<PAGE> 1
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON AUGUST 20, 1997
REGISTRATION NUMBER 333-
================================================================================
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
------------------------
FORM S-3
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
------------------------
COHO ENERGY, INC.
(Exact name of registrant as specified in its charter)
<TABLE>
<C> <C>
TEXAS 75-2488635
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
</TABLE>
14785 PRESTON ROAD, SUITE 860
DALLAS, TEXAS 75240
(972) 774-8300
(Address, including zip code, and telephone number, including area code, of
registrant's principal executive offices)
------------------------
JEFFREY CLARKE
14785 PRESTON ROAD, SUITE 860
DALLAS, TEXAS 75240
(972) 774-8300
(Name, address, including zip code, and telephone number, including area code,
of agent for service)
------------------------
Copies to:
<TABLE>
<C> <C>
FULBRIGHT & JAWORSKI L.L.P. CRAVATH, SWAINE & MOORE
1301 MCKINNEY, SUITE 5100 825 EIGHTH AVENUE
HOUSTON, TEXAS 77010-3095 NEW YORK, NEW YORK 10019
(713) 651-5151 (212) 474-1000
ATTN: JERRY L. WICKLIFFE ATTN: KRIS F. HEINZELMAN
</TABLE>
Approximate date of commencement of proposed sale to the public: As soon as
practicable after the Registration Statement becomes effective.
If the only securities being registered on this Form are being offered
pursuant to dividend or interest reinvestment plans, please check the following
box. [ ]
If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, other than securities offered only in connection with dividend or interest
reinvestment plans, check the following box. [ ]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]
CALCULATION OF REGISTRATION FEE
<TABLE>
<CAPTION>
================================================================================================================
TITLE OF EACH CLASS OF PROPOSED MAXIMUM AMOUNT OF
SECURITIES TO BE REGISTERED AGGREGATE OFFERING PRICE(1) REGISTRATION FEE
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Common Stock, $.01 par value.................... $96,253,501.50 $29,167.73
- ----------------------------------------------------------------------------------------------------------------
% Senior Subordinated Notes Due 2007....... $125,000,000.00 $37,878.79
================================================================================================================
</TABLE>
(1) Estimated solely for the purpose of calculating the registration fee
pursuant to Rule 457 under the Securities Act of 1933.
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE SECURITIES AND EXCHANGE COMMISSION ACTING PURSUANT
TO SAID SECTION 8(A), MAY DETERMINE.
================================================================================
<PAGE> 2
EXPLANATORY NOTE
This Registration Statement contains two prospectuses, one for an equity
offering and one for a simultaneous debt offering. The financial statement pages
and the summary reserve report for both prospectuses are identical and are
included in this Registration Statement only as part of the equity prospectus.
<PAGE> 3
INFORMATION CONTAINED HEREIN IS SUBJECT TO COMPLETION OR AMENDMENT. A
REGISTRATION STATEMENT RELATING TO THESE SECURITIES HAS BEEN FILED WITH THE
SECURITIES AND EXCHANGE COMMISSION. THESE SECURITIES MAY NOT BE SOLD NOR
MAY OFFERS TO BUY BE ACCEPTED PRIOR TO THE TIME THE REGISTRATION STATEMENT
BECOMES EFFECTIVE. THIS PROSPECTUS SHALL NOT CONSTITUTE AN OFFER TO SELL OR
THE SOLICITATION OF AN OFFER TO BUY NOR SHALL THERE BE ANY SALE OF THESE
SECURITIES IN ANY STATE IN WHICH SUCH OFFER, SOLICITATION OR SALE WOULD BE
UNLAWFUL PRIOR TO REGISTRATION OR QUALIFICATION UNDER THE SECURITIES LAWS
OF ANY SUCH STATE.
PROSPECTUS (Subject to Completion)
Issued August 20, 1997
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 AUGUST 18, 1997, THE REPORTED LAST SALE PRICE OF THE COMMON STOCK ON THE
NASDAQ STOCK MARKET WAS $9 3/4 PER SHARE.
CONCURRENTLY WITH THIS OFFERING OF THE SHARES OF COMMON STOCK (THIS "OFFERING"),
THE COMPANY IS OFFERING $125 MILLION IN AGGREGATE PRINCIPAL AMOUNT OF %
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 $ 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................ $ $ $ $
Total(3)................. $ $ $ $
</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 $600,000, 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 $ , $ and
$ , 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 , 1997 at the office of
Morgan Stanley & Co. Incorporated, New York, N.Y., against payment therefor in
New York funds.
------------------------
MORGAN STANLEY DEAN WITTER
JEFFERIES & COMPANY, INC.
PRUDENTIAL SECURITIES INCORPORATED
SMITH BARNEY INC.
September , 1997
<PAGE> 4
[MAP OF MISSISSIPPI AND LOUISIANA SHOWING LOCATION
OF COMPANY'S RESERVES]
2
<PAGE> 5
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................................ 18
Management's Discussion and Analysis
of Financial Condition and Results
of Operations....................... 20
</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... 45
Certain United States Tax Consequences
to Non-United States Holders........ 46
Underwriters.......................... 49
Legal Matters......................... 50
Experts............................... 51
Available Information................. 51
Glossary.............................. 52
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 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 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.
---------------------
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."
3
<PAGE> 6
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 $4.85 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> 7
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:
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> 8
Use of 3-D Seismic 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 oil and 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
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> 9
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 five 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........................................ 25,464,630 shares*
Concurrent Offering............................... Concurrent with this Offering, the Company is
offering $125 million aggregate principal amount
of its % 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>
- ---------------
* 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> 10
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) $ 32,784
Total assets............................................. 230,041 247,284 247,284 285,571
Long-term debt(f)........................................ 122,777 132,350 86,765 125,052
Total shareholders' equity............................... 81,466 85,228 130,813 130,813
</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> 11
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 annual production for the
most recent year.
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> 12
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> 13
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 expend 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 $125 million and a
debt-to-capitalization ratio of 49%. 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> 14
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 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> 15
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 attracting and retaining quality personnel and for materials and
third-party services essential for their exploration and development. 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> 16
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. 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 of 1933, as amended (the "Securities Act"), and Section 21E of the
Securities Exchange Act of 1934, as amended (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
14
<PAGE> 17
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.
DEBT OFFERING
Concurrently with this Offering, the Company is offering $125 million of
% 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. 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 August 18, 1997)................... 10 7/8 9 3/8
</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> 18
USE OF PROCEEDS
The net proceeds to be received by the Company from this Offering, assuming
an offering price of $9.75 per share, are estimated to be $45.6 million, after
deducting underwriting discounts and commissions and other estimated offering
expenses. Concurrent with this Offering, the Company is offering $125 million of
% Senior Subordinated Notes Due 2007 in the Debt Offering. 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 (estimated to be
$167.2 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 $ 35,838
======== ======== ========
Long-term debt:
Revolving Credit Facility(a)............................. $132,298 $ 86,713 $ --
% Senior Subordinated Notes Due 2007................... -- -- 125,000
Other long term debt..................................... 52 52 52
-------- -------- --------
Total long-term debt............................. 132,350 86,765 125,052
-------- -------- --------
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(b)...................... 204 254 254
Additional paid-in capital............................... 84,092 129,627 129,627
Retained earnings........................................ 932 932 932
-------- -------- --------
Total shareholders' equity....................... 85,228 130,813 130,813
-------- -------- --------
Total capitalization........................... $217,578 $217,578 $255,865
======== ======== ========
</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. Currently, the amount borrowed under the Revolving Credit
Facility is approximately $140 million.
(b) Excludes 2,569,678 shares subject to outstanding options under the Company's
stock option plans.
16
<PAGE> 19
SELECTED CONSOLIDATED FINANCIAL DATA
The following selected consolidated financial data for each of the three
years in the 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 and amortization.
EBITDA in 1993 has not been reduced for the recognition of noncash charges
relating 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> 20
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> 21
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> 22
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 ($0.33 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> 23
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> 24
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> 25
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 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 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 the loan converts to a term facility requiring quarterly principal
repayments until fully repaid in 2003. The
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<PAGE> 26
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 of $167.2 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 may 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 Senior Subordinated 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 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 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
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<PAGE> 27
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.
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<PAGE> 28
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 $4.85 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> 29
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:
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 3-D Seismic 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
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<PAGE> 30
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 Mississippi. A new Laurel
"look-alike" has exploration potential in the Tuscaloosa, Paluxy, Rodessa, Sligo
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<PAGE> 31
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 five 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,
--------------------- ----------------------
1994 1995 1996 1996 1997
----- ----- ----- ----- -------------- NET AVERAGE
% OF PRODUCTIVE PERCENTAGE WORKING
FIELD BOE BOE BOE BOE BOE 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; however, production total represents volume
since the effective acquisition date (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; however, production total represents volume
since the effective acquisition date (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.
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<PAGE> 32
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 represents approximately 29% of Coho's total
production on a BOE basis. 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
more 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 year end 1996.
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> 33
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 production during the
second quarter of 1997 showed a 150% increase from 1996 average annual
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 natural gas sand 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> 34
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, 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 the first, 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 late 1997 or 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).
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.
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<PAGE> 35
(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.
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.
33
<PAGE> 36
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 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.
34
<PAGE> 37
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 attracting and retaining
quality personnel and for materials and third-party services essential for their
exploration and development. The principal competitive factors in the
acquisition of crude oil and natural gas properties include the staff and data
necessary to identify, investigate and purchase such properties and the
financial resources necessary to acquire and develop them. Many of Coho's
competitors are substantially larger and have greater financial and other
resources than does Coho.
The principal resources necessary for the exploration for, and the
acquisition, exploitation, production and sale of, crude oil and natural gas are
leasehold or freehold prospects under which crude oil and natural gas reserves
may be discovered, drilling rigs and related equipment to explore for and
develop such reserves and capital assets required for the exploitation and
production of the reserves and knowledgeable personnel to conduct all phases of
crude oil and natural gas operations. Coho must compete for such resources with
both major oil companies and independent operators and also with other
industries for certain personnel and materials. Although Coho believes its
current resources are adequate to preclude any significant disruption of
operations in the immediate future, the continued availability of such materials
and resources to Coho cannot be assured.
CUSTOMERS AND MARKETS
Substantially all of Coho's crude oil is sold at the wellhead at posted
prices, as is 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.
35
<PAGE> 38
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.
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 $0.02 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.
36
<PAGE> 39
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-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
37
<PAGE> 40
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 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
38
<PAGE> 41
such spills in "waters of the United States." A "responsible party" includes the
owner or operator of a facility or vessel, or the lessee or permittee of the
area in which an offshore facility is located. The term "waters of the United
States" has been broadly defined to include inland waterbodies, including
wetlands, playa lakes, and intermittent streams. The OPA, as recently amended,
requires the lessee or permittee of the offshore area in which a crude oil or
natural gas 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 $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. 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 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 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 that have been released into the
environment and for damages to natural resources, and it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances released
into the environment. Currently, the Company does not own or operate CERCLA
identified sites.
The Resource Conservation and Recovery Act ("RCRA") is the principal
federal statute governing the treatment, storage and disposal of hazardous
wastes. RCRA imposes stringent operating requirements (and liability for failure
to meet such requirements) on a person who is either a "generator" or
"transporter" of hazardous waste or an "owner" or "operator" of a hazardous
waste treatment, storage or disposal facility. At present, RCRA includes a
statutory exemption that allows most crude oil and natural gas exploration and
production wastes to be classified as non-hazardous waste. A similar exemption
is contained in many of the state counterparts to RCRA. At various times in the
past, proposals have been made to amend RCRA and various state statutes to
rescind the exemption that excludes crude oil and natural gas exploration and
production wastes from regulation as hazardous waste under such statutes. Repeal
or modification of this exemption by administrative, legislative or judicial
process, or through changes in applicable state statutes, would increase the
volume of hazardous waste to be managed and disposed of by the Company.
Hazardous wastes are subject to more rigorous and costly disposal requirements
than are non-hazardous wastes. Any such change in the applicable statutes may
require the Company to make additional capital expenditures or incur increased
operating expenses.
A sizable portion of the Company's operations in Mississippi is conducted
within city limits. On an annual basis in order to obtain permits to conduct new
drilling operations, the Company is required to meet certain tests of financial
responsibility. The Company is conducting a voluntary program to remove inactive
aboveground storage tanks from its well sites. Inactive tanks are replaced, as
necessary, with newer aboveground storage tanks.
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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. The Company makes a
provision for future site restoration charges on a unit-of-production basis
which is included in depletion and depreciation expense.
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'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 are represented by a union. The Company
considers its employee relations to be satisfactory.
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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.
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<PAGE> 44
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. Ms. McAden was an
officer of Concap, within two years of the filing by seventeen real estate
limited partnerships in which Concap served as general partner of petitions for
reorganization under Chapter 11 of the U.S. Bankruptcy Code. The last case
before the U.S. Bankruptcy Court was settled in July 1994.
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 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
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Company by MSLEF II pursuant to the terms of the Registration Rights and
Shareholder Agreement dated as of December 8, 1994 (the "ING Shareholder
Agreement"), among MSLEF II and Quinn Oil Company Ltd. ("Quinn") (the previous
stockholders of ING) and the Company.
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
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
after this Offering will be 1,350,440 shares and 5.3%.
(b) Quinn Oil Company, Ltd. 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 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.
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<PAGE> 46
(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.
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.
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<PAGE> 47
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.
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 mature 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.
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.
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<PAGE> 48
The Revolving Credit Facility contains certain covenants which, among other
things, restricts the payment of dividends, limits the Company's ability to
incur additional debt, and provides that the Company must maintain minimum
amounts of shareholders equity and financial ratio coverages. See "Management's
Discussion and Analysis of Financial Results and Operations -- Liquidity and
Capital Resources."
SENIOR SUBORDINATED NOTES
Concurrently with this Offering, the Company is offering up to $125 million
aggregate principal amount of its % 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 , 2007. The
Notes will bear interest from September , 1997 at the rate of % per annum
payable semi-annually, commencing on , 1998. Certain subsidiaries of
the Company will issue guarantees of the Notes on a senior subordinated basis.
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 , 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 , 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 , 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 % 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 $65 million aggregate principal amount of
the Notes remains outstanding after such redemption.
Upon the occurrence of a Change of Control (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
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<PAGE> 49
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 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
47
<PAGE> 50
"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 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.
48
<PAGE> 51
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...........................
Jefferies & Company, Inc....................................
Prudential Securities Incorporated..........................
Smith Barney Inc............................................
---------
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 $ per share under the public offering price. The
Underwriters may allow, and such dealers may reallow, a concession not in excess
of $ 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
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 or 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
49
<PAGE> 52
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 approximately 28% 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.
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.
50
<PAGE> 53
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 of 1933 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
Securities Exchange Act of 1934, as amended (the "Exchange Act"), and, in
accordance therewith, files reports, proxy statements and other information with
the Securities and Exchange Commission (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 Act of 1933 (the "Securities
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.
51
<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.
52
<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 FOR INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Shareholders
of Coho Energy, Inc.
Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The information contained in Schedule III
is not a required part of the basic financial statements but is supplementary
information required by the Securities and Exchange Commission. This information
has been subjected to the auditing procedures applied in the audit of the basic
financial statements and, in our opinion, is fairly stated in all material
respects in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Dallas, Texas
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
-----------
$30,000,000
===========
</TABLE>
F-35
<PAGE> 90
ANNEX A
February 6, 1997
Coho Energy, Inc.
14785 Preston Road, Suite 860
Dallas, Texas 75240
Gentlemen:
At your request, we have reviewed Coho Energy, Inc.'s (Coho) estimates of
remaining recoverable proved reserves and estimated future cashflow as of
December 31, 1996 attributable to the interests owned by its three wholly owned
subsidiaries, Coho Resources, Inc., Coho Exploration, Inc. and Coho Louisiana
Production Company (CLPC). Coho's reserve estimates were prepared based upon
Securities and Exchange Commission (SEC) guidelines. When compared in total,
Coho's reserve estimates do not differ materially from the estimates prepared by
Ryder Scott. The properties reviewed by Ryder Scott Company Petroleum Engineers
(Ryder Scott) consisted of various fields in Louisiana, Mississippi, Texas, and
Offshore Texas. The estimated net proved reserves, estimated future net revenue
and discounted future net revenue as of December 31, 1996 attributable to
interests in the properties as estimated by Coho and reviewed by Ryder Scott,
are summarized below.
ESTIMATED NET REMAINING PROVED RESERVES
ATTRIBUTABLE TO LEASEHOLD AND ROYALTY INTERESTS
FOR PROPERTIES REVIEWED BY RYDER SCOTT
AS OF DECEMBER 31, 1996
<TABLE>
<CAPTION>
PROVED NET ESTIMATED FUTURE NET INCOME
REMAINING RESERVES M$
------------------------- ----------------------------
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> 91
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> 92
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> 93
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
<PAGE> 94
[COHO LOGO]
<PAGE> 95
INFORMATION CONTAINED HEREIN IS SUBJECT TO COMPLETION OR AMENDMENT. A
REGISTRATION STATEMENT RELATING TO THESE SECURITIES HAS BEEN FILED WITH THE
SECURITIES AND EXCHANGE COMMISSION. THESE SECURITIES MAY NOT BE SOLD NOR
MAY OFFERS TO BUY BE ACCEPTED PRIOR TO THE TIME THE REGISTRATION STATEMENT
BECOMES EFFECTIVE. THIS PROSPECTUS SHALL NOT CONSTITUTE AN OFFER TO SELL OR
THE SOLICITATION OF AN OFFER TO BUY NOR SHALL THERE BE ANY SALE OF THESE
SECURITIES IN ANY STATE IN WHICH SUCH OFFER, SOLICITATION OR SALE WOULD BE
UNLAWFUL PRIOR TO REGISTRATION OR QUALIFICATION UNDER THE SECURITIES LAWS
OF ANY SUCH STATE.
PROSPECTUS (Subject to Completion)
Issued August 20, 1997
<TABLE>
<S> <C> <C>
$125,000,000
[COHO LOGO]
% SENIOR SUBORDINATED NOTES DUE 2007
</TABLE>
------------------------
Interest payable and
------------------------
Interest on the % Senior Subordinated Notes Due 2007 of Coho Energy, Inc.
will be payable semi-annually on and of each year
commencing , 1998. The Notes are redeemable at the option of the
Company in whole or in part, at the redemption prices set forth herein, together
with accrued and unpaid interest, if any, to the date of redemption. In
addition, at any time prior to , 2000, the Company may redeem in aggregate
up to 35% of the original principal amount of the Notes with the proceeds of one
or more Equity Offerings (as defined herein) following which there is a Public
Market (as defined herein), at % of their principal amount, plus accrued
interest. Upon a Change of Control (as defined herein), each holder of the Notes
may require the Company to purchase all or a portion of such holder's Notes at
101% of the aggregate principal amount thereof, together with accrued and unpaid
interest, if any, to the date of purchase. See "Description of the Notes."
