<PAGE> 1
Filed Pursuant to Rule 424(b)(4)
Registration No. 333-33979
PROSPECTUS
8,584,482 Shares
[COHO LOGO]
COMMON STOCK
------------------------
OF THE 8,584,482 SHARES OF COMMON STOCK OFFERED HEREBY, 5,000,000 SHARES ARE
BEING SOLD BY COHO ENERGY, INC. AND 3,584,482 SHARES ARE BEING SOLD BY THE
SELLING SHAREHOLDERS. SEE "PRINCIPAL AND SELLING SHAREHOLDERS." THE COMPANY WILL
NOT RECEIVE ANY PROCEEDS FROM THE SALE OF SHARES BY THE SELLING SHAREHOLDERS.
THE COMMON STOCK IS QUOTED ON THE NASDAQ STOCK MARKET UNDER THE SYMBOL "COHO."
ON SEPTEMBER 29, 1997, THE REPORTED LAST SALE PRICE OF THE COMMON STOCK ON THE
NASDAQ STOCK MARKET WAS $11.00 PER SHARE.
CONCURRENTLY WITH THIS OFFERING OF THE SHARES OF COMMON STOCK (THIS "OFFERING"),
THE COMPANY IS OFFERING $150 MILLION IN AGGREGATE PRINCIPAL AMOUNT OF 8 7/8%
SENIOR SUBORDINATED NOTES DUE 2007 (THE "DEBT OFFERING" AND, TOGETHER WITH THIS
OFFERING, THE "OFFERINGS"). THE CLOSING OF THIS OFFERING IS NOT CONDITIONED UPON
THE CLOSING OF THE DEBT OFFERING. THE COMMON STOCK OFFERED HEREBY IS NOT BEING
OFFERED FOR SALE IN CANADA.
------------------------
SEE "RISK FACTORS" BEGINNING ON PAGE 10 FOR INFORMATION THAT SHOULD BE
CONSIDERED BY PROSPECTIVE INVESTORS.
------------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
------------------------
PRICE $10 1/2 A SHARE
------------------------
<TABLE>
<CAPTION>
UNDERWRITING PROCEEDS TO
PRICE TO DISCOUNTS AND PROCEEDS TO SELLING
PUBLIC COMMISSIONS(1) COMPANY(2) SHAREHOLDERS
-------- -------------- ----------- ------------
<S> <C> <C> <C> <C>
Per Share................ $10.50 $.55 $9.95 $9.95
Total(3)................. $90,137,061 $4,721,465 $49,750,000 $35,665,596
</TABLE>
- ------------
(1) The Company and the Selling Shareholders have agreed to indemnify the
Underwriters against certain liabilities, including liabilities under the
Securities Act of 1933. See "Underwriters."
(2) Before deducting expenses estimated at $650,000, all of which are payable by
the Company.
(3) The Selling Shareholders have granted to the Underwriters an option,
exercisable within 30 days of the date hereof, to purchase up to an
aggregate of 1,287,672 additional Shares of Common Stock at the price to
public less underwriting discounts and commissions for the purpose of
covering over-allotments, if any. If the Underwriters exercise such option
in full, the total price to public, underwriting discounts and commissions
and proceeds to Selling Shareholders will be $103,657,617, $5,429,685 and
$48,477,932, respectively. See "Underwriters."
------------------------
The Shares are offered, subject to prior sale, when, as and if accepted by
the Underwriters named herein and subject to approval of certain legal matters
by Cravath, Swaine & Moore, counsel for the Underwriters. It is expected that
delivery of the Shares will be made on or about October 3, 1997 at the office of
Morgan Stanley & Co. Incorporated, New York, N.Y., against payment therefor in
immediately available funds.
------------------------
MORGAN STANLEY DEAN WITTER
JEFFERIES & COMPANY, INC.
PRUDENTIAL SECURITIES INCORPORATED
SMITH BARNEY INC.
September 29, 1997
<PAGE> 2
COHO MAP
---------------------
CERTAIN PERSONS PARTICIPATING IN THIS OFFERING MAY ENGAGE IN TRANSACTIONS
THAT STABILIZE, MAINTAIN, OR OTHERWISE AFFECT THE PRICE OF THE COMMON STOCK.
SPECIFICALLY, THE UNDERWRITERS MAY OVERALLOT IN CONNECTION WITH THIS OFFERING
AND MAY BID FOR AND PURCHASE SHARES OF THE COMMON STOCK IN THE OPEN MARKET. FOR
A DESCRIPTION OF THESE ACTIVITIES, SEE "UNDERWRITERS."
IN CONNECTION WITH THIS OFFERING, CERTAIN UNDERWRITERS AND SELLING GROUP
MEMBERS MAY ENGAGE IN PASSIVE MARKET MAKING TRANSACTIONS IN THE COMMON STOCK ON
THE NASDAQ STOCK MARKET IN ACCORDANCE WITH RULE 103 UNDER REGULATION M. SEE
"UNDERWRITERS."
2
<PAGE> 3
NO DEALER, SALESMAN OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS
PROSPECTUS, AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT
BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY, THE SELLING
SHAREHOLDERS OR ANY OF THE UNDERWRITERS. THIS PROSPECTUS DOES NOT CONSTITUTE AN
OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY OF THE SHARES BY ANYONE
IN ANY JURISDICTION IN WHICH SUCH OFFER OR SOLICITATION IS NOT AUTHORIZED, OR IN
WHICH THE PERSON MAKING THE OFFER OR SOLICITATION IS NOT QUALIFIED TO DO SO OR
TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER OR SOLICITATION. UNDER
NO CIRCUMSTANCES SHALL THE DELIVERY OF THE PROSPECTUS OR ANY SALE MADE PURSUANT
TO THIS PROSPECTUS CREATE ANY IMPLICATION THAT INFORMATION CONTAINED IN THIS
PROSPECTUS IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE OF THIS PROSPECTUS.
---------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Incorporation of Certain Documents by
Reference........................... 3
Prospectus Summary.................... 4
Risk Factors.......................... 10
Forward-Looking Statements............ 14
Debt Offering......................... 15
Price Range of Common Stock........... 15
Dividend Policy....................... 15
Use of Proceeds....................... 16
Capitalization........................ 16
Selected Consolidated Financial
Data................................ 17
Management's Discussion and Analysis
of Financial Condition and Results
of Operations....................... 18
</TABLE>
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Business and Properties............... 26
Management............................ 41
Principal and Selling Shareholders.... 43
Description of Capital Stock.......... 44
Description of Certain Indebtedness... 46
Certain United States Tax Consequences
to Non-United States Holders........ 47
Underwriters.......................... 50
Legal Matters......................... 52
Experts............................... 52
Available Information................. 52
Glossary.............................. 54
Index of Financial Statements......... F-1
Summary Reserve Report................ A-1
</TABLE>
---------------------
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
Incorporated by reference in this Prospectus are the following documents
previously filed with the Securities and Exchange Commission (the "Commission"):
(i) the Company's Annual Report on Form 10-K for the year ended December 31,
1996; and (ii) the Company's Quarterly Reports on Form 10-Q for the quarters
ended March 31, 1997 and June 30, 1997.
All documents subsequently filed by the Company with the Commission
pursuant to Section 13(a), 13(c), 14 or 15 (d) of the Securities Exchange Act of
1934, as amended (the "Exchange Act"), prior to the termination of the offering
made by this Prospectus shall be deemed to be incorporated herein by reference
and to be a part hereof from the date of the filing of such documents. Any
statement contained hereunder or in a document incorporated or deemed to be
incorporated by reference herein shall be deemed to be modified or superseded
for purposes of this Prospectus to the extent that a statement contained herein,
therein or in any other subsequently filed document that also is deemed to be
incorporated by reference herein modifies or supersedes such statement. Any
statement so modified or superseded shall not be deemed, except as so modified
or superseded, to constitute a part of this Prospectus.
The Company will provide without charge to each person to whom this
Prospectus is delivered, upon the written or oral request of such person, a copy
of any and all documents incorporated by reference herein (other than exhibits
and schedules to such documents unless such exhibits or schedules are
specifically incorporated by reference in such documents). Such request should
be directed to Coho Energy, Inc., 14785 Preston Road, Suite 860, Dallas, TX
75240 (telephone: (972) 774-8300), Attention: Mr. Jeffrey Clarke.
3
<PAGE> 4
PROSPECTUS SUMMARY
The following information should be read in conjunction with, and is
qualified in its entirety by reference to, the more detailed information and the
Consolidated Financial Statements appearing elsewhere in this Prospectus. Unless
otherwise indicated, the information in this Prospectus assumes that the
Underwriters' over-allotment option is not exercised. References in this
Prospectus to the "Company" or "Coho" refer to Coho Energy, Inc., its
subsidiaries and their predecessors, or any of them, depending on the context.
Certain information contained in this summary and elsewhere in this Prospectus,
including information with respect to the Company's plans and strategy for its
business, are forward-looking statements. Prospective investors should carefully
consider the factors set forth herein under the caption "Risk Factors" for a
discussion of important factors that could cause actual results to differ
materially from the forward-looking statements contained in this Prospectus.
Certain oil and gas industry terms used in this Prospectus are defined under the
caption "Glossary" elsewhere in this Prospectus.
THE COMPANY
OVERVIEW
Coho Energy, Inc. is an independent energy company engaged, through its
wholly owned subsidiaries, in the development and production of, and exploration
for, crude oil and natural gas. The Company's crude oil activities are
concentrated principally in Mississippi, where it is that 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 maintainable with minimal incremental capital expenditures. At
December 31, 1996, the Company's total proved reserves were 53.7 MMBOE with a
Present Value of Proved Reserves of $417.1 million, approximately 76% of which
were proved developed reserves. At December 31, 1996, approximately 65% of
Coho's total proved reserves were comprised of crude oil and the Company's
reserve-to-production ratio was approximately 15 years. At June 30, 1997, the
Company owned an average working interest of 96% in, and operated over 99% 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
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 three-year
inventory of potential development drilling, secondary recovery and exploration
projects in this basin. The Company believes that its concentration in this
geographic area provides it with important competitive advantages such as its
extensive databases, operational infrastructure and economies of scale.
The Company's focus in the central Mississippi 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 10,717 BOE in the second quarter of 1997, representing a compound annual
growth rate of 19.4%. Over the five-year period ended December 31, 1996, the
Company discovered or acquired approximately 42.3 MMBOE of proved reserves at an
average finding cost of $4.84 per BOE. Over the same period, the Company has
replaced over 300% of its production. This increase in reserves from 24.1 MMBOE
at year end 1991 to 53.7 MMBOE at year end 1996 represents a five-year compound
annual growth rate of 17.4%. Consistent with the increase in production, EBITDA
has increased from $16.9 million in 1992 to $36.6 million for the twelve-month
period ended June 30, 1997.
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 operations are conducted primarily in the Brookhaven,
Laurel, Martinville, Soso and Summerland fields in Mississippi, and the Monroe
field in Louisiana.
4
<PAGE> 5
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 1996, Coho spent $41 million of its
total capital expenditures of $52 million on exploitation projects. As of June
30, 1997, Coho had ongoing exploitation projects in the Brookhaven, Laurel,
Martinville, Soso and Summerland fields. 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 increased spending on
conventional development drilling opportunities. This strategy is illustrated in
the Company's 1995 acquisition of the Brookhaven field in Mississippi. Less than
25% of the crude oil in place in the Tuscaloosa reservoir at Brookhaven has been
recovered to date. Since acquiring this property, the Company has increased
total daily field production to approximately 1,360 net BOE at June 30, 1997,
from approximately 230 net BOE at the time of acquisition. Additionally, in June
1997, the Company announced that test results of the first two exploratory wells
at Brookhaven have proven productive pay sands in three deeper formations. These
wells commenced production in the second quarter of 1997.
Secondary Recovery. Over the last three years, Coho has implemented 12
secondary recovery projects in the Mississippi salt basin. Six of these projects
have been successfully developed and six are in the pilot phase. The six
developed projects have increased production in these reservoirs by an average
of 475%, have produced over 3.3 MMBbls and have 7.7 MMBbls of remaining proved
reserves. These 11.0 MMBbls have an estimated finding and development cost of
$2.86 per Bbl. In 1996, Coho spent $11.2 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 28% of its 1997 capital
budget to exploration. In 1995, Coho completed a 24-square mile 3-D seismic
survey on the Martinville field. Based on this data, one successful exploratory
well was completed in 1996 and two additional exploration wells are planned in
1997. 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.
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.
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 57 development wells, of which 93% were completed successfully. The
Company anticipates that approximately 72% of its total 1997 capital expenditure
budget will be allocated to such relatively low-risk, high-return projects,
including secondary recovery projects which will comprise approximately 29% of
the total 1997 capital expenditure budget.
5
<PAGE> 6
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 and around its existing properties. These programs
have produced an attractive inventory of exploration projects that the Company
will continue to pursue. Approximately 28% of the Company's 1997 capital
expenditures will be allocated to such exploration projects.
Acquire Properties with Underdeveloped Reserves. The Company intends to
acquire underdeveloped crude oil and natural gas properties, primarily in the
interior salt basin of Mississippi, which have geological complexity and
multiple producing horizons. Management believes that the Company's extensive
experience in this area of Mississippi developed over the past 14 years should
enable it to efficiently increase reserves and improve production rates in this
geologically complex environment. For the month of June 1997, the Company's
average daily production per well in Mississippi was 95 BOE, which was
substantially higher than the domestic industry average of less than 12 BOE.
Additionally, management believes that this experience gives the Company a
significant competitive advantage in evaluating similarly situated acquisition
prospects.
Significant Control of Operations. Coho's strategy of increasing production
and reserves through acquiring and developing faulted, 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 June 30, 1997, Coho operated over 99% of its producing
properties with an average working interest of approximately 96%. This operating
control, combined with the Company's significant technical and geological
expertise in the Mississippi salt basin region, enables the Company to better
control the magnitude, quality 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, 1996, approximately 88%
of the Company's Mississippi reserves was concentrated in four 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 $3.83 per BOE and favorable cash
margins of $10.00 per BOE for the six months ended June 30, 1997.
RECENT DEVELOPMENTS
During the first half of 1997, the Company was focused principally on
continuing development activities in the Company's Laurel, Martinville and Soso
fields and exploration activity in the Brookhaven field. During the same time
period, Coho drilled 15 new wells, 14 of which were successful, including three
crude oil wells in the Laurel field, two exploration wells in the Brookhaven
field and five natural gas wells in the Monroe field. The Company believes that
events in the following three fields are among its most significant recent
developments.
Brookhaven. The Brookhaven field is one of several prolific fields in
southwest Mississippi that have produced from the Tuscaloosa formation. In an
attempt to establish commercial production below the Tuscaloosa, Coho drilled an
exploration well for the Paluxy and Washita Fredericksburg formations at
Brookhaven. This well encountered 14 potentially productive pay sands in the
Washita Fredericksburg and Paluxy formations. A tested Paluxy sand flowed at 200
gross BOPD and a Washita Fredericksburg sand was tested and has flowed since May
28, 1997 at over 400 gross BOPD.
The Company has also successfully tested a Rodessa natural gas exploration
well. This well was brought on line on June 12, 1997 and continues to flow at
approximately 2.6 MMcf of natural gas and 130 barrels of condensate per day.
This activity has established significant exploration success for the
Company. Since the original shallower Tuscaloosa formation covers 23 square
miles, the Company believes that the size of the structure for deeper formations
could be similar. Prior to the Company's recent deep success, only five
penetrations deeper than the Tuscaloosa existed on this 23-square mile
structure. Four of these penetrations were drilled during the 1940s and all five
of these penetrations have shown that the Washita Fredericksburg and Paluxy
reservoirs are extensive over the field.
6
<PAGE> 7
Laurel. The Company believes that the Laurel field, which covers less than
one square mile and has to date produced approximately 19 MMBbls, has
significant remaining potential for reserve and production growth. In order to
better quantify and verify the potential in the currently defined Laurel field
and the surrounding area, Coho commenced a 37-square mile 3-D seismic survey in
1996. A preliminary interpretation of the seismic data has been used in the
drilling of four successful crude oil wells in the first half of 1997 to verify
previously identified drilling locations. This data has increased the Company's
confidence for several exploration plays in the Eutaw formation in the current
Laurel field, the most productive formation in Mississippi. A new Laurel
"look-alike" has exploration potential in the Tuscaloosa, Paluxy, Rodessa, Sligo
and Hosston formations, and additionally in the Cotton Valley and Smackover
formations. The data will continue to be analyzed and an exploration program is
expected to evolve over 1998 and 1999.
Martinville. Following the initial processing of 3-D seismic data, Coho
drilled two Hosston-depth exploratory test wells in 1996. The Hosston has been
the most prolific producing formation in the Martinville field, having produced
approximately 5 MMBOE to date. A successful Hosston-depth well was drilled to
the west of the existing field and a dry hole Hosston-depth well was drilled to
the north of the existing field. The successful Hosston well also found
potential pay sands in the Rodessa and Sligo formations. This well was put on
production in the Hosston formation in September 1996 at approximately 650 BOE
per day and is currently flowing at 150 BOE per day having already produced 130
MBOE. This exploration discovery will result in further development during the
latter part of 1997 and 1998. The 3-D seismic has indicated several exploration
plays in the Smackover, Cotton Valley, Hosston, Rodessa and Eutaw formations.
These plays will be further analyzed beginning in late 1997.
THE OFFERING
<TABLE>
<S> <C>
Common Stock offered by the Company............... 5,000,000 shares
Common Stock offered by the Selling
Shareholders.................................... 3,584,482 shares
Total.................................... 8,584,482 shares
Common Stock to be outstanding after this
Offering........................................ 25,443,899 shares*
Concurrent Offering............................... Concurrent with this Offering, the Company is
offering $150 million aggregate principal amount
of its 8 7/8% Senior Subordinated Notes Due 2007
by a separate prospectus. The closing of the Debt
Offering is conditioned upon the closing of this
Offering; however, the closing of this Offering is
not conditioned upon the closing of the Debt
Offering.
Use of Proceeds................................... The net proceeds of this Offering are intended to
be used to fund a portion of the Company's capital
expenditure program. Initially, however, such
proceeds will be used to reduce borrowings under
the Company's Revolving Credit Facility (as
defined herein). The undrawn balance of this
facility will then be available for funding
capital expenditures as needed.
Nasdaq Stock Market symbol........................ COHO
</TABLE>
- ---------------
* Based on shares outstanding as of June 30, 1997. Does not include 2,569,678
shares of Common Stock subject to outstanding options under the Company's
stock option plans.
RISK FACTORS
Prior to making an investment decision, prospective investors should
consider carefully, together with other information contained in this
Prospectus, the risk factors discussed under the caption "Risk Factors" herein.
7
<PAGE> 8
SUMMARY CONSOLIDATED FINANCIAL DATA
The following table sets forth certain summary financial data for the
Company (1) with respect to the statement of operations and cash flows on an
actual basis for each of the years in the three year period ended December 31,
1996 and for the six months ended June 30, 1996 and June 30, 1997 and (2) with
respect to the balance sheet data at December 31, 1996 on an actual basis and at
June 30, 1997 (i) on an actual basis, (ii) as adjusted to give effect to this
Offering and (iii) as further adjusted to give effect to the Debt Offering. This
information should be read in conjunction with the Company's Consolidated
Financial Statements and "Management's Discussion and Analysis of Financial
Condition and Results of Operations" included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
-------------------------------- ---------------------
1994 1995 1996 1996 1997
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Operating revenues........................................ $ 26,464 $ 40,903 $ 54,272 $ 25,305 $ 29,521
Total operating expenses.................................. 23,769 32,574 37,419 17,991 19,766
-------- -------- -------- -------- --------
Operating income.......................................... 2,695 8,329 16,853 7,314 9,755
Interest and other income................................. 218 92 1,012 510 149
Interest expense.......................................... 4,190 8,140 8,476 4,233 4,682
-------- -------- -------- -------- --------
Earnings (loss) from continuing operations before income
taxes................................................... (1,277) 281 9,389 3,591 5,222
Income tax expense (benefit).............................. (303) 112 3,483 1,453 2,037
-------- -------- -------- -------- --------
Earnings (loss) from continuing operations................ $ (974) $ 169 $ 5,906 $ 2,138 $ 3,185
======== ======== ======== ======== ========
Net earnings (loss)....................................... $ (1,654) $ 1,780 $ 5,906 $ 2,138 $ 3,185
======== ======== ======== ======== ========
Preferred dividends....................................... $ 86 $ 944 $ -- $ -- $ --
Net earnings (loss) from continuing operations per common
share................................................... (.07) (.02) .29 .11 .15
Net earnings (loss) per common share...................... $ (.12) $ .05 $ .29 $ .11 $ .15
Weighted average common and common shares equivalent
outstanding............................................. 14,190 17,932 20,457 20,337 20,991
OTHER FINANCIAL DATA:
Cash flow from operations(a).............................. $ 7,928 $ 19,227 $ 26,351 $ 11,793 $ 14,407
EBITDA(b)................................................. 12,684 23,046 33,133 15,199 18,715
Capital expenditures...................................... 19,503 29,970 52,384 24,199 33,294
SELECTED RATIOS:
Ratio of earnings to fixed charges(c)..................... NM(d) NM(d) 2.1x 1.8x 2.1x
Ratio of EBITDA to interest expense....................... 3.0x 2.8x 3.9x 3.6x 4.0x
Ratio of long-term debt to EBITDA......................... 6.8x 4.7x 3.7x 3.2x(e) 3.5x(e)
</TABLE>
<TABLE>
<CAPTION>
AS OF
DECEMBER 31,
1996 AS OF JUNE 30, 1997
------------ --------------------------------------------
AS ADJUSTED FOR AS ADJUSTED FOR
ACTUAL ACTUAL THIS OFFERING THE OFFERINGS
------------ -------- --------------- ---------------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
BALANCE SHEET DATA:
Working capital (deficit)................................ $ 6,662 $ (2,118) $ (2,118) $ 59,150
Total assets............................................. 230,041 247,284 247,284 312,952
Long-term debt(f)........................................ 122,777 132,350 83,250 148,918
Total shareholders' equity............................... 81,466 85,228 134,328 134,328
</TABLE>
- ---------------
(a) Cash flow provided by operating activities before working capital
adjustments.
(b) Earnings before interest, taxes, depreciation, depletion and amortization.
EBITDA should not be considered as an alternative to, or more meaningful
than, net income or cash flow as determined in accordance with generally
accepted accounting principles as an indicator of the Company's operating
performance or liquidity.
(c) For purposes of determining the ratio of earnings to fixed charges, earnings
are defined as earnings from continuing operations before income taxes, plus
fixed charges. Fixed charges consist of interest expense, amortization of
debt expense, and pretax preferred stock dividends.
(d) The ratio is not meaningful for the years ended December 31, 1994 and 1995
because earnings were inadequate to cover fixed charges in those years by
$1,390 and $1,289, respectively.
(e) EBITDA for these periods has been annualized.
(f) Excludes current maturities of long-term debt.
8
<PAGE> 9
SUMMARY RESERVE DATA
The following table summarizes the estimates of the Company's historical
net proved crude oil and natural gas reserves as of the dates indicated and the
present value attributable to the reserves at such dates. The reserve and
present value data as of December 31, 1994, 1995 and 1996 have been reviewed by
Ryder Scott Company Petroleum Engineers, independent petroleum engineers ("Ryder
Scott"). A summary of the Ryder Scott report as of December 31, 1996 is included
as Annex A to this Prospectus. See "Risk Factors -- Uncertainty of Estimates of
Reserves and Future Net Revenues," "Business and Properties -- Oil and Gas
Operations" and "Supplemental Information about Oil and Gas Producing Activities
(Unaudited)" following the Notes to Consolidated Financial Statements of the
Company.
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
------------------------------
1994 1995 1996
-------- -------- --------
<S> <C> <C> <C>
PROVED RESERVES:
Crude oil and condensate (MBbls)............................ 27,515 30,798 34,822
Natural gas (MMcf).......................................... 100,117 107,872 113,132
Total (MBOE).............................................. 44,201 48,777 53,678
Estimated future net cash flows (before income tax, in
thousands)................................................ $281,220 $498,063 $819,968
Present Value of Proved Reserves (in thousands)............. $164,409 $268,618 $417,083
Proved developed reserves as a percent of total reserves.... 78% 81% 76%
OTHER RESERVE DATA:
Three-year average finding cost (per BOE)(a)................ $ 4.69 $ 5.39 $ 4.35
Reserve replacement percent(b).............................. 912% 236% 237%
Reserve to production ratio (years)(c)...................... 21 15 15
</TABLE>
- ---------------
(a) Equals the average total costs incurred relating to crude oil and natural
gas property acquisition, exploration and development during the three years
ended December 31 of the year shown in the column divided by the
corresponding crude oil and natural gas reserve additions through
acquisitions, extensions and discoveries and revisions of prior estimates.
