among the Registrant, Coho Resources, Inc., a
Nevada corporation, and Coho Resources Limited, an
Alberta, Canada corporation (incorporated by
reference to Exhibit 2.1 to the Company's
Registration Statement on Form S-4 (Reg. No.
33-65620)).
3(i).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(i).2 - Statement of Resolution Establishing Series of Shares
of Series A Preferred Stock dated December 8, 1994
(incorporated by reference to the Company's Form 8-K
filed on December 16, 1984).
3(i).3 - First Amendment to Statement of Resolution
Establishing Series of Shares of Series A Preferred
Stock dated August 23, 1995 (incorporated by
reference to Exhibit 3(i).1 to the Company's
Quarterly Report on Form 10-Q for the quarter ended
September 30, 1995).
3(ii).1 - Bylaws of the Company, filed as Exhibit 3.2 to the
Company's Registration Statement on Form S-4
(Registration No. 33-65620) and incorporated by
reference herein.
4.1 - Articles of Incorporation (included as Exhibit 3(i).1
above).
4.2 - Statement of Resolution Establishing Series of Shares
(included as Exhibit 3(i).2 above).
4.3 - Bylaws of the Company (included as Exhibit 3(ii).1
above).
4.4 - 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).
66
4.5 - 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).
4.6 - 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).
10.1 - Registration Rights and Shareholder Agreement dated
December 8, 1994 by and among Coho Energy, Inc., The
Morgan Stanley Leveraged Equity Fund II, LP, and
Quinn Oil Company Ltd (incorporated by reference to
Exhibit 10.2 to the Company's Annual Report on Form
10-K for the year ended December 31, 1994).
10.2 - 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).
*10.3 - 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)).
*10.4 - 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).
*10.5 - Second Amendment and Third 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).
*10.6 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).
*10.7 - 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).
*10.8 - 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).
*10.9 - 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).
*10.10 - 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).
*10.11 - 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).
*10.12 - 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).
67
*10.13 - 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).
10.14 - Third Amended and Restated Credit Agreement among
Coho Resources, Inc., Coho Louisiana Production
Company, Coho Exploration, Inc., Coho Energy, Inc.,
Banque Paribas, Houston Agency, Bank One, Texas,
N.A., and Meespierson N.V. dated as of August 8, 1996
(incorporated by reference to the Company's Quarterly
Report on Form 10-Q for the quarter ended September
30, 1996).
*10.15 - 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).
*10.16 - 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).
*10.17 - Form of Executive Severance Agreement entered into
with each of Keri Clarke, R. Lynn Guillory, Larry L.
Keller, Susan J. McAden, 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).
*10.18 - Stock Purchase Agreement dated March 4, 1996 among
Coho Energy, Inc., Interstate Natural Gas Company,
and Republic Gas Partners, L. L. C. (incorporated by
reference to the Exhibit 10.16 to the Company's
Annual Report on Form 10-K for the year ended
December 31, 1995.
10.19 - 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 From 10-K for the year
ended December 31, 1995).
10.20 - Gas Purchase Contract dated January 1, 1996, by and
between Mid Louisiana Production Company and Mid
Louisiana Marketing Company (incorporated by
reference to Exhibit 99.1 to the Company's current
report on Form 8-K dated April 3, 1996).
10.21 - Gas Transportation Agreement dated January 1, 1996,
by and between Mid Louisiana Gathering Company and
Mid Louisiana Marketing Company (incorporated by
reference to Exhibit 99.2 to the Company's current
report on Form 8-K dated April 3, 1996).
10.22 - Gas Transportation Agreement dated January 1, 1996,
by and between Fairbanks Gathering Company and Mid
Louisiana Marketing Company (incorporated by
reference to Exhibit 99.3 to the Company's current
report on Form 8-K dated April 3, 1996).
10.23 - 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.
10.24 - 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).
11.1 - Statement re computation of per share earnings.
21.1 - List of Subsidiaries of the Company.
27 - Financial Data Schedule
- ------------------
* 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 1997 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.