Concurrent with the offering made hereby (this "Offering") the Company and
certain selling shareholders are offering 8,584,482 shares of its Common Stock
(the "Equity Offering") pursuant to a simultaneous underwritten public offering.
This Offering is conditioned on the consummation of the Equity Offering. This
Offering and the Equity Offering are collectively referred to as the
"Offerings."
The Notes will be unsecured, general obligations of the Company subordinated in
right of payment to all existing and future Senior Indebtedness of the Company
but senior in right of payment to all existing and future subordinated
indebtedness of the Company. As of June 30, 1997, after giving effect to the
Offerings and the application of the proceeds therefrom, the Company and its
subsidiaries would have had no material Senior Indebtedness outstanding and $150
million available under its Revolving Credit Facility, which, when borrowed,
would constitute Senior Indebtedness. The Notes will be unconditionally
guaranteed on a senior subordinated basis by each of the Company's principal
operating subsidiaries.
------------------------
SEE "RISK FACTORS" BEGINNING ON PAGE 12 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 % AND ACCRUED INTEREST
------------------------
<TABLE>
<CAPTION>
UNDERWRITING DISCOUNTS AND
PRICE TO PUBLIC(1) COMMISSIONS(2) PROCEEDS TO COMPANY(1)(3)
------------------ -------------------------- -------------------------
<S> <C> <C> <C>
Per Note........................ % % %
Total........................... $ $ $
</TABLE>
- ------------
(1) Plus accrued interest from , 1997, if any.
(2) The Company has agreed to indemnify the Underwriters against certain civil
liabilities, including liabilities under the Securities Act of 1933. See
"Underwriters."
(3) Before deducting expenses of this Offering, estimated at $250,000.
------------------------
The Notes 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 Notes will be made on or about , 1997 at the office of
Morgan Stanley & Co. Incorporated, New York, N.Y., against payment therefor in
New York funds.
------------------------
MORGAN STANLEY DEAN WITTER JEFFERIES & COMPANY, INC.
September , 1997
<PAGE> 96
[MAP OF MISSISSIPPI AND LOUISIANA SHOWING
LOCATION OF COMPANY'S RESERVES]
2
<PAGE> 97
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Incorporation of Certain Documents by
Reference..................................... 3
Prospectus Summary.............................. 4
Risk Factors.................................... 12
Forward-Looking Statements...................... 17
Equity Offering................................. 17
Use of Proceeds................................. 18
Capitalization.................................. 18
Selected Consolidated Financial Data............ 19
Management's Discussion and Analysis of
Financial Condition and Results of
Operations.................................... 20
Business and Properties......................... 28
Management...................................... 43
</TABLE>
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Principal Shareholders.......................... 45
Description of the Notes........................ 46
Description of Revolving Credit Facility........ 77
Certain U.S. Federal Income Tax
Considerations................................ 78
Underwriters.................................... 80
Legal Matters................................... 81
Experts......................................... 81
Available Information........................... 82
Glossary........................................ 83
Index of Financial Statements................... F-1
Summary Reserve Report.......................... A-1
</TABLE>
---------------------
IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS, MAY OVER-ALLOT OR
EFFECT TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICES OF THE
SECURITIES OFFERED HEREBY AT LEVELS ABOVE THOSE WHICH MIGHT OTHERWISE PREVAIL IN
THE OPEN MARKET. SUCH TRANSACTION MAY BE EFFECTED IN THE OVER-THE-COUNTER MARKET
OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.
NO PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY
REPRESENTATION NOT CONTAINED OR INCORPORATED BY REFERENCE IN THIS PROSPECTUS IN
CONNECTION WITH THE OFFERING MADE HEREBY, AND, IF GIVEN OR MADE, SUCH
INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED
BY THE COMPANY OR BY ANY OTHER PERSON. THIS PROSPECTUS DOES NOT CONSTITUTE AN
OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY THE SECURITIES OFFERED BY
THIS PROSPECTUS IN ANY JURISDICTION WHERE, OR TO ANY PERSON WHOM, IT IS UNLAWFUL
TO MAKE SUCH AN OFFER OR SOLICITATION. NEITHER THE DELIVERY OF THIS PROSPECTUS
NOR ANY DISTRIBUTION OF SECURITIES MADE HEREUNDER OR THEREUNDER SHALL, UNDER ANY
CIRCUMSTANCES, CREATE AN IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE
AFFAIRS OF THE COMPANY SINCE THE DATE HEREOF OR THEREOF OR THAT THE INFORMATION
CONTAINED IN THIS PROSPECTUS IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE
HEREOF.
---------------------
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
Incorporated by reference in this Prospectus are the following documents
previously filed with 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 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> 98
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 $4.85 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> 99
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:
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> 100
Use of 3-D Seismic 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 oil and 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
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
6
<PAGE> 101
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 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 five 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.
7
<PAGE> 102
THE OFFERING
Issuer..................... Coho Energy, Inc.
Subsidiary Guarantors...... Coho Resources, Inc. and certain other non-foreign
subsidiaries.
Securities Offered......... $125,000,000 principal amount of % Senior
Subordinated Notes Due 2007.
Maturity Date.............. , 2007.
Interest Rate and Payment
Dates.................... The Notes will bear interest at a rate of %
per annum. Interest on the Notes will accrue from
the date of issuance thereof and will be payable
semi-annually on and of
each year, commencing , 1998.
Optional Redemption........ The Notes will be redeemable at the option of the
Company, in whole or in part, at the redemption
prices set forth herein, together with accrued and
unpaid interest to the date of redemption. If at
any time or from time to time before
2000, the Company consummates an Equity Offering
(as defined herein) following which there is a
Public Market, the Company may at its option use
all or a portion of the proceeds therefrom to
redeem up to 35% of the original principal amount
of the Notes at a redemption price equal to %
of the aggregate principal thereof, together with
accrued and unpaid interest to the date of
redemption, provided that at least $65 million in
aggregate principal amount of Notes remain
outstanding immediately after each such redemption
or that such redemption must retire the Notes in
their entirety and that such redemption occurs
within 60 days following the closing of the Equity
Offering. See "Description of Notes -- Optional
Redemption."
Repurchase Obligation Upon
Change of Control........ Upon the occurrence of a Change of Control and a
Rating Decline, 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. See "Description of the Notes --
Certain Covenants -- Change of Control."
Ranking.................... The Notes will be unsecured, general obligations of
the Company subordinated in right of payment to all
existing and future Senior Indebtedness (as defined
herein) of the Company. The Notes will rank pari
passu in right of payment with any future senior
subordinated indebtedness of the Company and will
be senior in right of payment to all existing and
future subordinated indebtedness of the Company. In
addition, the Notes will be effectively
subordinated to all liabilities of the Company's
subsidiaries, including trade payables. After
giving effect to the Offerings and the application
of proceeds therefrom, as of June 30, 1997, the
Company would have had no material outstanding
Senior Indebtedness. The Company may incur
additional indebtedness under the Revolving Credit
Facility after the Offering, and such indebtedness
will constitute Senior Indebtedness. In addition,
the Notes will be effectively subordinated to all
liabilities of the Company's subsidiaries (other
than those of the Subsidiary Guarantors), including
trade payables. After giving effect to the
Offerings and the application of the
8
<PAGE> 103
proceeds therefrom, as of June 30, 1997, the
Company's subsidiaries (other than the Subsidiary
Guarantors) would have had no liabilities to
Persons (as defined herein) other than the Company
and its subsidiaries. See "Risk
Factors -- Subordination" and "Description of the
Notes -- Ranking."
Subsidiary Guarantees...... The Notes will be irrevocably and unconditionally
guaranteed (the "Subsidiary Guarantees") on a
senior subordinated basis by the Subsidiary
Guarantors, each a wholly owned subsidiary of the
Company and, in the future, may be guaranteed by
other subsidiaries of the Company. The Subsidiary
Guarantees will be general, unsecured obligations
of the Subsidiary Guarantors, subordinated in right
of payment to all existing and future Senior
Indebtedness of the Subsidiary Guarantors,
including the obligations of the Subsidiary
Guarantors under the Revolving Credit Facility.
After giving effect to the Offerings and the
application of the proceeds therefrom, as of June
30, 1997, the Subsidiary Guarantors would have had
no Senior Indebtedness outstanding. The Subsidiary
Guarantors may incur additional indebtedness under
the Revolving Credit Facility after the Offering,
and such indebtedness will constitute Senior
Indebtedness. See "Risk Factors -- Subordination of
the Notes and the Subsidiary Guarantees" and
"Description of the Notes -- Ranking."
Certain Covenants.......... The Indenture pursuant to which the Notes will be
issued (the "Indenture") will contain certain
covenants for the benefit of the Holders,
including, among others, covenants limiting the
incurrence of additional indebtedness, the payment
of dividends, the redemption of capital stock, the
making of certain investments, the restriction of
dividends and other restrictions affecting
subsidiaries, the issuance of capital stock of
subsidiaries, asset sales, certain sale and
leaseback transactions, transactions with
affiliates and certain mergers and consolidations.
However, these limitations will be subject to a
number of important qualifications and exceptions.
See "Description of the Notes -- Certain
Covenants."
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.
Equity Offering............ Concurrently with the Debt Offering, the Company
and certain selling shareholders are offering
8,584,482 shares (9,872,154 shares if the
underwriters' over-allotment option is exercised in
full) of Common Stock for sale to the public, of
which 5,000,000 shares will be sold by the Company.
The Company will not receive any proceeds from the
sale of shares of Common Stock by the selling
shareholders in the Equity Offering. The closing of
this Offering is conditioned on the concurrent
closing of the Equity Offering; however, the
closing of the Equity Offering is not conditioned
upon the closing of this Offering.
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.
9
<PAGE> 104
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 and (ii) as adjusted to give effect to the
Offerings. 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
ACTUAL ACTUAL THE OFFERINGS
------------ -------- ---------------
(IN THOUSANDS)
<S> <C> <C> <C>
BALANCE SHEET DATA:
Working capital (deficit)................................... $ 6,662 $ (2,118) $ 32,784
Total assets................................................ 230,041 247,284 285,571
Long-term debt(f)........................................... 122,777 132,350 125,052
Total shareholders' equity.................................. 81,466 85,228 130,813
</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.
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<PAGE> 105
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 annual production for the
most recent year.
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>
11
<PAGE> 106
RISK FACTORS
Prospective purchasers of the Notes 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
12
<PAGE> 107
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 expend 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 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 $125 million and a
debt-to-capitalization ratio of 49%. 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 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
Notes -- Certain Covenants." The level of the Company's leverage from time to
time could have important consequences to holders of the Notes, including the
Company's ability to obtain additional financing for
13
<PAGE> 108
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 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
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
14
<PAGE> 109
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 the Equity
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 attracting and retaining quality personnel and for materials and
third-party services essential for their exploration and development. 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.
SUBORDINATION
The Notes will be subordinated in right of payment to all existing and
future Senior Indebtedness of the Company, which includes all indebtedness under
the Revolving Credit Facility. As of June 30, 1997, after giving effect to the
Offerings and the application of the proceeds therefrom, the Company would have
had no Senior Indebtedness outstanding and would have had up to $150 million
available under the Revolving Credit
15
<PAGE> 110
Facility, which, if borrowed, would be Senior Indebtedness. The Company
currently conducts business through its subsidiaries. Claims of creditors of the
Company's subsidiaries, including trade creditors, secured creditors and
creditors holding indebtedness and guarantees issued by such subsidiaries, and
claims of preferred stockholders (if any) of such subsidiaries, generally will
have priority with respect to the assets and earnings of such subsidiaries over
the claims of creditors of the Company, including holders of the Notes, even if
such obligations do not constitute Senior Indebtedness of such subsidiaries.
However, the Notes will be guaranteed by certain subsidiaries of the Company.
See "Description of the Notes -- Subsidiary Guaranties." Such guarantees,
however, will be subordinate in right of payment to any Senior Indebtedness of
such subsidiaries. Although the Indenture will limit the incurrence of
Indebtedness and preferred stock of certain subsidiaries, such limitation is
subject to a number of significant qualifications. Moreover, the Indenture will
not impose any limitation on the incurrence by subsidiaries of liabilities that
are not considered indebtedness under the Indenture. See "Description of the
Notes -- Certain Covenants -- Limitation on Indebtedness."
The obligations of each Subsidiary Guarantor (as defined herein) under its
guaranty will be senior subordinated obligations. As such, the rights of holders
of the Notes to receive payment by a Subsidiary Guarantor will be subordinated
in right of payment to the rights of holders of Senior Indebtedness of such
Subsidiary Guarantor. The terms of the subordination with respect to the
Company's obligations under the Notes will apply equally to a Subsidiary
Guarantor and the obligations of such Subsidiary Guarantor under its guaranty.
In the event of liquidation, dissolution, reorganization, bankruptcy or any
similar proceeding regarding the Company, the assets of the Company will be
available to pay obligations on the Notes only after the Senior Indebtedness of
the Company has been paid in full. Accordingly, there may not be sufficient
funds remaining to pay amounts due on all or any of the Notes. In addition, the
subordination provisions of the Indenture will provide that no cash payment may
be made with respect to the Notes during the continuance of a payment default
under any Senior Indebtedness of the Company. Furthermore, if certain
non-payment defaults exist with respect to certain Senior Indebtedness of the
Company, the holders of such Senior Indebtedness will be able to prevent
payments on the Notes for certain periods of time. See "Description of the
Notes -- Ranking."
PAYMENT UPON A CHANGE OF CONTROL
Upon the occurrence of a Change of Control, each holder of the Notes may
require the Company to repurchase all or a portion of such holder's Notes at
101% of the principal amount of the Notes, together with accrued and unpaid
interest to the date of repurchase. The Indenture will require that, prior to
such a repurchase, the Company must either repay all outstanding Senior
Indebtedness or obtain any required consents to such repurchase. If a Change of
Control were to occur, the Company may not have the financial resources to repay
all of the Senior Indebtedness, the Notes and any other indebtedness that would
become payable upon the occurrence of such Change of Control. See "Description
of the Notes -- Certain Covenants -- Change of Control."
LACK OF PUBLIC MARKET
The Notes are a new issue of securities for which there is currently no
trading market. The Company does not intend to apply for a listing of the Notes
on a securities exchange. The Underwriters have advised the Company that they
currently intend to make a market in the Notes, although the Underwriters are
not obligated to do so, and any market making with respect to the Notes may be
discontinued at any time without notice. See "Underwriters." There can be no
assurance as to the liquidity of any market that may develop for the Notes, the
ability of the holders of the Notes to sell their Notes or the price at which
such holders would be able to sell their Notes. If a market were to exist, the
Notes could trade at prices that may be lower than the initial offering price
thereof depending on many factors, including prevailing interest rates and the
markets for similar securities, general economic conditions and the financial
condition and performance of, and prospects for, the Company.
16
<PAGE> 111
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
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.
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 of 1933, as amended (the "Securities Act"), and Section 21E of the
Securities Exchange Act of 1934, as amended (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.
EQUITY OFFERING
Concurrently with this Offering, the Company and the Selling Shareholders
are offering 5,000,000 shares and 3,584,482 shares, respectively, of Common
Stock to the public. In addition, in the Equity Offering, the Selling
Shareholders have granted the underwriters an option to purchase up to 1,287,672
additional shares of Common Stock to cover over-allotments. The consummation of
this Offering is conditioned upon the simultaneous closing of the Equity
Offering; however, the Equity Offering is not conditioned upon the consummation
of this Offering.
17
<PAGE> 112
USE OF PROCEEDS
The net proceeds to be received by the Company from this Offering are
estimated to be $121.6 million, after deducting underwriting discounts and
commissions and other estimated offering expenses. Concurrent with this
Offering, the Company is offering 5,000,000 shares of its Common Stock. This
Offering is conditioned on the consummation of the Equity Offering; however, the
closing of the Equity Offering is not conditioned upon the closing of this
Offering. The Company intends to use the total net proceeds of the Offerings
(estimated to be $167.2 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 and (ii) the capitalization of the Company as
adjusted to give effect to the Offerings. 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 ADJUSTED
FOR THE
ACTUAL OFFERINGS
-------- -----------
(IN THOUSANDS)
<S> <C> <C>
Cash and cash equivalents................................... $ 936 $ 35,838
======== ========
Long-term debt:
Revolving Credit Facility(a).............................. $132,298 $ --
% Senior Subordinated Notes Due 2007.................... -- 125,000
Other long term debt...................................... 52 52
-------- --------
Total long-term debt.............................. 132,350 125,052
-------- --------
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(b)...................... 204 254
Additional paid-in capital................................ 84,092 129,627
Retained earnings......................................... 932 932
-------- --------
Total shareholders' equity........................ 85,228 130,813
-------- --------
Total capitalization......................... $217,578 $255,865
======== ========
</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. Currently, the amount borrowed under the Revolving Credit
Facility is approximately $140 million.
(b) Excludes 2,569,678 shares subject to outstanding options under the Company's
stock option plans.
18
<PAGE> 113
SELECTED CONSOLIDATED FINANCIAL DATA
The following selected consolidated financial data for each of the three
years in the 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 and amortization.
EBITDA in 1993 has not been reduced for the recognition of noncash charges
relating 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.
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<PAGE> 114
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 Coho Resources Limited
("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
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<PAGE> 115
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.
21
<PAGE> 116
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 ($0.33 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 period in 1996. The depletion and depreciation rate decreased from
$5.05 per BOE in the first quarter of 1997
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<PAGE> 117
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.
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<PAGE> 118
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 Bbl 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).
24
<PAGE> 119
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 on line 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
25
<PAGE> 120
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 of $167.2 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 may 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 Senior Subordinated 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 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 1996, the Company
incurred capital expenditures of $52.4 million compared with $30.0 million for
1995.
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<PAGE> 121
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.
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<PAGE> 122
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 $4.85 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
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<PAGE> 123
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:
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 3-D Seismic 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
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<PAGE> 124
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 Mississippi. A new Laurel
"look-alike" has exploration potential in the Tuscaloosa, Paluxy, Rodessa, Sligo
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<PAGE> 125
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 five 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,
----------------------- ----------------------
1994 1995 1996 1996 1997
----- ----- ----- ----- -------------- NET AVERAGE
% OF PRODUCTIVE PERCENTAGE WORKING
FIELD BOE BOE BOE BOE BOE 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; however, production total represents volume
since the effective acquisition date (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; however, production total represents volume
since the effective acquisition date (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.