(b) Equals current period reserve additions through acquisitions of reserves,
extensions and discoveries, and revisions to prior estimates divided by the
production for such period.
(c) Calculated by dividing year-end proved reserves by such year's annual
production.
SUMMARY OPERATING DATA
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------ SIX MONTHS ENDED
1994 1995 1996 JUNE 30, 1997
------ ------ ------ -----------------
<S> <C> <C> <C> <C>
PRODUCTION VOLUMES:
Crude oil and condensate (MBbls)................... 1,977 2,178 2,467 1,282
Natural gas (MMcf)................................. 670 7,093 6,646 3,545
Total (MBOE)..................................... 2,089 3,360 3,576 1,873
AVERAGE SALES PRICE PER UNIT:
Crude oil and condensate (per Bbl)................. $12.86 $13.62 $16.42 $17.03
Natural gas (per Mcf).............................. 1.55 1.59 2.07 2.17
PER BOE DATA:
Average sales price................................ $12.67 $12.17 $15.18 $15.76
Production expenses................................ 4.49 3.71 3.88 3.83
------ ------ ------ -------
Gross margin..................................... 8.18 8.46 11.30 11.93
General and administrative expenses................ 1.64 1.61 2.03 1.93
------ ------ ------ -------
Cash margin...................................... $ 6.54 $ 6.85 $ 9.27 $10.00
====== ====== ====== =======
</TABLE>
9
<PAGE> 10
RISK FACTORS
Prospective purchasers of shares of the Common Stock offered hereby should
carefully consider together with other information in this Prospectus, the
following factors that affect the Company.
BUSINESS RISKS
Exploration and development for crude oil and natural gas involves many
risks. There is no assurance that commercial quantities of crude oil and natural
gas will be discovered by the Company, or that the Company will be able to
continue to acquire underdeveloped crude oil and natural gas fields and enhance
production and reserves by workovers, secondary recovery projects, recompletions
and development drilling. In addition, because the Company's strategy is to
acquire interests in underdeveloped crude oil and natural gas fields that have
been operated by others for many years, the Company may be liable for any damage
or pollution caused by the former operators of such crude oil and natural gas
fields. The Company's operations are also subject to all of 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 certain regulations that may, in
certain circumstances, impose strict liability for pollution damage, and to
interruption or termination by government 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 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 is not fully insured could have a material adverse effect
on the Company's financial condition and results of operations.
CRUDE OIL AND NATURAL GAS PRICES; MARKETING OF PRODUCTION
The Company's revenues and earnings are dependent upon prevailing prices
for crude oil and natural gas. Historically, the prices of crude oil and natural
gas have been volatile and are subject to wide fluctuations in response to
relatively minor changes in the supply of and demand for crude oil and natural
gas, market uncertainty, weather conditions and a variety of other factors
beyond the control of the Company. Prices are also affected by governmental
actions and international cartels. These external factors and the volatile
nature of the energy markets make it difficult to estimate future prices of
crude oil and natural gas. Although the Company hedges a portion of its
production to provide some protection from price declines, any substantial or
extended decline in the price of crude oil and natural gas would have a material
adverse effect on the Company's financial condition and results of operations.
Governmental regulation of crude oil and natural gas production and
transportation, general economic conditions, changes in supply and changes in
demand all could adversely affect the Company's ability to produce and market
its crude oil and natural gas. If market factors were to change dramatically,
the financial impact on the Company could be substantial. The overall
availability of markets and the volatility of product prices are beyond the
control of the Company and represent a significant risk.
UNCERTAINTY OF ESTIMATES OF RESERVES AND FUTURE NET REVENUES
This Prospectus contains estimates of the Company's crude oil and natural
gas reserves and the discounted future net revenues to be derived from the
reserves, which have been reviewed by Ryder Scott Company Petroleum Engineers,
independent petroleum engineers. There are numerous uncertainties inherent in
estimating quantities of proved crude oil and natural gas reserves, including
many factors beyond the control of the Company. The estimates in this Prospectus
are based on several assumptions, all of which are to some degree speculative.
Actual future production, revenues, taxes, operating expenses, development
expenditures and quantities of recoverable crude oil and natural gas reserves
could vary substantially from those assumed in the estimates. Any significant
variance in these assumptions could materially affect the estimated quantity and
10
<PAGE> 11
value of reserves set forth in this Prospectus. Reservoir engineering is a
subjective process of estimating underground accumulations of crude oil and
natural gas that cannot be measured exactly, and the accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretation and judgment. Accordingly, estimates of the
economically recoverable quantities of crude oil and natural gas attributable to
any particular group of properties, classifications of such reserves based on
risk of recovery and estimates of the future net revenues expected therefrom
prepared by different engineers or by the same engineers at different times may
vary substantially. There also can be no assurance that the reserves set forth
in this Prospectus will ultimately be produced or that the proved undeveloped
reserves set forth in this Prospectus will be developed within the periods
anticipated. It is likely that variances from the estimates will be material. In
addition, the estimates of future net revenues from proved reserves of the
Company and the present value thereof are based upon certain assumptions about
future production levels, prices and costs that may not be correct when judged
against actual subsequent experience. The meaningfulness of such estimates is
highly dependent upon the accuracy of the assumptions upon which they are based.
Actual results will differ, and are likely to differ materially, from the
results estimated.
ABILITY TO REPLACE RESERVES
The Company's future success depends upon its ability to find or acquire
additional crude oil and natural gas reserves that are economically recoverable.
Except to the extent that the Company conducts successful exploration or
development activities or acquires properties containing proved reserves, the
proved reserves of the Company will generally decline as reserves are produced.
Acquisitions of producing crude oil and natural gas properties have been an
important element of the Company's success, and the Company intends to continue
to acquire producing crude oil and natural gas properties. There can be no
assurance that the Company's acquisition and exploration activities or planned
development and exploitation projects will result in significant additional
reserves or that the Company will have continuing success drilling productive
wells at economic finding costs.
SUBSTANTIAL CAPITAL REQUIREMENTS
The Company is dependent upon its ability to obtain financing for
acquiring, exploring and developing crude oil and natural gas properties beyond
its internally generated cash flow. Historically, the Company has financed these
activities primarily through its bank credit facility, internally generated
funds and the issuance of equity securities. The Company currently has plans for
substantial capital expenditures to continue its acquisition and development
activities. The Company expects to utilize its existing credit facility to
borrow funds required from time to time to supplement its own available cash. If
revenues or the Company's borrowing base decrease as a result of lower crude oil
and natural gas prices, operating difficulties or declines in reserves, the
Company's ability to obtain the capital necessary to undertake or complete
future activities may be limited. No assurances can be given that the Company
will have adequate funds available to it under its existing credit facility to
carry out its strategy or that the Company will be able to make any mandatory
principal payments required by the lenders under such facility. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources" and "Description of Certain
Indebtedness -- Revolving Credit Facility."
EFFECTS OF LEVERAGE AND RESTRICTIVE DEBT COVENANTS
As of June 30, 1997, after giving effect to the Offerings and the
application of the estimated net proceeds therefrom, the Company would have had
total indebtedness for money borrowed of approximately $149 million and a
debt-to-capitalization ratio of 53%. The Company intends to incur additional
indebtedness for money borrowed in the future under the Revolving Credit
Facility as it executes its strategy for acquisition, exploration and
development of crude oil and natural gas reserves. Moreover, although the
indenture to be executed in conjunction with the Debt Offering will contain
covenants that limit the incurrence by the Company and its subsidiaries of
additional indebtedness, such limitations are subject to a number of important
qualifications and exceptions. See "Description of Certain
Indebtedness -- Senior Subordinated Notes." The level of the Company's leverage
from time to time could have important consequences to holders of the
11
<PAGE> 12
Common Stock, including the Company's ability to obtain additional financing for
working capital, capital expenditures, acquisitions or general corporate
purposes, and the Company's ability to adjust to changing market conditions, may
be impaired in the future.
At present the Company is (and following the Offerings the Company will
continue to be) subject to a number of significant covenants that, among other
things, restrict the ability of the Company to dispose of assets, incur
additional indebtedness, repay other indebtedness, pay dividends, enter into
certain investments or acquisitions, repurchase or redeem capital stock, engage
in mergers or consolidations or engage in certain transactions with subsidiaries
and affiliates and that otherwise restrict corporate activities. There can be no
assurance that such restrictions will not adversely affect the Company's ability
to finance its future operations or capital needs or engage in other business
activities that may be in the interest of the Company. In addition, the
Revolving Credit Facility requires the Company to maintain compliance with
certain financial ratios. The ability of the Company to comply with such ratios
may be affected by events beyond the Company's control. A breach of any of these
covenants or the inability of the Company to comply with the required financial
ratios could result in a default under the Revolving Credit Facility. In the
event of any such default, all borrowings outstanding under the Revolving Credit
Facility, together with accrued interest and other fees, could be declared due
and payable and the Company could be required to sell assets and apply all of
its available cash to repay such borrowings. If payment of the indebtedness
under the Revolving Credit Facility, the Notes or any other indebtedness of the
Company were to be accelerated, there can be no assurance that the assets of the
Company would be sufficient to repay such indebtedness in full. See "Description
of Certain Indebtedness -- Revolving Credit Facility."
RISKS OF HEDGING TRANSACTIONS
The Company regularly enters into hedging transactions for its crude oil
and natural gas production and expects to continue to do so in the future. Such
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 hedges
and may expose the Company to the risk of financial loss in certain
circumstances, including possibly instances where the Company's production is
less than expected or there is an unexpected event materially affecting prices.
The crude oil and natural gas swap agreements generally provide for the Company
to receive or make counterparty payments based upon the differential between a
fixed price and a variable indexed price. The Company is exposed to the credit
risk of nonperformance by counterparties to its hedging contracts. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Results of Operations."
POSSIBLE LIMITATIONS ON NET OPERATING LOSS CARRYFORWARDS
At December 31, 1996, Coho Resources, Inc. ("CRI"), a subsidiary of the
Company, had regular federal income tax net operating loss carryforwards of
$67.2 million and federal alternative minimum tax net operating loss
carryforwards of $15.4 million. The value of the carryforwards depends on the
ability of CRI and its subsidiaries to generate federal taxable income. For
alternative minimum tax purposes, only 90% of alternative minimum taxable income
(i.e., federal taxable income with adjustments) in any given year may be offset
against the alternative minimum tax net operating loss carryforwards.
The availability of these carryforwards to reduce future federal taxable
income of CRI and its subsidiaries is subject to various limitations under
applicable United States tax rules. In particular, the use of such carryforwards
would be restricted if certain changes in the ownership of the Company and,
indirectly, CRI occur (such as the issuance or exercise of rights to acquire
Common Stock, changes in the holdings of 5-percent shareholders (as defined in
Treasury Regulations) or the offering of Common Stock in certain circumstances)
during any three-year period resulting in more than a 50 percentage point
aggregate change in the beneficial ownership of the Company.
In the event of such a change in the beneficial ownership of the Company,
Section 382 of the Internal Revenue Code of 1986, as amended (the "Code"), would
impose an annual limitation on the amount of taxable income of CRI and its
subsidiaries which may be offset by CRI's net operating loss carryforwards. The
limitation is generally the amount equal to the product of the fair market value
of the equity of CRI
12
<PAGE> 13
immediately before such ownership change and a percentage approximately equal to
the yield on long-term, tax exempt bonds during the month in which the ownership
change occurs.
Although no assurance can be made, the Company believes that this Offering,
when combined with other changes in the ownership of the Company during the past
three years, will not result in an ownership change of the Company (or CRI) for
purposes of Section 382 of the Code. However, future acquisitions and
dispositions of Common Stock of the Company by new or existing 5-percent
shareholders of the Company (such as the exercise of outstanding stock options)
or issuances of Common Stock by the Company, when combined with similar
transactions that have occurred in the past three years, could result in such a
change and cause the limitations of Section 382 to become applicable to CRI.
COMPETITION
The crude oil and natural gas exploration, development and production
business 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 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 the Company's competitors for such properties, personnel,
materials and services have greater financial and other resources than the
Company. See "Business and Properties -- Competition."
REGULATION
The Company's business is regulated by certain federal, state and local
laws and regulations relating to the development, production, marketing,
transportation and storage of crude oil and natural gas, as well as the
protection of the environment and employee health and safety. Specifically, Coho
is subject to legislation regarding emissions into the environment, water
discharges, storage and disposal of solid and hazardous wastes, and the
remediation of contamination caused by releases of regulated substances. In
addition, legislation has been enacted that requires well and facility sites to
be abandoned and reclaimed to the satisfaction of state authorities. Permits are
required for certain of the Company's operations, and these permits are subject
to modification, renewal and revocation by issuing authorities. Governmental
authorities have the power to enforce compliance with applicable laws and
regulations, and violations may result in civil or criminal penalties, the
curtailment or cessation of operations, or both. Although compliance with these
laws, regulations and permits has not had a material adverse effect on the
Company's operations or financial condition to date, such laws and regulations
change frequently, and the Company is unable to predict the ultimate cost of
compliance. Such cost could be substantial. There can be no assurance that
present or future regulation will not adversely affect the Company's exploration
and development for, or the production and marketing of, crude oil and natural
gas. In addition, because the Company acquires interests in properties that have
been operated in the past by others, it may be liable for environmental damage
caused by such former operators. See "Business and Properties -- Governmental
Regulations."
DEPENDENCE ON KEY PERSONNEL
The Company believes that its current operations and future prospects are
dependent to a significant extent upon the efforts of several members of its
senior management team. The loss of the services of certain of these key
individuals could have an adverse effect upon the Company.
CONCENTRATION OF CUSTOMERS
During 1996, the Company derived approximately 66% and 15% of its operating
revenues from EOTT Energy Corp. and Mid Louisiana Marketing Company (which was
formerly a wholly owned subsidiary of the Company that was sold on April 3,
1996), respectively. While the Company believes that its relationships with
13
<PAGE> 14
these customers is good, any loss of revenue from these customers due to
nonpayment or late payment by the customer would have an adverse effect on the
Company's results of operations.
ANTI-TAKEOVER EFFECTS OF CERTAIN PROVISIONS
Certain provisions of the Articles of Incorporation and Bylaws of the
Company may tend to deter potential unsolicited offers or other efforts to
obtain control of the Company that are not approved by the Board of Directors,
including the right of the Board of Directors, without any action by the
shareholders of the Company, to fix the rights and preferences of undesignated
preferred stock, including dividend, liquidation and voting rights. See
"Description of Capital Stock." In addition, in 1994 the Company instituted a
rights plan, whereby one stock purchase right attached to each share of Common
Stock. Such purchase right is automatically triggered on the occurrence of
certain changes of control, as defined in the rights plan. All of such
provisions may have the effect of delaying, deferring or preventing a change of
control of the Company.
SHARES ELIGIBLE FOR FUTURE SALE
At July 31, 1997, without regard to the shares to be sold by the Selling
Shareholders, 7,395,876 shares of Common Stock held by certain shareholders of
the Company were considered to be restricted securities pursuant to Rule 144
promulgated under the Securities Act of 1933, as amended (the "Securities Act").
Sales of substantial amounts of Common Stock into the public market pursuant to
Rule 144, or a perception that such sales could occur, could adversely affect
the market price of the Common Stock and could impair the Company's future
ability to raise capital through the sale of its equity securities. Certain
officers, directors and shareholders of the Company, including the Selling
Shareholders, have agreed with the Underwriters that they will not offer for
sale, sell or otherwise dispose of any shares of Common Stock for a period of 90
days after the date of this Prospectus. See "Underwriters."
ABSENCE OF DIVIDENDS
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 Revolving Credit Facility and
the indenture to be executed in conjunction with the Debt Offering restrict the
payment of dividends by the Company and CRI. Coho Energy, Inc. is currently 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 Coho Resources Limited ("CRL") to Coho Energy, Inc. See "Dividend
Policy."
FORWARD-LOOKING STATEMENTS
This Prospectus includes certain statements that may be deemed to be
"forward-looking statements" within the meaning of Section 27A of the Securities
Act and Section 21E of the Exchange Act. All statements, other than statements
of historical facts, included in this Prospectus 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 the risk factors discussed herein, 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. Prospective investors are cautioned that any
such statements are not guarantees of future performance and that actual results
or developments may differ materially from those projected in the
forward-looking statements.
14
<PAGE> 15
DEBT OFFERING
Concurrently with this Offering, the Company is offering $150 million of
8 7/8% Senior Subordinated Notes Due 2007, to the public. The Indenture to be
executed in conjunction with the Debt Offering will contain certain covenants,
including covenants that limit (i) indebtedness, (ii) restricted payments, (iii)
issuances and sales of capital stock of restricted subsidiaries, (iv)
sale/leaseback transactions, (v) transactions with affiliates, (vi) liens, (vii)
asset sales, (viii) dividends and other payment restrictions affecting
restricted subsidiaries and (ix) mergers and consolidations. The closing of this
Offering is not conditioned upon the consummation of the Debt Offering; however,
the consummation of the Debt Offering is conditioned upon the consummation of
this Offering. See "Description of Certain Indebtedness -- Senior Subordinated
Notes."
PRICE RANGE OF COMMON STOCK
The Common Stock is quoted 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.
<TABLE>
<CAPTION>
HIGH LOW
---- ---
<S> <C> <C>
Year ended December 31, 1995
First Quarter............................................. $ 5 1/2 $4 23/32
Second Quarter............................................ 6 1/8 4 7/8
Third Quarter............................................. 5 9/16 4 7/16
Fourth Quarter............................................ 5 3/8 4 1/2
Year ended December 31, 1996
First Quarter............................................. 6 5/8 4 5/8
Second Quarter............................................ 7 1/8 5 15/16
Third Quarter............................................. 7 1/2 6 1/8
Fourth Quarter............................................ 8 1/4 6 3/4
Year ended December 31, 1997
First Quarter............................................. 9 1/4 6 7/8
Second Quarter............................................ 11 1/2 6 7/8
Third Quarter (through September 29, 1997)................ 11 5/16 9
</TABLE>
A recent reported last sale price for the Common Stock as reported on the
Nasdaq Stock Market is set forth on the cover page of this Prospectus. On July
31, 1997, there were approximately 172 holders of record of the Common Stock.
DIVIDEND POLICY
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 Revolving Credit Facility
restrict the payment of dividends by the Company and CRI. Coho Energy, Inc. is
currently 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.
15
<PAGE> 16
USE OF PROCEEDS
The net proceeds to be received by the Company from this Offering are
estimated to be $49.1 million, after deducting underwriting discounts and
commissions and other estimated offering expenses. Concurrent with this
Offering, the Company is offering $150 million of 8 7/8% Senior Subordinated
Notes Due 2007 in the Debt Offering. The closing of this Offering is not
conditioned on the consummation of the Debt Offering; however, the closing of
the Debt Offering is conditioned upon the closing of this Offering. The Company
intends to use the total net proceeds of the Offerings to the Company (estimated
to be $193.6 million) to fund a portion of the Company's capital expenditure
program. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Liquidity and Capital Resources." Initially, however,
such net proceeds will be used to reduce borrowings under the Revolving Credit
Facility. The undrawn balance under the Revolving Credit Facility will then be
available for capital expenditures and general corporate purposes, including the
acquisition of additional producing crude oil and natural gas properties.
Amounts borrowed under the Revolving Credit Facility were used to finance
acquisitions of crude oil and natural gas properties, development and
exploitation activities and for general corporate purposes, and bear interest,
at the option of the Company, at prime or LIBOR plus a margin premium based on a
ratio, calculated on a rolling four quarter basis, of consolidated indebtedness
to EBITDA, with the highest applicable margin being 1.50% (currently 1.375%).
The Revolving Credit Facility remains outstanding until January 1, 2000, at
which time the outstanding advance will convert to a term loan.
CAPITALIZATION
The following table sets forth as of June 30, 1997 (i) the actual
capitalization of the Company, (ii) the capitalization of the Company as
adjusted to give effect to this Offering and (iii) the capitalization of the
Company as further adjusted to give effect to the Debt Offering. See "Use of
Proceeds." This table should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Consolidated Financial Statements included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
JUNE 30, 1997
---------------------------------
AS AS
ADJUSTED ADJUSTED
FOR THIS FOR THE
ACTUAL OFFERING OFFERINGS
-------- -------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Cash and cash equivalents.................................. $ 936 $ 936 $ 62,204
======== ======== ========
Long-term debt:
Revolving Credit Facility(a)............................. $132,298 $ 83,198 $ --
8 7/8% Senior Subordinated Notes Due 2007(b)............. -- -- 148,866
Other long term debt..................................... 52 52 52
-------- -------- --------
Total long-term debt............................. 132,350 83,250 148,918
-------- -------- --------
Shareholders' equity:
Preferred stock, $0.01 par value, 10,000,000 shares
authorized, none issued............................... -- -- --
Common stock, $0.01 par value, 50,000,000 shares
authorized, 20,443,899 issued and outstanding,
25,443,899 shares as adjusted(c)...................... 204 254 254
Additional paid-in capital............................... 84,092 133,142 133,142
Retained earnings........................................ 932 932 932
-------- -------- --------
Total shareholders' equity....................... 85,228 134,328 134,328
-------- -------- --------
Total capitalization........................... $217,578 $217,578 $283,246
======== ======== ========
</TABLE>
- ---------------
(a) At June 30, 1997, after giving effect to the temporary repayment of
indebtedness with the proceeds of the Offerings, the Company would have had
borrowing base availability under the Revolving Credit Facility of $150
million. Actual amounts include $2.3 million of letters of credit issued
pursuant to the Revolving Credit Facility to secure repayment of certain
promissory notes. These promissory notes were repaid on August 18, 1997,
from advances under the Revolving Credit Facility, and the letters of credit
were released. At September 29, 1997, the amount borrowed under the
Revolving Credit Facility was $146.0 million.
(b) Net of $1.1 million of original issue discount.
(c) Excludes 2,569,678 shares subject to outstanding options under the Company's
stock option plans.
16
<PAGE> 17
SELECTED CONSOLIDATED FINANCIAL DATA
The following selected consolidated financial data for each of the years in
the three-year period ended December 31, 1996 are derived from, and are
qualified by reference to, the Company's audited Consolidated Financial
Statements included elsewhere herein. The following selected consolidated
financial data for each year of the two year period ended December 31, 1993 are
derived from, and are qualified by reference to, the Company's audited
consolidated financial statements not included herein. The selected consolidated
financial data for the six-month periods ended June 30, 1996 and 1997 are
derived from the unaudited consolidated financial statements of the Company
included elsewhere herein and, in the opinion of management, include all
adjustments, consisting of normal recurring accruals, necessary for a fair
presentation of the data presented. The results for the six months ended June
30, 1997 are not necessarily indicative of results for the full year. The
information presented below should be read in conjunction with Coho's
Consolidated Financial Statements and "Management's Discussion and Analysis of
Financial Condition and Results of Operations" included elsewhere herein.
<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
------------------------------------------------------- ----------------------
1992 1993 1994 1995 1996 1996 1997
-------- -------- -------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Operating revenues:
Net crude oil and natural gas production... $ 26,915 $ 28,263 $ 26,464 $ 40,903 $ 54,272 $ 25,305 $ 29,521
-------- -------- -------- -------- -------- -------- --------
Operating expenses:
Crude oil and natural gas production....... 5,603 7,164 7,840 10,514 11,277 5,541 6,113
Taxes on oil and gas production............ 1,647 1,609 1,532 1,943 2,598 1,266 1,070
General and administrative expenses........ 2,779 2,997 3,435 5,400 7,264 3,299 3,623
Other expenses(a).......................... -- 21,000 973 -- -- -- --
Depletion and depreciation................. 7,773 10,677 9,989 14,717 16,280 7,885 8,960
-------- -------- -------- -------- -------- -------- --------
Total operating expenses............. 17,802 43,447 23,769 32,574 37,419 17,991 19,766
-------- -------- -------- -------- -------- -------- --------
Operating income (loss)..................... 9,113 (15,184) 2,695 8,329 16,853 7,314 9,755
Interest and other income................... 124 87 218 92 1,012 510 149
Interest expense............................ 3,270 3,571 4,190 8,140 8,476 4,233 4,682
-------- -------- -------- -------- -------- -------- --------
Earnings (loss) from continuing operations
before income taxes........................ 5,967 (18,668) (1,277) 281 9,389 3,591 5,222
Income tax expense (benefit)................ 2,330 (5,219) (303) 112 3,483 1,453 2,037
-------- -------- -------- -------- -------- -------- --------
Earnings (loss) from continuing
operations................................. $ 3,637 $(13,449) $ (974) $ 169 $ 5,906 $ 2,138 $ 3,185
======== ======== ======== ======== ======== ======== ========
Net earnings (loss)......................... $ 3,637 $(13,449) $ (1,654) $ 1,780 $ 5,906 $ 2,138 $ 3,185
======== ======== ======== ======== ======== ======== ========
Preferred dividends......................... $ -- $ -- $ 86 $ 944 $ -- $ -- $ --
Net earnings (loss) from continuing
operations per common share................ .31 (1.12) (.07) (.02) .29 .11 .15
Net earnings (loss) per common share........ $ .31 $ (1.12) $ (.12) $ .05 $ .29 $ .11 $ .15
Weighted average common and common shares
equivalent outstanding..................... 11,847 12,013 14,190 17,932 20,457 20,337 20,991
OTHER FINANCIAL DATA:
Cash flow from operations(b)................ $ 14,352 $ 12,248 $ 7,928 $ 19,227 $ 26,351 $ 11,793 $ 14,407
EBITDA(c)................................... 16,886 15,493 12,684 23,046 33,133 15,199 18,715
Capital expenditures........................ 26,341 24,122 19,503 29,970 52,384 24,199 33,294
Cash provided (used) by operating
activities................................. 16,924 13,572 (682) 12,835 16,847 10,329 17,321
Cash provided (used) by investing
activities................................. (26,341) (22,923) (31,624) (29,336) (31,810) 213 (28,205)
Cash provided (used) by financing
activities................................. 9,750 10,029 29,983 16,318 15,397 (11,563) 9,956
SELECTED RATIOS:
Ratio of earnings to fixed charges(d)....... 2.8x NM(e) NM(e) NM(e) 2.1x 1.8x 2.1x
Ratio of EBITDA to interest expense......... 5.2x 4.3x 3.0x 2.8x 3.9x 3.6x 4.0x
Ratio of long-term debt to EBITDA........... 3.1x 3.5x 6.8x 4.7x 3.7x 3.2x(f) 3.5x(f)
BALANCE SHEET DATA (AT END OF PERIOD):
Working capital (deficit)................... $ 1,790 $ 871 $ (2,379) $ 14,433 $ 6,662 $ (6,068) $ (2,118)
Total assets................................ 111,292 104,286 196,970 204,042 230,041 200,691 247,284
Long-term debt(g)........................... 52,000 54,000 86,311 107,403 122,777 95,959 132,350
Redeemable preferred stock.................. -- -- 16,125 -- -- -- --
Total shareholders' equity.................. 49,158 44,279 56,416 74,321 81,466 76,496 85,228
</TABLE>
- ---------------
(a) Amount for 1993 reflects the writedown in carrying value of crude oil and
natural gas properties ($20,000) and reorganization costs ($1,000). Amount
for 1994 reflects restructuring expenses.
(b) Cash provided by operating activities before working capital adjustments.
(c) Earnings before interest, taxes, depreciation, depletion, amortization and
other non-cash charges. Certain non-cash charges in 1993 relate to the
writedown in carrying value of crude oil and natural gas properties. EBITDA
should not be considered as an alternative to, or more meaningful than, net
income or cash flow as determined in accordance with generally accepted
accounting principles as an indicator of the Company's operating performance
or liquidity.
(d) For purposes of determining the ratio of earnings to fixed charges, earnings
are defined as earnings from continuing operations before income taxes, plus
fixed charges. Fixed charges consist of interest expense, amortization of
debt expense, and pretax preferred stock dividends.
(e) The ratio is not meaningful for the years ended December 31, 1993, 1994 and
1995 because earnings were inadequate to cover fixed charges in those years
by $18,668, $1,390 and $1,289, respectively.
(f) EBITDA for these periods has been annualized.
(g) Excludes current maturities of long-term debt.
17
<PAGE> 18
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. Prospective investors
should carefully consider the factors set forth under the caption "Risk Factors"
for a discussion of important factors that could cause actual results to differ
materially from the forward-looking statements contained in this Prospectus.
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.
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 the
first six months of 1997. Operating revenues increased from $26.9 million in
1992 to $54.3 million in 1996 and have continued to increase to $29.5 million
for the six months ended June 30, 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 believes its recent exploration success in the
Brookhaven field coupled with the recent 3-D seismic surveys at Laurel and
Martinville 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
18
<PAGE> 19
production taxes) per BOE have decreased from $4.11 and $4.62 in 1992 and 1993,
respectively, to $3.88 and $3.83 in 1996 and the first six months of 1997,
respectively.
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 colder 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
related 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, quality and timing of its capital
expenditures by obtaining high working interests in and operating its
properties. At June 30, 1997, the Company owned an average working interest of
96% in, and operated over 99% of, its producing properties.
RESULTS OF OPERATIONS
SELECTED OPERATING DATA
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
--------------------------- -----------------
1994 1995 1996 1996 1997
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
PRODUCTION:
Crude oil (Bbl/day)........................ 5,416 5,966 6,742 6,612 7,084
Natural gas (Mcf/day)...................... 1,836 19,431 18,160 17,938 19,583
BOE (Bbl/day)........................... 5,722 9,205 9,769 9,602 10,348
AVERAGE SALES PRICES:
Crude oil (per Bbl)........................ $ 12.86 $ 13.62 $ 16.42 $ 15.71 $ 17.03
Natural gas (per Mcf)(a)................... 1.55 1.59 2.07 1.96 2.17
PER BOE DATA:
Production costs(b)........................ $ 4.49 $ 3.71 $ 3.88 $ 3.90 $ 3.83
Depletion.................................. 4.78 4.38 4.55 4.51 4.78
PRODUCTION REVENUES (IN THOUSANDS):
Crude oil.................................. $25,427 $29,654 $40,527 $18,902 $21,826
Natural gas................................ 1,037 11,249 13,745 6,403 7,695
------- ------- ------- ------- -------
Total production revenues............... $26,464 $40,903 $54,272 $25,305 $29,521
======= ======= ======= ======= =======
</TABLE>
- ---------------
(a) Natural gas prices are net of fuel costs used in gas gathering.
(b) Includes lease operating expenses and production taxes, exclusive of general
and administrative costs.
19
<PAGE> 20
SIX MONTHS ENDED JUNE 30, 1997 COMPARED WITH SIX MONTHS ENDED JUNE 30, 1996
Operating Revenues. During the first six months of 1997, production
revenues increased 17% to $29.5 million as compared to $25.3 million for the
same period in 1996. This increase was principally due to a 7% increase in crude
oil production, a 9% increase in natural gas production, and increases in the
prices received for crude oil and natural gas (including hedging gains and
losses discussed below) of 8% and 11%, respectively.
The 9% increase in daily natural gas production is primarily a result of
the continued positive response from the Company's development efforts in the
Martinville and Brookhaven fields. The 7% increase in daily crude oil production
during the first half of 1997 is due to significant production increases made in
the Martinville, Soso and Brookhaven fields, with production increasing by 201%,
49% and 81%, respectively. These production increases were partially offset by
production decreases in the Summerland and Laurel fields due to the unusually
high frequency of weather-related power outages and mechanical problems during
the first quarter of 1997. In addition, the Summerland field is experiencing
normal production declines due to the maturity of the field.
Average crude oil prices increased during the first half of 1997 compared
to the same period in 1996 due to the strong demand for crude oil and higher oil
prices in the first quarter of 1997 as compared to the first quarter of 1996.
The posted price for the Company's crude oil averaged $19.35 per Bbl for the six
months ended June 30, 1997, a 2% increase over the average posted price of
$19.04 per Bbl experienced in the first six months of 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, increased 11% from $1.96 per Mcf in the first six months of 1996 to
$2.17 per Mcf in the first six months of 1997, due to increased heating needs
during the winter season and an overall tightening of supply and demand in the
market.
Production revenues for the six months ended June 30, 1997 included crude
oil hedging losses of $396,000 ($.31 per Bbl) compared to crude oil hedging
losses of $1.3 million ($1.09 per Bbl) for the same period in 1996. Production
revenues in 1997 also included natural gas hedging gains of $86,000 ($.02 per
Mcf) compared with natural gas hedging losses of $1.1 million ($.33 per Mcf) for
the same period in 1996. Additionally, the Company has entered into certain
arrangements which fix a minimum WTI price per Bbl of $19.00 and a maximum WTI
price of $23.90 for 4,000 Bbls of production per day through December 31, 1997.
The Company also has 920,000 MMbtu of natural gas production hedged over the
July through September 1997 period at an average price of $2.35 per MMbtu.
Interest and other income decreased to $149,000 in the first half of 1997
from $510,000 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, partially offset by $137,000 of interest received in the first
quarter of 1997 on a federal tax refund.
Expenses. Production expenses (including production taxes) were $7.2
million for the first six months of 1997 compared to $6.8 million for the first
six months of 1996. This increase primarily reflects additional production
volumes. On a BOE basis, production costs decreased to $3.83 per BOE in 1997
compared to $3.90 per BOE in 1996 for the six month periods.
General and administrative costs increased 10% between the comparable six
month periods from $3.3 million in 1996 to $3.6 million in 1997, primarily due
to staff additions to handle the increased drilling and recompletion activity.
Interest expense increased 11% for the six month period ended June 30, 1997
compared to the same period in 1996, due to higher borrowing levels during 1997
as compared to 1996.
Depletion and depreciation expense increased 14% to $9.0 million for the
six months ended June 30, 1997 from $7.9 million in 1996. These increases are
primarily the result of increased production volumes and an increased rate per
BOE, which increased to $4.78 in 1997, compared with $4.51 for the comparable
six month
20
<PAGE> 21
period in 1996. The depletion and depreciation rate decreased from $5.05 per BOE
in the first quarter of 1997 to $4.54 per BOE in the second quarter of 1997
primarily due to significant reserve additions from the exploration success in
the Brookhaven field.
The Company's net earnings for the six months ended June 30, 1997 were $3.2
million, as compared to net earnings of $2.1 million for the same period in 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 in 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 expenses 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.
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.
21
<PAGE> 22
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."
Since April, borrowing levels have 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 operating loss carryforwards ("NOLs") for United States
and Canadian federal income tax purposes were approximately $71 million at
December 31, 1996 and expire between 1997 and 2010. Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS 109")
requires that the tax benefit 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 NOLs prior to their expiration. A valuation allowance has been established
with respect to approximately $9 million of these NOLs as it is uncertain
whether they will be utilized before they expire. See "Risk Factors -- Possible
Limitations on Net Operating Loss Carryforwards."
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.
YEAR ENDED DECEMBER 31, 1995 COMPARED WITH YEAR ENDED DECEMBER 31, 1994
Operating Revenues. During 1995, production revenues increased 55% to $40.9
million as compared to $26.5 million in 1994. This increase was principally due
to increased natural gas production, a 10% increase in crude oil production and
a 6% increase in crude oil prices received.
The 10% increase in daily crude oil production for 1995 to 5,966 Bbls was
primarily a result of the continued positive response from the Company's
waterflood projects in the Laurel field, particularly in the Rodessa formation,
as well as results from increased drilling at Summerland, where four wells were
drilled in the last half of 1994 and first half of 1995. The significant
increase in natural gas production, to approximately 19.4 MMcf per day,
reflected the Company's acquisition of ING in December 1994 and ING's production
from the Monroe field in north Louisiana. While Coho had very little natural gas
production prior to the acquisition, the Company's production profile during
1995 was 65% crude oil and 35% natural gas.
Crude oil prices increased significantly during the first half of 1995
compared to the same period in 1994 and were reasonably stable for the balance
of 1995. The posted price for the Company's crude oil averaged $16.73 per Bbl
for 1995, an 8% increase over the average posted price of $15.55 per Bbl
experienced in 1994. The price per barrel received by the Company is adjusted
for the quality and gravity of crude oil and is generally lower than the posted
price. The crude oil prices received by the Company during 1995 did not increase
as significantly as the average posted price because the price recorded by the
Company includes the effects of the hedging gains and losses discussed below.
During 1995, the Company amended certain of its marketing arrangements for the
sale of substantially all of its crude oil. The new sales agreement reduced the
spread between the posted price and the price received by the Company by
approximately $.75 per Bbl, resulting in a net increase in revenues to the
Company. This change was effective during the second quarter of 1995.
The price for natural gas deteriorated during the first nine months of 1995
from 1994 year end prices. Mild winter weather across the United States and
delayed summer temperature increases reduced demand during the normally higher
volume heating and cooling seasons, and prices reflected this reduced demand.
During the fourth quarter of 1995, demand increased and natural gas prices
responded. In 1995, the average price per Mcf of natural gas received by the
Company was $1.59.
Production revenues for 1995 included crude oil hedging losses of $593,000
($.27 per Bbl), while production revenues for 1994 included crude oil hedging
gains of $1.1 million ($.54 per Bbl). Production revenues in 1995 also include
natural gas hedging gains of $1.0 million ($.15 per Mcf).
22
<PAGE> 23
Expenses. Production expenses (including production taxes) were $12.5
million in 1995 compared to $9.4 million in 1994. This increase reflects
additional production volumes. On a BOE basis, production costs decreased to
$3.71 per BOE in 1995 compared to $4.49 per BOE in 1994. This decrease was the
result of increased natural gas production in 1995, which typically has lower
operating costs than crude oil wells, and increased crude oil production
volumes, which also tend to reduce costs on a BOE basis.
General and administrative costs increased substantially in 1995 to $5.4
million compared to $3.4 million in 1994. This increase was a result of
increased staff to administer the production operations acquired in the ING
acquisition. General and administrative expenses were $1.61 per BOE in 1995 and
$1.64 per BOE in 1994. During 1995, in connection with the rationalization of
operations following the ING acquisition, the Company effected 41 of 42 planned
employee terminations and paid termination benefits totalling $2.1 million,
which were offset against a restructuring charge which was accrued in 1994.
Interest expense increased to $8.1 million in 1995 from $4.2 million in
1994. This increase was primarily due to higher borrowing levels related to the
acquisition of ING in December 1994, as well as the Company's ongoing capital
expenditure program. Advances under the Company's Revolving Credit Facility were
$103.4 million (excluding gas storage loans) at December 31, 1995, compared to
$86 million at December 31, 1994. The general increase in interest rates also
contributed to the increase in interest costs for the period. The average
interest rate paid on outstanding indebtedness under the Company's Revolving
Credit Facility was 8.4% in 1995, compared to 6.8% in 1994.
Depletion and depreciation expense increased 47% to $14.7 million in 1995
from $10.0 million in 1994, as a result of the ING acquisition and the resultant
increased natural gas production volumes combined with the increased crude oil
production volumes in 1995. The depletion rate per BOE decreased to $4.38 in
1995 as compared to $4.78 in 1994. The per BOE decrease results from lower
depletion rates on the ING reserves and from additions in proved crude oil
reserves associated with the Company's exploration and development activities.
The Company's net income for 1995 was $1.8 million, including $1.6 million
of income from discontinued marketing and transportation operations, as compared
to a net loss of $1.7 million in 1994 for the reasons discussed above.
LIQUIDITY AND CAPITAL RESOURCES
Capital Sources. Cash flow generated from operating activities for the six
months ended June 30, 1996, and June 30, 1997, was $10.3 million and $17.3
million, respectively, and was $12.8 million and $16.8 million for the years
ended December 31, 1995 and December 31, 1996, respectively. Production and
price increases are the major factors contributing to the improved cash flow.
At June 30, 1997, the Company had a working capital deficit of $2.1 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. At December 31, 1996 the Company had
working capital of $6.7 million primarily due to higher than normal crude oil
and natural gas receivables as a result of new wells coming online and due to
investments in marketable securities.
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.
Under the Revolving Credit Facility, the lenders have a maximum commitment
of $250 million. Additionally, the amount available to the Company in borrowing
capacity for general corporate purposes ("Borrowing Base") is $150 million, with
an additional $20 million immediately available to the Company to provide bridge
financing for acquisitions. The revolving period terminates on January 1, 2000,
at which time
23
<PAGE> 24
the loan converts to a term facility requiring quarterly principal repayments
until fully repaid in 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 1.375%, with the highest applicable margin being 1.50%. CRI is the
borrower 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 June 30, 1997, outstanding advances under the Company's Revolving Credit
Facility were $130 million, all of which were classified as long term, and
letters of credit outstanding aggregated $2.3 million to secure promissory notes
issued in August 1995 relating to the acquisition of the Brookhaven field,
leaving $17.7 million available thereunder.
The Revolving Credit Facility contains certain financial and other
covenants including (i) the maintenance of minimum amounts of shareholders'
equity ($65 million plus 50% of accumulated consolidated net income beginning in
1994 for the cumulative period), (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. At June 30, 1997 and December 31, 1996, shareholders' equity
exceeded the minimum required under the Revolving Credit Facility by
approximately $14.8 million and $12.6 million, respectively, and the ratios of
current assets to current liabilities were 2.2 to 1 and 4.1 to 1, respectively.
For the six months ended June 30, 1997 and the year ended December 31, 1996, the
ratios of cash flow to interest expense were 4.5 to 1 and 4.3 to 1,
respectively.
Estimated net proceeds from the Offerings to the Company of $193.6 million
will be used to fund a portion of the Company's capital expenditure programs
including those planned for the last six months of 1997. Initially, such net
proceeds will be used to repay all outstanding borrowings under the Company's
Revolving Credit Facility and to provide 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 executed
in conjunction with the Debt Offering will limit the Company's ability to pay
dividends, primarily based on the level of the Company's outstanding
indebtedness and primarily limited to 50% of consolidated net income earned
after the date the Notes are issued. 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 the first six months of 1997, the Company
incurred capital expenditures of $33.3 million compared with $24.2 million for
the first six months of 1996. The capital expenditures incurred during the first
six months of 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 the first six months of 1997, the Company drilled 15 wells as follows:
three producing crude oil wells in the Laurel field, one producing crude oil
well and one dryhole in the Martinville field, one producing crude oil well in
the Soso field, two producing crude oil wells and one producing natural gas well
in the Brookhaven field, five producing natural gas wells in the Monroe field
and one producing offshore natural gas well in the North Padre field. The
Company also had four wells being drilled at June 30, 1997, one in each of the
Brookhaven, Martinville, Laurel and North Padre fields. During
24
<PAGE> 25
1996, the Company incurred capital expenditures of $52.4 million compared with
$30.0 million for 1995. Drilling activity increased significantly during 1996
over prior years. The Company drilled a total of 33 gross wells during 1996 as
compared to 7 and 9 gross wells drilled in 1994 and 1995, respectively. The
majority of the 1996 drilling activity was in the Martinville and Brookhaven
fields with the drilling of 12 and 6 gross wells in each field respectively. The
remaining 15 wells were drilled in the Monroe field (6 gross wells), the Laurel
field (5 gross wells), the Summerland field (3 gross wells) and the Soso field
(1 gross well). Additionally, 1996 capital expenditures include costs associated
with a 37 square mile 3-D seismic program in the Laurel field. Approximately 38%
of the capital spent in 1996 was associated with projects, primarily secondary
recovery and 3-D seismic projects, which were not yet complete and therefore did
not have an effect on daily production.
General and administrative costs directly associated with the Company's
exploration and development activities were $1.2 million and $1.5 million for
the six months ended June 30, 1996 and 1997, respectively, and were $1.8 million
and $2.5 million for the years ended December 31, 1995 and 1996, respectively,
and were included in total capital expenditures.
In June 1997, the Board of Directors approved a $10 million increase in the
1997 capital expenditure program to a total of $54 million, which includes the
costs of drilling approximately 30 development wells and 9 exploratory wells
during the full year. Management believes that, barring any significant
acquisitions or other unforeseen capital requirements, funds provided by the
Offerings, 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 1999. The Company has no material
capital commitments and is consequently able to adjust the level of its
expenditures as circumstances warrant.
25
<PAGE> 26
BUSINESS AND PROPERTIES
OVERVIEW
Coho Energy, Inc. is an independent energy company engaged, through its
wholly owned subsidiaries, in the development and production of, and exploration
for, crude oil and natural gas. The Company's crude oil activities are
concentrated principally in Mississippi, where it is that 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 maintainable with minimal incremental capital expenditures. At
December 31, 1996, the Company's total proved reserves were 53.7 MMBOE with a
Present Value of Proved Reserves of $417.1 million, approximately 76% of which
were proved developed reserves. At December 31, 1996, approximately 65% of
Coho's total proved reserves were comprised of crude oil and the Company's
reserve-to-production ratio was approximately 15 years. At June 30, 1997, the
Company owned an average working interest of 96% in, and operated over 99% 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
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 three-year
inventory of potential development drilling, secondary recovery and exploration
projects in this basin. The Company believes that its concentration in this
geographic area provides it with important competitive advantages such as its
extensive databases, operational infrastructure and economies of scale.
The Company's focus in the central Mississippi 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 10,717 BOE in the second quarter of 1997, representing a compound annual
growth rate of 19.4%. Over the five-year period ended December 31, 1996, the
Company discovered or acquired approximately 42.3 MMBOE of proved reserves at an
average finding cost of $4.84 per BOE. Over the same period, the Company has
replaced over 300% of its production. This increase in reserves from 24.1 MMBOE
at year end 1991 to 53.7 MMBOE at year end 1996 represents a five-year compound
annual growth rate of 17.4%. Consistent with the increase in production, EBITDA
has increased from $16.9 million in 1992 to $36.6 million for the twelve-month
period ended June 30, 1997.
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 operations are conducted primarily in the Brookhaven,
Laurel, Martinville, Soso and Summerland fields in Mississippi, and the Monroe
field in Louisiana.
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 1996, Coho spent $41 million of its
total capital expenditures of $52 million on exploitation projects. As of June
30, 1997, Coho had ongoing exploitation projects in the Brookhaven, Laurel,
Martinville, Soso and Summerland fields. 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 increased spending on
conventional development drilling opportunities. This strategy is illustrated in
the Company's 1995 acquisition of the Brookhaven field in Mississippi. Less than
25% of the crude oil in place in the Tuscaloosa reservoir at Brookhaven has been
recovered to date. Since
26
<PAGE> 27
acquiring this property, the Company has increased total daily field production
to approximately 1,360 net BOE at June 30, 1997, from approximately 230 net BOE
at the time of acquisition. Additionally, in June 1997, the Company announced
that test results of the first two exploratory wells at Brookhaven have proven
productive pay sands in three deeper formations. These wells commenced
production in the second quarter of 1997.
Secondary Recovery. Over the last three years, Coho has implemented 12
secondary recovery projects in the Mississippi salt basin. Six of these projects
have been successfully developed and six are in the pilot phase. The six
developed projects have increased production in these reservoirs by an average
of 475%, have produced over 3.3 MMBbls and have 7.7 MMBbls of remaining proved
reserves. These 11.0 MMBbls have an estimated finding and development cost of
$2.86 per Bbl. In 1996, Coho spent $11.2 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 28% of its 1997 capital
budget to exploration. In 1995, Coho completed a 24-square mile 3-D seismic
survey on the Martinville field. Based on this data, one successful exploratory
well was completed in 1996 and two additional exploration wells are planned in
1997. 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.
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.
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 57 development wells, of which 93% were completed successfully. The
Company anticipates that approximately 72% of its total 1997 capital expenditure
budget will be allocated to such relatively low-risk, high-return projects,
including secondary recovery projects which will comprise approximately 29% of
the total 1997 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 and around its existing properties. These programs
have produced an attractive inventory of exploration projects that the Company
will continue to pursue. Approximately 28% of the Company's 1997 capital
expenditures will be allocated to such exploration projects.
Acquire Properties with Underdeveloped Reserves. The Company intends to
acquire underdeveloped crude oil and natural gas properties, primarily in the
interior salt basin of Mississippi, which have geological complexity and
multiple producing horizons. Management believes that the Company's extensive
experience in this area of Mississippi developed over the past 14 years should
enable it to efficiently increase reserves and improve production rates in this
geologically complex environment. For the month of June 1997, the
27
<PAGE> 28
Company's average daily production per well in Mississippi was 95 BOE, which was
substantially higher than the domestic industry average of less than 12 BOE.
Additionally, management believes that this experience gives the Company a
significant competitive advantage in evaluating similarly situated acquisition
prospects.