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<PAGE> 126
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 represents approximately 29% of Coho's total
production on a BOE basis. 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
more 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 year end 1996.
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
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<PAGE> 127
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 production during the
second quarter of 1997 showed a 150% increase from 1996 average annual
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 natural Sparta gas sand 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.
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<PAGE> 128
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, 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 the first, 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 late 1997 or 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).
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.
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<PAGE> 129
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
35
<PAGE> 130
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 attracting and retaining
quality personnel and for materials and third-party services essential for their
exploration and development. The principal competitive factors in the
acquisition of crude oil and natural gas properties include the staff and data
36
<PAGE> 131
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 gas production 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 gas sales
contract for its Monroe field 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 oil and gas may vary significantly
during certain times of the year due to the volatility of the oil and 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.
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<PAGE> 132
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 $0.02 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-
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<PAGE> 133
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
39
<PAGE> 134
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 in "waters
of the United States." A "responsible party" includes the owner or operator of a
facility or vessel, or the lessee or permittee of the area in which an offshore
facility is located. The term "waters of the United States" has been broadly
defined to include inland waterbodies, including wetlands, playa lakes, and
intermittent streams. The OPA, as recently amended, requires the lessee or
permittee of the offshore area in which a crude oil or natural gas 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
40
<PAGE> 135
the United States to increase the amount of financial responsibility to $150.0
million depending on the risks posed by the quantity of crude oil that is
handled by the facility. On March 25, 1997, the MMS proposed regulations to
implement the financial responsibility requirements under the OPA. The proposed
regulations would use an offshore facility's worst case oil-spill discharge
volume to determine if the responsible party must demonstrate increased
financial responsibility. 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 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 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 that have been released into the
environment and for damages to natural resources, and it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances released
into the environment. Currently, the Company does not own or operate CERCLA
identified sites.
The Resource Conservation and Recovery Act ("RCRA") is the principal
federal statute governing the treatment, storage and disposal of hazardous
wastes. RCRA imposes stringent operating requirements (and liability for failure
to meet such requirements) on a person who is either a "generator" or
"transporter" of hazardous waste or an "owner" or "operator" of a hazardous
waste treatment, storage or disposal facility. At present, RCRA includes a
statutory exemption that allows most crude oil and natural gas exploration and
production wastes to be classified as non-hazardous waste. A similar exemption
is contained in many of the state counterparts to RCRA. At various times in the
past, proposals have been made to amend RCRA and various state statutes to
rescind the exemption that excludes crude oil and natural gas exploration and
production wastes from regulation as hazardous waste under such statutes. Repeal
or modification of this exemption by administrative, legislative or judicial
process, or through changes in applicable state statutes, would increase the
volume of hazardous waste to be managed and disposed of by the Company.
Hazardous wastes are subject to more rigorous and costly disposal requirements
than are non-hazardous wastes. Any such change in the applicable statutes may
require the Company to make additional capital expenditures or incur increased
operating expenses.
A sizable portion of the Company's operations in Mississippi is conducted
within city limits. On an annual basis in order to obtain permits to conduct new
drilling operations, the Company is required to meet certain tests of financial
responsibility. The Company is conducting a voluntary program to remove inactive
aboveground storage tanks from its well sites. Inactive tanks are replaced, as
necessary, with newer aboveground storage tanks.
Some states have enacted statutes governing the handling, treatment,
storage and disposal of naturally occurring radioactive material ("NORM"). NORM
is present in varying concentrations in subsurface and hydrocarbon reservoirs
around the world and may be concentrated in scale, film and sludge in equipment
that comes in contact with crude oil 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
41
<PAGE> 136
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 statues and laws. The Company makes a
provision for future site restoration charges on a unit-of-production basis
which is included in depletion and depreciation expense.
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'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 are represented by a union. The Company
considers its employee relations to be satisfactory.
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<PAGE> 137
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.
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<PAGE> 138
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. Ms. McAden was an
officer of Concap, within two years of the filing by seventeen real estate
limited partnerships in which Concap served as general partner of petitions for
reorganization under Chapter 11 of the U.S. Bankruptcy Code. The last case
before the U.S. Bankruptcy Court was settled in July 1994.
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 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.
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<PAGE> 139
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 (the "ING Shareholder Agreement"), among MSLEF II and
Quinn Oil Company Ltd. ("Quinn") (the previous stockholders of ING) and the
Company.
PRINCIPAL SHAREHOLDERS
The following table sets forth the beneficial ownership of Common Stock
following the Offerings by (i) each person or entity who, to the knowledge of
the Company, based on information received from or on behalf of such persons,
will be the beneficial owner of more than 5% of the outstanding shares of Common
Stock and (ii) 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
AFTER OFFERING
-------------------
NAME OF BENEFICIAL OWNER NUMBER PERCENT
------------------------ --------- -------
<S> <C> <C>
The Morgan Stanley Leveraged Equity Fund II, L.P.(a)........ 2,520,998 9.9%
All directors and executive officers as a group (18
persons)(b)............................................... 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 2,520,998 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 overallotment option in the Equity
Offering is exercised in full, the number and percentage of shares
beneficially owned after the Offerings will be 1,350,440 shares and 5.3%.
(b) 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.
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<PAGE> 140
DESCRIPTION OF THE NOTES
GENERAL
The Notes are to be issued under an Indenture, to be dated as of ,
1997 (the "Indenture"), between the Company and , as Trustee (the
"Trustee"). A copy of the form of Indenture is filed as an exhibit to the
Registration Statement of which this Prospectus is a part. The following summary
of certain provisions of the Indenture does not purport to be complete and is
subject to, and is qualified in its entirety by reference to, the Indenture and,
the Notes including the definitions of certain terms therein and those terms
made a part of the Indenture by the Trust Indenture Act of 1939, as amended.
TERMS OF THE NOTES
The Notes will be unsecured senior subordinated obligations of the Company,
initially limited to $125 million aggregate principal amount, and will mature on
, 2007. The Notes will bear interest at the rate per annum shown on
the cover page hereof from September , 1997, or from the most recent date to
which interest has been paid or provided for, payable semiannually to Holders of
record at the close of business on the or immediately preceding the
interest payment date on and of each year, commencing , 1998.
Interest on overdue principal and (to the extent permitted by law) on overdue
installments of interest will accrue at 1% per annum in excess of such rate.
Interest on the Notes will be computed on the basis of a 360-day year of twelve
30-day months.
Principal of and interest on the Notes will be payable, and the Notes may
be exchanged or transferred, at the office or agency of the Company in the
Borough of Manhattan, The City of New York (which initially shall be the
corporate trust office of the Trustee, at New York, New York ), except
that, at the option of the Company, payment of interest may be made by check
mailed to the address of the Holders as such address appears in the Note
Register.
The Notes will be issued only in fully registered form, without coupons, in
denominations of $1,000 and any integral multiple of $1,000. No service charge
shall be made for any registration of transfer or exchange of Notes, but the
Company may require payment of a sum sufficient to cover any transfer tax or
other similar governmental charge payable in connection therewith.
Subject to the covenants described below under "-- Certain Covenants" and
applicable law, the Company may issue additional Notes under the Indenture in an
unlimited principal amount. The Notes offered hereby and any additional Notes
subsequently issued would be treated as a single class for all purposes under
the Indenture.
OPTIONAL REDEMPTION
Prior to , 2002, the Notes will be redeemable at the Company's option,
in whole or in part, at any time or from time to time, upon not less than 30 nor
more than 60 days' prior notice mailed by first-class mail to each Holder's
registered address, at a redemption price (expressed as a percentage of
principal amount) equal to the sum of the principal amount of such Notes plus
the Applicable Premium thereon at the time of redemption (subject to the right
of holders of record on the relevant record date to receive interest due on the
relevant interest payment date).
The following definitions are used to determine the Applicable Premium:
"Applicable Premium" means, with respect to a Note at any time, the greater
of (i) 1.0% of the principal amount of such Note at such time and (ii) the
excess of (A) the present value at such time of the principal amount plus all
interest payments due on such Note, computed using a discount rate equal to the
Treasury Rate plus two basis points, over (B) the principal amount of such Note
at such time.
"Treasury Rate" means the yield to maturity at the time of computation of
United States Treasury securities with a constant maturity (as compiled and
published in the most recent Federal Reserve Statistical Release H.15(519) which
has become publicly available at least two business days prior to the date fixed
for
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<PAGE> 141
repayment or, in the case of defeasance, prior to the date of deposit (or, if
such Statistical Release is no longer published, any publicly available source
of similar market data)) most nearly equal to the then remaining average life to
Stated Maturity) of the Notes; provided, however, that if the average life to
Stated Maturity of the Notes is not equal to the constant maturity of a United
States Treasury security for which a weekly average yield is given, the Treasury
Rate shall be obtained by linear interpolation (calculated to the nearest
one-twelfth of a year) from the weekly average yields of United States Treasury
securities for which such yields are given.
From and after , 2002, the Notes will be redeemable, at the
Company's option, in whole or in part, at any time or from time to time, upon
not less than 30 nor more than 60 days' prior notice mailed by first-class mail
to each Holder's registered address, at the following redemption prices
(expressed in percentages of principal amount), plus accrued interest to the
redemption date (subject to the right of Holders of record on the relevant
record date to receive interest due on the relevant interest payment date), if
redeemed during the 12-month period commencing on of the years set forth
below:
<TABLE>
<CAPTION>
REDEMPTION
PERIOD PRICE
------ ----------
<S> <C>
2002...................................................... %
2003......................................................
2004 and thereafter....................................... 100
</TABLE>
In addition, at any time and from time to time prior to , 2000, the
Company may redeem in the aggregate up to 35% of the original principal amount
of the Notes with the proceeds of one or more Equity Offerings following which
there is a Public Market, at a redemption price (expressed as a percentage of
principal amount) of % plus accrued interest to the redemption date
(subject to the right of Holders of record on the relevant record date to
receive interest due on the relevant interest payment date); provided, however,
that either at least $65,000,000 aggregate principal amount of the Notes must
remain outstanding after each such redemption or such redemption must retire the
Notes in their entirety and that such redemption occurs within 60 days following
the closing of such Equity Offering.
In the case of any partial redemption, selection of the Notes for
redemption will be made by the Trustee on a pro rata basis, by lot or by such
other method as the Trustee in its sole discretion shall deem to be fair and
appropriate, although no Note of $1,000 in original principal amount or less
shall be redeemed in part. If any Note is to be redeemed in part only, the
notice of redemption relating to such Note shall state the portion of the
principal amount thereof to be redeemed. A new Note in principal amount equal to
the unredeemed portion thereof will be issued in the name of the Holder thereof
upon cancellation of the original Note.
SINKING FUND
There will be no sinking fund payments for the Notes.
SUBSIDIARY GUARANTEES
CRI and each other Restricted Subsidiary of the Company (including Coho
Louisiana Production Company, Coho Exploration, Inc., ING, Coho Fairbanks
Gathering Company and Coho Louisiana Gathering Company and excluding each Exempt
Foreign Subsidiary) that has total net assets (exclusive of the Capital Stock of
another Restricted Subsidiary) as of the end of the most recent fiscal year (as
set forth on the balance sheet of such Subsidiary prepared in accordance with
GAAP) equal to or greater than the greater of $2.5 million and one percent (1%)
of Adjusted Consolidated Net Tangible Assets as of such date, will issue a
Subsidiary Guaranty of the Notes as described herein. Each Subsidiary Guarantor,
as primary obligor and not merely as surety, will irrevocably and
unconditionally guarantee on a senior subordinated basis the performance and the
punctual payment when due, whether at Stated Maturity, by acceleration or
otherwise, of all the Obligations of the Company under the Indenture and the
Notes (all such Obligations guaranteed by the Subsidiary Guarantors being herein
called the "Guaranteed Obligations" and each such Subsidiary Guaranty being
herein called a "Subsidiary Guaranty"). Each Subsidiary Guaranty will be limited
in amount to an
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<PAGE> 142
amount not to exceed the maximum amount that can, after giving effect to all
other contingent and fixed liabilities of the applicable Subsidiary Guarantor,
be guaranteed by such Subsidiary Guarantor without rendering such Subsidiary
Guaranty voidable under applicable law relating to fraudulent transfer or
fraudulent conveyance or similar laws affecting the rights of creditors
generally. Each Subsidiary Guarantor will agree to pay, in addition to the
amount stated above, any and all expenses (including reasonable counsel fees and
expenses) incurred by the Trustee and the Holders in enforcing any rights under
the Subsidiary Guaranty with respect to such Subsidiary Guarantor.
Each Subsidiary Guaranty is a continuing guarantee and shall (a) remain in
full force and effect until payment in full of all the Guaranteed Obligations,
(b) be binding upon the relevant Subsidiary Guarantor and (c) enure to the
benefit of and be enforceable by the Trustee, the Holders and their successors,
transferee and assigns.
Pursuant to the Indenture, any Subsidiary Guarantor may consolidate with,
merge with or into, or transfer all or substantially all its assets to any other
Person to the same extent the Company may consolidate with, merge with or into,
or transfer all or substantially all its assets to, any other Person; provided,
however, that if such Person is not the Company or a Subsidiary Guarantor, such
Subsidiary Guarantor's Obligations under the Indenture and its Subsidiary
Guaranty must be expressly assumed by such other Person. See "-- Certain
Covenants -- Merger and Consolidation."
RANKING
The indebtedness evidenced by the Notes and any Subsidiary Guaranty will be
unsecured, general obligations of the Company and the relevant Subsidiary
Guarantor, respectively, subordinated in right of payment, as set forth in the
Indenture, to the prior payment of all Senior Indebtedness of the Company or
Senior Indebtedness of the applicable Subsidiary Guarantor, as the case may be,
whether outstanding on the Issue Date or thereafter incurred, including the
Company's and such Subsidiary Guarantor's obligations under the Revolving Credit
Facility. After giving effect to the Offerings and the application of the
proceeds therefrom, as of June 30, 1997, the Company would have had no Senior
Indebtedness outstanding and would have had up to $150 million available under
the Revolving Credit Facility which, if borrowed, would be Senior Indebtedness.
Only Indebtedness of the Company that is Senior Indebtedness will rank
senior to the Notes and only Indebtedness of a Subsidiary Guarantor that is
Senior Indebtedness of such Subsidiary Guarantor will rank senior to such
Subsidiary Guarantor's Subsidiary Guaranty, in each case in accordance with the
provisions of the Indenture. The Notes and the Subsidiary Guarantees will in all
respects rank pari passu with all other Senior Subordinated Indebtedness of the
Company or Senior Subordinated Indebtedness of the relevant Subsidiary
Guarantor, as the case may be. The Company has agreed in the Indenture that it
will not Incur, directly or indirectly, and it will not permit any Subsidiary
Guarantor to Incur, directly or indirectly, any Indebtedness that is subordinate
or junior in ranking in right of payment to its Senior Indebtedness unless such
Indebtedness is Senior Subordinated Indebtedness or is expressly subordinated in
right of payment to Senior Subordinated Indebtedness. Unsecured Indebtedness is
not deemed to be subordinated or junior to Secured Indebtedness merely because
it is unsecured.
Substantially all the operations of the Company are currently conducted
through its subsidiaries. Claims of creditors of any such subsidiaries which are
not Subsidiary Guarantors, including trade creditors, secured creditors and
creditors holding guarantees issued by such subsidiaries, and claims of
preferred stockholders (if any) of such subsidiaries generally will have
priority with respect to the assets and earnings of such subsidiaries over the
claims of creditors of the Company, including holders of the Notes, even though
such obligations would not constitute Senior Indebtedness of the Company. The
Notes and the Subsidiary Guarantees, therefore, will be effectively subordinated
to creditors (including trade creditors) and preferred stockholders (if any) of
subsidiaries of the Company (other than the Subsidiary Guarantors). After giving
effect to the Offerings and the application of the proceeds therefrom, as of
June 30, 1997, the Company's subsidiaries (other than the Subsidiary Guarantors)
would have had no liabilities to Persons other than to the Company and its
subsidiaries. Although the Indenture limits the incurrence of Indebtedness and
the issuance
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<PAGE> 143
of preferred stock of certain of the Company's subsidiaries, such limitation is
subject to a number of significant qualifications; moreover, the Indenture does
not impose any limitation on the incurrence by such subsidiaries of liabilities
that are not considered Indebtedness under the Indenture. See "-- Certain
Covenants -- Limitation on Indebtedness."
The Company may not pay principal of, premium (if any) or interest on, the
Notes or make any deposit pursuant to the provisions described under
"Defeasance" below or may not repurchase, redeem or otherwise retire any Notes
(collectively, "pay the Notes") if (i) any Designated Senior Indebtedness of the
Company is not paid when due or (ii) any other default on Designated Senior
Indebtedness of the Company occurs and the maturity of such Designated Senior
Indebtedness is accelerated in accordance with its terms unless, in either case,
the default has been cured or waived and any such acceleration has been
rescinded or such Designated Senior Indebtedness has been paid in full. However,
the Company may pay the Notes without regard to the foregoing if the Company and
the Trustee receive written notice approving such payment from the
Representative of the Designated Senior Indebtedness with respect to which
either of the events set forth in clause (i) or (ii) of the immediately
preceding sentence has occurred and is continuing. During the continuance of any
default (other than a default described in clause (i) or (ii) of the second
preceding sentence) with respect to any Designated Senior Indebtedness of the
Company pursuant to which the maturity thereof may be accelerated immediately
without further notice (except such notice as may be required to effect such
acceleration) or the expiration of any applicable grace periods, the Company may
not pay the Notes for a period (a "Payment Blockage Period") commencing upon the
receipt by the Trustee (with a copy to the Company) of written notice (a
"Blockage Notice") of such default from the Representative of the holders of
such Designated Senior Indebtedness specifying an election to effect a Payment
Blockage Period and ending 179 days thereafter (or earlier if such Payment
Blockage Period is terminated (i) by written notice to the Trustee and the
Company from the Person or Persons who gave such Blockage Notice, (ii) because
the default giving rise to such Blockage Notice is no longer continuing or (iii)
because such Designated Senior Indebtedness has been repaid in full).
Notwithstanding the provisions described in the immediately preceding sentence,
unless the holders of such Designated Senior Indebtedness or the Representative
of such holders have accelerated the maturity of such Designated Senior
Indebtedness, the Company must resume payments on the Notes after the end of
such Payment Blockage Period. The Notes shall not be subject to more than one
Payment Blockage Period in any consecutive 360-day period, irrespective of the
number of defaults with respect to Designated Senior Indebtedness of the Company
during such period.
Upon any payment or distribution of the assets of the Company upon a total
or partial liquidation or dissolution or reorganization of or similar proceeding
relating to the Company or its property, the holders of Senior Indebtedness of
the Company will be entitled to receive payment in full of such Senior
Indebtedness before the Noteholders are entitled to receive any payment in
respect of the Notes, and until the Senior Indebtedness of the Company is paid
in full, any payment or distribution to which Noteholders would be entitled from
the Company but for the subordination provisions of the Indenture will be made
to holders of such Senior Indebtedness of the Company as their interests may
appear. If a distribution is made to Noteholders that, due to the subordination
provisions, should not have been made to them, such Noteholders are required to
hold it in trust for the holders of Senior Indebtedness of the Company and pay
it over to them as their interests may appear.
If payment of the Notes is accelerated because of an Event of Default, the
Company or the Trustee shall promptly notify the holders of Designated Senior
Indebtedness of the Company or the Representative of such holders of the
acceleration.
The obligations of a Subsidiary Guarantor under its Subsidiary Guaranty, as
they relate to the principal and interest on the Notes, are unsecured senior
subordinated obligations. As such, the rights of Noteholders to receive payment
by a Subsidiary Guarantor pursuant to its Subsidiary Guaranty will be
subordinated in right of payment to the rights of holders of Senior Indebtedness
of such Subsidiary Guarantor. The terms of the subordination provisions
described above with respect to the Company's obligations under the Notes apply
equally to a Subsidiary Guarantor and the obligations of such Subsidiary
Guarantor under its Subsidiary Guaranty, as they relate to the principal of and
interest on the Notes.
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<PAGE> 144
By reason of the subordination provisions contained in the Indenture, in
the event of insolvency, creditors of the Company who are holders of Senior
Indebtedness of the Company may recover more from the Company, ratably, than the
Noteholders, and creditors of the Company who are not holders of Senior
Indebtedness of the Company may recover less from the Company, ratably, than
holders of Senior Indebtedness and may recover more, ratably, than the
Noteholders.
Notwithstanding the foregoing, payment from the money or the proceeds of
U.S. Government Obligations held in any defeasance trust described under
"Defeasance" below will not be contractually subordinated in right of payment to
any Senior Indebtedness of the Company or subject to the restrictions described
herein.
CERTAIN DEFINITIONS
"Additional Assets" means (i) any property or assets (other than
Indebtedness and Capital Stock) in the Oil and Gas Business of the Company; (ii)
the Capital Stock of a Person that becomes a Restricted Subsidiary as a result
of the acquisition of such Capital Stock by the Company or another Restricted
Subsidiary or (iii) Capital Stock constituting a minority interest in any Person
that at such time is a Restricted Subsidiary; provided, however, that any such
Restricted Subsidiary described in clauses (ii) or (iii) above is primarily
engaged in the Oil and Gas Business.
"Adjusted Consolidated Assets" means at any time the total amount of assets
of the Company and its Restricted Subsidiaries (less applicable depreciation,
amortization and other valuation reserves), after deducting therefrom all
current liabilities of the Company and its consolidated Restricted Subsidiaries
(excluding intercompany items), all as set forth on the consolidated balance
sheet of the Company and its Restricted Subsidiaries as of the end of the most
recent fiscal quarter ended at least 45 days prior to the date of determination.
"Adjusted Consolidated Net Tangible Assets" or "ACNTA" means (without
duplication), as of the date of determination, (a) the sum of (i) discounted
future net revenue from proved crude oil and natural gas reserves of the Company
and its Restricted Subsidiaries calculated in accordance with SEC guidelines
before any state or federal income taxes, as estimated in a reserve report
prepared as of the end of the Company's most recently completed fiscal year,
which reserve report is prepared or reviewed by independent petroleum engineers,
as increased by, as of the date of determination, the discounted future net
revenue of (A) estimated proved crude oil and natural gas reserves of the
Company and its Restricted Subsidiaries attributable to acquisitions consummated
since the date of such year-end reserve report, and (B) estimated crude oil and
natural gas reserves of the Company and its Restricted Subsidiaries attributable
to extensions, discoveries and other additions and upward determinations of
estimates of proved crude oil and natural gas reserves due to exploration,
development or exploitation, production or other activities which reserves were
not reflected in such year-end reserve report which would, in the case of
determinations made pursuant to clauses (A) and (B), in accordance with standard
industry practice, result in such additions or revisions, in each case
calculated in accordance with SEC guidelines (utilizing the prices utilized in
such year-end reserve report), and decreased by, as of the date of
determination, the discounted future net revenue attributable to (C) estimated
proved crude oil and natural gas reserves of the Company and its Restricted
Subsidiaries reflected in such year-end reserve report produced or disposed of
since the date of such year-end reserve report and (D) reductions in the
estimated crude oil and natural gas reserves of the Company and its Restricted
Subsidiaries reflected in such year-end reserve report since the date of such
year-end reserve report attributable to downward determinations of estimates of
proved crude oil and natural gas reserves due to exploration, development or
exploitation, production or other activities conducted or otherwise occurring
since the date of such year-end reserve report which would, in the case of
determinations made pursuant to clauses (C) and (D), in accordance with standard
industry practice, result in such determinations, in each case calculated in
accordance with SEC guidelines (utilizing the prices utilized in such year-end
reserve report); provided, however, that, in the case of each of the
determinations made pursuant to clauses (A) through (D), such increases and
decreases shall be as estimated by the Company's engineers, except that if as a
result of such acquisitions, dispositions, discoveries, extensions or revisions,
there is a Material Change which is an increase, then such increases and
decreases in the discounted future net revenue shall be confirmed in writing by
an independent petroleum engineer, (ii) the capitalized costs that are
attributable to crude oil and natural
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gas properties of the Company and its Restricted Subsidiaries to which no proved
crude oil and natural gas reserves are attributed, based on the Company's books
and records as of a date no earlier than the date of the Company's latest annual
or quarterly financial statements, (iii) the Net Working Capital on a date no
earlier than the date of the Company's latest annual or quarterly financial
statements and (iv) the greater of (I) the net book value on a date no earlier
than the date of the Company's latest annual or quarterly financial statements
and (II) the appraised value, as estimated by independent appraisers, of other
tangible assets of the Company and its Restricted Subsidiaries as of a date no
earlier than the date of the Company's latest audited financial statements
(provided that the Company shall not be required to obtain such an appraisal of
such assets if no such appraisal has been performed), minus (b) to the extent
not otherwise taken into account in the immediately preceding clause (a), the
sum of (i) minority interests, (ii) any natural gas balancing liabilities of the
Company and its Restricted Subsidiaries reflected in the Company's latest
audited financial statements, (iii) the discounted future net revenue,
calculated in accordance with SEC guidelines (utilizing the same prices utilized
in the Company's year-end reserve report), attributable to reserves subject to
participation interests, overriding royalty interests or other interests of
third parties, pursuant to participation, partnership, vendor financing or other
agreements then in effect, or which otherwise are required to be delivered to
third parties, (iv) the discounted future net revenue, calculated in accordance
with SEC guidelines (utilizing the same prices utilized in the Company's
year-end reserve report), attributable to reserves that are required to be
delivered to third parties to fully satisfy the obligations of the Company and
its Restricted Subsidiaries with respect to Volumetric Production Payments on
the schedules specified with respect thereto and (v) the discounted future net
revenue, calculated in accordance with SEC guidelines, attributable to reserves
subject to Dollar-Denominated Production Payments that, based on the estimates
of production included in determining the discounted future net revenue
specified in the immediately preceding clause (a)(i) (utilizing the same prices
utilized in the Company's year-end reserve report), would be necessary to
satisfy fully the obligations of the Company and its Restricted Subsidiaries
with respect to Dollar-Denominated Production Payments on the schedules
specified with respect thereto.
"Affiliate" of any specified Person means any other Person, directly or
indirectly, controlling or controlled by or under direct or indirect common
control with such specified Person. For the purposes of this definition,
"control" when used with respect to any Person means the power to direct the
management and policies of such Person, directly or indirectly, whether through
the ownership of voting securities, by contract or otherwise; and the terms
"controlling" and "controlled" have meanings correlative to the foregoing. For
purposes of the provisions described under "-- Certain Covenants -- Limitation
on Restricted Payments," "-- Certain Covenants -- Limitation on Affiliate
Transactions" and "-- Certain Covenants -- Limitations on Sales of Assets and
Subsidiary Stock" only, "Affiliate" shall also mean any beneficial owner of
Capital Stock representing 10% or more of the total voting power of the Voting
Stock (on a fully diluted basis) of the Company or of rights or warrants to
purchase such Capital Stock (whether or not currently exercisable) and any
Person who would be an Affiliate of any such beneficial owner pursuant to the
first sentence hereof.
"Asset Disposition" means any sale, lease, transfer or other disposition
(or series of related sales, leases, transfers or dispositions) by the Company
or any Restricted Subsidiary, including any disposition by means of a merger,
consolidation or similar transaction (each referred to for the purposes of this
definition as a "disposition"), of (i) any shares of Capital Stock of a
Restricted Subsidiary (other than directors' qualifying shares or shares
required by applicable law to be held by a Person other than the Company or a
Restricted Subsidiary), (ii) all or substantially all the assets of any division
or line of business of the Company or any Restricted Subsidiary or (iii) any
other assets of the Company or any Restricted Subsidiary outside of the ordinary
course of business of the Company or such Restricted Subsidiary. Notwithstanding
the foregoing, none of the following shall be deemed to be an Asset Disposition:
(1) a disposition by a Restricted Subsidiary to the Company or by the Company or
a Restricted Subsidiary to a Wholly Owned Subsidiary, (2) for purposes of the
covenant described under "-- Certain Covenants -- Limitation on Sales of Assets
and Subsidiary Stock" only, a disposition that constitutes a Restricted Payment
permitted by the covenant described under "-- Certain Covenants -- Limitation on
Restricted Payments"), a disposition of all or substantially all the assets of
the Company in compliance with "-- Certain Covenants -- Merger and
Consolidation" or a disposition that constitutes a Change of Control pursuant to
clause (iii) of the definition thereof, (3) the sale or transfer (whether or not
in the ordinary course of business) of crude oil and natural gas
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properties or direct or indirect interests in real property; provided, however,
that at the time of such sale or transfer such properties do not have associated
with them any proved reserves, (4) the abandonment, farm-out, lease or sublease
of developed or undeveloped crude oil and natural gas properties in the ordinary
course of business, (5) the trade or exchange by the Company or any Subsidiary
of the Company of any crude oil and natural gas property owned or held by the
Company or such Subsidiary for any crude oil and natural gas property owned or
held by another Person or (6) the sale or transfer of hydrocarbons or other
mineral products or surplus or obsolete equipment in the ordinary course of
business.
"Attributable Debt" in respect of a Sale/Leaseback Transaction means, as at
the time of determination, the present value (discounted at the interest rate
implicit in the Sale/Leaseback Transaction, compounded annually) of the total
obligations of the lessee for rental payments during the remaining term of the
lease included in such Sale/Leaseback Transaction (including any period for
which such lease has been extended).
"Average Life" means, as of the date of determination, with respect to any
Indebtedness or Preferred Stock, the quotient obtained by dividing (i) the sum
of the products of numbers of years from the date of determination to the dates
of each successive scheduled principal payment of such Indebtedness or
redemption or similar payment with respect to such Preferred Stock multiplied by
the amount of such payment by (ii) the sum of all such payments.
"Banks" has the meaning specified in the Credit Agreement.
"Board of Directors" means the Board of Directors of the Company or any
committee thereof duly authorized to act on behalf of such Board.
"Business Day" means each day which is not a Legal Holiday (as defined in
the Indenture).
"Capital Lease Obligations" means an obligation that is required to be
classified and accounted for as a capital lease for financial reporting purposes
in accordance with GAAP, and the amount of Indebtedness represented by such
obligation shall be the capitalized amount of such obligation determined in
accordance with GAAP; and the Stated Maturity thereof shall be the date of the
last payment of rent or any other amount due under such lease prior to the first
date upon which such lease may be terminated by the lessee without payment of a
penalty.
"Capital Stock" of any Person means any and all shares, interests, rights
to purchase, warrants, options, participation or other equivalents of or
interests in (however designated) equity of such Person, including any Preferred
Stock, but excluding any debt securities convertible into such equity.
"Change of Control" means the occurrence of any of the following events:
(i) any "person" (as such term is used in Sections 13(d) and 14(d) of
the Exchange Act) is or becomes the beneficial owner (as defined in Rules
13d-3 and 13d-5 under the Exchange Act, except that for purposes of this
clause (i) such person shall be deemed to have "beneficial ownership" of
all shares that such person has the right to acquire, whether such right is
exercisable immediately or only after the passage of time), directly or
indirectly, of more than 35% of the total voting power of the Voting Stock
of the Company (for the purposes of this clause (i), such person shall be
deemed to beneficially own any Voting Stock of a specified corporation held
by a parent corporation, if such person is the beneficial owner (as defined
in this clause (i)), directly or indirectly, of more than 35% of the voting
power of the Voting Stock of such parent corporation;
(ii) during any period of two consecutive years from and after the
Issue Date, individuals who at the beginning of such period constituted the
Board of Directors (together with any new directors whose election by such
Board of Directors or whose nomination for election by the shareholders of
the Company was approved by a vote of a majority of the directors of the
Company then still in office who were either directors at the beginning of
such period or whose election or nomination for election was previously so
approved) cease for any reason to constitute a majority of the Board of
Directors then in office; or
(iii) the merger or consolidation of the Company with or into another
Person or the merger of another Person with or into the Company, or the
sale of all or substantially all the assets of the Company
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to another Person (other than a Person that is controlled by the Permitted
Holders), and, in the case of any such merger or consolidation, the
securities of the Company that are outstanding immediately prior to such
transaction and which represent 100% of the aggregate voting power of the
Voting Stock of the Company are changed into or exchanged for cash,
securities or property, unless pursuant to such transaction such securities
are changed into or exchanged for, in addition to any other consideration,
securities of the surviving corporation that represent immediately after
such transaction, at least a majority of the aggregate voting power of the
Voting Stock of the surviving corporation.
"Code" means the Internal Revenue Code of 1986, as amended.
"Consolidated Coverage Ratio" as of any date of determination means the
ratio of (i) the aggregate amount of EBITDA for the period of the most recent
four consecutive fiscal quarters ending at least 45 days prior to the date of
such determination to (ii) Consolidated Interest Expense for such four fiscal
quarters; provided, however, that (1) if the Company or any Restricted
Subsidiary has Incurred any Indebtedness since the beginning of such period that
remains outstanding or if the transaction giving rise to the need to calculate
the Consolidated Coverage Ratio is an Incurrence of Indebtedness, or both,
EBITDA and Consolidated Interest Expense for such period shall be calculated
after giving effect on a pro forma basis to such Indebtedness as if such
Indebtedness had been Incurred on the first day of such period and the discharge
of any other Indebtedness repaid, repurchased, defeased or otherwise discharged
with the proceeds of such new Indebtedness as if such discharge had occurred on
the first day of such period, (2) if the Company or any Restricted Subsidiary
has repaid, repurchased, defeased or otherwise discharged any Indebtedness since
the beginning of such period or if any Indebtedness is to be repaid,
repurchased, defeased or otherwise discharged on the date of the transaction
giving rise to the need to calculate the Consolidated Coverage Ratio, EBITDA and
Consolidated Interest Expense for such period shall be calculated on a pro forma
basis as if such discharge had occurred on the first day of such period and as
if the Company or such Restricted Subsidiary has not earned the interest income
actually earned during such period in respect of cash or Temporary Cash
Investments used to repay, repurchase, defease or otherwise discharge such
Indebtedness, (3) if since the beginning of such period the Company or any
Restricted Subsidiary shall have made any Asset Disposition (other than an Asset
Disposition involving assets having a fair market value of less than the greater
of one percent (1%) of Adjusted Consolidated Net Tangible Assets as of the end
of the Company's then most recently completed fiscal year and $2.0 million),
then EBITDA for such period shall be reduced by an amount equal to EBITDA (if
positive) directly attributable to the assets which are the subject of such
Asset Disposition for such period, or increased by an amount equal to EBITDA (if
negative), directly attributable thereto for such period and Consolidated
Interest Expense for such period shall be reduced by an amount equal to the
Consolidated Interest Expense directly attributable to any Indebtedness of the
Company or any Restricted Subsidiary repaid, repurchased, defeased or otherwise
discharged with respect to the Company and its continuing Restricted
Subsidiaries in connection with such Asset Disposition for such period (or, if
the Capital Stock of any Restricted Subsidiary is sold, the Consolidated
Interest Expense for such period directly attributable to the Indebtedness of
such Restricted Subsidiary to the extent the Company and its continuing
Restricted Subsidiaries are no longer liable for such Indebtedness after such
sale), (4) if since the beginning of such period the Company or any Restricted
Subsidiary (by merger or otherwise) shall have made an Investment in any
Restricted Subsidiary (or any person which becomes a Restricted Subsidiary) or
an acquisition (including by way of lease) of assets, including any acquisition
of assets occurring in connection with a transaction requiring a calculation to
be made hereunder, EBITDA and Consolidated Interest Expense for such period
shall be calculated after giving pro forma effect thereto (including the
Incurrence of any Indebtedness) as if such Investment or acquisition occurred on
the first day of such period and (5) if since the beginning of such period any
Person (that subsequently became a Restricted Subsidiary or was merged with or
into the Company or any Restricted Subsidiary since the beginning of such
period) shall have made any Asset Disposition, any Investment or acquisition of
assets that would have required an adjustment pursuant to clause (3) or (4)
above if made by the Company or a Restricted Subsidiary during such period,
EBITDA and Consolidated Interest Expense for such period shall be calculated
after giving pro forma effect thereto as if such Asset Disposition, Investment
or acquisition occurred on the first day of such period. For purposes of this
definition, whenever pro forma effect is to be given to an acquisition of
assets, the amount of income or earnings relating thereto and the amount of
Consolidated Interest Expense associated with any Indebtedness
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Incurred in connection therewith, the pro forma calculations shall be determined
in good faith by a responsible financial or accounting Officer of the Company.
If any Indebtedness bears a floating rate of interest and is being given pro
forma effect, the interest of such Indebtedness shall be calculated as if the
rate in effect on the date of determination had been the applicable rate for the
entire period (taking into account any Interest Rate Agreement applicable to
such Indebtedness if such Interest Rate Agreement has a remaining term in excess
of 12 months).