Significant Control of Operations. Coho's strategy of increasing production
and reserves through acquiring and developing faulted, 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 June 30, 1997, Coho operated over 99% of its producing
properties with an average working interest of approximately 96%. This operating
control, combined with the Company's significant technical and geological
expertise in the Mississippi salt basin region, enables the Company to better
control the magnitude, quality 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, 1996, approximately 88%
of the Company's Mississippi reserves was concentrated in four 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 $3.83 per BOE and favorable cash
margins of $10.00 per BOE for the six months ended June 30, 1997.
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.
RECENT DEVELOPMENTS
During the first half of 1997, the Company was focused principally on
continuing development activities in the Company's Laurel, Martinville and Soso
fields and exploration activity in the Brookhaven field. During the same time
period, Coho drilled 15 new wells, 14 of which were successful, including three
crude oil wells in the Laurel field, two exploration wells in the Brookhaven
field and five natural gas wells in the Monroe field. The Company believes that
events in the following three fields are among its most significant recent
developments.
Brookhaven. The Brookhaven field is one of several prolific fields in
southwest Mississippi that have produced from the Tuscaloosa formation. In an
attempt to establish commercial production below the Tuscaloosa, Coho drilled an
exploration well for the Paluxy and Washita Fredericksburg formations at
Brookhaven. This well encountered 14 potentially productive pay sands in the
Washita Fredericksburg and Paluxy formations. A tested Paluxy sand flowed at 200
gross BOPD and a Washita Fredericksburg sand was tested and has flowed since May
28, 1997 at over 400 gross BOPD.
The Company has also successfully tested a Rodessa natural gas exploration
well. This well was brought on line on June 12, 1997 and continues to flow at
approximately 2.6 MMcf of natural gas and 130 barrels of condensate per day.
This activity has established significant exploration success for the
Company. Since the original shallower Tuscaloosa formation covers 23 square
miles, the Company believes that the size of the structure for deeper formations
could be similar. Prior to the Company's recent deep success, only five
penetrations deeper than the Tuscaloosa existed on this 23-square mile
structure. Four of these penetrations were drilled during the 1940s and all five
of these penetrations have shown that the Washita Fredericksburg and Paluxy
reservoirs are extensive over the field.
Laurel. The Company believes that the Laurel field, which covers less than
one square mile and has to date produced approximately 19 MMBbls, has
significant remaining potential for reserve and production growth. In order to
better quantify and verify the potential in the currently defined Laurel field
and the surrounding area, Coho commenced a 37-square mile 3-D seismic survey in
1996. A preliminary interpretation of the seismic data has been used in the
drilling of four successful crude oil wells in the first half of 1997 to verify
previously identified drilling locations. This data has increased the Company's
confidence for several exploration plays in the Eutaw formation in the current
Laurel field, the most productive formation in
28
<PAGE> 29
Mississippi. A new Laurel "look-alike" has exploration potential in the
Tuscaloosa, Paluxy, Rodessa, Sligo and Hosston formations, and additionally in
the Cotton Valley and Smackover formations. The data will continue to be
analyzed and an exploration program is expected to evolve over 1998 and 1999.
Martinville. Following the initial processing of 3-D seismic data, Coho
drilled two Hosston-depth exploratory test wells in 1996. The Hosston has been
the most prolific producing formation in the Martinville field, having produced
approximately 5 MMBOE to date. A successful Hosston-depth well was drilled to
the west of the existing field and a dry hole Hosston-depth well was drilled to
the north of the existing field. The successful Hosston well also found
potential pay sands in the Rodessa and Sligo formations. This well was put on
production in the Hosston formation in September 1996 at approximately 650 BOE
per day and is currently flowing at 150 BOE per day having already produced 130
MBOE. This exploration discovery will result in further development during the
latter part of 1997 and 1998. The 3-D seismic has indicated several exploration
plays in the Smackover, Cotton Valley, Hosston, Rodessa and Eutaw formations.
These plays will be further analyzed beginning in late 1997.
OIL AND GAS OPERATIONS
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 the six
months ended June 30, 1996 and 1997 and for each of the years in the three-year
period ended December 31, 1996 and the number of productive wells producing as
of June 30, 1997, all of which are crude oil wells unless otherwise indicated:
<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS
DECEMBER 31, ENDED JUNE 30,
--------------------- ---------------------- AS OF JUNE 30, 1997
1994 1995 1996 1996 1997 ----------------------------------
----- ----- ----- ----- -------------- NET AVERAGE
BOE/ BOE/ BOE/ BOE/ BOE/ % OF PRODUCTIVE PERCENTAGE WORKING
FIELD DAY DAY DAY DAY DAY TOTAL WELLS OPERATED INTEREST
----- ----- ----- ----- ----- ------ ----- ---------- ---------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Brookhaven,
Mississippi........... -- 130(a) 416 336 669 7% 23 100% 93%
Laurel, Mississippi..... 3,100 3,470 3,317 3,579 3,048 29 37 100 92
Martinville,
Mississippi........... 440 343 580 358 1,290 13 22 100 95
Monroe, Louisiana(b).... 280(c) 3,097 2,892 2,869 2,818 27 2,654 100 96
Soso, Mississippi....... 449 470 772 705 1,068 10 24 100 93
Summerland,
Mississippi........... 1,139 1,242 1,451 1,474 1,082 10 20 100 90
Other(d)................ 314 453 341 281 373 4 13 73 62
----- ----- ----- ----- ------ --- -----
Total........... 5,722 9,205 9,769 9,602 10,348 100% 2,793 99.9 96
===== ===== ===== ===== ====== === =====
</TABLE>
- ---------------
(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) Calculated as a 365 day average, although the effective acquisition date was
December 8, 1994.
(d) Of the wells indicated, three 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.
Like other fields, Coho made the acquisition anticipating increased
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.
As a result of its study, the Company identified and drilled five new well bores
in the field in 1996. The five penetrations found unswept crude oil reserves
associated with structural and stratigraphic complexity. Three of these
penetrations were completed as commercial producers and two will be used as
injectors to aid the secondary recovery operations.
29
<PAGE> 30
In addition to its exploitation success, the Company has had significant
exploration success in the first half of 1997. In June, the Company announced
that test results of the BFU 5-7 #1 exploratory well indicated pay sands in the
Paluxy and Washita Fredricksburg formations. The well encountered approximately
180 net feet of pay in 11 Paluxy sands and three Washita Fredricksburg sands. A
single Washita Fredricksburg sand was tested and flowed at over 400 gross BOPD
and a tested Paluxy sand flowed at 200 gross BOPD. In addition, 28 additional
feet of pay were indicated in the Tuscaloosa formation, even though this
reservoir has been producing for more than fifty years. The Company is currently
drilling an up-dip well from the BFU 5-7 #1 well and a down structure
delineation well. The Company has also successfully tested a Rodessa exploration
well. This geopressured Rodessa well is currently producing approximately 2.6
MMcf of gas and 130 barrels of condensate per day. The Company plans to drill an
offset well to the Rodessa discovery during the last half of 1997. In total,
average net daily production in the second quarter of 1997 was 860 BOE, an
increase of 107% from the average net daily production in 1996.
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
existing Brookhaven field.
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 the six months ended June 30, 1997. At June 30,
1997, the field contained 40 wells producing from the Stanley, Christmas,
Tuscaloosa, Washita Fredricksburg, Paluxy, Mooringsport, Rodessa, Sligo and
Hosston reservoirs. Proved crude oil reserves at Laurel totalled 14.6 MMBbls at
December 31, 1996.
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 total, the secondary recovery projects have added over 6.3 MMBbls to
total reserves.
In addition to the continued exploitation program, the Company is
continuing an active exploration program at Laurel. In 1996, 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 significant exploration possibilities in the acreage
surrounding the field.
The average net daily production for the second quarter of 1997 from Laurel
was 3,004 BOE, which was down approximately 10.4% compared to 1996 net daily
production, as a result of the Company's redirection of water injection
activities 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. As of August 1, 1997, the net daily production was approximately
3,500 BOE. Coho's average working interest is 92% in the 40 producing wells it
operated in the Laurel field at June 30, 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 BOPD, while during the second
quarter of 1997 it produced 1,475 BOPD. The field covers more than 7,400 acres,
and currently has 17 producing wellbores. Like Laurel, the field is
characterized by highly complex faulting and produces from multiple horizons.
Coho currently has an average 95% 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
30
<PAGE> 31
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. As part of
the secondary recovery project, 4 service wells and 3 producing wells were
drilled with strong reservoir response. Reserves at the end of 1996 totaled 4.6
MMBOE, a 57% increase over proved reserves in 1995, and average daily production
during the second quarter of 1997 showed a 150% increase from 1996 average daily
production.
The data from the 3-D seismic shoot is also being utilized to further
develop the exploration possibilities for the field. In 1996, two exploration
wells were drilled, and one proved to be successful in the Hosston formation,
with initial daily production flowing at 665 gross BOE. Other significant
exploration possibilities exist in the shallow Eutaw formation (approximately
8,000 ft.) as well as the deep Cotton Valley, Smackover and Haynesville
formations.
Monroe Field, Louisiana. In December 1994, as part of the ING acquisition,
the Company acquired a 98% working interest and operations in a major portion of
the Monroe field. The 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 the second quarter of 1997 was 2,920 BOE, down slightly
from 1996 average daily production primarily due to operational problems
associated with seasonal but unusually high levels of flooding. In 1996, the
Company initiated a shallow Sparta sand natural gas drilling program which led
to six new shallow natural gas wells being drilled in the field at a depth of
250 to 900 feet each. This Sparta program, coupled with continued operating
efficiencies and improved natural gas prices, resulted in December 31, 1996 net
proved reserves of 97.5 Bcf of natural gas in the Monroe field, a 4% increase
over December 31, 1995 proved reserves. Plans in 1997 include continuation of
the Sparta drilling program and commencement of a 1,600 foot Wilcox drilling
program.
As part of the ING acquisition the Company also acquired a 100% interest in
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 and 24 compressor units with a rated capacity of
approximately 11,800 horsepower. In 1996, these systems gathered approximately
28.9 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 255 BOPD. In the second quarter of 1997, the average daily production
was 1,109 BOE, an increase of 43.7% over 1996 average daily production. Reserves
at December 31, 1996 totaled 5.6 MMBOE, a 54% increase over year-end 1995.
Soso is a large, geologically complex field which had already produced over
60 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 formation. These projects have played a significant role in the
threefold increase in daily production.
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.
31
<PAGE> 32
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 June 30, 1997, the Company operated 22 producing wells and
has an average working interest of 89.6% 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 BOPD (of which only
200 Bbls were economic) in 1989 at the date of acquisition, to 1,700 BOPD in
June 1997. Net daily crude oil production in 1996 represented a 16.8% increase
over 1995 production and was also the highest annual crude oil production in the
38 year life of the field. Average daily production during the second quarter of
1997 was 1,090 BOPD, down 24.9% from 1996 average daily production.
At December 31, 1996, the Summerland field had proved reserves of 5.8 MMBOE
reflecting a 18% decline in reserves from year-end 1995. This decline in
reserves was primarily associated with high production volumes during 1996 and
the drilling of two unsuccessful wells in the Tuscaloosa formation. Summerland
has some additional exploration possibilities from deep drilling in the Cotton
Valley and Smackover formations.
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, 1996, these fields had combined net
proved reserves of 3.8 MMBOE. The Company is in the process of selling the Frio
properties.
Tunisia, North Africa. Coho has an interest in two permits covering 1.5
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 both the onshore Anaguid and offshore Alyane
permits 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 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 early 1998. Coho's estimated
cost to drill this well is less than $2.0 million. The Company's current working
interest is 50% in the Anaguid permit and 100% in the Alyane permit (up from 50%
in 1995 due to the non-renewal of a 50% option by a third party). The Company is
currently evaluating its options with respect to the Alyane permit.
PRODUCTION
The following table sets forth certain information regarding Coho's
volumes, average prices received and average production costs associated with
its sales of crude oil and natural gas for the six months ended June 30, 1996
and 1997 and for each of the years in the three-year period ended December 31,
1996:
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
-------------------------- ----------------
1994 1995 1996 1996 1997
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
CRUDE OIL:
Volumes (MBbls)..................... 1,977 2,178 2,467 1,203 1,282
Average sales price (per Bbl)(a).... $12.86 $13.62 $16.42 $15.71 $17.03
NATURAL GAS:
Volumes (MMcf)...................... 670(b) 7,093 6,646 3,265 3,544
Average sales price (per Mcf)(c).... $ 1.55 $ 1.59 $ 2.07 $ 1.96 $ 2.17
AVERAGE PRODUCTION COST (PER
BOE)(d)............................. $ 4.49 $ 3.71 $ 3.88 $ 3.90 $ 3.83
</TABLE>
- ---------------
(a) Includes the effects of crude oil price hedging contracts. Price per Bbl
before the effect of hedging was $12.32, $13.89 and $18.34 for the years
ended December 31, 1994, 1995 and 1996, respectively, and $16.80 and $17.34
for the six months ended June 30, 1996 and 1997, respectively.
(b) Includes volumes from ING properties for the one month post-acquisition
period.
(c) Includes the effects of natural gas price hedging contracts. Price per Mcf
before the effect of hedging was $1.55, $1.44 and $2.24 for the years ended
December 31, 1994, 1995 and 1996, respectively, and $2.29 and $2.15 for the
six months ended June 30, 1996 and 1997, respectively.
(d) Includes lease operating expenses and production taxes.
32
<PAGE> 33
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.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS
--------------------------------------------- ENDED
1994 1995 1996 JUNE 30, 1997
------------ ------------ ------------- -------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
EXPLORATORY:
Crude oil............... -- -- -- -- 1 1.0 1 1.0
Natural gas............. -- -- -- -- -- -- 1 .8
Dry holes............... 1 .3 1* .5* 1 1.0 1 1.0
DEVELOPMENT:
Crude oil............... 4 3.7 6 5.4 13 12.0 6 5.6
Natural gas............. -- -- 1 1.0 6 6.0 6 5.4
Dry holes............... -- -- -- -- 4 3.7 -- --
Service wells........... 2 1.7 1 .9 8 7.5 -- --
-- --- -- --- -- ---- -- ----
Total........... 7 5.7 9 7.8 33 31.2 15 13.8
== === == === == ==== == ====
</TABLE>
- ---------------
* Well drilled in Tunisia
RESERVES
The following table summarizes the Company's net proved crude oil and
natural gas reserves by field as of December 31, 1996, the most recent date for
which reserve data is available, which have been reviewed by Ryder Scott.
<TABLE>
<CAPTION>
CRUDE NATURAL NET PROVED
OIL GAS RESERVES
(MBBLS) (MMCF) (MBOE)
------- ------- ----------
<S> <C> <C> <C>
Brookhaven, Mississippi............................... 2,803 316 2,855
Laurel, Mississippi................................... 14,573 463 14,650
Martinville, Mississippi.............................. 4,490 651 4,599
Monroe, Louisiana..................................... -- 97,545 16,257
Soso, Mississippi..................................... 5,640 -- 5,640
Summerland, Mississippi............................... 5,849 -- 5,849
Other................................................. 1,467 14,157 3,828
------ ------- ------
Total....................................... 34,822 113,132 53,678
====== ======= ======
</TABLE>
At December 31, 1996, the Company had net proved developed reserves of
40,579 MBOE and net proved undeveloped reserves of 13,099 MBOE. The Present
Value of Proved Reserves was $417.1 million, which represented $299.3 million
for the proved developed and $117.8 million for the proved undeveloped reserves.
At December 31, 1995, the Company reported total proved reserves of 48,777 MBOE
and the Present Value of Proved Reserves was $268.6 million. This total
represents an increase of 4,901 MBOE and $148.5 million in reserves and Present
Value of Proved Reserves, respectively, at December 31, 1996. The increase was
attributable to extensions and discoveries associated with the Company's efforts
in Mississippi, the increase in posted crude oil prices and increased natural
gas prices, as well as a new crude oil marketing contract which reduced the
spread between the actual price received by Coho for its crude oil and posted
prices.
There are numerous uncertainties inherent in estimating quantities of
proved crude 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 quantity and value of
reserves set forth herein. In
33
<PAGE> 34
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. See "Risk Factors -- Uncertainty of Estimates of
Reserves and Future Net Revenues."
In general, the volume 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 of operations from producing activities, see
"Supplemental Information Related to Oil and Gas Activities" appearing in note
16 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 June 30, 1997:
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
------------------ ----------------
GROSS NET GROSS NET
------- ------- ------ ------
<S> <C> <C> <C> <C>
Mississippi................................... 25,126 23,168 20,678 19,479
Louisiana..................................... 125,770 105,496 1,598 1,419
Texas......................................... 2,796 2,796 1,691 1,691
Offshore Gulf of Mexico....................... 5,760 2,269 -- --
------- ------- ------ ------
Total............................... 159,452 133,729 23,967 22,589
======= ======= ====== ======
</TABLE>
The Company also holds a working interest in two exploratory permits in
Tunisia, North Africa; an onshore permit covering 1,412,000 gross acres (50%
working interest) and an offshore permit covering 115,000 gross acres (100%
working interest).
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 not 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
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
34
<PAGE> 35
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 the custom 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 1996 two purchasers of Coho's crude oil and natural
gas, EOTT Energy Corp. ("EOTT") and Mid Louisiana Marketing Company, accounted
for 66% and 15%, 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 natural gas produced in the Monroe field (approximately 17.4 MMcf per
day in 1996) 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, 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 colder 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.
OFFICE AND FIELD FACILITIES
The Company leases its executive and administrative offices in Dallas,
Texas, consisting of 38,568 square feet, under a lease that continues through
October 2000. The Company also leases a field office in Laurel, Mississippi
covering approximately 5,000 square feet, under a non-cancelable lease extending
through June 2000. The field office facilities in Fairbanks, Louisiana and
Brookhaven, Mississippi are owned by the Company.
35
<PAGE> 36
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 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 and $.02 per Mcf in Louisiana. 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.
In addition, the U.S. Court of Appeals for the D.C. Circuit recently ruled
that the MMS can only collect royalties on gas that is produced, bought or sold,
and cannot collect revenues from financial arrangements, such as take-or-pay
settlements.
In 1995, the MMS issued a notice of proposed rulemaking in which it
proposed to amend its regulations governing the calculation of royalties and the
valuation of natural gas produced from federal leases. The principal feature in
the amendments, as proposed, would have established an alternative market index
based method to calculate royalties on certain natural gas production sold to
affiliates or pursuant to non-arm's-
36
<PAGE> 37
length sales contracts. The MMS proposed this rulemaking to facilitate royalty
valuation in light of changes in the natural gas marketing environment. The MMS
subsequently reopened the public comment period under the proposed rule due to
the diversity of comments received under the proposed rule. As a result, the MMS
outlined five options for alternatives to using gross proceeds as a basis for
natural gas valuation. On April 22, 1997, the MMS withdrew its proposed
rulemaking to amend such regulations. At the same time, the MMS solicited
comments on two supplemental options for valuing natural gas produced from
federal leases -- one being index-based and the other being based on the royalty
collection practice in Norway by which royalty values are established by a
"Petroleum Price Board." The MMS recently extended the period for public
comments on the two supplemental options to September 22, 1997. In 1996, the MMS
proposed a rulemaking to update transportation allowance regulations to reflect
the changes in the natural gas industry due to FERC Order No. 636 unbundling.
The rulemaking would clarify which costs are deductible from federal and Indian
leases. The Final Rule is expected this year. The Company cannot predict what
action the MMS will take on these matters, nor can it predict at this stage of
the rulemaking proceeding how the Company might be affected by amendments to the
regulations.
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 proposed a rulemaking to modify the valuation
procedures for arm's-length and non-arm's-length crude oil transactions. The
intent of the rule is to decrease the reliance on posted prices and assign a
value to crude oil that better reflects market value. On July 3, 1997, the MMS
proposed changes to the previously proposed rulemaking. Comments on proposed
changes were due by August 4, 1997. 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
37
<PAGE> 38
these 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 court remanded the case to the FERC,
which has not yet acted on remand. The U.S. Supreme Court declined to review the
D.C. Circuit's decision. 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 or
sale of crude oil, condensate or natural gas. It is therefore 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 its 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
38
<PAGE> 39
$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 MMS. The Company cannot predict the final form 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 than 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.
39
<PAGE> 40
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 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 two wildlife refuges in 1996. The Company continues to cooperate with the
other 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.
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 years, 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 of 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 July 31, 1997, Coho had 132 employees associated with its operations,
including 27 field personnel in Mississippi and 40 field personnel in Louisiana.
None of the Company's employees is represented by a union. The Company considers
its employee relations to be satisfactory.
40
<PAGE> 41
MANAGEMENT
The names of the executive officers and directors of the Company and
certain information with respect to them are set forth below.
<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
Jeffrey Clarke.................... 52 President, Chief Executive Officer and Director
R.M. Pearce....................... 46 Executive Vice President and Chief Operating
Officer
Eddie M. LeBlanc, III............. 48 Senior Vice President and Chief Financial Officer
Anne Marie O'Gorman............... 38 Senior Vice President Corporate Development and
Corporate Secretary
Keri Clarke....................... 41 Vice President, Land and Environmental/Regulatory
Affairs
R. Lynn Guillory.................. 50 Vice President, Human Resources and Administration
Larry L. Keller................... 38 Vice President, Exploitation
Patrick S. Wright................. 41 Vice President, Operations
Susan J. McAden................... 40 Controller
Robert B. Anderson................ 71 Director
Roy R. Baker...................... 75 Director
Frederick K. Campbell............. 59 Director
Louis F. Crane.................... 56 Director
Howard I. Hoffen.................. 33 Director
Kenneth H. Lambert................ 52 Director
Douglas R. Martin................. 52 Director
Carl S. Quinn..................... 66 Director
Jake Taylor....................... 50 Director
</TABLE>
Jeffrey Clarke has served as Chairman of the Company since October 1993 and
as President and Chief Executive Officer of the Company since September 1993.
Mr. Clarke served as Executive Vice President and Chief Operating Officer of CRI
from May 1982 until May 1990, as President and Chief Operating Officer from May
1990 to October 1992 and as President and Chief Executive Officer of CRI since
October 1992. He has served as Senior Vice President, Chief Operating Officer
and a director of CRL since 1984 and has been engaged by CRL in various
capacities since 1980. Jeffrey Clarke and Keri Clarke, Vice President, Land and
Environmental/Regulatory Affairs of the Company, are brothers.
R. M. Pearce has served as Executive Vice President and Chief Operating
Officer of the Company since August 1995 and has been an officer of Coho since
November 1993. From July 1991 to October 1993, Mr. Pearce served as President of
GRL Production Services Company.
Eddie M. LeBlanc, III joined the Company as Senior Vice President and Chief
Financial Officer when the Company acquired ING on December 8, 1994. From the
inception of ING in March 1992 through its acquisition by the Company, Mr.
LeBlanc was Senior Vice President and Chief Financial Officer of ING. From
August 1991 until March 1992, Mr. LeBlanc was an independent businessman.
Anne Marie O'Gorman was appointed Senior Vice President Corporate
Development in March 1996 having been Vice President, Corporate Development of
Coho (and CRI, prior to September 1993) from August 1993. Ms. O'Gorman has been
employed by CRI or CRL in various capacities since 1985. Ms. O'Gorman has served
as Secretary of the Company since September 1993.
Keri Clarke has served as Vice President, Land and Environmental/Regulatory
Affairs of Coho (or CRI, prior to September 1993) since 1989. He has also been
employed by CRL in various positions since 1981. Keri Clarke and Jeffrey Clarke
are brothers.
R. Lynn Guillory joined the Company as Vice President, Human Resources and
Administration when the Company acquired ING. Mr. Guillory held that same
position with ING since its inception in March 1992. From August 1991 until the
inception of ING, Mr. Guillory was an independent businessman.
41
<PAGE> 42
Larry L. Keller has served as Vice President, Exploitation of Coho (or CRI,
prior to September 1993) from August 1993 and has been employed in various
engineering positions with CRI since July 1990.
Patrick S. Wright joined Coho as Vice President, Operations in January
1996. From January 1991 until he joined Coho, Mr. Wright served in several
managerial positions with Snyder Oil Corporation (an international oil and gas
exploration and production company) .
Susan J. McAden joined the Company as Controller in February 1995. From
September 1993 to February 1995, Ms. McAden was Vice President and Controller of
Lincoln Property Company (a property development and management company). From
November 1990 to September 1993, Ms. McAden was Chief Accounting Officer and
Treasurer of Concap Equities, Inc.("Concap") (the acting general partner for
sixteen public real estate partnerships) and from November 1989 to November
1990, Ms. McAden was Vice President-Controller of Concap.
Robert B. Anderson has served as President of R. B. Anderson Energy Company
(a private oil and gas and real estate company) since 1989.
Roy R. Baker has been an independent consultant in the oil and gas industry
since 1984.
Frederick K. Campbell served as Vice Chairman of the Board of Directors of
CRI from June 1990 until September 1993, served as a director of CRL from 1980
until September 1993 and served as CRL's Chairman of the Board from 1982 until
June 1992. Mr. Campbell has served as Chairman of the Board and Chief Executive
Officer of Campco International Capital Ltd. (private investment company) since
1984.
Louis F. Crane has served as President and Chief Executive Officer of
Orleans Capital (investment portfolio management firm) since November 1991. Mr.
Crane is a director of Offshore Logistics Inc. and Columbia Universal Corp.
Howard I. Hoffen has been a Principal since January 1996 and was previously
a Vice President of Morgan Stanley & Co. Incorporated. Mr. Hoffen joined Morgan
Stanley in 1985 and became a member of the Merchant Banking Division in 1986.
Mr. Hoffen is currently a Vice President of the general partner of The Morgan
Stanley Leveraged Equity Fund II, L.P. ("MSLEF II")and a director of Amerin
Guaranty Corporation and Catalytica Inc.
Kenneth H. Lambert served as Chairman of the Board of Directors of CRI from
1980 until September 1993, as Chief Executive Officer of CRI from 1980 to 1992
and as President of CRI from 1980 to 1990. Mr. Lambert served as President and
Chief Executive Officer of CRL from 1980 to June 1992, and as Chairman of the
Board of CRL from June 1992 until September 1993. Mr. Lambert has served as
President and Chief Executive Officer of Nugold Technology Ltd. (a private
company dealing in the recovery of precious metals) since April 1993. Mr.
Lambert is chairman of the board, president, chief executive officer and
director of Edmonton International Industries Ltd. (a Canadian public investment
holding company) and Chairman of the Board of Destination Resorts, Inc. (a
Canadian public resort development corporation).
Douglas R. Martin has served as Chairman of Pursuit Resources Corp. (a
Canadian public oil and gas company) since September 1993. Mr. Martin served as
Senior Vice President and Chief Financial Officer of CRI from May 1990 to August
1993. He served as CRL's Senior Vice President and Chief Financial Officer from
April 1990 to August 1993.
Carl S. Quinn served as Chairman of the Board, President and Chief
Executive Officer of ING from its inception in March 1992 until its acquisition
by the Company in December 1994. Mr. Quinn was Chairman of the Board, President
and Chief Executive Officer of Arkla Exploration Company (an oil and gas
company) from October 1989 through December 1991. Mr. Quinn is a director of
Atmos Energy Corporation.
Jake Taylor has been an independent financial consultant since 1989.
Messrs. Hoffen and Quinn were elected to the Board of Directors upon the
issuance of Common Stock and Series A Preferred Stock for the acquisition of
ING. Each were designated to serve as directors of the Company by MSLEF II
pursuant to the terms of the Registration Rights and Shareholder Agreement dated
as of December 8, 1994, as amended (the "ING Shareholder Agreement"), among
MSLEF II and Quinn Oil Company Ltd. ("Quinn") (the previous stockholders of ING)
and the Company.
42
<PAGE> 43
PRINCIPAL AND SELLING SHAREHOLDERS
The following table sets forth, as of July 31, 1997, the beneficial
ownership of Common Stock by (i) each shareholder of the Company selling Common
Stock in this Offering (a "Selling Shareholder"), (ii) each person or entity
who, to the knowledge of the Company, based on information received from or on
behalf of such persons, was the beneficial owner of more than 5% of the
outstanding shares of Common Stock, and (iii) all executive officers and
directors of Coho as a group. Unless otherwise specified, such persons have sole
voting power and sole dispositive power with respect to all shares attributable
to him.
<TABLE>
<CAPTION>
SHARES BENEFICIALLY
OWNED PRIOR SHARES BENEFICIALLY
TO OFFERING OWNED AFTER OFFERING
------------------- SHARES ---------------------
NAME OF BENEFICIAL OWNER NUMBER PERCENT BEING OFFERED NUMBER PERCENT
------------------------ --------- ------- ------------- ---------- --------
<S> <C> <C> <C> <C> <C>
SELLING SHAREHOLDERS:
The Morgan Stanley Leveraged Equity Fund
II, L.P.(a).......................... 5,597,653 27.4% 3,076,655 2,520,998 9.9%
Quinn Oil Company Ltd. and Carl S.
Quinn(b)............................. 574,685 2.8 307,827 266,858 1.0
Lambert Holdings Ltd., Edmonton
International Industries Ltd., 297139
Alberta Ltd. and Kenneth H.
Lambert(c)........................... 648,239 3.2 200,000 448,239 1.8
OTHER PRINCIPAL SHAREHOLDERS:
Wellington Management Company(d)........ 1,115,857 5.5 -- 1,115,857 4.4
Neuberger & Berman(e)................... 1,045,800 5.1 -- 1,045,800 4.1
All directors and executive officers as a
group (18 persons)(b)(c)(f)............. 3,821,620 18.7 507,827 3,313,799 13.0
</TABLE>
- ---------------
(a) MSLEF II, Morgan Stanley Leveraged Equity Fund II, Inc. and Morgan Stanley,
Dean Witter, Discover & Co. may each be deemed to have sole voting and
dispositive power with respect to the 5,597,653 shares of Common Stock that
were issued to MSLEF II in connection with the acquisition of ING and the
payment of dividends in exchange for cancellation of the Company's Series A
Preferred Stock in August 1995. If the Underwriters' overallotment option is
exercised in full, the number and percentage of shares beneficially owned by
MSLEF II after this Offering will be 1,350,440 shares and 5.3%.
(b) Quinn and Carl S. Quinn, a director of the Company, may each be deemed to
have sole voting and dispositive power with respect to the 559,685 shares of
Common Stock that were issued to Quinn in connection with the acquisition of
ING and the payment of dividends in exchange for cancellation of the
Company's Series A Preferred Stock in August 1995. The number of shares
shown as beneficially owned by Mr. Quinn include shares owned by such
entities and also include 15,000 shares that may be acquired by Mr. Quinn
within 60 days upon the exercise of stock options. If the Underwriters'
overallotment option is exercised in full, the number and percentage of
shares beneficially owned after this Offering will be 149,744 shares and
.6%.
(c) Mr. Lambert, a director of the Company, is the beneficial owner of the
shares held by Lambert Management Ltd., Lambert Holdings Ltd., Edmonton
International Industries Ltd., 372268 Alberta Ltd., 249172 Alberta Ltd., and
297139 Alberta Ltd. The number of shares shown as beneficially owned by Mr.
Lambert include the shares owned by such entities and also include 78,058
shares that may be acquired by Mr. Lambert within 60 days upon the exercise
of stock options. Included in Mr. Lambert's total shares are 35,959 shares
which are held by family members; Mr. Lambert claims no beneficial interest
in these shares.
(d) Based solely on information contained in a Schedule 13G dated January 24,
1997 filed with the Commission. Wellington Management Company acts as a
financial advisor for its clients and has shared voting power with respect
to 470,467 shares, and shared dispositive power with respect to 1,115,857
shares, of Common Stock that are owned by its clients.
(e) Based solely on information contained in a Schedule 13G dated February 10,
1997 filed with the Commission, Neuberger & Berman acts as investment
advisor for its clients and has sole voting power with respect to 192,000
shares of Common Stock, shared voting power with respect to 623,000 shares
and shared dispositive power with respect to 1,045,800 shares of Common
Stock owned by its clients.
(f) Includes 2,046,151 shares that may be acquired within 60 days upon the
exercise of stock options held by all directors and executive officers as a
group.
43
<PAGE> 44
DESCRIPTION OF CAPITAL STOCK
The authorized capital stock of Coho consists of 50,000,000 shares of
Common Stock, par value $.01 per share, and 10,000,000 shares of preferred
stock, par value $.01 per share. At July 31, 1997, 20,464,630 shares of Common
Stock were outstanding and no shares of Preferred Stock were outstanding. A
total of 2,544,197 shares of Common Stock are reserved for issuance upon the
exercise of options granted under the Company's Stock Option Plans.
COMMON STOCK
Holders of shares of Common Stock are entitled to one vote per share in the
election of directors and on all other matters submitted to a vote of
shareholders. Such holders have the right to cumulate their votes in the
election of directors. Holders of Common Stock have no redemption or conversion
rights and no preemptive or other rights to subscribe for securities of Coho. In
the event of a liquidation, dissolution or winding up of Coho, holders of Common
Stock are entitled to share equally and ratably in all of the assets remaining,
if any, after satisfaction of all debts and liabilities of Coho, and the
preferential rights of any series of Preferred Stock then outstanding. The
shares of Common Stock outstanding are, and the shares to be offered hereby will
be, fully paid and non-assessable.
Holders of Common Stock have an equal and ratable right to receive
dividends, when, as and if declared by the Board of Directors out of funds
legally available therefor and only after payment of, or provision for, full
dividends on all outstanding shares of any series of Preferred Stock and after
Coho has made provision for any required sinking or purchase funds for series of
Preferred Stock. See "Dividend Policy."
PREFERRED STOCK
The Preferred Stock may be issued, from time to time, in one or more
series, and the Board of Directors, without further approval of the
shareholders, is authorized to fix the dividend rights and terms, redemption
rights and terms, liquidation preferences, conversion rights, voting rights and
sinking fund provisions applicable to each such series of Preferred Stock. If
Coho issues a series of Preferred Stock in the future that has voting rights or
preferences over the Common Stock with respect to the payment of dividends and
upon Coho's liquidation, dissolution or winding up, the rights of the holders of
the Common Stock offered hereby may be adversely affected. The issuance of
shares of Preferred Stock could be utilized, under certain circumstances, in an
attempt to prevent an acquisition of Coho. The Company has no present intention
to issue any shares of Preferred Stock.
LIMITATION OF DIRECTOR LIABILITY
The Articles of Incorporation of Coho contain a provision that limits the
liability of Coho's directors as permitted under Texas law. The provision
eliminates the liability of a director to Coho or its shareholders for monetary
damages for negligent or grossly negligent acts or omissions in the director's
capacity as a director. The provision does not affect the liability of a
director (i) for breach of his duty of loyalty to Coho or to shareholders, (ii)
for acts or omissions not in good faith or that involve intentional misconduct
or a knowing violation of law, (iii) for acts or omissions for which the
liability of a director is expressly provided by an applicable statute, or (iv)
in respect of any transaction from which a director received an improper
personal benefit. Pursuant to the Articles of Incorporation, the liability of
directors will be further limited or eliminated without action by shareholders
if Texas law is amended to further limit or eliminate the personal liability of
directors.
RIGHTS PLAN
In September 1994, the Company adopted a Rights Plan which, as amended,
provided for the distribution by the Company of one common share purchase right
(a "Right") for each outstanding share of Common Stock to holders of record of
Common Stock at the close of business on September 28, 1994, and for the
issuance of one Right for each share of Common Stock thereafter issued prior to
the earlier of the date the Rights first become exercisable, the date of
redemption of the Rights and September 13, 2004, the expiration
44
<PAGE> 45
date of the Rights. Until such time that the Rights become exercisable, the
Rights will be evidenced by the certificates representing the shares of Common
Stock with respect to which the Rights were issued and may only be traded with
such shares.
The Rights become exercisable on the earlier of (i) ten business days after
a public announcement that a person or group of affiliated or associated persons
(an "Acquiring Person"), which term does not include the Company, any subsidiary
of the Company, any employee benefit plan of the Company or the Company's
subsidiaries, or any entity holding Common Stock for or pursuant to any such
plan, have acquired beneficial ownership of 20% or more of the Common Stock and
(ii) ten business days after the commencement of, or the first public
announcement of an intention to make, a tender offer or exchange offer the
consummation of which would result in beneficial ownership by a person or group
(excluding the Company, any subsidiary of the Company, any employee benefit plan
of the Company or of its subsidiaries, and any entity holding Common Stock for
or pursuant to any such plan) of 20% or more of the Common Stock outstanding.
At any time up until ten business days after the acquisition by an
Acquiring Person of 20% or more of the Common Stock, the Board of Directors of
the Company may redeem the Rights in whole, but not in part, at a price of $.01
per Right.
REGISTRATION RIGHTS
The Company is a party to a Registration Rights Agreement with MSLEF II and
Quinn and an Amended and Restated Registration Rights Agreement with Kenneth H.
Lambert and Frederick K. Campbell, two directors of the Company. MSLEF II, Quinn
and Mr. Lambert are the Selling Shareholders in this Offering. The Registration
Rights Agreement with MSLEF II and Quinn generally provides that each may make
up to three requests to have certain shares of Common Stock registered by the
Company. The Registration Rights Agreement will continue to be applicable to
shares of Common Stock owned by MSLEF II and Quinn following this Offering. The
Amended and Restated Registration Rights Agreement with Messrs. Lambert and
Campbell generally provides each individual with the right to make one request
and to participate in a registration by the Company (a "piggyback" registration)
for certain shares of Common Stock owned by such individuals. The Amended and
Restated Registration Rights Agreement will continue to be applicable to shares
of Common Stock owned by Mr. Lambert after the Offering. Mr. Campbell has
indicated to the Company that he does not desire to participate in this
Offering.
TRANSFER AGENT AND REGISTRAR
The transfer agents for the Common Stock are Chase Mellon Shareholder
Services L.L.C. and Montreal Trust Company of Canada and the registrar is Chase
Mellon Shareholder Services L.L.C.
45
<PAGE> 46
DESCRIPTION OF CERTAIN INDEBTEDNESS
REVOLVING CREDIT FACILITY
The Company has a revolving credit facility (the "Revolving Credit
Facility") with Banque Paribas, Houston Agency, Bank One Texas, N.A. and
MeesPierson, N.V., as co-agents, and Bank of Scotland, Credit Lyonnais, New York
Branch, Christiana Bank Og Kreditkasse and Den Norske Bank AS (collectively, the
"Lenders"). The total credit commitment and borrowing base under the Revolving
Credit Facility at June 30, 1997 was $250 million and $150 million,
respectively. In addition, the Revolving Credit Facility provides $20 million of
bridge financing for acquisitions. The Revolving Credit Facility is secured by
the crude oil and natural gas properties of the Company and guaranteed by all of
the Company's material subsidiaries, excluding the Revolving Credit Facility
co-borrowers, and such guarantees are secured by all of the crude oil and
natural gas properties of the subsidiaries and the stock of all guaranteeing
subsidiaries. The Revolving Credit Facility is subject to borrowing base
availability as determined from time to time by the Lenders at their sole
discretion, and in accordance with customary practices and standards in effect
from time to time for crude oil and natural gas loans to borrowers similar to
the Company. The borrowing base may be affected from time to time by the
performance of the Company's crude oil and natural gas properties and changes in
crude oil and natural gas prices. The Company incurs a commitment fee of 3/8%
per annum on the unused portion of the borrowing base and 1/4% per annum on the
unused portion of the bridge financing capability.
The Revolving Credit Facility consists of a $150 million revolving credit
loan, the revolving period of which is scheduled to terminate on January 1,
2000. The balance remaining outstanding at that time will convert to a term loan
repayable in 14 equal quarterly installments commencing on March 31, 2000, and
with the final installment being payable on June 30, 2003. The Revolving Credit
Facility bears interest at the option of the Company at (i) LIBOR plus a maximum
of 1.50% or (ii) the Prime Rate. At June 30, 1997, outstanding borrowings under
the Revolving Credit Facility were approximately $130 million. An additional
$2.3 million was reserved against the issuance of standby letters of credit. At
September 29, 1997, the amount borrowed under the Revolving Credit Facility was
$146.0 million.
In addition to the $150 million borrowing base, the Revolving Credit
Facility provides for $20 million in bridge financing for acquisitions. Any
borrowings under the bridge facility which remains outstanding after any
borrowing base redetermination subsequent to any acquisition shall be repaid by
the earlier of (i) one year from the acquisition date of the assets requiring
the bridge financing borrowings or (ii) the maturity date of the bridge
financing facility. Borrowings under the bridge facility bear interest at the
option of the Company at (i) LIBOR plus 2.75% or (ii) Citibank Prime plus 1.0%.
The bridge financing availability matures on December 31, 1997.
The Revolving Credit Facility contains certain covenants which, among other
things, restrict the payment of dividends, limit the Company's ability to incur
additional debt, and provide that the Company must maintain minimum amounts of
shareholders equity and financial ratio coverages. See "Management's Discussion
and Analysis of Financial Position and Results of Operations -- Liquidity and
Capital Resources."
SENIOR SUBORDINATED NOTES
Concurrently with this Offering, the Company is offering up to $150 million
aggregate principal amount of its 8 7/8% Senior Subordinated Notes Due 2007,
pursuant to the Debt Offering. The following is a summary of certain terms of
the Notes and is qualified in its entirety by reference to the Indenture (the
"Indenture") relating to the Notes. A copy of the proposed form of Indenture has
been filed with the Registration Statement of which this Prospectus forms a
part.
The 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 and will be subordinated to future
senior indebtedness of the Company. The Notes mature on October 15, 2007. The
Notes will 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 will issue guarantees of the Notes on a senior subordinated basis.
46
<PAGE> 47
The Notes will be redeemable at the option of the Company, in whole or in
part, at any time or from time to time, at a premium which, for the period prior
to October 15, 2002, will be based on a Treasury make-whole calculation and, for
the period after such date, will be at a fixed percentage that declines to par
on or after October 15, 2004, in each case together with accrued and unpaid
interest to the date of redemption. In the event the Company consummates an
Equity Offering (as defined in the Indenture) prior to October 15, 2000, the
Company may, at its option, use all or a portion of the proceeds from such
offering to redeem up to 35% of the original aggregate principal amount of the
Notes at a redemption price equal to 108.875% of the aggregate principal amount
of the Notes to be redeemed, plus accrued and unpaid interest, if any, thereon
to the redemption date, provided at least $80 million aggregate principal amount
of the Notes remains outstanding after such redemption.
Upon the occurrence of a Change of Control and a Rating Decline (each as
defined in the Indenture), each holder of Notes will have the right to require
the Company to purchase all or a portion of such holder's Notes at a price equal
to 101% of the aggregate principal amount thereof, together with accrued and
unpaid interest to the date of purchase.
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.
CERTAIN UNITED STATES TAX CONSEQUENCES
TO NON-UNITED STATES HOLDERS
The following is a general discussion of certain anticipated United States
federal income and estate tax consequences of the ownership and disposition of
Common Stock applicable to Non-United States Holders of Common Stock. For the
purpose of this discussion, a "Non-United States Holder" is any corporation,
individual, partnership, estate or trust that is, as to the United States, a
foreign corporation, a nonresident alien individual, a foreign partnership or a
foreign estate or trust as such terms are defined in the Code. This discussion
does not deal with all aspects of United States income and estate taxation that
may be relevant to a Non-United States Holder in light of his, her or its
particular circumstances or to certain Non-United States Holders that may be
subject to special treatment under United States federal tax laws (i.e.,
insurance companies, tax-exempt organizations, financial institutions or
broker-dealers) and does not deal with foreign, state and local tax consequences
that may be relevant to Non-United States Holders in light of their personal
circumstances. Furthermore, the following discussion is based on current
provisions of the Code and administrative and judicial interpretations as of the
date hereof, all of which are subject to change, possibly with retroactive
effect. Prospective foreign investors are urged to consult their tax advisors
regarding the United States federal, state and local and non-United States
income and other tax consequences of owning and disposing of Common Stock.
DIVIDENDS
Generally, any dividend paid to a Non-United States Holder of Common Stock
will be subject to United States withholding tax at a rate of 30% of the gross
amount of the dividend, or at a lesser applicable treaty rate. Under current
United States Treasury regulations and published rulings, dividends paid to an
address in a foreign country generally are presumed to be paid to a resident of
such country for purposes of determining the applicable treaty rate, if any.
Under proposed United States Treasury regulations not currently in effect,
however, a Non-United States Holder of Common Stock who wishes to claim the
benefit of an applicable treaty rate would be required to satisfy applicable
certification and other requirements. A Non-United States Holder of Common Stock
eligible for a reduced rate of United States withholding tax pursuant to a tax
treaty may obtain a refund of any excess amounts currently withheld by filing an
appropriate claim for refund with the United States Internal Revenue Service
(the "Service"). To the extent that a distribution with respect to the Common
Stock represents a return of basis for United States federal income tax
purposes, a Non-United
47
<PAGE> 48
States Holder may apply for a refund of any amounts currently withheld with
respect to such return of basis by filing an appropriate claim for a refund with
the Service.
Dividends received by a Non-United States Holder that are effectively
connected with a United States trade or business conducted by such Non-United
States Holder are exempt from such withholding tax. However, such effectively
connected dividends, net of certain deductions and credits, are taxed at the
same graduated rates applicable to United States persons. A Non-United States
Holder may claim exemption from withholding under the effectively connected
income exception by filing Form 4224 (Statement Claiming Exemption from
Withholding of Tax on Income Effectively Connected With the Conduct of Business
in the United States) with the Company or its paying agent.
In addition to the graduated tax described above, dividends received by a
corporate Non-United States Holder that are effectively connected with a United
States trade or business of the corporate Non-United States Holder may also be
subject to a branch profits tax at a rate of 30% or at a lesser applicable
treaty rate.
If the holder of Common Stock is a domestic or foreign partnership engaged
in a United States trade or business, the partnership generally will be required
to withhold tax on any effectively connected dividend includible in the
distributive share of partnership income (the "Distributive Share") of a partner
who is a non-United States person (a "Foreign Partner"), whether or not
distributed, at the highest applicable rate of United States taxation
(currently, 39.6% for a noncorporate partner and 35% for a corporate partner). A
domestic partnership will be required to withhold tax at the 30% withholding tax
rate (or applicable treaty rate) on any dividend includible in the Distributive
Share of a Foreign Partner that is not an effectively connected dividend,
whether or not distributed. Different withholding requirements may apply to
partnerships that are publicly traded, and such partnerships are accordingly
advised to consult their tax advisors.
SALE OF COMMON STOCK
A Non-United States Holder generally will not be subject to United States
federal income tax (and no tax generally will be withheld) with respect to any
gain realized upon the sale or other disposition of his, her or its Common Stock
unless (i) such gain is effectively connected with a United States trade or
business of the Non-United States Holder, (ii) the Non-United States Holder is
an individual who is present in the United States for a period or periods
aggregating 183 days or more during the calendar year (or taxable year if one
has been established) in which such disposition occurs, the Common Stock is a
capital asset and either (a) such individual's "tax home," within the meaning of
Section 911(d)(3) of the Code, is in the United States or (b) the gain is
attributable to an office or other fixed place of business maintained in the
United States by such individual,(iii) the Non-United States Holder is subject
to tax pursuant to the provisions of United States federal income tax laws
applicable to certain United States expatriates, or (iv) the Company is or has
been a "United States real property holding corporation" for federal income tax
purposes. Non-United States holders who would be subject to United States
federal income tax with respect to gain recognized on a sale or other
disposition of Common Stock should consult applicable treaties, which may
provide for different rules.
The Company has determined that it is a "United States real property
holding corporation" for United States federal income tax purposes. Accordingly,
a Non-United States Holder who holds or held (during the five-year period
preceding such disposition) more than five percent of the Common Stock will be
subject to federal income tax on the sale or other disposition of such stock as
a result of the Company's being a "United States real property holding
corporation," assuming that the Common Stock continues to be "regularly traded
on an established securities market" for tax purposes.
BACKUP WITHHOLDING AND INFORMATION REPORTING
Payments of dividends to a Non-United States Holder at an address outside
the United States may be subject to information reporting, but will not, under
current law, generally be subject to backup withholding. The payment of the
proceeds of the disposition of Common Stock to or through the United States
office of a broker is subject to information reporting and backup withholding at
a rate of 31% unless the owner of the stock certifies its non-United States
status under penalties of perjury or otherwise establishes an exemption. The
payment of the proceeds of the disposition by a Non-United States Holder of
Common Stock to or
48
<PAGE> 49
through a foreign office of a broker will not be subject to backup withholding.
The Service has indicated, however, that it is studying the possible application
of backup withholding in the case of a foreign office of a broker that is (a) a
United States person, (b) a United States-controlled foreign corporation or (c)
a foreign person 50% or more of whose gross income for certain periods is from a
United States trade or business. Moreover, in the case of foreign offices of
such brokers, information reporting will apply to such payments of proceeds
unless such broker has documentary evidence in its files of the owner's foreign
status and has no actual knowledge to the contrary. Backup withholding is not an
additional tax. Amounts withheld under the backup withholding rules are
generally allowable as a refund or credit against such Non-United States
Holder's United States federal income tax liability, if any, provided that the
required information is furnished to the Service.