"Consolidated Current Liabilities" as of the date of determination means
the aggregate amount of liabilities of the Company and its Restricted
Subsidiaries which would properly be classified as current liabilities
(including taxes accrued as estimated), on a consolidated balance sheet of the
Company and its Restricted Subsidiaries at such date, after eliminating (i) all
intercompany items between the Company and any Restricted Subsidiary and (ii)
all current maturities of long-term Indebtedness, all as determined in
accordance with GAAP consistently applied.
"Consolidated Indebtedness" at any date of determination means the
principal amount of Indebtedness of the Company and its Restricted Subsidiaries
outstanding on such date determined on a consolidated basis in accordance with
GAAP.
"Consolidated Interest Expense" means, for any period, the total interest
expense of the Company and its Restricted Subsidiaries for such period,
determined on a consolidated basis in accordance with GAAP, plus, to the extent
not included in such total interest expense, and to the extent incurred by the
Company or its Restricted Subsidiaries, without duplication, (i) interest
expense attributable to Capital Lease Obligations and imputed interest with
respect to Attributable Debt, (ii) capitalized interest, (iii) non-cash interest
expenses, (iv) commissions, discounts and other fees and charges owed with
respect to letters of credit and bankers' acceptance financing, (v) net costs
(including amortization of fees and up-front payments) associated with interest
rate caps and other interest rate and currency options that, at the time entered
into, resulted in the Company and its Restricted Subsidiaries being net payees
as to future payouts under such caps or options, and interest rate and currency
swaps and forwards for which the Company or any of its Restricted Subsidiaries
has paid a premium, (vi) dividends (excluding dividends paid in shares of
Capital Stock which is not Disqualified Stock) in respect of all Disqualified
Stock held by Persons other than the Company or a Wholly Owned Subsidiary, (vii)
interest accruing on any Indebtedness of any other Person to the extent such
Indebtedness is Guaranteed by the Company or any Restricted Subsidiary or
secured by a Lien on assets of the Company or any Restricted Subsidiary to the
extent such Indebtedness constitutes Indebtedness of the Company or any
Restricted Subsidiary (whether or not such Guarantee or Lien is called upon);
provided, however, "Consolidated Interest Expense" shall not include any (x)
amortization of costs relating to original debt issuances other than the
amortization of debt discount related to the issuance of zero coupon securities
or other securities with an original issue price of not more than 90% of the
principal thereof, (y) Consolidated Interest Expense with respect to any
Indebtedness Incurred pursuant to clause (b)(8) of the covenant described under
"-- Certain Covenants -- Limitation on Indebtedness" and (z) noncash interest
expense Incurred in connection with interest rate caps and other interest rate
and currency options that, at the time entered into, resulted in the Company and
its Restricted Subsidiaries being either neutral or net payors as to future
payouts under such caps or options.
"Consolidated Net Income" means, for any period, the net income of the
Company and its Subsidiaries determined on a consolidated basis; provided,
however, that there shall not be included in such Consolidated Net Income: (i)
any net income of any Person (other than the Company) if such Person is not a
Restricted Subsidiary, except that (A) subject to the exclusion contained in
clause (iv) below, the Company's equity in the net income of any such Person for
such period shall be included in such Consolidated Net Income up to the
aggregate amount of cash actually distributed by such Person during such period
to the Company or a Restricted Subsidiary as a dividend or other distribution
(subject, in the case of a dividend or other distribution paid to a Restricted
Subsidiary, to the limitations contained in clause (iii) below) and (B) the
Company's equity in a net loss of any such Person for such period shall be
included in determining such Consolidated Net Income; (ii) any net income (or
loss) of any Person acquired by the Company or a Subsidiary in a pooling of
interests transaction for any period prior to the date of such acquisition;
(iii) any net income of any Restricted Subsidiary (other than a Subsidiary
Guarantor) if such Restricted Subsidiary is
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subject to restrictions, directly or indirectly, on the payment of dividends or
the making of distributions by such Restricted Subsidiary, directly or
indirectly, to the Company, except that (A) subject to the exclusion contained
in clause (iv) below, the Company's equity in the net income of any such
Restricted Subsidiary for such period shall be included in such Consolidated Net
Income up to the aggregate amount of cash actually distributed by such
Restricted Subsidiary during such period to the Company or another Restricted
Subsidiary as a dividend or other distribution (subject, in the case of a
dividend or other distribution paid to another Restricted Subsidiary, to the
limitation contained in this clause) and (B) the Company's equity in a net loss
of any such Restricted Subsidiary for such period shall be included in
determining such Consolidated Net Income; (iv) any gain or loss realized upon
the sale or other disposition of any assets of the Company or its consolidated
Subsidiaries (including pursuant to any sale-and-leaseback arrangement) which is
not sold or otherwise disposed of in the ordinary course of business and any
gain or loss realized upon the sale or other disposition of any Capital Stock of
any Person; (v) extraordinary gains or losses; and (vi) the cumulative effect of
a change in accounting principles. Notwithstanding the foregoing, for the
purposes of the covenant described under "Certain Covenants -- Limitation on
Restricted Payments" only, there shall be excluded from Consolidated Net Income
any dividends, repayments of loans or advances or other transfers of assets from
Unrestricted Subsidiaries to the Company or a Restricted Subsidiary to the
extent such dividends, repayments or transfers increase the amount of Restricted
Payments permitted under such covenant pursuant to clause (a)(3)(D) thereof.
"Consolidated Net Tangible Assets," as of any date of determination, means
the total amount of assets (less accumulated depreciation and amortization,
allowances for doubtful receivables, other applicable reserves and other
properly deductible items) which would appear on a balance sheet of the Company
and its Restricted Subsidiaries, determined on a consolidated basis in
accordance with GAAP, and after giving effect to purchase accounting and after
deducting therefrom Consolidated Current Liabilities and, to the extent
otherwise included, the amounts of: (i) minority interests in Restricted
Subsidiaries held by Persons other than the Company or a Restricted Subsidiary;
(ii) excess of cost over fair value of assets of businesses acquired, as
determined in good faith by the Board of Directors; (iii) any revaluation or
other write-up in book value of assets subsequent to the Issue Date as a result
of a change in the method of valuation in accordance with GAAP consistently
applied; (iv) unamortized debt discount and expenses and other unamortized
deferred charges, goodwill, patents, trademarks, service marks, trade names,
copyrights, licenses, organization or developmental expenses and other
intangible items; (v) treasury stock; (vi) cash set apart and held in a sinking
or other analogous fund established for the purpose of redemption or other
retirement of Capital Stock to the extent such obligation is not reflected in
Consolidated Current Liabilities; and (vii) Investments in and assets of
Unrestricted Subsidiaries.
"Consolidated Net Worth" means the total of the amounts shown on the
balance sheet of the Company and its consolidated Subsidiaries, determined on a
consolidated basis in accordance with GAAP, as of the end of the most recent
fiscal quarter of the Company ending at least 45 days prior to the taking of any
action for the purpose of which the determination is being made, as (i) the par
or stated value of all outstanding Capital Stock of the Company plus (ii)
paid-in capital or capital surplus relating to such Capital Stock plus (iii) any
retained earnings or earned surplus less (A) any accumulated deficit and (B) any
amounts attributable to Disqualified Stock.
"Credit Agreement" means that certain Credit Agreement, dated as of August
8, 1996, as amended, by and among the Company and (or any successor thereto or
replacement thereof), as agent and as a lender, and certain other institutions,
as lenders, providing for up to $250.0 million of Indebtedness, including any
related notes, guarantees, collateral documents, instruments and agreements
executed in connection therewith, and in each case as amended, restated,
modified, renewed, refunded, replaced or refinanced, in whole or in part, from
time to time.
"Credit Facilities" means, with respect to the Company or any Restricted
Subsidiary, one or more debt facilities (including the Credit Agreement) or
commercial paper facilities with banks or other institutional lenders providing
for revolving credit loans, term loans, production payments, receivables
financing (including through the sale of receivables to such lenders or to
special purpose entities formed to borrow from such
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lenders against such receivables) or letters of credit, in each case, as
amended, restated, modified, renewed, refunded, replaced or refinanced in whole
or in part from time to time.
"Currency Agreement" means in respect of a Person any foreign exchange
contract, currency swap agreement or other similar agreement to which such
Person is a party or a beneficiary.
"Default" means any event which is, or after notice or passage of time or
both would be, an Event of Default.
"Designated Senior Indebtedness" in respect of a Subsidiary Guarantor means
(i) all the obligations of such Subsidiary Guarantor under any Credit Facility
(including the Credit Agreement) and (ii) any other Senior Indebtedness of such
Subsidiary Guarantor which, at the date of determination, has an aggregate
principal amount outstanding of, or under which, at the date of determination,
the holders thereof are committed to lend up to, at least $25.0 million and is
specifically designated by such Subsidiary Guarantor in the instrument
evidencing or governing such Senior Indebtedness as "Designated Senior
Indebtedness" for purposes of the Indenture.
"Disqualified Stock" means, with respect to any Person, any Capital Stock
to the extent that by its terms (or by the terms of any security into which it
is convertible or for which it is exchangeable) or upon the happening of any
event, it (i) matures or is mandatorily redeemable pursuant to a sinking fund
obligation or otherwise, (ii) is convertible or exchangeable for Indebtedness or
Disqualified Stock or (iii) is redeemable, in whole or in part, at the option of
the holder thereof, in each case described in the immediately preceding clauses
(i) , (ii) or (iii), on or prior to the Stated Maturity of the Notes; provided,
however, that any Capital Stock that would not constitute Disqualified Stock but
for provisions thereof giving holders thereof the right to require such Person
to repurchase or redeem such Capital Stock upon the occurrence of an "asset
sale" or "change of control" occurring prior to the first anniversary of the
Stated Maturity of the Notes shall not constitute Disqualified Stock if (x) the
"asset sale" or "change of control" provisions applicable to such Capital Stock
are not more favorable to the holders of such Capital Stock than the provisions
described under "-- Certain Covenants -- Limitation on Sales of Assets and
Subsidiary Stock" and "-- Certain Covenants -- Change of Control" and (y) any
such requirement only becomes operative after compliance with such corresponding
terms applicable to the Notes, including the purchase of any Notes tendered
pursuant thereto.
"Dollar-Denominated Production Payments" means production payment
obligations recorded as liabilities in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
"EBITDA" for any period means the sum of Consolidated Net Income, plus
Consolidated Interest Expense plus the following to the extent deducted in
calculating such Consolidated Net Income: (a) provision for taxes based on
income or profits, (b) depletion and depreciation expense, (c) amortization
expense (d) exploration costs and (e) all other noncash charges (excluding any
such non-cash charge to the extent that it represents an accrual of or reserve
for cash charges in any future period or amortization of a prepaid cash expense
that was paid in a prior period except such amounts as the Company determines in
good faith are nonrecurring), and less, to the extent included in calculating
such Consolidated Net Income and in excess of any costs or expenses attributable
thereto and deducted in calculating such Consolidated Net Income, the sum of (x)
the amount of deferred revenues that are amortized during such period and are
attributable to reserves that are subject to Volumetric Production Payments and
(y) amounts recorded in accordance with GAAP as repayments of principal and
interest pursuant to Dollar-Denominated Production Payments. Notwithstanding the
foregoing, the provision for taxes based on the income or profits of, and the
depreciation and amortization and other non-cash charges of, a Restricted
Subsidiary of the Company shall be added to Consolidated Net Income to compute
EBITDA only to the extent (and in the same proportion) that the net income of
such Restricted Subsidiary was included in calculating Consolidated Net Income
and only if a corresponding amount would be permitted at the date of
determination to be dividended to the Company by such Restricted Subsidiary
without prior approval (that has not been obtained), pursuant to the terms of
its charter and all agreements, instruments, judgments, decrees, orders,
statutes, rules and governmental regulations applicable to such Restricted
Subsidiary or its stockholders.
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"Equity Offering" means a primary offering, whether public or private, of
shares of common stock of the Company.
"Exchange Act" means the Securities Exchange Act of 1934, as amended.
"Exempt Foreign Subsidiary" means (i) any Subsidiary engaged in the Oil and
Gas Business exclusively outside the United States of America, irrespective of
its jurisdiction of incorporation and (ii) any other Subsidiary whose assets
(excluding any cash and Cash Equivalents) consist exclusively of Capital Stock
or Indebtedness of one or more Subsidiaries described in clause (i) of this
definition, that, in any case, is so designated by the Company in an Officers'
Certificate delivered to the Trustee and (a) is not a guarantor of, and has not
granted any lien to secure, any Indebtedness of the Company or any Subsidiary
other than another Exempt Foreign Subsidiary and (b) does not have total assets
that, when aggregated with the total assets of any other Exempt Foreign
Subsidiary, exceed 25% of the Company's consolidated total assets, as determined
in accordance with GAAP, as reflected on the Company's most recent quarterly or
annual balance sheet. The Company may revoke the designation of any Exempt
Foreign Subsidiary by notice to the Trustee.
"GAAP" means generally accepted accounting principles in the United States
of America as in effect on the Issue Date, including those set forth in (i) the
opinions and pronouncements of the Accounting Principles Board of the American
Institute of Certified Public Accountants, (ii) statements and pronouncements of
the Financial Accounting Standards Board, (iii) such other statements by such
other entity as approved by a significant segment of the accounting profession,
and (iv) the rules and regulations of the SEC governing the inclusion of
financial statements (including pro forma financial statements) in periodic
reports required to be filed pursuant to Section 13 of the Exchange Act,
including opinions and pronouncements in staff accounting bulletins and similar
written statements from the accounting staff of the SEC.
"Guarantee" means, without duplication, any obligation, contingent or
otherwise, of any Person directly or indirectly guaranteeing any Indebtedness of
any Person and any obligation, direct or indirect, contingent or otherwise, of
such Person (i) to purchase or pay (or advance or supply funds for the purchase
or payment of) such Indebtedness of such Person (whether arising by virtue of
partnership arrangements, or by agreements to keep-well, to purchase assets,
goods, securities or services, to take-or-pay or to maintain financial statement
conditions or otherwise) or (ii) entered into for the purpose of assuring in any
other manner the obligee of such Indebtedness of the payment thereof or to
protect such obligee against loss in respect thereof (in whole or in part);
provided, however, that the term "Guarantee" shall not include endorsements for
collection or deposit in the ordinary course of business. The term "Guarantee"
used as a verb has a corresponding meaning. The term "Guarantor" shall mean any
Person Guaranteeing any obligation.
"Hedging Obligations" of any Person means the obligations of such Person
pursuant to any Oil and Gas Hedging Contract, Interest Rate Agreement or
Currency Agreement.
"Holder" or "Noteholder" means the Person in whose name a Note is
registered on the Registrar's books.
"Incur" means issue, assume, Guarantee, incur or otherwise become liable
for; provided, however, that any Indebtedness or Capital Stock of a Person
existing at the time such Person becomes a Subsidiary (whether by merger,
consolidation, acquisition or otherwise) shall be deemed to be Incurred by such
Subsidiary at the time it becomes a Subsidiary. The term "Incurrence" when used
as a noun shall have a correlative meaning. The accretion of principal of a
non-interest bearing or other discount security shall not be deemed the
Incurrence of Indebtedness.
"Indebtedness" means, with respect to any Person on any date of
determination (without duplication), (i) the principal of and premium (if any)
in respect of (A) indebtedness of such Person for money borrowed and (B)
indebtedness evidenced by notes, debentures, bonds or other similar instruments
for the payment of which such Person is responsible or liable; (ii) all Capital
Lease Obligations of such Person and all Attributable Debt in respect of
Sale/Leaseback Transactions entered into by such Person; (iii) all obligations
of such Person issued or assumed as the deferred purchase price of property
(which purchase price is due more than six months after the date of taking
delivery of title to such property), including all obligations of such Person
for the deferred purchase price of property under any title retention agreement
(but excluding trade accounts payable arising in the ordinary course of
business); (iv) all obligations of such Person for the
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reimbursement of any obligor on any letter of credit, banker's acceptance or
similar credit transaction (other than obligations with respect to letters of
credit securing obligations (other than obligations described in (i) through
(iii) above) entered into in the ordinary course of business of such Person to
the extent such letters of credit are not drawn upon or, if and to the extent
drawn upon, such drawing is reimbursed no later than the tenth Business Day
following receipt by such Person of a demand for reimbursement following payment
on the letter of credit); (v) the amount of all obligations of such Person with
respect to the redemption, repayment or other repurchase of any Disqualified
Stock or, with respect to any Subsidiary of such Person the liquidation
preference with respect to, any Preferred Stock (but excluding, in each case,
any accrued dividends); (vi) all obligations of such Person relating to any
Production Payment or in respect of production imbalances (but excluding
production imbalances arising in the ordinary course of business); (vii) all
obligations of the type referred to in clauses (i) through (vi) of other Persons
and all dividends of other Persons for the payment of which, in either case,
such Person is responsible or liable, directly or indirectly, as obligor,
guarantor or otherwise, including by means of any Guarantee (including, with
respect to any Production Payment, any warranties or guarantees of production or
payment by such Person with respect to such Production Payment but excluding
other contractual obligations of such Person with respect to such Production
Payment); (viii) all obligations of the type referred to in clauses (i) through
(vii) of other Persons secured by any Lien on any property or asset of such
first-mentioned Person (whether or not such obligation is assumed by such
first-mentioned Person), the amount of such obligation being deemed to be the
lesser of the value of such property or assets or the amount of the obligation
so secured and (ix) to the extent not otherwise included in this definition,
Hedging Obligations of such Person. The amount of Indebtedness of any Person at
any date shall be the outstanding balance at such date of all unconditional
obligations as described above and the maximum liability, assuming the
contingency giving rise to the obligation were to have occurred on such date, of
any Guarantees outstanding at such date.
None of the following shall constitute Indebtedness: (i) indebtedness
arising from agreements providing for indemnification or adjustment of purchase
price or from guarantees securing any obligations of the Company or any of its
Subsidiaries pursuant to such agreements, incurred or assumed in connection with
the disposition of any business, assets or Subsidiary of the Company, other than
guarantees or similar credit support by the Company or any of its Subsidiaries
of Indebtedness incurred by any Person acquiring all or any portion of such
business, assets or Subsidiary for the purpose of financing such acquisition;
(ii) any trade payables and other accrued current liabilities incurred in the
ordinary course of business as the deferred purchase price of property; (iii)
obligations arising from guarantees to suppliers, lessors, licensees,
contractors, franchisees or customers incurred in the ordinary course of
business; (iv) obligations (other than express Guarantees of indebtedness for
borrowed money) in respect of Indebtedness of other Persons arising in
connection with (A) the sale or discount of accounts receivable, (B) trade
acceptances and (C) endorsements of instruments for deposit in the ordinary
course of business; (v) obligations in respect of performance bonds provided by
the Company or its Subsidiaries in the ordinary course of business and
refinancing thereof; (vi) obligations arising from the honoring by a bank or
other financial institution of a check, draft or similar instrument drawn
against insufficient funds in the ordinary course of business, provided,
however, that such obligation is extinguished within two Business Days of its
incurrence; and (vii) obligations in respect of any obligations under workers'
compensation laws and similar legislation.