The procedures described above for withholding tax on dividend payments,
and some of the associated backup withholding and information reporting rules,
are currently the subject of proposed regulations issued in 1996, which are
proposed to be effective for payments made after December 31, 1997, subject to
certain transition rules (the "1996 Proposed Regulations"). The 1996 Proposed
Regulations, if adopted in their current form, would modify the procedures for
establishing an exemption from withholding tax described above. Informal
statements by the Service indicate that the 1996 Proposed Regulations, when
finally adopted, will be made effective for payments made after December 31,
1998. No official announcement to this effect, however, has been issued by the
Service.
FEDERAL ESTATE TAX
Common Stock owned, or treated as owned, by a nonresident alien individual
at the time of his or her death will be included in such holder's gross estate
for United States federal estate tax purposes and, subject to certain credits,
taxed at graduated rates of up to 55%, unless an applicable estate tax treaty
provides otherwise.
THE FOREGOING DISCUSSION IS A SUMMARY OF THE PRINCIPAL UNITED STATES
FEDERAL INCOME AND ESTATE TAX CONSEQUENCES OF THE OWNERSHIP, SALE OR OTHER
DISPOSITION OF THE COMMON STOCK BY NON-UNITED STATES HOLDERS. ACCORDINGLY,
INVESTORS ARE URGED TO CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE UNITED
STATES FEDERAL INCOME AND ESTATE TAX CONSEQUENCES OF THE OWNERSHIP AND
DISPOSITION OF THE COMMON STOCK, INCLUDING THE APPLICATION AND EFFECT OF THE
LAWS OF ANY STATE, LOCAL, FOREIGN OR OTHER TAXING JURISDICTION.
49
<PAGE> 50
UNDERWRITERS
Under the terms and subject to the conditions set forth in the Underwriting
Agreement dated the date hereof, the Company and the Selling Shareholders have
agreed to sell 5,000,000 and 3,584,482 shares, respectively, of the Common Stock
to the Underwriters named below (the "Underwriters"), for whom Morgan Stanley &
Co. Incorporated, Jefferies & Company, Inc., Prudential Securities Incorporated
and Smith Barney Inc. are acting as Representatives, and the Underwriters have
agreed severally to purchase the number of shares of Common Stock set forth
opposite their respective names in the table below:
<TABLE>
<CAPTION>
NUMBER
OF
UNDERWRITER SHARES
----------- ---------
<S> <C>
Morgan Stanley & Co. Incorporated........................... 1,646,182
Jefferies & Company, Inc. .................................. 1,646,100
Prudential Securities Incorporated.......................... 1,646,100
Smith Barney Inc. .......................................... 1,646,100
ABN Amro Chicago Corporation................................ 160,000
Bear, Stearns & Co. Inc..................................... 160,000
Brean Murray, Foster Securities Inc. ....................... 80,000
Gaines, Berland Inc. ....................................... 80,000
Howard, Weil, Labouisse, Friedrichs Incorporated............ 160,000
Joephthal, Lyon & Ross Incorporated......................... 80,000
Lehman Brothers Inc. ....................................... 160,000
McDonald & Company Securities, Inc. ........................ 80,000
Neuberger & Berman, LLC..................................... 80,000
Oppenheimer & Co., Inc. .................................... 160,000
Ormes Capital Markets, Inc. ................................ 80,000
Petrie Parkman & Co., Inc. ................................. 160,000
Principal Financial Securities, Inc. ....................... 80,000
Rauscher Pierce Refsnes, Inc. .............................. 160,000
Raymond James & Associates, Inc. ........................... 80,000
Sanders Morris Mundy Inc. .................................. 80,000
SF Investments, Inc. ....................................... 80,000
TD Securities Inc. ......................................... 80,000
---------
Total............................................. 8,584,482
=========
</TABLE>
The Underwriting Agreement provides that the obligations of the several
Underwriters to pay for and accept delivery of the shares of Common Stock
offered hereby are subject to the approval of certain legal matters by their
counsel and to certain other conditions. The Underwriters are obligated to take
and pay for all of the shares of Common Stock offered hereby (other than those
covered by the Underwriters' over-allotment option described below) if any such
shares are taken.
The Underwriters initially propose to offer part of the shares of Common
Stock directly to the public at the Price to Public set forth on the cover page
hereof and part to certain dealers at a price which represents a concession not
in excess of $.33 per share under the public offering price. The Underwriters
may allow, and such dealers may reallow, a concession not in excess of $.10 per
share to other Underwriters or to certain dealers. After the initial offering of
the shares of Common Stock, the offering price and other selling terms may from
time to time be varied by the Underwriters.
Pursuant to the Underwriting Agreement, two of the Selling Shareholders,
Quinn and MSLEF II, have granted to the Underwriters an option, exercisable for
30 days from the date of this Prospectus, to purchase up to 1,287,672 additional
shares of Common Stock at the public offering price set forth on the cover page
hereof, less underwriting discounts and commissions. The Underwriters may
exercise such option to purchase solely for the purpose of covering
over-allotments, if any, made in connection with the offering of the shares of
50
<PAGE> 51
Common Stock offered hereby. To the extent such option is exercised, each
Underwriter will become obligated, subject to certain conditions, to purchase
approximately the same percentage of such additional shares of Common Stock as
the number set forth opposite to such Underwriter's name in the preceding table
bears to the total number of shares of Common Stock offered by the Underwriters
hereby.
The Company, its executive officers and directors and the Selling
Shareholders have agreed that, without the prior written consent of Morgan
Stanley & Co. Incorporated, they will not (i) offer, pledge, sell, contract to
sell, sell any option or contract to purchase, purchase any option or contract
to sell, grant any option, right or warrant to purchase, or otherwise transfer
or dispose of, directly or indirectly, any shares of Common Stock or any
securities convertible into or exercisable or exchangeable for Common Stock
(provided that such shares or securities are either currently owned by such
person or are acquired in connection with the Offering) or (ii) enter into any
swap or other agreement that transfers, in whole or in part, any of the economic
consequences of ownership of such shares of Common Stock, whether any such
transaction described in clause (i) or (ii) above is to be settled by delivery
of Common Stock or such other securities, in cash or otherwise, for a period of
90 days after the date hereof, other than (x) the sale to the Underwriters of
the shares of Common Stock offered hereby or (y) the issuance by the Company of
shares of Common Stock upon the exercise of any options granted or shares of
Common Stock issued pursuant to existing benefit plans of the Company.
Each of the Underwriters has represented and, during the period of six
months after the date hereof, agreed that (a) it has not offered or sold and
will not offer or sell any shares of Common Stock in the United Kingdom except
to persons whose ordinary activities involve them in acquiring, holding,
managing or disposing of investments (as principal or agent) for the purpose of
their business or otherwise in circumstances which have not resulted and will
not result in an offer to the public in the United Kingdom within the meaning of
the Public Offers of Securities Regulations (1995) (the "Regulations"); (b) it
has complied and will comply with all applicable provisions of the Financial
Services Act 1986 and the Regulations with respect to anything done by it in
relation to the shares of Common Stock offered hereby in, from or otherwise
involving the United Kingdom; and (c) it has only issued or passed on and will
only issue or pass on to any person in the United Kingdom any document received
by it in connection with the issue of the shares of Common Stock if that person
is of a kind described in Article 11(3) of the Financial Services Act 1986
(Investment Advertisements) (Exemptions) Order 1996, or is a person to whom such
document may otherwise lawfully be issued or passed on.
In connection with the ING acquisition in 1994, MSLEF II, an affiliate of
Morgan Stanley & Co. Incorporated, acquired Common Stock and Series A Preferred
Stock of the Company representing 27.4% of the equity capital of the Company. In
addition, Mr. Howard Hoffen, currently a Principal of Morgan Stanley & Co.
Incorporated, was nominated to the Board of Directors by MSLEF II pursuant to
the terms of the ING Shareholder Agreement. MSLEF II, which is a Selling
Shareholder, beneficially owns 5,597,653 shares of Common Stock (27.4% of the
Common Stock on a fully diluted basis) prior to this Offering and following this
Offering will beneficially own 2,520,998 shares (9.9%) (1,350,440 shares, or
5.3%, if the Underwriters' over-allotment option is exercised in full).
Jefferies & Company, Inc. has from time to time provided financial advisory
services to the Company, for which services Jefferies & Company, Inc. has
received customary compensation.
In order to facilitate this Offering, the Underwriters may engage in
transactions that stabilize, maintain or otherwise affect the price of the
Common Stock. Specifically, the Underwriters may overallot in connection with
this Offering, creating a short position in the Common Stock for their own
account. In addition, to cover overallotments or to stabilize the price of the
Common Stock, the Underwriters may bid for, and purchase, shares of Common Stock
in the open market. Finally, the underwriting syndicate may reclaim selling
concessions allowed to an underwriter or a dealer for distributing the Common
Stock in this Offering, if the syndicate repurchases previously distributed
Common Stock in transactions to cover syndicate short positions, in
stabilization transactions or otherwise. Any of these activities may stabilize
or maintain the market price of the Common Stock above independent market
levels. The Underwriters are not required to engage in these activities, and may
end any of these activities at any time.
51
<PAGE> 52
The Company, the Selling Shareholders and the Underwriters have agreed to
indemnify each other against certain liabilities that may be incurred in
connection with the offering of the Common Stock, including liabilities under
the Securities Act, or to contribute to payments that the other may be required
to make in respect thereof.
LEGAL MATTERS
Certain legal matters with respect to the shares of Common Stock offered
hereby will be passed upon for Coho by Fulbright & Jaworski L.L.P., Houston,
Texas. The Underwriters have been represented by Cravath, Swaine & Moore, New
York, New York.
EXPERTS
The consolidated financial statements and schedule of Coho Energy, Inc. and
subsidiaries for the year ended December 31, 1994 have been included and
incorporated by reference herein and in the Registration Statement in reliance
upon the reports of KPMG Peat Marwick LLP, independent certified public
accountants, appearing elsewhere herein, and upon the authority of said firm as
experts in accounting and auditing.
The consolidated financial statements of Coho Energy Inc. as of December
31, 1996 and 1995, included in this Prospectus and elsewhere in this
Registration Statement have been audited by Arthur Andersen LLP, independent
public accountants, as indicated in their reports with respect thereto, and are
included herein in reliance upon the authority of said firm as experts in giving
said reports.
With respect to the unaudited interim financial information for the six
months ended June 30, 1997, Arthur Andersen LLP has applied limited procedures
in accordance with professional standards for a review of that information.
However, their separate report thereon states that they did not audit and they
do not express an opinion on that interim financial information. Accordingly,
the degree of reliance on their report on that information should be restricted
in light of the limited nature of the review procedures applied. In addition,
the accountants are not subject to the liability provisions of Section 11 of the
Securities Act for their report on the unaudited interim financial information
because that report is not a "report" or a "part" of the Registration Statement
prepared or certified by the accountants within the meaning of Sections 7 and 11
of the Act.
The evaluation of the Ryder Scott Company Petroleum Engineers, independent
consulting petroleum engineers, of Coho's proved reserves of crude oil and
natural gas and related information set forth herein and based on such
evaluation are included herein in reliance upon the authority of such firm as an
expert with respect to such matters.
AVAILABLE INFORMATION
Coho Energy, Inc. is subject to the informational requirements of the
Exchange Act, and, in accordance therewith, files reports, proxy statements and
other information with the Commission. Such reports, proxy statements and other
information may be inspected and copied at the offices of the Commission, Room
1024, Judiciary Plaza Building, 450 Fifth Street, N.W., Washington, D.C. 20549,
and the Regional Offices of the Commission at Citicorp Center, Suite 1400, 500
West Madison Street, Chicago, Illinois 60661, and Seven World Trade Center, New
York, New York 10048. Copies of such material can also be obtained at prescribed
rates from the Public Reference Section of the Commission at Room 1024,
Judiciary Plaza Building, 450 Fifth Street, N.W., Washington D.C. 20549. In
addition, such materials filed electronically by the Company with the Commission
are available at the Commission's World Wide Web site at http://www.sec.gov. The
Common Stock is traded on the Nasdaq Stock Market and such reports, proxy and
information statements, and other information, may be inspected at the Nasdaq
Stock Market, 1735 K Street, N.W., Washington, D.C. 20006.
Coho Energy, Inc. has filed with the Commission a Registration Statement on
Form S-3 (herein, together with all amendments and exhibits, referred to as the
"Registration Statement") under the Securities
52
<PAGE> 53
Act with respect to the securities offered hereby. This Prospectus does not
contain all of the information set forth in the Registration Statement and the
exhibits thereto, certain parts of which are omitted in accordance with the
rules and regulations of the Commission. Statements made in this Prospectus as
to the contents of any contract, agreement or other document referred to are not
necessarily complete; with respect to each such contract, agreement or other
document filed as an exhibit to the Registration Statement, reference is made to
the exhibit for a more complete description of the matter involved, and each
such statement is qualified in its entirety by such reference. The Registration
Statement and any amendments thereto, including exhibits filed as a part
thereof, are available for inspection and copying at the Commission's offices as
described above.
53
<PAGE> 54
GLOSSARY
Unless otherwise indicated, natural gas volumes are stated at the legal
pressure base of the State or area in which the reserves are located at 60
degrees Fahrenheit. The following definitions 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.
54
<PAGE> 55
INDEX OF FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
-------
<S> <C>
AUDITED CONSOLIDATED FINANCIAL STATEMENTS:
Report of Independent Public Accountants.................... F-2
Independent Auditors' Report................................ F-3
Consolidated Balance Sheets, December 31, 1995 and 1996..... F-4
Consolidated Statements of Earnings, Years Ended December
31, 1994, 1995 and 1996................................... F-5
Consolidated Statements of Shareholders' Equity, Years Ended
December 31, 1994, 1995
and 1996.................................................. F-6
Consolidated Statements of Cash Flows, Years Ended December
31, 1994, 1995 and 1996................................... F-7
Notes to Consolidated Financial Statements, Years Ended
December 31, 1994, 1995
and 1996.................................................. F-8
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:
Report of Independent Public Accountants.................... F-24
Condensed Consolidated Balance Sheet, June 30, 1997......... F-25
Condensed Consolidated Statements of Earnings, Six Months
Ended June 30, 1996 and
1997...................................................... F-26
Condensed Consolidated Statements of Cash Flows, Six Months
Ended June 30, 1996 and 1997.............................. F-27
Notes to Condensed Consolidated Financial Statements, Six
Months Ended June 30, 1997................................ F-28
AUDITED CONDENSED PARENT COMPANY FINANCIAL STATEMENTS:
Report of Independent Public Accountants.................... F-30
Independent Auditors' Report................................ F-31
Condensed Balance Sheets, December 31, 1995 and 1996........ F-32
Condensed Statements of Earnings, Years Ended December 31,
1994, 1995 and 1996....................................... F-33
Condensed Statements of Cash Flows, Years Ended December 31,
1994, 1995 and 1996....................................... F-34
Notes to Condensed Financial Statements, Years Ended
December 31, 1994, 1995 and 1996.......................... F-35
</TABLE>
F-1
<PAGE> 56
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, 1996 and 1995, and the related consolidated statements of earnings,
shareholders' equity, and cash flows for the years then ended. 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 audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the 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, 1996 and 1995, and the results of
their operations and their cash flows for the years then ended in conformity
with generally accepted accounting principles.
We have also audited the adjustments described in Note 2 that were applied
to restate the 1994 financial statements. In our opinion, such adjustments are
appropriate and have been properly applied.
Arthur Andersen LLP
Dallas, Texas
February 21, 1997
F-2
<PAGE> 57
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders of
Coho Energy, Inc.:
We have audited the accompanying consolidated statement of earnings,
shareholders' equity, and cash flows of Coho Energy, Inc. and subsidiaries for
the year ended December 31, 1994. These consolidated financial statements are
the responsibility of the Company's management. Our responsibility is to express
an opinion on these consolidated financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements of Coho Energy, Inc.
and subsidiaries referred to above present fairly, in all material respects, the
results of their operations and their cash flows for the year ended December 31,
1994, in conformity with generally accepted accounting principles.
KPMG Peat Marwick LLP
Dallas, Texas
February 24, 1995
F-3
<PAGE> 58
COHO ENERGY, INC.
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31
--------------------
1995 1996
-------- --------
<S> <C> <C>
Current assets
Cash and cash equivalents................................. $ 1,430 $ 1,864
Accounts receivable, principally trade.................... 5,049 11,884
Deferred income taxes..................................... 973 913
Investment in marketable securities....................... -- 1,962
Other current assets...................................... 869 995
Net assets of discontinued operations (note 2)............ 17,421 --
-------- --------
25,742 17,618
Property and equipment, at cost net of accumulated depletion
and depreciation, based on full cost accounting method
(note 3).................................................. 175,899 210,212
Other assets................................................ 2,401 2,211
-------- --------
$204,042 $230,041
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable, principally trade....................... $ 4,108 $ 5,752
Accrued liabilities and other payables.................... 6,933 5,043
Current portion of long term debt (note 4)................ 268 161
-------- --------
11,309 10,956
Long term debt, excluding current portion (note 4).......... 107,403 122,777
Deferred income taxes (note 5).............................. 11,009 14,842
-------- --------
129,721 148,575
-------- --------
Commitments and contingencies (note 9)
Shareholders' equity (note 8)
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 20,165,263 and 20,347,126
shares at December 31, 1995 and 1996, respectively..... 202 203
Additional paid-in capital................................ 82,278 83,516
Retained deficit.......................................... (8,159) (2,253)
-------- --------
Total shareholders' equity........................ 74,321 81,466
-------- --------
$204,042 $230,041
======== ========
</TABLE>
See accompanying Notes to Consolidated Financial Statements
F-4
<PAGE> 59
COHO ENERGY, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EARNINGS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-----------------------------
1994 1995 1996
------- ------- -------
<S> <C> <C> <C>
Operating revenues
Crude oil and natural gas production (note 10)............ $26,464 $40,903 $54,272
------- ------- -------
Operating expenses
Crude oil and natural gas production...................... 7,840 10,514 11,277
Taxes on oil and gas production........................... 1,532 1,943 2,598
General and administrative................................ 3,435 5,400 7,264
Restructuring expenses (note 12).......................... 973 -- --
Depletion and depreciation................................ 9,989 14,717 16,280
------- ------- -------
Total operating expenses.......................... 23,769 32,574 37,419
------- ------- -------
Operating income (loss)..................................... 2,695 8,329 16,853
------- ------- -------
Other income and expenses
Interest and other income................................. 218 92 1,012
Interest expense.......................................... (4,190) (8,140) (8,476)
------- ------- -------
(3,972) (8,048) (7,464)
------- ------- -------
Earnings (loss) from continuing operations before income
taxes..................................................... (1,277) 281 9,389
------- ------- -------
Income taxes (note 5)
Current (recovery) expense................................ (11) 457 (411)
Deferred (reduction) expense.............................. (292) (345) 3,894
------- ------- -------
(303) 112 3,483
------- ------- -------
Net earnings (loss) from continuing operations.............. (974) 169 5,906
Discontinued operations (note 2)
Income (loss) from discontinued marketing and
transportation operations (less applicable income tax
expense (benefit) of $(417) and $1,384 in 1994 and
1995, respectively..................................... (680) 1,611 --
------- ------- -------
Net earnings (loss)......................................... (1,654) 1,780 5,906
Dividends on preferred stock................................ (86) (944) --
------- ------- -------
Net earnings (loss) applicable to common stock.............. $(1,740) $ 836 $ 5,906
======= ======= =======
Earnings (loss) from continuing operations per common
share..................................................... $ (0.07) $ (.02) $ .29
======= ======= =======
Earnings (loss) per common share............................ $ (0.12) $ .05 $ .29
======= ======= =======
</TABLE>
See accompanying Notes to Consolidated Financial Statements
F-5
<PAGE> 60
COHO ENERGY, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT NUMBERS OF SHARES)
<TABLE>
<CAPTION>
NUMBER OF
COMMON ADDITIONAL RETAINED
SHARES COMMON PAID-IN EARNINGS
OUTSTANDING STOCK CAPITAL (DEFICIT) TOTAL
----------- ------ ---------- --------- -------
<S> <C> <C> <C> <C> <C>
Balance at December 31, 1993............... 14,007,302 $140 $51,394 $(7,255) $44,279
Issued on
(i) Acquisition of Interstate Natural
Gas Company....................... 2,775,000 28 13,847 -- 13,875
(ii) Exercise of Employee Stock
Options.......................... 623 -- 2 -- 2
Net Loss................................. -- -- -- (1,654) (1,654)
Dividends on preferred stock............. -- -- -- (86) (86)
---------- ---- ------- ------- -------
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
========== ==== ======= ======= =======
</TABLE>
See accompanying Notes to Consolidated Financial Statements
F-6
<PAGE> 61
COHO ENERGY, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
--------------------------------
1994 1995 1996
-------- -------- --------
<S> <C> <C> <C>
Cash flows from operating activities
Net earnings (loss)....................................... $ (1,654) $ 1,780 $ 5,906
Adjustments to reconcile net earnings (loss) to net cash
provided (used) by operating activities:
Depletion and depreciation............................. 10,074 15,876 16,280
Deferred income taxes.................................. (709) 653 3,894
Amortization of debt issue costs and other............. 217 918 271
Changes in:
Accounts receivable.................................... (1,233) (4,696) (6,983)
Inventory.............................................. 1,803 2,060 --
Accounts payable and accrued liabilities............... (6,260) (3,221) 40
Other assets........................................... (1,524) (872) (489)
Investment in marketable securities.................... -- -- (1,512)
Deferred income taxes and other current liabilities.... 287 337 (560)
Deferred hedging gain.................................. (1,683) -- --
-------- -------- --------
Net cash provided (used) by operating activities............ (682) 12,835 16,847
-------- -------- --------
Cash flows from investing activities
Property and equipment.................................... (19,503) (29,970) (52,384)
Changes in accounts payable and accrued liabilities
related to exploration and development................. 428 986 (902)
Cash included in net assets of discontinued operations.... -- (352) --
Proceeds on sale of property and equipment................ -- -- 21,476
Net non cash assets of acquired company (note 6)............ (12,549) -- --
-------- -------- --------
Net cash used in investing activities....................... (31,624) (29,336) (31,810)
-------- -------- --------
Cash flows from financing activities
Increase in long term debt................................ 37,567 19,140 52,600
Repayment of long term debt............................... (7,500) (1,822) (37,617)
Increase in gas storage loan.............................. -- 4,000 --
Repayment of gas storage loan............................. -- (5,000) --
Proceeds from exercised stock options..................... -- -- 414
Issuance of common stock.................................. 2 -- --
Dividends on preferred stock.............................. (86) -- --
-------- -------- --------
Net cash provided by financing activities................... 29,983 16,318 15,397
-------- -------- --------
Net increase (decrease) in cash and cash equivalents........ (2,323) (183) 434
Cash and cash equivalents at beginning of year.............. 3,936 1,613 1,430
-------- -------- --------
Cash and cash equivalents at end of year.................... $ 1,613 $ 1,430 $ 1,864
======== ======== ========
</TABLE>
See accompanying Notes to Consolidated Financial Statements
F-7
<PAGE> 62
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
(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 a 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
F-8
<PAGE> 63
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
properties are not amortized but are individually assessed for impairment. The
costs of any impaired properties are transferred to the balance of crude oil and
natural gas properties being depleted. Estimated future site restoration and
abandonment costs are charged to earnings at the rate of depletion of proved
crude oil and natural gas reserves and are included in accumulated depletion and
depreciation.
In accordance with the full cost method of accounting, the net capitalized
costs of crude oil and natural gas properties as well as estimated future
development, site restoration and abandonment costs are not to exceed their
related estimated future net revenues discounted at 10%, net of tax
considerations, plus the lower of cost or estimated fair value of unproved
properties.
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 test for impairment.
Other Assets
Other assets generally include deferred financing charges which are
amortized over the term of the related financing under the effective interest
rate 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
Earnings per common share 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) for the years
ended (1994 -- 14,190,029; 1995 -- 17,931,993; 1996 -- 20,457,398) after
consideration of preferred dividends.
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
F-9
<PAGE> 64
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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. Natural gas transportation revenues are recognized
based upon contractual terms and the related transported volume.