"Interest Rate Agreement" means any interest rate swap agreement, interest
rate cap agreement or other financial agreement or arrangement designed to
protect the Company or any Restricted Subsidiary against fluctuations in
interest rates.
"Investment" in any Person means any direct or indirect advance, loan
(other than advances to customers or joint interest partners or drilling
partnerships sponsored by the Company or any Restricted Subsidiary in the
ordinary course of business that are recorded as accounts receivable on the
balance sheet of the lender) or other extensions of credit (including by way of
Guarantee or similar arrangement) or capital contribution to (by means of any
transfer of cash or other property to others or any payment for property or
services for the account or use of others), or any purchase or acquisition of
Capital Stock, Indebtedness or other similar instruments issued by such Person.
For purposes of the definition of "Unrestricted Subsidiary," the definition of
"Restricted Payment" and the covenant described under "-- Certain
Covenants -- Limita-
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tion on Restricted Payments," (i) "Investment" shall include the portion
(proportionate to the Company's equity interest in such Subsidiary) of the fair
market value of the net assets of any Subsidiary of the Company at the time that
such Subsidiary is designated an Unrestricted Subsidiary; provided, however,
that upon a redesignation of such Subsidiary as a Restricted Subsidiary, the
Company shall be deemed to continue to have a permanent "Investment" in an
Unrestricted Subsidiary equal to an amount (if positive) equal to (x) the
Company's "Investment" in such Subsidiary at the time of such redesignation less
(y) the portion (proportionate to the Company's equity interest in such
Subsidiary) of the fair market value of the net assets of such Subsidiary at the
time of such redesignation; and (ii) any property transferred to or from an
Unrestricted Subsidiary shall be valued at its fair market value at the time of
such transfer, in each case as determined in good faith by the Board of
Directors.
"Issue Date" means the date on which the Notes are originally issued.
"Lien" means any mortgage, pledge, security interest, encumbrance, lien or
charge of any kind (including any conditional sale or other title retention
agreement or lease in the nature thereof).
"Limited Recourse Indebtedness" means, with respect to any Production
Payments, Indebtedness, the terms of which limit the liability of the Company
and its Restricted Subsidiaries solely to the hydrocarbons covered by such
Production Payments; provided, however, that no default with respect to such
Indebtedness would permit any holder of any other Indebtedness of the Company or
any Restricted Subsidiary to declare a default on such other Indebtedness or
cause the payment thereof to be accelerated or payable prior to its stated
maturity.
"Material Change" means an increase or decrease (excluding changes that
result solely from changes in prices) of more than 15% during a fiscal quarter
in the discounted future net revenues from proved crude oil and natural gas
reserves of the Company and its Restricted Subsidiaries, calculated in
accordance with clause (a)(i) of the definition of Adjusted Consolidated Net
Tangible Assets; provided, however, that the following will be excluded from the
calculation of Material Change: (i) any acquisitions during the fiscal quarter
of crude oil and natural gas reserves that have been estimated by independent
petroleum engineers and with respect to which a report or reports of such
engineers exist and (ii) any disposition of properties existing at the beginning
of such fiscal quarter that have been disposed of in compliance with the
covenant described under "-- Certain Covenants -- Limitation on Sales of Assets
and Subsidiary Stock."
"Moody's" means Moody's Investor's Service, Inc. and its successors.
"Net Available Cash" from an Asset Disposition means cash payments received
therefrom (including any cash payments received by way of deferred payment of
principal pursuant to a note or installment receivable or otherwise, but only as
and when received, but excluding any other consideration received in the form of
assumption by the acquiring Person of Indebtedness or other obligations relating
to such properties or assets or received in any other noncash form) in each case
net of (i) all legal, title and recording tax expenses, commissions and other
fees (including financial and other advisory fees) and expenses incurred, and
all Federal, state, provincial, foreign and local taxes required to be accrued
as a liability under GAAP, as a consequence of such Asset Disposition, (ii) all
payments made on any Indebtedness which is secured by any assets subject to such
Asset Disposition, in accordance with the terms of any Lien upon or other
security agreement of any kind with respect to such assets, or which must by its
terms, or in order to obtain a necessary consent to such Asset Disposition, or
by applicable law, be repaid out of the proceeds from such Asset Disposition,
(iii) all distributions and other payments required to be made to minority
interest holders in Subsidiaries or joint ventures as a result of such Asset
Disposition and (iv) the deduction of appropriate amounts provided by the seller
as a reserve, in accordance with GAAP, against any liabilities associated with
the property or other assets disposed in such Asset Disposition and retained by
the Company or any Restricted Subsidiary after such Asset Disposition.
"Net Cash Proceeds," with respect to any issuance or sale of Capital Stock,
means the cash proceeds of such issuance or sale net of attorneys' fees,
accountants' fees, underwriters' or placement agents' fees, discounts or
commissions and brokerage, consultant and other fees actually incurred in
connection with such issuance or sale and net of taxes paid or payable as a
result thereof.
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"Net Present Value" means, with respect to any proved hydrocarbon reserves,
the discounted future net cash flows associated with such reserves, determined
in accordance with the rules and regulations (including interpretations thereof)
of the SEC in effect on the Issue Date.
"Oil and Gas Business" means the business of the exploration for, and
exploitation, development, acquisition, production, processing (but not
refining), marketing, storage and transportation of, hydrocarbons, and other
related energy and natural resource businesses (including oil and gas services
businesses related to the foregoing).
"Net Working Capital" means (a) all current assets of the Company and its
Restricted Subsidiaries minus (b) all current liabilities of the Company and its
Restricted Subsidiaries, except current liabilities included in Indebtedness,
determined in accordance with GAAP.
"Oil and Gas Hedging Contract" means any oil and gas purchase or hedging
agreement, and other agreement or arrangement, in each case, that is designed to
provide protection against oil and gas price fluctuations.
"Permitted Business Investment" means any investment or expenditure made in
the ordinary course of, and of a nature that is or shall have become customary
in, the Oil and Gas Business, including investments or expenditures for actively
exploiting, exploring for, acquiring, developing, producing, processing,
gathering, marketing or transporting oil and gas through agreements,
transactions, interests or arrangements which permit one to share risks or
costs, comply with regulatory requirements regarding local ownership or satisfy
other objectives customarily achieved through the conduct of Oil and Gas
Business jointly with third parties, including (i) ownership interests in oil
and gas properties, processing facilities, gathering systems or ancillary real
property interests and (ii) Investments in the form of or pursuant to operating
agreements, processing agreements, farm-in agreements, farm-out agreements,
development agreements, area of mutual interest agreements, unitization
agreements, pooling agreements, joint bidding agreements, service contracts,
joint venture agreements, partnership agreements (whether general or limited),
subscription agreements, stock purchase agreements and other similar agreements
with third parties.
"Permitted Investment" means an Investment by the Company or any Restricted
Subsidiary in (i) a Restricted Subsidiary or a Person that will, upon the making
of such Investment, become a Restricted Subsidiary; provided, however, that the
primary business of such Restricted Subsidiary is an Oil and Gas Business; (ii)
another Person if as a result of such Investment such other Person is merged or
consolidated with or into, or transfers or conveys all or substantially all its
assets to, the Company or a Restricted Subsidiary; provided, however, that such
Person's primary business is an Oil and Gas Business; (iii) Temporary Cash
Investments; (iv) receivables owing to the Company or any Restricted Subsidiary
if created or acquired in the ordinary course of business and payable or
dischargeable in accordance with customary trade terms; provided, however, that
such trade terms may include such concessionary trade terms as the Company or
any such Restricted Subsidiary deems reasonable under the circumstances; (v)
payroll, travel and similar advances to cover matters that are expected at the
time of such advances ultimately to be treated as expenses for accounting
purposes and that are made in the ordinary course of business; (vi) loans or
advances to employees made in the ordinary course of business; (vii) stock,
obligations or securities received in settlement of debts created in the
ordinary course of business and owing to the Company or any Restricted
Subsidiary or in satisfaction of judgments; (viii) any Person to the extent such
Investment represents the non-cash portion of the consideration received for an
Asset Disposition as permitted pursuant to the covenant described under
"-- Certain Covenants -- Limitation on Sales of Assets and Subsidiary Stock" and
(ix) Permitted Business Investments.
"Permitted Liens" means, with respect to any Person, (a) pledges or
deposits by such Person under worker's compensation laws, unemployment insurance
laws or similar legislation, or good faith deposits in connection with bids,
tenders, contracts (other than for the payment of Indebtedness) or leases to
which such Person is a party, or deposits to secure public or statutory
obligations of such Person or deposits of cash or United States government bonds
to secure surety or appeal bonds to which such Person is a party, or deposits as
security for contested taxes or import duties or for the payment of rent, in
each case Incurred in the ordinary course of business; (b) Liens imposed by law,
such as carriers', warehousemen's and mechanics'
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Liens, in each case for sums not yet due or being contested in good faith by
appropriate proceedings or other Liens arising out of judgments or awards
against such Person with respect to which such Person shall then be proceeding
with an appeal or other proceedings for review; (c) Liens for property taxes not
yet subject to penalties for non-payment or which are being contested in good
faith and by appropriate proceedings; (d) Liens in favor of issuers of surety
bonds or letters of credit issued pursuant to the request of and for the account
of such Person in the ordinary course of its business; provided, however, that
such letters of credit do not constitute Indebtedness; (e) minor survey
exceptions, minor encumbrances, easements or reservations of, or rights of
others for, licenses, rights of way, sewers, electric lines, telegraph and
telephone lines and other similar purposes, or zoning or other restrictions as
to the use of real property or Liens incidental to the conduct of the business
of such Person or to the ownership of its properties which were not Incurred in
connection with Indebtedness and which do not in the aggregate materially impair
their use in the operation of the business of such Person; (f) Liens securing
Indebtedness Incurred to finance the construction, purchase or lease of, or
repairs, improvements or additions to, property of such Person (including Liens
securing Indebtedness of the pollution control or revenue bond type); provided,
however, that the Lien may not extend to any other property owned by such Person
or any of its Subsidiaries at the time the Lien is Incurred, and the
Indebtedness secured by the Lien may not be Incurred more than 180 days after
the later of the acquisition, completion of construction, repair, improvement,
addition or commencement of full operation of the property subject to the Lien;
(g) Liens to secure Indebtedness permitted under the provisions described in
clause (b)(1) or (b)(8) under "-- Certain Covenants -- Limitation on
Indebtedness;" provided, however, that any such Lien securing Indebtedness
described in such clause (b)(8) shall be limited to the hydrocarbons related
thereto and any gathering systems utilized in gathering and transporting such
hydrocarbons; (h) Liens existing on the Issue Date; (i) Liens on property or
shares of Capital Stock of another Person at the time such other Person becomes
a Subsidiary of such Person; provided, however, that such Liens are not created,
incurred or assumed in connection with, or in contemplation of, such other
Person becoming such a Subsidiary; provided further, however, that such Lien may
not extend to any other property owned by such Person or any of its
Subsidiaries; (j) Liens on property at the time such Person or any of its
Subsidiaries acquires the property, including any acquisition by means of a
merger or consolidation with or into such Person or a Subsidiary of such Person;
provided, however, that such Liens are not created, incurred or assumed in
connection with, or in contemplation of, such acquisition; provided further,
however, that the Liens may not extend to any other property owned by such
Person or any of its Subsidiaries; (k) Liens securing Indebtedness or other
obligations of a Subsidiary of such Person owing to such Person or a wholly
owned Subsidiary of such Person (or, in the case of the Company, to a Wholly
Owned Subsidiary); (l) Liens securing Hedging Obligations so long as such
Hedging Obligations relate to Indebtedness that is, and is permitted to be under
the Indenture, secured by a Lien on the same property securing such Hedging
Obligations; (m) Liens arising in the ordinary course of business in favor of
the United States, any state thereof, any foreign country or any department,
agency, instrumentality or political subdivision of any such jurisdiction, to
secure partial, progress, advance or other payments pursuant to any contract or
statute; (n) Liens to secure any Refinancing (or successive Refinancing) as a
whole, or in part, of any Indebtedness secured by any Lien referred to in the
foregoing clause (f), (h), (i) and (j); provided, however, that (x) such new
Lien shall be limited to all or part of the same property that secured the
original Lien (plus improvements to or on such property) and (y) the
Indebtedness secured by such Lien at such time is not increased to any amount
greater than the sum of (A) the outstanding principal amount or, if greater,
committed amount of the Indebtedness described under clause (f), (h), (i) or (j)
at the time the original Lien became a Permitted Lien and (B) an amount
necessary to pay any fees and expenses, including premiums, related to such
refinancing, refunding, extension, renewal or replacement; (o) Liens on, or
related to, properties to secure all or part of the costs incurred in the
ordinary course of business of exploration, drilling, development production,
processing, transportation, marketing or storage or operation thereof; (p) Liens
on pipeline or pipeline facilities hydrocarbons or other properties which arise
out of operation of law; (q) Liens reserved in oil and gas mineral leases for
bonus or rental payments and for compliance with the terms of such leases; (r)
Liens arising under partnership agreements, oil and gas leases, farm-out
agreements, division orders, contracts for the sale, purchase, exchange,
transportation or processing (but not the refining) of oil, gas or other
hydrocarbons, unitization and pooling declarations and agreements, development
agreements, operating agreements, area of mutual interest agreements, and other
similar agreements which are customary in the Oil and Gas Business; (s) judgment
and attachment Liens not giving
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rise to an Event of Default or Liens created by or existing from any litigation
or legal proceeding that are currently being contested in good faith by
appropriate proceedings and for which adequate reserves have been made; (t)
Liens in favor of collecting or payor banks having a right of setoff,
revocation, refund or chargeback with respect to money or instruments of the
Company or any Subsidiary on deposit with or in possession of such bank; and (u)
royalties, overriding royalties, revenue interests, net revenue interests, net
profit interests, reversionary interests, production payments, production sales
contracts, operating agreements, and other similar interests, properties,
arrangements, and agreements, all as ordinarily exist with respect to the
Company's properties. Notwithstanding the foregoing, "Permitted Liens" will not
include any Lien described in clause (f), (i) or (j) above to the extent (A)
such Lien applies to any Additional Assets or Permitted Business Investment
acquired directly or indirectly from Net Available Cash pursuant to clause
(a)(i)(B) or paragraph (c) of the covenant described under "-- Certain
Covenants -- Limitation on Sales of Assets and Subsidiary Stock" and (B) the
fair value of such Additional Assets or Permitted Business Investment is less
than the sum of (x) the amount of Indebtedness secured by such Lien plus (y) the
amount of Net Available Cash so invested in such Additional Assets or Permitted
Business Investment.
"Permitted Marketing Obligations" means Indebtedness of the Company or any
Restricted Subsidiary under letter of credit or borrowed money obligations, or
in lieu of or in addition to such letters of credit or borrowed money,
guarantees of such Indebtedness or other obligations of the Company or any
Restricted Subsidiary by any other Restricted Subsidiary of the Company, as
applicable, related to the purchase by the Company or any Restricted Subsidiary
of hydrocarbons for which the Company or such Restricted Subsidiary has
contracts to sell; provided, however, that in the event that such Indebtedness
or obligations are guaranteed by the Company or any Restricted Subsidiary, then
either (i) the Person with which the Company or such Restricted Subsidiary has
contracts to sell has an investment grade credit rating from S&P or Moody's, or
in lieu thereof, a Person guaranteeing the payment of such obligated Person has
an investment grade credit rating from S & P or Moody's, or (ii) such Person
posts, or has posted for it, a letter of credit in favor of the Company or such
Restricted Subsidiary with respect to all such Person's obligations to the
Company or such Subsidiary under such contracts.
"Person" means any individual, corporation, partnership, joint venture,
association, joint-stock company, trust, unincorporated organization, government
or any agency or political subdivision thereof or any other entity.
"Preferred Stock," as applied to the Capital Stock of any corporation,
means Capital Stock of any class or classes (however designated) which is
preferred as to the payment of dividends, or as to the distribution of assets
upon any voluntary or involuntary liquidation or dissolution of such
corporation, over shares of Capital Stock of any other class of such
corporation.
The term "principal" of a Note means the principal of the Note plus the
premium, if any, payable on the Note which is due or overdue or is to become due
at the relevant time.
"Production Payments" means, collectively, Dollar-Denominated Production
Payments and Volumetric Production Payments.
"Public Market" means any time when at least 15% of the total issued and
outstanding common stock of the Company has been distributed by means of an
effective registration statement under the Securities Act or sales pursuant to
Rule 144 under the Securities Act.
"Rating Agency" means S&P and Moody's or, if S&P or Moody's shall have
ceased to be a "nationally recognized statistical rating organization" (as
defined in Rule 436 under the Act) or shall have ceased to make publicly
available a rating on any outstanding securities of any company engaged
primarily in the oil and gas business, such other organization or organizations,
as the case may be, then making publicly available a rating on the Notes as is
selected by the Company.
"Rating Date" means, in respect of each Change of Control, the date that is
immediately prior to the date of the first public announcement of an event or
series of events that results in a Change of Control.
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"Rating Decline" means the occurrence on any date following the Rating Date
and prior to a date that is 90 days after the occurrence of a corresponding
Change of Control (which period shall be deemed to be extended so long as prior
to the end of such 90-day period and continuing thereafter the rating of the
Notes is under publicly announced consideration for possible downgrade by either
Rating Agency) of either of the following: (i) the rating of the Notes by either
Rating Agency within such period shall be at least one gradation below the
rating of the Notes by such Rating Agency on the Rating Date; or (ii) either
Rating Agency shall withdraw its ratings of the Notes. A gradation shall include
changes within rating categories (e.g., with respect to S&P a decline in a
rating from BB+ to BB, or from B to B-, will constitute a decrease of one
gradation).
"Refinance" means, in respect of any Indebtedness, to refinance, extend,
renew, refund, repay, prepay, redeem, decease or retire, or to issue other
Indebtedness in exchange or replacement for, such Indebtedness. "Refinanced" and
"Refinancing" shall have correlative meanings.
"Refinancing Indebtedness" means Indebtedness that Refinances any
Indebtedness of the Company or any Restricted Subsidiary existing on the Issue
Date or Incurred in compliance with the Indenture including Indebtedness that
Refinances Refinancing Indebtedness; provided, however, that (i) such
Refinancing Indebtedness has a Stated Maturity no earlier than the Stated
Maturity of the Indebtedness being Refinanced, (ii) such Refinancing
Indebtedness has an Average Life at the time such Refinancing Indebtedness is
Incurred that is equal to or greater than the Average Life of the Indebtedness
being Refinanced and (iii) such Refinancing Indebtedness has an aggregate
principal amount (or if Incurred with original issue discount, an aggregate
issue price) that is equal to or less than the aggregate principal amount (or if
Incurred with original issue discount, the aggregate accreted value) then
outstanding or committed (plus fees and expenses, including any premium and
defeasance costs) under the Indebtedness being Refinanced; provided further,
however, that Refinancing Indebtedness shall not include (x) Indebtedness of a
Subsidiary (other than a Subsidiary Guarantor) that Refinances Indebtedness of
the Company or (y) Indebtedness of the Company or a Restricted Subsidiary that
Refinances Indebtedness of an Unrestricted Subsidiary.
"Representative" means any trustee, agent or representative (if any) for an
issue of Senior Indebtedness of a Subsidiary Guarantor.
"Restricted Payment" with respect to any Person means (i) the declaration
or payment of any dividends or any other distributions of any sort in respect of
its Capital Stock (including any payment in connection with any merger or
consolidation involving such Person) or similar payment to the direct or
indirect holders of its Capital Stock (other than (x) dividends or distributions
payable solely in its Capital Stock (other than Disqualified Stock), (y)
dividends or distributions payable solely to the Company or a Restricted
Subsidiary, and (z) pro rata dividends or other distributions made by a
Subsidiary that is not a Wholly Owned Subsidiary to minority stockholders (or
owners of an equivalent interest in the case of a Subsidiary that is an entity
other than a corporation)), (ii) the purchase, redemption or other acquisition
or retirement for value of any Capital Stock of the Company held by any Person
or of any Capital Stock of a Restricted Subsidiary held by any Affiliate of the
Company (other than a Restricted Subsidiary), including the exercise of any
option to exchange any Capital Stock (other than into Capital Stock of the
Company that is not Disqualified Stock), (iii) the purchase, repurchase,
redemption, defeasance or other acquisition or retirement for value, prior to
scheduled maturity, scheduled repayment or scheduled sinking fund payment of any
Subordinated Obligations (other than the purchase, repurchase or other
acquisition of Subordinated Obligations purchased in anticipation of satisfying
a sinking fund obligation, principal installment or final maturity, in each case
due within one year of the date of acquisition) or (iv) the making of any
Investment in any Person (other than a Permitted Investment).
"Restricted Subsidiary" means any Subsidiary of the Company that is not an
Unrestricted Subsidiary.
"S&P" means Standard & Poor's Rating Services, a division of The
McGraw-Hill Company, Inc., and its successors.
"Sale/Leaseback Transaction" means an arrangement relating to property now
owned or hereafter acquired whereby the Company or a Restricted Subsidiary
transfers such property to a Person and the
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Company or a Restricted Subsidiary leases it from such Person, provided that the
fair market value of such property (as reasonably determined by the Board of
Directors acting in good faith) is $10 million or more.
"SEC" means the Securities and Exchange Commission.
"Secured Indebtedness" means any Indebtedness of the Company secured by a
Lien.
"Senior Indebtedness" means with respect to any Person (i) Indebtedness of
such Person, and all obligations of such Person under any Credit Facility,
whether outstanding on the Issue Date or thereafter Incurred and (ii) accrued
and unpaid interest (including interest accruing on or after the filing of any
petition in bankruptcy or for reorganization relating such Person to the extent
post-filing interest is allowed in such proceeding) in respect of (A)
indebtedness of such Person for money borrowed and (B) indebtedness evidenced by
notes, debentures, bonds or other similar instruments for the payment of which
such Person is responsible or liable unless, with respect to obligations
described in the immediately preceding clause (i) or (ii), in the instrument
creating or evidencing the same or pursuant to which the same is outstanding, it
is provided that such obligations are not superior in right of payment to the
applicable Subsidiary Guaranty; provided, however, that Senior Indebtedness
shall not include (1) any obligation of such Person to any Subsidiary of such
Person, (2) any liability for Federal, state, local or other taxes owed or owing
by such Person, (3) any accounts payable or other liability to trade creditors
arising in the ordinary course of business (including guarantees thereof or
instruments evidencing such liabilities), (4) any Indebtedness of such Person
(and any accrued and unpaid interest in respect thereof) which is subordinate or
junior in any respect to any other Indebtedness or other obligation of such
Person or (5) that portion of any Indebtedness which at the time of Incurrence
is Incurred in violation of the Indenture (other than, in the case of a
Subsidiary Guarantor, Indebtedness under any Credit Facility that is Incurred on
the basis of a representation by such Subsidiary Guarantor to the applicable
lenders that such Person is permitted to Incur such Indebtedness under the
Indenture).
"Senior Subordinated Indebtedness" means with respect to the Company or a
Subsidiary Guarantor, the Notes, with respect to the Company, and the Subsidiary
Guaranty of such Subsidiary Guarantor and any other Indebtedness of the Company
or such Subsidiary Guarantor, as the case may be, that specifically provides
that such Indebtedness is to rank pari passu with the Notes or such Subsidiary
Guaranty, as the case may be, in right of payment and is not subordinated by its
terms in right of payment to any Indebtedness or other obligation of the Company
or such Subsidiary Guarantor, as the case may be, which is not Senior
Indebtedness of the Company or such Subsidiary Guarantor, as the case may be.
"Significant Subsidiary" means any Restricted Subsidiary that would be a
"Significant Subsidiary" of the Company within the meaning of Rule 1-02 under
Regulation S-X promulgated by the SEC.
"Stated Maturity" means, with respect to any security, the date specified
in such security as the fixed date on which the final payment of principal of
such security is due and payable, including pursuant to any mandatory redemption
provision (but excluding any provision providing for the repurchase of such
security at the option of the holder thereof upon the happening of any
contingency unless such contingency has occurred).
"Subordinated Obligation" means any Indebtedness of the Company (whether
outstanding on the Issue Date or thereafter Incurred) which is subordinate or
junior in right of payment to the Notes pursuant to a written agreement to that
effect.
"Subsidiary" means, in respect of any Person, any corporation, association,
partnership or other business entity of which more than 50% of the total voting
power of shares of Capital Stock or other interests (including partnership
interests) entitled (without regard to the occurrence of any contingency) to
vote in the election of directors, managers or trustees thereof is at the time
owned or controlled, directly or indirectly, by (i) such Person, (ii) such
Person and one or more Subsidiaries of such Person or (iii) one or more
Subsidiaries of such Person.
"Subsidiary Guarantor" means CRI, Coho Louisiana Production Company, Coho
Exploration, Inc., Interstate Natural Gas Company, Coho Fairbanks Gathering
Company and Coho Louisiana Gathering
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Company, and each other Restricted Subsidiary (other than an Exempt Foreign
Subsidiary) of the Company that (i) has total net assets (exclusive of the
Capital Stock of other Restricted Subsidiaries) as of the end of the most recent
fiscal year (as set forth on the balance sheet of such Subsidiary prepared in
accordance with GAAP) equal to or greater than the greater of $2.5 million and
one percent (1%) of Adjusted Consolidated Net Tangible Assets as of such date
and (ii) delivers a Subsidiary Guaranty.
"Subsidiary Guaranty" means a Guarantee by a Subsidiary Guarantor of the
Company's obligations with respect to the Notes, which Guarantee will be
subordinated to Senior Indebtedness of such Subsidiary Guarantor on the terms
described under "-- Ranking." Any such Subsidiary Guaranty (i) will be
substantially in the form prescribed by the Indenture, (ii) will be limited in
amount to an amount not to exceed the maximum amount that can be guaranteed by
the applicable Subsidiary Guarantor without rendering such Subsidiary Guaranty,
as it relates to such Subsidiary Guarantor, voidable under applicable law
relating to fraudulent conveyance or fraudulent transfer or similar laws
affecting the rights of creditors generally and (iii) will provide that, upon
the sale or other disposition (including by way of consolidation or merger) of a
Subsidiary Guarantor or the sale or disposition of all or substantially all the
assets of a Subsidiary Guarantor permitted by the Indenture, such Subsidiary
Guarantor shall be released from all its obligations under its Subsidiary
Guaranty.
"Temporary Cash Investments" means any of the following: (i) any investment
in direct obligations of the United States of America or any agency thereof or
obligations guaranteed by the United States of America or any agency thereof,
(ii) investments in time deposit accounts, certificates of deposit and
money-market deposits maturing within 180 days of the date of acquisition
thereof issued by a bank or trust company which is organized under the laws of
the United States of America, any state thereof or any foreign country
recognized by the United States, and which bank or trust company has capital,
surplus and undivided profits aggregating in excess of $50.0 million (or the
foreign currency equivalent thereof) and has outstanding debt which is rated "A"
(or such similar equivalent rating) or higher by at least one nationally
recognized statistical rating organization (as defined in Rule 436 under the
Securities Act) or any money-market fund sponsored by a registered broker dealer
or mutual fund distributor, (iii) repurchase obligations with a term of not more
than 30 days for underlying securities of the types described in clause (i)
above entered into with a bank meeting the qualifications described in clause
(ii) above, (iv) investments in commercial paper, maturing not more than 180
days after the date of acquisition, issued by a Person (other than an Affiliate
of the Company) organized and in existence under the laws of the United States
of America or any foreign country recognized by the United States of America
with a rating at the time as of which any investment therein is made of "P-2"
(or higher) according to Moody's Investors Service, Inc. or "A-2" (or higher)
according to Standard and Poor's Ratings Group, and (v) investments in
securities with maturities of six months or less from the date of acquisition
issued or fully guaranteed by any state, commonwealth or territory of the United
States of America, or by any political subdivision or taxing authority thereof,
and rated at least "A" by Standard & Poor's Ratings Group or "A" by Moody's
Investors Service, Inc.
"Unrestricted Subsidiary" means (i) any Subsidiary of the Company that at
the time of determination shall be designated an Unrestricted Subsidiary by the
Board of Directors in the manner provided below and (ii) any Subsidiary of an
Unrestricted Subsidiary. The Board of Directors may designate any Subsidiary of
the Company (including any newly acquired or newly formed Subsidiary) to be an
Unrestricted Subsidiary unless such Subsidiary or any of its Subsidiaries owns
any Capital Stock or Indebtedness of, or holds any Lien on any property of, the
Company or any other Subsidiary of the Company that is not a Subsidiary of the
Subsidiary to be so designated; provided, however, that either (A) the
Subsidiary to be so designated has total assets of $1,000 or less or (B) if such
Subsidiary has assets greater than $1,000, such designation would be permitted
under the covenant described under "-- Certain Covenants -- Limitation on
Restricted Payments." The Board of Directors may designate any Unrestricted
Subsidiary to be a Restricted Subsidiary; provided, however, that immediately
after giving effect to such designation (x) the Company could Incur $1.00 of
additional Indebtedness under paragraph (a) of the covenant described under
"-- Certain Covenants -- Limitation on Indebtedness" and (y) no Default shall
have occurred and be continuing. Any such designation by the Board of Directors
shall be evidenced by the Company to the Trustee by promptly filing with the
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Trustee a copy of the board resolution giving effect to such designation and an
Officers' Certificate certifying that such designation complied with the
foregoing provisions.
"U.S. Government Obligations" means direct obligations (or certificates
representing an ownership interest in such obligations) of the United States of
America (including any agency or instrumentality thereof) for the payment of
which the full faith and credit of the United States of America is pledged and
which are not callable at the issuer's option.
"Volumetric Production Payments" means production payment obligations
recorded as deferred revenue in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
"Voting Stock" of a Person means all classes of Capital Stock or other
interests (including partnership interests) of such Person then outstanding and
normally entitled (without regard to the occurrence of any contingency) to vote
in the election of directors, managers or trustees thereof.
"Wholly Owned Subsidiary" means a Restricted Subsidiary all the Capital
Stock of which (other than directors' qualifying shares and shares held by other
Persons to the extent such shares are required by applicable law to be held by a
Person other than the Company or a Restricted Subsidiary) is owned by the
Company or one or more Wholly Owned Subsidiaries.
CERTAIN COVENANTS
The Indenture contains covenants including, among others, the following:
Limitation on Indebtedness. (a) The Company shall not, and shall not permit
any Restricted Subsidiary to, Incur, directly or indirectly, any Indebtedness;
provided, however, that the Company or a Restricted Subsidiary may Incur
Indebtedness if, on the date of such Incurrence and after giving effect thereto,
either (i) the Consolidated Coverage Ratio equals or exceeds 2.25 to 1.0, or
(ii) the Company's Adjusted Consolidated Net Tangible Assets would be equal to
or greater than 200% of Consolidated Indebtedness.
(b) Notwithstanding the foregoing paragraph (a), the Company and any
Restricted Subsidiary may Incur the following Indebtedness:
(1) Indebtedness Incurred pursuant to any Credit Facility, so long as
the aggregate principal amount of all Indebtedness outstanding under all
Credit Facilities does not, at any one time, exceed the aggregate amount of
borrowing availability as of such date under all Credit Facilities that
determine availability on the basis of a borrowing base or other
asset-based calculation; provided, however, that in no event shall such
amount exceed the greater of (x) $250 million and (y) 75% of ACNTA as of
the date of such Incurrence; provided further, however, that if any
Indebtedness Incurred pursuant to this clause (1) would cause the total
principal amount of Indebtedness outstanding under this clause (1) to
exceed the greater of (A) (x) $200.0 million minus (y) the aggregate amount
of all Net Available Cash of Asset Dispositions applied to reduce Senior
Indebtedness pursuant to clause (a)(i)(A) of the covenant described under
the caption "-- Limitation on Sales of Assets and Subsidiary Stock" and (B)
65% of ACNTA as of the date of such Incurrence, the Consolidated Coverage
Ratio on the date of such Incurrence must be at least 2.0 to 1;
(2) Indebtedness owed to and held by the Company or a Wholly Owned
Subsidiary; provided, however, that any subsequent issuance or transfer of
any Capital Stock which results in any such Wholly Owned Subsidiary ceasing
to be a Wholly Owned Subsidiary or any subsequent transfer of such
Indebtedness (other than to the Company or another Wholly Owned Subsidiary)
shall be deemed, in each case, to constitute the Incurrence of such
Indebtedness by the issuer thereof;
(3) The Notes (other than additional Notes) and the Subsidiary
Guaranties;
(4) Indebtedness outstanding on the Issue Date (other than
Indebtedness described in clause (1), (2) or (3) of this covenant);
(5) Indebtedness or Preferred Stock of a Restricted Subsidiary
Incurred and outstanding on or prior to the date on which such Restricted
Subsidiary was acquired by the Company (other than Indebtedness
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or Preferred Stock Incurred in connection with, or to provide all or any
portion of the funds or credit support utilized to consummate, the
transaction or series of related transactions pursuant to which such
Restricted Subsidiary became a Restricted Subsidiary or was acquired by the
Company);
(6) Refinancing Indebtedness in respect of Indebtedness Incurred
pursuant to paragraph (a) or pursuant to clause (3), (4), (5) above, or
this clause (6); provided, however, that to the extent such Refinancing
Indebtedness directly or indirectly Refinances Indebtedness or Preferred
Stock of a Restricted Subsidiary described in clause (5), such Refinancing
Indebtedness shall be Incurred only by such Restricted Subsidiary or the
Company;
(7) Indebtedness of the Company or a Restricted Subsidiary represented
by Capital Lease Obligations, mortgage financings or purchase money
obligations, in each case Incurred for the purpose of financing all or any
part of the purchase price or cost of construction or improvement of
property used in an Oil and Gas Business or Incurred to Refinance any such
purchase price or cost of construction or improvement, in each case (other
than a Refinancing) Incurred no later than 365 days after the date of such
acquisition or the date of completion of such construction or improvement;
provided, however, that the principal amount of any Indebtedness Incurred
pursuant to this clause (7) (other than a Refinancing) in any single
calendar year shall not exceed $20 million;
(8) Indebtedness with respect to Production Payments; provided,
however, that any such Indebtedness shall be Limited Recourse Indebtedness;
provided further, however, that the Net Present Value attributable to the
reserves related to such Production Payments shall not exceed 30% of ACNTA
at the time of Incurrence;
(9) Indebtedness consisting of Interest Rate Agreements directly
related to Indebtedness permitted to be Incurred by the Company and its
Restricted Subsidiaries pursuant to the Indenture;
(10) Indebtedness under Oil and Gas Hedging Contracts and Currency
Agreements entered into in the ordinary course of business for the purpose
of limiting risks that arise in the ordinary course of business of the
Company and its Restricted Subsidiaries;
(11) Indebtedness in respect of letters of credit issued for the
benefit of the Company or any of its Restricted Subsidiaries to the extent
they are issued in connection with the ordinary course of business of the
Company and its Restricted Subsidiaries, Incurred in an aggregate principal
amount which, when taken together with the principal amount of all other
Indebtedness Incurred pursuant to this clause (11) and then outstanding,
does not exceed the greater of (x) $20 million and (y) 10% of the maximum
Indebtedness that would at such time be permitted to be outstanding
pursuant to clause (b)(1) above;
(12) Indebtedness of the Company or a Restricted Subsidiary Incurred
to finance capital expenditures and Refinancing Indebtedness Incurred in
respect thereof in an aggregate principal amount which, when taken together
with the principal amount of all other Indebtedness Incurred pursuant to
this clause (12) and then outstanding, does not exceed $20 million;
(13) Indebtedness of the Company or a Restricted Subsidiary Incurred
for the purpose of financing all or any part of the cost of acquiring oil
and gas properties, another Person (other than a Person that was,
immediately prior to such acquisition, a Subsidiary of the Company) engaged
in the Oil and Gas Business or all or substantially all the assets of such
a Person; provided, however, that on the date of such Incurrence and after
giving effect thereto, the Consolidated Coverage Ratio equals or exceeds
2.0 to 1.0;
(14) Permitted Marketing Obligations; and
(15) Indebtedness in an aggregate principal amount which, together
with the principal amount of all other Indebtedness of the Company and its
Restricted Subsidiaries outstanding on the date of such Incurrence (other
than Indebtedness permitted by clauses (1) through (14) above or paragraph
(a)) does not exceed $20 million.