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 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, and
accordingly, its operations are segregated in the accompanying statements of
operations.
Revenues of the marketing and transportation segment were $7,965,000 and
$71,773,000 for 1994 and 1995, respectively. 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.
The components of net assets of discontinued operations included in the
Consolidated Balance Sheet as of December 31, 1995, were as follows:
<TABLE>
<S> <C>
Cash........................................................ $ 352
Accounts receivable......................................... 11,606
Inventory................................................... 2,555
Other current assets........................................ 1,682
Property, plant and equipment, net.......................... 21,054
Accounts payable............................................ (6,400)
Accrued liabilities......................................... (2,821)
Gas storage loan............................................ (4,000)
Other liabilities........................................... (5,318)
Deferred income taxes....................................... (1,289)
-------
$17,421
=======
</TABLE>
F-10
<PAGE> 65
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
3. PROPERTY AND EQUIPMENT
<TABLE>
<CAPTION>
DECEMBER 31
----------------------
1995 1996
--------- ---------
<S> <C> <C>
Crude oil and natural gas leases and rights including
exploration, development and equipment thereon, at cost... $ 278,197 $ 328,836
Accumulated depletion and depreciation...................... (102,298) (118,624)
--------- ---------
$ 175,899 $ 210,212
========= =========
</TABLE>
Overhead expenditures directly associated with exploration for and
development of crude oil and natural gas reserves have been capitalized in
accordance with the accounting policies of the Company. Such charges totalled
$1,371,000, $1,788,000 and $2,452,000 in 1994, 1995 and 1996, respectively.
During 1994, 1995 and 1996, 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 $6,254,000 and
$8,284,000 at December 31, 1995 and 1996, respectively, have been excluded from
costs subject to depletion. These costs are anticipated to be included in costs
subject to depletion during the next three to five years.
Depletion and depreciation expense per equivalent barrel of production was
$4.78, $4.38 and $4.55 in 1994, 1995 and 1996, respectively.
4. LONG TERM DEBT
<TABLE>
<CAPTION>
1995 1996
-------- --------
<S> <C> <C>
Revolving credit facility................................... $103,400 $120,500
Promissory notes............................................ 4,190 2,323
Other....................................................... 485 234
-------- --------
108,075 123,057
Unamortized discount on promissory notes.................... (404) (119)
Current maturities on long term debt........................ (268) (161)
-------- --------
$107,403 $122,777
======== ========
</TABLE>
Revolving Credit Facility
In August 1992, the Company established a revolving credit and term loan
facility with a group of international and domestic financial institutions. The
agreement, as amended and restated ("the Restated Credit Agreement"), provides a
maximum facility of $250 million for general corporate purposes. The amount
actually available to the Company ("Borrowing Base") is determined on the basis
of a discounted present value attributable to the Company's proved crude oil and
natural gas properties as determined from time to time by the Company's lenders.
As of December 31, 1996, the Borrowing Base was $150 million, with an additional
$20 million immediately available to the Company to provide bridge financing for
acquisitions. The Borrowing Base is redetermined semi-annually by the group of
financial institutions. Outstanding advances as of December 31, 1996, were
$120.5 million. The Company also has letters of credit aggregating $2.3 million
outstanding under the revolving credit facility as of December 31, 1996, to
secure the promissory notes, leaving $27.2 million in available borrowing under
the credit facility for general corporate purposes. The Restated Credit
Agreement permits advances and repayments until January 1, 2000, at which time
the outstanding advances will convert to a non-revolving term facility. The
repayment of all advances is
F-11
<PAGE> 66
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 Prime or a Eurodollar rate plus a maximum of 1.5% (currently
1.375%) 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. In January 2000, the loan converts to a non-revolver
term facility requiring quarterly repayments until fully repaid in 2003. 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.
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%) due 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). At December 31, 1996, the $2.3 million due in August 1997 remains
outstanding and is classified as long term debt due to the Company's intent to
borrow funds under the long term credit facility for such payments. The
remaining promissory notes are fully secured by letters of credit issued under
the Company's revolving credit.
Debt Repayments
Assuming the Borrowing Base for the revolving credit facility is not
reduced below the current loan balance outstanding and the maturity dates of the
loans are not extended, estimated aggregate principal repayments for each of the
next five years are as follows: ; 1997 -- $161,000; 1998 -- $57,000; 1999 --
$16,000; 2000 -- $35,092,000; 2001 -- $35,092,000 and $52,639,000 thereafter.
F-12
<PAGE> 67
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. INCOME TAXES
Deferred income taxes are recorded based upon differences between financial
statement and income tax basis of assets and liabilities. The tax effects of
these differences which give rise to deferred income tax assets and liabilities
at December 31, 1995 and 1996, were as follows:
<TABLE>
<CAPTION>
1995 1996
------- -------
<S> <C> <C>
DEFERRED TAX ASSETS
Net operating loss carryforwards.......................... $28,513 $26,087
Alternative minimum tax credit carryforwards.............. 758 1,866
Employee benefits......................................... 170 46
Other..................................................... 171 (46)
------- -------
Total gross deferred tax assets........................... 29,612 27,953
Less valuation allowance.................................. (3,679) (4,150)
------- -------
Net deferred tax assets................................... 25,933 23,803
------- -------
DEFERRED TAX LIABILITIES
Property and equipment, due to differences in depletion
and depreciation....................................... 35,969 37,732
------- -------
NET DEFERRED TAX LIABILITY.................................. $10,036 $13,929
======= =======
</TABLE>
The valuation allowance for deferred tax assets as of December 31, 1995 and
1996 includes $2,035,000 and $2,052,000, 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.
The following table reconciles the differences between recorded income tax
expense and the expected income tax expense obtained by applying the basic tax
rate to earnings (loss) before income taxes:
<TABLE>
<CAPTION>
1994 1995 1996
------- ---- -------
<S> <C> <C> <C>
Earnings (loss) before income taxes from continuing
operations............................................... $(1,277) $281 $ 9,389
======= ==== =======
Expected income tax expense (recovery) (statutory
rate -- 34%)............................................. $ (434) $ 95 $ 3,192
State taxes -- deferred.................................... (66) 232 (353)
Federal benefit of state taxes............................. 22 (78) 120
Change in valuation allowance.............................. 182 (168) 471
Other...................................................... (7) 31 53
------- ---- -------
$ (303) $112 $ 3,483
======= ==== =======
</TABLE>
F-13
<PAGE> 68
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
At December 31, 1996, the Company had the following income tax
carryforwards available to reduce future years' income for tax purposes:
<TABLE>
<CAPTION>
EXPIRES AMOUNT
--------- -------
<S> <C> <C>
Net operating loss carryforwards for federal income tax
purposes.................................................. 1997 $ 1,723
1998 5,432
1999 1,727
2000 4,253
2001 3,015
2002-2010 51,049
-------
$67,199
=======
Operating loss carryforwards for Canadian income tax
purposes.................................................. 1999-2003 $ 4,049
=======
Operating loss carryforwards for federal alternative minimum
tax purposes.............................................. 2008-2010 $15,356
=======
Federal alternative minimum tax credit carryforwards........ -- $ 1,866
=======
Operating loss carryforwards for Mississippi income tax
purposes.................................................. 2010 $ 9,690
=======
Operating loss carryforwards for Louisiana income tax
purposes.................................................. 2005-2011 $ 8,784
=======
</TABLE>
6. ACQUISITIONS
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 is $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).
On December 8, 1994, the Company acquired all of the capital stock of ING.
ING, through its subsidiaries, was a privately held natural gas producer,
gatherer and pipeline company operating in Louisiana and Mississippi.
Consideration paid by the Company for the acquisition of ING was $20 million
cash, 2,775,000 common shares of the Company and 161,250 shares of redeemable
preferred stock having an aggregate stated value of $16.1 million. The
acquisition of ING was accounted for using the purchase method. Also, see Note
2, "Discontinued Operations" regarding the disposition of the marketing and
transportation segment.
F-14
<PAGE> 69
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following unaudited pro forma information of the Company for the year
ended December 31, 1994, has been prepared assuming the ING acquisition occurred
on January 1, 1994. Such pro forma information is not necessarily indicative of
what actually could have occurred had the acquisition taken place on January 1,
1994 and excludes the restructuring charges described in note 12.
<TABLE>
<CAPTION>
1994
-------
<S> <C>
Revenues.................................................... $38,602
Net earnings from continuing operations..................... 599
Net earnings................................................ 1,175
Net earnings applicable to common stock..................... 150
Earnings per common share:
Net earnings from continuing operations................... $0.01
Net earnings.............................................. $0.01
</TABLE>
7. REDEEMABLE PREFERRED STOCK
The redeemable preferred stock issued in connection with the acquisition of
ING 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. A summary of the status of the
Company's stock option plans at December 31, 1994, 1995 and 1996 and changes
during the years then ended follows:
<TABLE>
<CAPTION>
1994 1995 1996
-------------------- -------------------- --------------------
WTD AVG WTD AVG WTD AVG
SHARES EX PRICE SHARES EX PRICE SHARES EX PRICE
--------- -------- --------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at January 1...... 1,212,230 $5.83 1,533,813 $5.63 1,700,313 $5.56
Granted..................... 380,000 4.99 166,500 4.98 202,000 5.19
Exercised................... (623) 3.48 -- -- (81,863) 5.05
Canceled.................... (57,794) 5.06 -- -- (4,666) 5.43
--------- ----- --------- ----- --------- -----
Outstanding at December 31.... 1,533,813 5.63 1,700,313 5.56 1,815,784 5.55
--------- ----- --------- ----- --------- -----
Exercisable at December 31.... 652,657 5.85 1,048,402 5.75 1,390,118 5.69
Available for grant at
December 31................. 243,170 39,670 118,836
</TABLE>
F-15
<PAGE> 70
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Significant option groups outstanding at December 31, 1996 and related
weighted average price and life information follows:
<TABLE>
<CAPTION>
WTD. AVG.
OPTIONS OPTIONS EXERCISE REMAINING
GRANT DATE OUTSTANDING EXERCISABLE PRICE LIFE (YEARS)
---------- ----------- ----------- --------- ------------
<S> <C> <C> <C> <C>
June 13, 1996....................... 12,000 -- $6.63 5
February 22, 1996................... 150,000 -- 5.13 6
January 8, 1996..................... 40,000 -- 5.00 6
September 25, 1995.................. 50,000 33,333 5.00 5
September 12, 1995.................. 58,000 19,338 5.00 6
August 3, 1995...................... 24,000 24,000 4.88 5
April 14, 1995...................... 32,500 10,834 5.00 5
December 4, 1994.................... 105,000 38,333 5.01 6
November 10, 1994................... 240,000 159,996 5.00 5
June 7, 1994........................ 115,741 115,741 5.65 4
March 28, 1994...................... 5,000 5,000 4.50 3
October 22, 1993.................... 406,089 406,089 6.00 4
September 29, 1993.................. 105,067 105,067 6.84 3
November 18, 1992................... 9,999 9,999 5.25 2
October 19, 1992.................... 462,388 462,388 5.61 2
</TABLE>
The weighted average fair value at date of grant for options granted during
1995 and 1996 was $2.25 and $2.21 per option, respectively. The fair value of
options at date of grant was estimated using the Black-Scholes model with the
following weighted average assumptions:
<TABLE>
<CAPTION>
1995 1996
----- -----
<S> <C> <C>
Expected life (years)................................ 5 5
Interest rate........................................ 6.28% 5.37%
Volatility........................................... 43.43% 38.79%
Dividend yield....................................... -- --
</TABLE>
Had compensation cost for these plans been determined consistent with FASB
Statement No. 123, the Company's pro forma net income and earnings per share
from continuing operations would have been as follows:
<TABLE>
<CAPTION>
1995 1996
---- ------
<S> <C> <C> <C>
Net income (loss) As reported................................. $169 $5,906
Pro forma................................... $(67) $5,625
Income (loss) per share As reported................................. $.01 $ .29
Pro forma................................... $ -- $ .27
</TABLE>
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 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 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
F-16
<PAGE> 71
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 January 1996, the Company was named a defendant in a lawsuit filed in
the Circuit Court of Jasper County, Mississippi. The lawsuit stems from the
accidental death of an employee of an independent contractor doing work for the
Company in late 1995. The plaintiffs are seeking compensatory and punitive
damages. A subsequent lawsuit was filed by another employer of the independent
contractor for injuries allegedly sustained during the accident.
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 position or results
of operations.
(b) The Company has leased (i) 33,261 square feet of office space in
Dallas, Texas under a non-cancelable lease extending through October 2000, (ii)
5,000 square feet of office space in Laurel, Mississippi under a non-cancelable
lease extending through June 2000, and (iii) various vehicles under
non-cancelable leases extending through March 1999. Rental expense totalled
$321,000, $487,000 and $694,000 in 1994, 1995 and 1996, respectively. Minimum
rentals payable under these leases for each of the next five years are as
follows: 1997 -- $674,000; 1998 -- $603,000; 1999 -- $556,000; 2000 -- $449,000
and 2001 -- $0. Total rentals payable over the remaining terms of the leases are
$2,282,000.
(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 $3,000,000, excluding
the Monroe gas field discussed below. A total of $928,000 has been included in
depletion and depreciation expense with respect to such costs as of December 31,
1996.
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 statues 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
$705,000 has been included in depletion and depreciation expense with respect to
such costs as of December 31, 1996.
(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
F-17
<PAGE> 72
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 most
of 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 $851,000.
(f) In conjunction with 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 5 occasions. The
number
of shares of Common Stock subject to registration rights as of December 31,
1996, is approximately 6,157,000.
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 $1,075,000; $441,000 and
$(5,908,000) for 1994, 1995 and 1996, respectively, resulting from these hedging
programs. At December 31, 1996, the Company has 15,000 Mmbtu per day of natural
gas production hedged for the months January through March 1997, at an average
price of $3.07 per Mmbtu. The Company has also entered into certain arrangements
which fix a minimum West Texas Intermediate ("WTI") price per barrel of $18.00
and a maximum WTI price of $21.30 for 4,000 barrels of oil production per day
for the period January 1, 1997 through June 30, 1997 and arrangements which fix
an average WTI price of $23.47 for 3,000 barrels of oil production per day for
the period January 1, 1997 through March 31, 1997. At December 31, 1995 and
1996, the Company had deferred hedging losses of $335,000 and $-0-,
respectively, attributable to crude oil and natural gas production.
The stated value of long term debt approximates fair market value since the
interest applicable to each instrument approximates market rates.
During the year ended December 31, 1996, two purchasers of Coho's crude oil
and natural gas, EOTT Energy Corp. ("EOTT") and Mid Louisiana Marketing Company
(formerly a wholly owned subsidiary sold on April 3, 1996 -- see note 2),
accounted for 66% and 15%, respectively, of Coho's receipt of operating
revenues. In 1994 and 1995 Amerada Hess Corporation ("Amerada") accounted for
64% and 66%, respectively, of Coho's receipt of operating revenues. Included in
accounts receivable is $1,767,000; $2,691,000 and $7,222,491 due from these
customers at December 31, 1994, 1995 and 1996, respectively.
F-18
<PAGE> 73
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
11. RELATED PARTY TRANSACTIONS
(a) Corporations controlled by certain directors, officers 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:
<TABLE>
<CAPTION>
1994 1995 1996
---- ---- ----
<S> <C> <C> <C>
Campco International Capital Ltd. (i)
Net crude oil and natural gas revenues.................... $94 $219 $243
Capital expenditures...................................... 96 77 101
Payable to (receivable from) CRI at the balance sheet
date................................................... 26 (3) (22)
</TABLE>
- ---------------
(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, 1996.
(c) Certain of the Company's hedging agreements are with an affiliate of
the Company, Morgan Stanley Capital Group, which owns over 10% of the Company's
outstanding common stock. Management of the Company believes that such
transactions are on similar terms as could be obtained from unrelated third
parties.
12. RESTRUCTURING EXPENSES
Subsequent to the acquisition of ING, the Company reviewed the operations
of the combined companies and identified opportunities to reduce administrative
overhead and operating costs beyond the scope contemplated when the acquisition
was made. In conjunction with the development and implementation of a plan to
effect these cost savings, the Company has recorded a charge of $2,494,000
($1,521,000 of which is included in discontinued operations -- see note 2) in
the 1994 consolidated financial statements representing employee benefits,
severance and outplacement service payments for 23 executive and administrative
positions and 19 operating positions (primarily pipeline positions). During 1995
and 1996, the Company effectuated all 42 terminations and paid termination
benefits totalling $2,062,000 and $412,000, respectively.
13. CASH FLOW INFORMATION
Supplemental cash flow information is presented below:
<TABLE>
<CAPTION>
1994 1995 1996
------ ------- ------
<S> <C> <C> <C>
Cash paid (received) during the period
Interest.............................................. $4,118 $ 7,574 $8,259
Income taxes.......................................... $ (11) $(1,131) $ 478
</TABLE>
F-19
<PAGE> 74
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
14. CANADIAN ACCOUNTING PRINCIPLES
These financial statements have been prepared in conformity with generally
accepted accounting principles ("GAAP") as presently established in the United
States. These principles differ in certain respects from those applicable in
Canada. These differences would have affected net earnings (loss) as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
---------------------------
1994 1995 1996
------- ------ ------
<S> <C> <C> <C>
Net earnings (loss) based on US GAAP.................... $(1,654) $1,780 $5,096
Adjustment to depletion based on difference in carrying
value of oil and gas properties related to:
ING acquisition (i)................................... 55 576 556
Business combination with Odyssey Exploration, Inc.
in 1990............................................ (211) (198) (178)
Application of Canadian full cost ceiling test........ (569) (535) (482)
Deferred tax effect of adjustment above................. 246 53 35
------- ------ ------
Net earnings (loss) based on Canadian GAAP.............. $(2,133) $1,676 $5,027
======= ====== ======
Net earnings (loss) per common share based on Canadian
GAAP.................................................. $ (0.15) $ 0.09 $ 0.25
======= ====== ======
</TABLE>
- ---------------
(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.
The effect on the consolidated balance sheets of the differences between
United States and Canadian GAAP is as follows:
<TABLE>
<CAPTION>
UNDER
AS INCREASE CANADIAN
REPORTED (DECREASE) GAAP
-------- ---------- --------
<S> <C> <C> <C>
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
DECEMBER 31, 1995
Property and Equipment............................. $175,899 $ 2,295 $178,194
Deferred Income Taxes.............................. 11,009 (4,733) 6,276
Shareholder's Equity............................... 74,321 7,029 81,350
</TABLE>
F-20
<PAGE> 75
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
15. SUPPLEMENTARY QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH TOTAL
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
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
Net earnings per share..................... $ .05 $ .06 $ .06 $ .12 $ .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
Net 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
======= ======= ======= ======= =======
1994
Operating revenues......................... $ 5,814 $ 6,280 $ 6,464 $ 7,906 $26,464
Operating income........................... 766 824 968 137 2,695
Income (loss) from continuing operations... 68 (24) (85) (933) (974)
Income (loss) from discontinued
operations.............................. -- -- -- (680) (680)
Net earnings (loss)........................ 68 (24) (85) (1,613) (1,654)
Net earnings (loss) per share:
Continuing operations................... $ 0.00 $ 0.00 $ (0.01) $ (0.07) $ (0.07)
Discontinued operations................. -- -- -- (0.05) (0.05)
------- ------- ------- ------- -------
Net income (loss) per share............. $ 0.00 $ 0.00 $ (0.01) $ (0.12) $ (0.12)
======= ======= ======= ======= =======
</TABLE>
The per share figures are computed based on the weighted average number of
shares outstanding for each period shown.
16. SUPPLEMENTAL INFORMATION RELATED TO OIL AND GAS ACTIVITIES
(a) Costs Incurred
Costs incurred for property acquisition, exploration and development
activities were as follows:
<TABLE>
<CAPTION>
1994 1995 1996
-------- -------- --------
<S> <C> <C> <C>
Property acquisitions
Proved............................................. $ 52,277 $ 7,294 $ 1,139
Unproved........................................... 692 2,253 986
Exploration.......................................... 1,099 3,378 6,528
Development.......................................... 16,469 19,194 41,091
Other................................................ 305 677 894
-------- -------- --------
$ 70,842 $ 32,796 $ 50,638
======== ======== ========
Property and equipment, net of accumulated
depletion.......................................... $157,170 $175,899 $210,212
======== ======== ========
</TABLE>
F-21
<PAGE> 76
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.
<TABLE>
<CAPTION>
RESERVE QUANTITIES
------------------
OIL GAS
(MBBLS) (MMCF)
------- -------
<S> <C> <C>
Estimated reserves at December 31, 1993..................... 24,892 14,064
Revisions of previous estimates............................. 1,053 (205)
Purchase of reserves in place............................... 373 86,928
Extensions and discoveries.................................. 3,174 --
Production.................................................. (1,977) (670)
------ -------
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
====== =======
Proved developed reserves at December 31,
1994................................................... 19,800 87,166
1995................................................... 23,478 94,878
1996................................................... 24,089 98,936
</TABLE>
(c) Standardized Measure of Oil and Gas Reserves (unaudited)
Standardized Measure of Discounted Future Net Cash Flows and Changes
Therein Relating to Proved Reserves.
The following standardized measure of discounted future net cash flows was
computed in accordance with the rules and regulations of the Securities and
Exchange Commission and 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.
F-22
<PAGE> 77
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:
<TABLE>
<CAPTION>
1994 1995 1996
--------- --------- ----------
<S> <C> <C> <C>
Future cash inflows............................. $ 511,689 $ 766,196 $1,174,356
Future production costs......................... (196,374) (234,309) (301,619)
Future development costs........................ (34,095) (33,824) (52,769)
--------- --------- ----------
Future net cash flows before income taxes....... 281,220 498,063 819,968
Annual discount at 10%.......................... (116,811) (229,445) (402,885)
--------- --------- ----------
Present value of future net cash flows before
income taxes ("Present Value of Proved
Reserves").................................... 164,409 268,618 417,083
Future income taxes discounted at 10%........... (29,390) (43,679) (79,864)
--------- --------- ----------
Standardized measure of discounted future net
cash flows.................................... $ 135,019 $ 224,939 $ 337,219
========= ========= ==========
December 31 West Texas Intermediate posted price
($ per Bbl)................................... $ 16.00 $ 18.00 $ 25.25
Estimated December 31 Company average realized
price
$/Bbl......................................... $ 13.01 $ 15.69 $ 22.02
$/Mcf......................................... $ 1.58 $ 2.54 $ 3.53
</TABLE>
The following are the significant sources of changes in discounted future
net cash flows relating to proved reserves:
<TABLE>
<CAPTION>
1994 1995 1996
-------- -------- --------
<S> <C> <C> <C>
Crude oil and natural gas sales, net of production
costs............................................ $(17,092) $(28,446) $(46,305)
Net changes in anticipated prices and production
costs............................................ 29,548 93,551 128,960
Extensions and discoveries, less related costs..... 11,002 24,281 74,560
Changes in estimated future development costs...... (9,474) (10,581) (2,580)
Development costs incurred during the period....... 16,469 19,194 6,321
Net change due to sales and purchase of reserves in
place............................................ 50,741 10,409 1,108
Accretion of discount.............................. 8,111 16,441 26,862
Revision of previous quantity estimates............ 6,086 11,768 (1,643)
Net changes in income taxes........................ (20,824) (14,289) (36,185)
Changes in timing of production and other.......... (12,091) (32,408) (38,818)
-------- -------- --------
Net increase (decrease)............................ 62,476 89,920 112,280
Beginning of year.................................. 72,543 135,019 224,939
-------- -------- --------
End of year........................................ $135,019 $224,939 $337,219
======== ======== ========
</TABLE>
F-23
<PAGE> 78
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Shareholders of Coho Energy, Inc.:
We have reviewed the accompanying condensed consolidated balance sheet of
Coho Energy Inc. (a Texas corporation) as of June 30, 1997, and the related
condensed consolidated statements of earnings and cash flows for the six-month
period then ended. These financial statements are the responsibility of the
company's management.
We conducted our review in accordance with standards established by the
American Institute of Certified Public Accountants. A review of interim
financial information consists principally of applying analytical procedures to
financial data and making inquiries of persons responsible for financial and
accounting matters. It is substantially less in scope than an audit conducted in
accordance with generally accepted auditing standards, the objective of which is
the expression of an opinion regarding the financial statements taken as a
whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that
should be made to the accompanying financial statements referred to above for
them to be in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
August 14, 1997
F-24
<PAGE> 79
COHO ENERGY, INC.
AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEET
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
ASSETS
<TABLE>
<CAPTION>
JUNE 30,
1997
-----------
(UNAUDITED)
<S> <C>
Current assets
Cash and cash equivalents................................. $ 936
Accounts receivable, principally trade.................... 7,908
Deferred income taxes..................................... 913
Other current assets...................................... 1,002
--------
10,759
Property and equipment, at cost net of accumulated depletion
and depreciation, based on full cost accounting method
(note 2).................................................. 234,545
Other assets................................................ 1,980
--------
$247,284
========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable, principally trade....................... $ 7,167
Accrued liabilities and other payables.................... 5,649
Current portion of long term debt......................... 61
--------
12,877
Long term debt excluding current portion.................... 132,350
Deferred income taxes....................................... 16,829
--------
162,056
--------
Commitments and contingencies (note 4)
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 and Outstanding 20,443,899
shares................................................. 204
Additional paid-in capital................................ 84,092
Retained earnings......................................... 932
--------
Total shareholders' equity................................ 85,228
--------
$247,284
========
</TABLE>
See accompanying Notes to Condensed Consolidated Financial Statements
F-25
<PAGE> 80
COHO ENERGY, INC.
AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30
------------------
1996 1997
------- -------
<S> <C> <C>
Operating revenues
Net crude oil and natural gas production.................. $25,305 $29,521
Operating expenses
Crude oil and natural gas production...................... 5,541 6,113
Taxes on crude oil and natural gas production............. 1,266 1,070
General and administrative................................ 3,299 3,623
Depletion and depreciation................................ 7,885 8,960
------- -------
Total operating expenses.......................... 17,991 19,766
------- -------
Operating income............................................ 7,314 9,755
------- -------
Other income and expenses
Interest and other income................................. 510 149
Interest expense.......................................... (4,233) (4,682)
------- -------
(3,723) (4,533)
------- -------
Earnings from operations before income taxes................ 3,591 5,222
Income taxes expense........................................ 1,453 2,037
------- -------
Net earnings applicable to common stock..................... $ 2,138 $ 3,185
======= =======
Earnings per common share (note 3).......................... $ 0.11 $ 0.15
======= =======
</TABLE>
See accompanying Notes to Condensed Consolidated Financial Statements
F-26
<PAGE> 81
COHO ENERGY, INC.
AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30
--------------------
1996 1997
-------- --------
<S> <C> <C>
Cash flows from operating activities
Net earnings.............................................. $ 2,138 $ 3,185
Adjustments to reconcile net earnings to net cash
provided by operating activities:
Depletion and depreciation........................... 7,885 8,960
Deferred income taxes................................ 1,345 1,987
Amortization of debt issue costs and other items..... 425 275
Changes in operating assets and liabilities:
Accounts receivable and other assets................. (2,265) 4,019
Accounts payable and accrued liabilities............. 801 (3,067)
Investment in marketable securities............... -- 1,962
-------- --------
Net cash provided by operating activities................. 10,329 17,321
-------- --------
Cash flows from investing activities
Property and equipment.................................... (24,199) (33,294)
Changes in accounts payable and accrued liabilities
related to exploration and development................. 2,903 5,089
Net proceeds from sale of marketing and transportation
operations................................................ 21,509 --
-------- --------
Net cash provided by (used in) investing activities......... 213 (28,205)
-------- --------
Cash flows from financing activities
Increase in long term debt................................ 15,107 17,000
Repayment of long term debt............................... (26,706) (7,621)
Proceeds from exercise of stock options................... 36 577
-------- --------
Net cash provided by (used in) financing activities......... (11,563) 9,956
-------- --------
Net increase (decrease) in cash and cash equivalents........ (1,021) (928)
Cash and cash equivalents at beginning of period............ 1,430 1,864
-------- --------
Cash and cash equivalents at end of period.................. $ 409 $ 936
======== ========
Cash paid (received) during the period for:
Interest.................................................. $ 4,600 $ 4,312
======== ========
Income taxes.............................................. $ 533 $ 639
======== ========
</TABLE>
See accompanying Notes to Condensed Consolidated Financial Statements
F-27
<PAGE> 82
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SIX MONTHS ENDED JUNE 30, 1997
(TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED)
(UNAUDITED)
1. BASIS OF PRESENTATION
General
The accompanying condensed consolidated financial statements of Coho
Energy, Inc. (the "Company") have been prepared without audit, in accordance
with the rules and regulations of the Securities and Exchange Commission and do
not include all disclosures normally required by generally accepted accounting
principles or those normally made in annual reports on Form 10-K. All material
adjustments, consisting only of normal recurring accruals, which, in the opinion
of management, were necessary for a fair presentation of the results for the
interim periods, have been made. The results of operations for the six month
period ended June 30, 1997 are not necessarily indicative of the results to be
expected for the full year. The condensed consolidated financial statements
should be read in conjunction with the notes to the financial statements, that
are included herein as part of the Company's annual report on Form 10-K for the
year ended December 31, 1996.
2. PROPERTY AND EQUIPMENT
<TABLE>
<CAPTION>
JUNE 30,
1997
---------
<S> <C>
Crude oil and natural gas leases and rights including
exploration, development and equipment thereon, at cost... $ 362,129
Accumulated depletion and depreciation...................... (127,584)
---------
$ 234,545
=========
</TABLE>
Overhead expenditures directly associated with exploration and development
of crude oil and natural gas reserves have been capitalized in accordance with
the accounting policies of the Company. Such charges totalled $1,201,000 and
$1,454,000 for the six months ended June 30, 1996 and 1997, respectively.
During the six months ended June 30, 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.
At June 30, 1997, unproved crude oil and natural gas properties totalling
$6,166,000, were excluded from costs subject to depletion. These costs are
anticipated to be included in costs subject to depletion during the next three
to five years.
3. EARNINGS PER SHARE
Earnings per share have been calculated based on the weighted average
number of shares outstanding (including common stock plus, when their effect is
dilutive, common stock equivalents consisting of stock options) for the six
months ended June 30, 1996 and 1997 of 20,336,803 and 20,991,484, respectively.
4. COMMITMENTS AND CONTINGENCIES
The Company is a defendant in various legal proceedings and claims which
arise in the normal course of business. Based on discussions with legal counsel,
the Company does not believe that the ultimate resolution of such actions will
have a significant effect on the Company's financial position; however, an
unfavorable outcome could have a material adverse effect on the current year
results.
Like other crude oil and natural gas producers, the Company's operations
are subject to extensive and rapidly changing federal and state environmental
regulations governing emissions into the atmosphere, waste
F-28
<PAGE> 83
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
water discharges, solid and hazardous waste management activities and site
restoration and abandonment activities. The Company does not believe that any
potential liability, in excess of amounts already provided for, would have a
significant effect on the Company's financial position.
The Company has entered into certain financial arrangements which act as a
hedge against price fluctuations in future crude oil production. Gains and
losses on these transactions are recorded in earnings when the future production
sale occurs. The Company has 920,000 Mmbtu of natural gas production hedged over
the period from July through September 1997, at an average price of $2.35 per
Mmbtu. The Company has also entered into certain arrangements which fixes a
minimum West Texas Intermediate ("WTI") price per barrel of $19.00 and a maximum
WTI price per barrel of $23.90 for 4,000 barrels of oil production per day
through December 31, 1997.
F-29
<PAGE> 84
REPORT OF 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
February 21, 1997
F-30
<PAGE> 85
INDEPENDENT AUDITORS' REPORT ON SUPPLEMENTARY INFORMATION
The Board of Directors
Coho Energy, Inc.:
We have audited and reported separately herein on the consolidated
financial statements of Coho Energy, Inc. and subsidiaries for the year ended
December 31, 1994.
Our audit was made for the purpose of forming an opinion on the basic
financial statements of Coho Energy, Inc. taken as a whole. The supplementary
information included in Schedule III is presented for purposes of additional
analysis and is not a required part of the basic consolidated financial
statements. Such information has been subjected to the auditing procedures
applied in the audit of the basic consolidated financial statements and, in our
opinion, is fairly stated in all material respects in relation to the basic
consolidated financial statements taken as a whole.
KPMG PEAT MARWICK LLP
Dallas, Texas
February 24, 1995
F-31
<PAGE> 86
COHO ENERGY, INC.
AND SUBSIDIARIES
SCHEDULE III
CONDENSED FINANCIAL INFORMATION -- PARENT ONLY
The following presents the condensed balance sheets as of December 31, 1996
and 1995 and statements of earnings and statements of cash flows for Coho
Energy, Inc., the parent company, for the years ended December 31, 1996, 1995
and 1994.
COHO ENERGY, INC.
(PARENT)
CONDENSED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31
------------------
1995 1996
------- -------
<S> <C> <C>
CURRENT ASSETS
CASH AND CASH EQUIVALENTS................................. $ 3 $ 304
DUE FROM SUBSIDIARIES..................................... 7,035 7,535
------- -------
7,038 7,839
INVESTMENTS IN SUBSIDIARIES, at equity...................... 67,303 73,632
------- -------
$74,341 $81,471
======= =======
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable.......................................... $ 20 $ 5
------- -------
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 20,165,263 and 20,347,126 shares at December 31,
1995 and 1996, respectively........................... 202 203
Additional paid-in capital................................ 82,278 83,516
Retained earnings (deficit)............................... (8,159) (2,253)
------- -------
Total shareholders' equity........................ 74,321 81,466
------- -------
$74,341 $81,471
======= =======
</TABLE>
See accompanying Notes to Condensed Financial Information
F-32
<PAGE> 87
SCHEDULE III
COHO ENERGY, INC.
(PARENT)
CONDENSED STATEMENT OF EARNINGS
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
DECEMBER 31
-----------------------------
1994 1995 1996
------- ------- -------
<S> <C> <C> <C>
OPERATING EXPENSES
General and administrative................................ $ 409 $ 428 $ 423
EQUITY IN (INCOME) LOSS OF SUBSIDIARIES..................... 1,245 (2,208) (6,329)
------- ------- -------
NET INCOME (LOSS)........................................... (1,654) 1,780 5,906
DIVIDENDS ON PREFERRED STOCK................................ (86) (944) (--)
------- ------- -------
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK................ $(1,740) $ 836 $ 5,906
======= ======= =======
INCOME (LOSS) PER COMMON SHARE.............................. $ (0.12) $ 0.05 $ .29
======= ======= =======
</TABLE>
See accompanying Notes to Condensed Financial Information
F-33
<PAGE> 88
SCHEDULE III
COHO ENERGY, INC.
(PARENT)
CONDENSED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-----------------------------
1994 1995 1996
------- ------- -------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)......................................... $(1,654) $ 1,780 $ 5,906
Adjustments to reconcile net income (loss) to net provided
by operating activities:
Equity in (income) loss of subsidiaries................ 1,245 (2,208) (6,329)
Increase (decrease) in accounts payable................ 88 (94) (15)
------- ------- -------
Net cash used in operating activities....................... (321) (522) (438)
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Advances from (to) subsidiaries........................... 463 466 325
------- ------- -------
Net cash provided by (used in) investing activities......... 463 466 325
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of common stock.................................. 2 -- --
Proceeds from stock options exercised..................... -- -- 414
Dividends on preferred stock.............................. (86) -- --
------- ------- -------
Net cash provided by (used in) financing activities......... (84) -- 414
------- ------- -------
Increase (decrease) in cash................................. 58 (56) 301
Cash, at beginning of period................................ 1 59 3
------- ------- -------
Cash, at end of period...................................... $ 59 $ 3 $ 304
======= ======= =======
</TABLE>
See accompanying Notes to Condensed Financial Information
F-34
<PAGE> 89
SCHEDULE III
COHO ENERGY, INC.
(PARENT)
NOTES TO CONDENSED FINANCIAL INFORMATION
FOR THE YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
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, 1996.
2. COMMITMENTS AND CONTINGENCIES
The Registrant has guaranteed $122,800,000 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, 1996, the Company was in
compliance with all debt covenants.
3. REDEEMABLE PREFERRED STOCK
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.
4. NON CASH INVESTING AND FINANCING ACTIVITIES
On December 8, 1994, the Company and CRI acquired all of the capital stock
of Interstate Natural Gas Company. The Company paid the following non-cash
amounts for its share of the acquisition cost.
<TABLE>
<S> <C>
Common Stock (2,775,000 shares)............................. $13,875,000
Preferred Stock (161,250 shares)............................ 16,125,000
-----------
$30,000,000
===========
</TABLE>
F-35
<PAGE> 90
(This page intentionally left blank)
<PAGE> 91
ANNEX A
February 6, 1997
Coho Energy, Inc.
14785 Preston Road, Suite 860
Dallas, Texas 75240
Gentlemen:
At your request, we have reviewed Coho Energy, Inc.'s (Coho) estimates of
remaining recoverable proved reserves and estimated future cashflow as of
December 31, 1996 attributable to the interests owned by its three wholly owned
subsidiaries, Coho Resources, Inc., Coho Exploration, Inc. and Coho Louisiana
Production Company (CLPC). Coho's reserve estimates were prepared based upon
Securities and Exchange Commission (SEC) guidelines. When compared in total,
Coho's reserve estimates do not differ materially from the estimates prepared by
Ryder Scott. The properties reviewed by Ryder Scott Company Petroleum Engineers
(Ryder Scott) consisted of various fields in Louisiana, Mississippi, Texas, and
Offshore Texas. The estimated net proved reserves, estimated future net revenue
and discounted future net revenue as of December 31, 1996 attributable to
interests in the properties as estimated by Coho and reviewed by Ryder Scott,
are summarized below.
ESTIMATED NET REMAINING PROVED RESERVES
ATTRIBUTABLE TO LEASEHOLD AND ROYALTY INTERESTS
FOR PROPERTIES REVIEWED BY RYDER SCOTT
AS OF DECEMBER 31, 1996
<TABLE>
<CAPTION>
PROVED NET ESTIMATED FUTURE NET INCOME
REMAINING RESERVES M$
------------------------- ----------------------------
OIL/CONDENSATE GAS DISCOUNTED
FIELD MBARRELS MMCF UNDISCOUNTED AT 10%
----- -------------- ------- ------------- -----------
<S> <C> <C> <C> <C>
Laurel...................................... 14,573 463 196,224 102,547
Monroe...................................... 0 97,545 289,589 119,423
Summerland.................................. 5,849 0 68,681 34,786
Martinville................................. 4,490 651 75,628 46,689
Soso........................................ 5,640 0 75,940 41,934
California.................................. 102 8,573 30,416 18,703
North Padre................................. 0 5,365 14,980 12,396
Bentonia.................................... 784 0 10,442 6,195
Glazier..................................... 574 0 7,669 4,055
Brookhaven.................................. 2,803 316 49,593 29,663
AMWAR (Frio)................................ 7 219 805 692
------ ------- ------- -------
Total....................................... 34,822 113,132 819,967 417,083
Developed Reserves.......................... 24,089 98,936 624,321 299,247
Undeveloped Reserves........................ 10,733 14,196 195,646 117,836
</TABLE>
Oil and condensate volumes are expressed in standard 42 gallon barrels. All
gas volumes are expressed in millions of cubic feet (MMCF) at the official
temperature and pressure bases of the areas where the gas reserves are located.
The future net revenue is after the deduction of production taxes and
costs. The costs are comprised of production taxes, the normal direct costs of
operating the wells, ad valorem taxes, recompletion costs, and development
costs. The future undiscounted net revenue is before the deduction of state and
federal income taxes and general administrative overhead, and has not been
adjusted for outstanding loans which may exist nor does it include any
adjustment for cash on hand or undistributed income.
A-1
<PAGE> 92
Ryder Scott has made no attempt to account for any accumulated gas
production imbalances that may exist.
The gas reserves shown for the California Field also includes gas reserves
for the Round Prairie Field. These gas reserves have been established by the
drilling of several wells which were never produced due to being non-commercial
at the time. Since new wells must be drilled to produce these reserves, they are
placed in the undeveloped category. The gas contains a large amount of hydrogen
sulfide and must be processed through a sulfur recovery plant to be marketable.
Negotiations are currently underway to obtain space in an existing plant in
order to market the gas and associated sulfur reserves. The anticipated future
income from sulfur is included in the income quantities presented herein,
although no sulfur reserves are shown.
The proved reserves presented in this report comply with the Securities and
Exchange Commission (SEC) Regulation S-X Part 210.4-10 Sec. (a) as clarified by
subsequent Commission Staff Accounting Bulletins, and are based on the following
definitions and criteria:
Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from
known reservoirs under existing conditions. Reservoirs are considered
proved if economic producability is supported by actual production or
formation tests. In certain instances, proved reserves are assigned on the
basis of a combination of core analysis and electrical and other type logs
which indicate the reservoirs are analogous to reservoirs in the same field
which are producing or have demonstrated the ability to produce on a
formation test. The area of a reservoir considered proved includes (1) that
portion delineated by drilling and defined by fluid contacts, if any, and
(2) the adjoining portions not yet drilled that can be reasonably judged as
economically productive on the basis of available geological and
engineering data. In the absence of data on fluid contacts, the lowest
known structural occurrence of hydrocarbons controls the lower proved limit
of the reservoir. Proved reserves are estimates of hydrocarbons to be
recovered from a given date forward. They may be revised as hydrocarbons
are produced and additional data become available. Proved natural gas
reserves are comprised of non-associated, associated, and dissolved gas. An
appropriate reduction in gas reserves has been made for the expected
removal of natural gas liquids, for lease and plant fuel, and the exclusion
of non-hydrocarbon gases if they occur in significant quantities and are
removed prior to sale. Reserves that can be produced economically through
the application of improved recovery techniques are included in the proved
classification when these qualifications are met: (1) successful testing by
a pilot project or the operation of an installed program in the reservoir
provides support for the engineering analysis on which the project or
program was based, and (2) it is reasonably certain the project will
proceed. Improved recovery includes all methods for supplementing natural
reservoir forces and energy, or otherwise increasing ultimate recovery from
a reservoir, including (1) pressure maintenance, (2) cycling, and (3)
secondary recovery in its original sense. Improved recovery also includes
the enhanced recovery methods of thermal, chemical flooding, and the use of
miscible and immiscible displacement fluids. Estimates of proved reserves
do not include crude oil, natural gas, or natural gas liquids being held in
underground storage. Depending on the status of development, these proved
reserves are further subdivided into:
(i) "developed reserves" which are those proved reserves reasonably
expected to be recovered through existing wells with existing equipment
and operating methods, including (a) "developed producing reserves"
which are those proved developed reserves reasonably expected to be
produced from existing completion intervals now open for production in
existing wells, and (b) "developed non-producing reserves" which are
those proved developed reserves which exist behind the casing of
existing wells which are reasonably expected to be produced through
these wells in the predictable future where the cost of making such
hydrocarbons available for production should be relatively small
compared to the cost of a new well; and
(ii) "undeveloped reserves" which are those proved reserves reasonably
expected to be recovered from new wells on undrilled acreage, from
existing wells where a relatively large expenditure is required, and
from acreage for which an application of fluid injection or other
improved recovery technique is contemplated where the technique has been
proved effective by actual tests in the area in the same reservoir.
Reserves from undrilled acreage are limited to those drilling units
offsetting
A-2
<PAGE> 93
productive units that are reasonably certain of production when drilled.
Proved reserves for other undrilled units are included only where it can
be demonstrated with reasonable certainty that there is continuity of
production from the existing productive formation.
Because of the direct relationship between volumes of proved undeveloped
reserves and development plans, we include in the proved undeveloped category
only reserves assigned to undeveloped locations that we have been assured will
definitely be drilled and reserves assigned to the undeveloped portions of
secondary or tertiary projects which we have been assured will definitely be
developed.
Coho furnished us with crude oil and natural gas prices in effect at
December 31, 1996 and, in accordance with SEC regulations, Coho states that
these prices were held constant to depletion of the properties in their cashflow
projections. We were advised that the prices included in the report were based
on the following posted prices for December 1996:
<TABLE>
<CAPTION>
DECEMBER 1996
POSTED PRICE
$/BARREL
-------------
<S> <C>
Mississippi Light Sweet................................. 24.25
Mississippi Light Sour.................................. 21.75
Mississippi Heavy Sour.................................. 20.45
</TABLE>
The price Coho receives will vary from the posted prices from property to
property, due principally to variations in API gravity and contractual
arrangements with the purchaser.
Coho advises that year end natural gas prices, without escalation over the
producing life of the reserves, were used in the evaluation of natural gas
properties. For the largest natural gas property, Monroe Field in Louisiana,
CLPC furnished us a price of $3.58 per MCF. Actual future prices may vary
significantly from these December 1996 prices. Therefore, quantities of reserves
actually recovered may differ significantly from the estimated quantities
presented in this report.
Operating costs for the leases and wells in this report are based on the
operating expense reports of Coho and include only those costs directly
applicable to the leases or wells. Development costs are based on authorizations
for expenditure for the proposed work or current cost estimates for similar
projects. The current operating and development costs were held constant
throughout the life of the properties. Abandonment costs for these onshore
properties were not considered because of their relative insignificance.
Ryder Scott has not prepared independent projections of future production
and income, but has relied on those prepared by Coho utilizing the data
described herein without review.
No deduction was made for indirect costs such as general administration and
overhead expenses, loan repayments, interest expenses, and exploration and
development prepayments.
Review Procedure and Opinion
In performing our review, we have relied upon data furnished by Coho with
respect to property interests owned, production and well tests from examined
wells, geological structural and isopach maps, well logs, core analyses, and
pressure measurements. These data were accepted as authentic and sufficient for
determining the reserves unless, during the course of our examination a matter
of question came to our attention in which case the data were not accepted until
all questions were satisfactorily resolved. Our review included such tests and
procedures as we considered necessary under the circumstances to render the
conclusions set forth herein.
On an aggregate basis, Ryder Scott's estimates of remaining proved reserves
for the properties reviewed did not differ materially from Coho's estimates;
however, in certain fields there were proved reserve differences in excess of 10
percent. However, in Coho's three largest properties, Laurel, Summerland, and
Monroe, Ryder Scott's and Coho's reserve estimates were within 10 percent. These
three fields comprise in excess of 70 percent of Coho's reserves on a barrel of
oil equivalent basis. There were also instances where differences for individual
reservoirs or wells within a field existed; however, there generally were
compensating factors such as being higher in one reservoir or well and lower in
another. These variances were due to a difference in interpretation of data.
A-3
<PAGE> 94
In our opinion, Coho's estimates of the proved reserves, future net revenue
and discounted future net revenue for its interests in the properties reviewed
are, in the aggregate, reasonable and were prepared in accordance with generally
accepted engineering and evaluation principles, and we found no bias in the
utilization and analysis of data.
Certain technical personnel of Coho are responsible for the preparation of
reserve estimates on new properties and for the preparation of revised
estimates, when necessary, on old properties. These personnel assembled the
necessary data and maintained the data and work papers in an orderly manner. We
consulted with these technical personnel and had access to their work papers and
supporting data in the course of our review.
Reserve Estimates
The reserves for the properties that we reviewed were estimated by
performance methods, analogy or the volumetric method. The reserve estimates by
the performance method utilized extrapolations of various historical data in
those cases where such data were definitive. Reserves were estimated by the
volumetric method in those cases where there were inadequate historical data to
establish a definitive trend or where the use of production performance data as
a basis for the reserve estimates was considered to be inappropriate.
The reserves presented herein, as estimated by Coho and reviewed by Ryder
Scott, are estimates only and should not be construed as being exact quantities.
They may or may not be actually recovered. Moreover, estimates of reserves may
increase or decrease as a result of future operations.
The future production rates from properties now on production may be more
or less than estimated because of changes in market demand or allowables set by
regulatory bodies. Properties which are not currently producing may start
producing earlier or later than anticipated in our estimates of their future
production rates.
The future prices received by Coho for the sale of its production may be
higher or lower than the prices used in this report as described above, and the
operating costs and other costs relating to such production may also increase or
decrease from existing levels; however, such possible changes in prices and
costs were, in accordance with rules adopted by SEC, omitted from consideration
in preparing this report.
General
The reserve estimates for the properties that we reviewed are based on data
available through December 1996.
Neither we nor any of our employees have any interest in the subject
properties and neither the employment to do this work nor the compensation is
contingent on our estimates of reserves for the properties which were reviewed.
This report was prepared for the exclusive use of Coho and will not be
released by Ryder Scott to any other parties without Coho's written permission.
The data and work papers used in the preparation of this report are available
for examination by authorized parties in our offices. Please contact us if we
can be of further service.
Very truly yours,
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
/s/ HARRY J. GASTON, JR.
------------------------------------
Harry J. Gaston, Jr., P.E.
President
A-4