(c) Notwithstanding the foregoing, the Company shall not Incur any
Indebtedness pursuant to the foregoing paragraph (b) if the proceeds thereof are
used, directly or indirectly, to Refinance any Subordinated
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Obligations unless such Indebtedness shall be subordinated to the Notes to at
least the same extent as such Subordinated Obligations.
(d) For purposes of determining compliance with the foregoing covenant, (i)
in the event that an item of Indebtedness meets the criteria of more than one of
the types of Indebtedness described above, the Company, in its sole discretion,
will classify such item of Indebtedness and only be required to include the
amount and type of such Indebtedness in one of the above clauses and (ii) an
item of Indebtedness may be divided and classified in more than one of the types
of Indebtedness described above.
(e) Notwithstanding paragraphs (a) and (b) above, no Restricted Subsidiary
shall Incur any Indebtedness if such Indebtedness is subordinate or junior in
ranking in any respect to any Senior Indebtedness of such Restricted Subsidiary,
unless such Indebtedness is Senior Subordinated Indebtedness of such Restricted
Subsidiary.
Limitation on Restricted Payments. (a) The Company shall not, and shall not
permit any Restricted Subsidiary, directly or indirectly, to make a Restricted
Payment if at the time the Company or such Restricted Subsidiary makes such
Restricted Payment: (1) a Default shall have occurred and be continuing (or
would result therefrom); (2) the Company is not able to Incur an additional
$1.00 of Indebtedness pursuant to paragraph (a) of the covenant described under
"-- Limitation on Indebtedness;" or (3) the aggregate amount of such Restricted
Payment and all other Restricted Payments since the Issue Date would exceed the
sum of: (A) 50% of the Consolidated Net Income accrued during the period
(treated as one accounting period) from the beginning of the fiscal quarter
immediately following the fiscal quarter during which the Notes are originally
issued to the end of the most recent fiscal quarter ending at least 45 days
prior to the date of such Restricted Payment (or, in case such Consolidated Net
Income shall be a deficit, minus 100% of such deficit); (B) the aggregate Net
Cash Proceeds received by the Company from the issuance or sale of its Capital
Stock (other than Disqualified Stock) subsequent to the Issue Date (other than
an issuance or sale to a Subsidiary of the Company and other than an issuance or
sale to an employee stock ownership plan or to a trust established by the
Company or any of its Subsidiaries for the benefit of their employees); (C) the
aggregate Net Cash Proceeds received by the Company from the issue or sale
subsequent to the Issue Date of its Capital Stock (other than Disqualified
Stock) to an employee stock ownership plan; provided, however, that if such
employee stock ownership plan incurs any Indebtedness with respect thereto, such
aggregate amount shall be limited to an amount equal to any increase in the
Consolidated Net Worth of the Company resulting from principal repayments made
by such employee stock ownership plan with respect to such Indebtedness; (D) the
amount by which Indebtedness of the Company is reduced on the Company's balance
sheet upon the conversion or exchange (other than by a Subsidiary of the
Company) subsequent to the Issue Date, of any Indebtedness of the Company
convertible or exchangeable for Capital Stock (other than Disqualified Stock) of
the Company (less the amount of any cash, or the fair value of any other
property, distributed by the Company upon such conversion or exchange); and (E)
an amount equal to the sum of (i) the net reduction in Investments in
Unrestricted Subsidiaries resulting from dividends, repayments of loans or
advances or other transfers of assets, in each case to the Company or any
Restricted Subsidiary from Unrestricted Subsidiaries, and (ii) the portion
(proportionate to the Company's equity interest in such Subsidiary) of the fair
market value of the net assets of an Unrestricted Subsidiary at the time such
Unrestricted Subsidiary is designated a Restricted Subsidiary; provided,
however, that the foregoing sum shall not exceed, in the case of any
Unrestricted Subsidiary, the amount of Investments previously made (and treated
as a Restricted Payment) by the Company or any Restricted Subsidiary in such
Unrestricted Subsidiary.
(b) The provisions of the foregoing paragraph (a) shall not prohibit: (i)
any purchase or redemption of Capital Stock or Subordinated Obligations of the
Company made by exchange for, or out of the proceeds of the substantially
concurrent sale of, Capital Stock of the Company (other than Disqualified Stock
and other than Capital Stock issued or sold to a Subsidiary of the Company or an
employee stock ownership plan or to a trust established by the Company or any of
its Subsidiaries for the benefit of their employees); provided, however, that
(A) such purchase or redemption shall be excluded in the calculation of the
amount of Restricted Payments and (B) the Net Cash Proceeds from such sale shall
be excluded from the calculation of amounts under clause (3)(B) of paragraph (a)
above (but only to the extent that such Net Cash Proceeds were used to purchase
or redeem such Capital Stock as provided in this clause (i)); (ii) any purchase,
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repurchase, redemption, defeasance or other acquisition or retirement for value
of Subordinated Obligations made by exchange for, or out of the proceeds of the
substantially concurrent sale of, Indebtedness of the Company which is permitted
to be Incurred pursuant to the covenant described under "-- Limitation on
Indebtedness;" provided, however, that such purchase, repurchase, redemption,
defeasance or other acquisition or retirement for value shall be excluded in the
calculation of the amount of Restricted Payments; (iii) dividends paid within 60
days after the date of declaration thereof if at such date of declaration such
dividend would have complied with this covenant; provided, however, that at the
time of payment of such dividend, no other Default shall have occurred and be
continuing (or result therefrom); provided further, however, that such dividend
shall be included in the calculation of the amount of Restricted Payments; (iv)
the repurchase of shares of, or options to purchase shares of, common stock of
the Company or any of its Subsidiaries from employees, former employees,
directors or former directors of the Company or any of its Subsidiaries (or
permitted transferees of such employees, former employees, directors or former
directors), pursuant to the terms of the agreements (including employment
agreements) or plans (or amendments thereto) approved by the Board of Directors
under which such individuals purchase or sell or are granted the option to
purchase or sell, shares of such common stock; provided, however, that the
aggregate amount of such repurchases shall not exceed $2 million in any calendar
year and $10 million in the aggregate; provided further, however, that such
repurchases shall be excluded in the calculation of the amount of Restricted
Payments; or (v) other Restricted Payments in an aggregate amount not to exceed
$20 million; provided, however, that such Restricted Payments shall be excluded
in the calculation of the amount of Restricted Payments.
Limitation on Restrictions on Distributions from Restricted
Subsidiaries. The Company shall not, and shall not permit any Restricted
Subsidiary to, create or otherwise cause or permit to exist or become effective
any consensual encumbrance or restriction on the ability of any Restricted
Subsidiary (a) to pay dividends or make any other distributions on its Capital
Stock or pay any Indebtedness owed to the Company or a Restricted Subsidiary,
(b) to make any loans or advances to the Company or a Restricted Subsidiary or
(c) to transfer any of its property or assets to the Company or a Restricted
Subsidiary, except: (i) any encumbrance or restriction pursuant to an agreement
in effect at or entered into on the Issue Date; (ii) any encumbrance or
restriction with respect to a Restricted Subsidiary pursuant to an agreement
relating to any Indebtedness Incurred by such Restricted Subsidiary on or prior
to the date on which such Restricted Subsidiary was acquired by the Company
(other than Indebtedness Incurred as consideration in, or to provide all or any
portion of the funds or credit support utilized to consummate, the transaction
or series of related transactions pursuant to which such Restricted Subsidiary
became a Restricted Subsidiary or was acquired by the Company) and outstanding
on such date; (iii) any encumbrance or restriction pursuant to an agreement
effecting a Refinancing of Indebtedness Incurred pursuant to an agreement
referred to in clause (i) or (ii) of this covenant or this clause (iii) or
contained in any amendment to an agreement referred to in clause (i) or (ii) of
this covenant or this clause (iii); provided, however, that the encumbrances and
restrictions with respect to such Restricted Subsidiary contained in any such
refinancing agreement or amendment are no less favorable to the Noteholders than
encumbrances and restrictions with respect to such Restricted Subsidiary
contained in such agreements; (iv) any such encumbrance or restriction
consisting of customary nonassignment provisions in leases governing leasehold
interests to the extent such provisions restrict the transfer of the lease or
the property leased thereunder; (v) in the case of clause (c) above,
restrictions contained in security agreements or mortgages securing Indebtedness
of a Restricted Subsidiary to the extent such restrictions restrict the transfer
of the property subject to such security agreements or mortgages; and (vi) any
restriction with respect to a Restricted Subsidiary imposed pursuant to an
agreement entered into for the sale or disposition of all or substantially all
the Capital Stock or assets of such Restricted Subsidiary pending the closing of
such sale or disposition.
Limitation on Sales of Assets and Subsidiary Stock. (a) In the event and to
the extent that the Net Available Cash received by the Company or any Restricted
Subsidiary from one or more Asset Dispositions occurring on or after the Issue
Date in any period of 12 consecutive months exceeds 15% of Adjusted Consolidated
Net Tangible Assets as of the beginning of such 12-month period, then the
Company shall (i) within 180 days (in the case of (A) below) or 18 months (in
the case of (B) below) after the date such Net Available Cash so received
exceeds such 15% of Adjusted Consolidated Net Tangible Assets (A) apply
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an amount equal to such excess Net Available Cash to repay Senior Indebtedness
or Indebtedness of a Restricted Subsidiary, in each case owing to a Person other
than the Company or any Affiliate of the Company or (B) invest an equal amount,
or the amount not so applied pursuant to clause (A), in Additional Assets or a
Permitted Business Investment or (ii) apply such excess Net Available Cash (to
the extent not applied pursuant to clause (i)) as provided in the following
paragraphs of the covenant described hereunder. The amount of such excess Net
Available Cash required to be applied during the applicable period and not
applied as so required by the end of such period shall constitute "Excess
Proceeds."
If, as of the first day of any calendar month, the aggregate amount of
Excess Proceeds not theretofore subject to an Excess Proceeds Offer (as defined
below) totals at least $10.0 million, the Company must, not later than the
fifteenth Business Day of such month, make an offer (an "Excess Proceeds Offer")
to purchase from the Holders on a pro rata basis an aggregate principal amount
of Notes equal to the Excess Proceeds (rounded down to the nearest multiple of
$1,000) on such date, at a purchase price equal to 100% of the principal amount
of such Notes, plus, in each case, accrued interest (if any) to the date of
purchase (the "Excess Proceeds Payment").
The Company will comply, to the extent applicable, with the requirements of
Section 14(e) of the Exchange Act and any other securities laws or regulations
thereunder in the event that such Excess Proceeds are received by the Company
under the covenant described hereunder and the Company is required to repurchase
Notes as described above. To the extent that the provisions of any securities
laws or regulations conflict with the provisions of the covenant described
hereunder, the Company shall comply with the applicable securities laws and
regulations and shall not be deemed to have breached its obligations under the
covenant described hereunder by virtue thereof.
(b) In the event of the transfer of substantially all (but not all) the
property and assets of the Company as an entirety to a Person in a transaction
permitted by the covenant described under "-- Merger and Consolidation," the
Successor Company (as defined therein) shall be deemed to have sold the
properties and assets of the Company not so transferred for purposes of this
covenant, and shall comply with the provisions of this covenant with respect to
such deemed sale as if it were an Asset Disposition and the Successor Company
shall be deemed to have received Net Available Cash in an amount equal to the
fair market value (as determined in good faith by the Board of Directors) of the
properties and assets not so transferred or sold.
(c) In the event of an Asset Disposition by the Company or any Restricted
Subsidiary that consists of a sale of hydrocarbons and results in Production
Payments, the Company or such Restricted Subsidiary shall apply an amount equal
to the Net Available Cash received by the Company or such Restricted Subsidiary
to (i) reduce Senior Indebtedness of the Company or Indebtedness of a Restricted
Subsidiary, in each case owing to a Person other than the Company or any
Affiliate of the Company, within 180 days after the date such Net Available Cash
is so received, or (ii) invest in Additional Assets or a Permitted Business
Investment within 18 months after the date such Net Available Cash is so
received.
Limitation on Affiliate Transactions. (a) The Company shall not, and shall
not permit any Restricted Subsidiary to, enter into or permit to exist any
transaction (including the purchase, sale, lease or exchange of any property,
employee compensation arrangements or the rendering of any service) with any
Affiliate of the Company (an "Affiliate Transaction") unless the terms thereof
(1) are no less favorable to the Company or such Restricted Subsidiary than
those that could be obtained at the time of such transaction in arm's-length
dealings with a Person who is not such an Affiliate, (2) if such Affiliate
Transaction involves an amount in excess of $10.0 million, is set forth in
writing and has been approved by a majority of the members of the Board of
Directors having no personal stake in such Affiliate Transaction or (3) if such
Affiliate Transaction involves an amount in excess of $20.0 million, has been
determined by a nationally recognized investment banking firm or other qualified
independent appraiser to be fair, from a financial standpoint, to the Company
and its Restricted Subsidiaries.
(b) The provisions of the foregoing paragraph (a) shall not prohibit (i)
any sale of hydrocarbons or other mineral products to an Affiliate of the
Company or the entering into or performance of Oil and Gas Hedging Contracts,
gas gathering, transportation or processing contracts or oil or natural gas
marketing or exchange contracts with an Affiliate of the Company, in each case,
in the ordinary course of business, so long
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as the terms of any such transaction are approved by a majority of the members
of the Board of Directors who are disinterested with respect to such
transaction, (ii) the sale to an Affiliate of the Company of Capital Stock of
the Company that does not constitute Disqualified Stock, (iii) transactions
contemplated by any employment agreement or other compensation plan or
arrangement existing on the Issue Date or thereafter entered into by the Company
or any of its Restricted Subsidiaries in the ordinary course of business, (iv)
transactions between or among the Company and its Restricted Subsidiaries, (v)
transactions between the Company or any of its Restricted Subsidiaries and
Persons that are controlled (as defined in the definition of "Affiliate") by the
Company (an "Unrestricted Affiliate"); provided that no other Person that
controls (as so defined) or is under common control with the Company holds any
Investments in such Unrestricted Affiliate; (vi) Restricted Payments and
Permitted Investments that are permitted by the provisions of the Indenture
described above under the caption "-- Limitation on Restricted Payments," (vii)
loans or advances to employees in the ordinary course of business and approved
by the Company's Board of Directors in an aggregate principal amount not to
exceed $2.0 million outstanding at any one time and (viii) transactions
contemplated by the Registration Rights and Shareholder Agreement dated as of
December 8, 1994, among the Company, The Morgan Stanley Leveraged Equity Fund
II, L.P. and Quinn Oil Company Ltd.
Change of Control. (a) Upon the occurrence of a Change of Control and a
corresponding Rating Decline, each Holder shall have the right to require that
the Company repurchase such Holder's Notes at a purchase price in cash equal to
101% of the principal amount thereof plus accrued and unpaid interest, if any,
to the date of purchase (subject to the right of Holders of record on the
relevant record date to receive interest on the relevant interest payment date),
in accordance with the terms contemplated in paragraph (b) below.
(b) Within 30 days following a Rating Decline following a corresponding
Change of Control (or, in the event the Rating Decline occurs prior to the
corresponding Change of Control, within 30 days following the corresponding
Change of Control), the Company shall mail a notice to each Holder with a copy
to the Trustee stating: (1) that a Change of Control and corresponding Rating
Decline have occurred and that such Holder has the right to require the Company
to purchase such Holder's Notes at a purchase price in cash equal to 101% of the
principal amount thereof plus accrued and unpaid interest, if any, to the date
of purchase (subject to the right of Holders of record on the relevant record
date to receive interest on the relevant interest payment date); (2) the
circumstances and relevant facts regarding such Change of Control and
corresponding Rating Decline (including information with respect to pro forma
historical income, cash flow and capitalization after giving effect to such
Change of Control and corresponding Rating Decline); (3) the repurchase date
(which shall be no earlier than 30 days nor later than 60 days from the date
such notice is mailed); and (4) the instructions determined by the Company,
consistent with the covenant described hereunder, that a Holder must follow in
order to have its Notes purchased.
(c) The Company shall comply, to the extent applicable, with the
requirements of Section 14(e) of the Exchange Act and any other securities laws
or regulations in connection with the repurchase of Notes pursuant to this
covenant described hereunder. To the extent that the provisions of any
securities laws or regulations conflict with the provisions of the covenant
described hereunder, the Company shall comply with the applicable securities
laws and regulations and shall not be deemed to have breached its obligations
under the covenant described hereunder by virtue thereof.
The Change of Control purchase feature is a result of negotiations between
the Company and the Underwriters. Management has no present intention to engage
in a transaction involving a Change of Control, although it is possible that the
Company would decide to do so in the future. Subject to the limitations
discussed below, the Company could, in the future, enter into certain
transactions, including acquisitions, refinancing or other recapitalizations,
that would not constitute a Change of Control under the Indenture, but that
could increase the amount of indebtedness outstanding at such time or otherwise
affect the Company's capital structure or credit ratings. Restrictions on the
ability of the Company to incur additional Indebtedness are contained in the
covenants described under "-- Limitation on Indebtedness," "-- Limitation on
Liens" and "-- Limitation on Sale/Leaseback Transactions." Such restrictions can
only be waived with the consent of the holders of a majority in principal amount
of the Notes then outstanding. Except for the limitations contained in such
covenants, however, the Indenture will not contain any covenants or provisions
that may afford holders of the Notes protection in the event of a highly
leveraged transaction.
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The Credit Agreement generally prohibits the Company from purchasing any
Notes and also provides that the occurrence of certain change of control events
with respect to the Company would constitute a default thereunder. In the event
a Change of Control and corresponding Rating Decline occur at a time when the
Company is prohibited from purchasing Notes, the Company could seek the consent
of its lenders to the purchase of Notes or could attempt to refinance the
borrowings that contain such prohibition. If the Company does not obtain such a
consent or repay such borrowings, the Company would remain prohibited from
purchasing Notes. In such case, the Company's failure to purchase tendered Notes
would constitute an Event of Default under the Indenture which would, in turn,
constitute a default under the Credit Agreement. In such circumstances, the
subordination provisions in the Indenture would likely restrict payment to the
Holders of Notes pursuant to the Subsidiary Guaranties.
Future indebtedness of the Company may contain prohibitions on the
occurrence of certain events that would constitute a Change of Control or
require such indebtedness to be repurchased upon a Change of Control. Moreover,
the exercise by the holders of their right to require the Company to repurchase
the Notes could cause a default under such indebtedness, even if the Change of
Control and corresponding Rating Decline, due to the financial effect of such
repurchase on the Company. Finally, the Company's ability to pay cash to the
holders of Notes following the occurrence of a Change of Control and a
corresponding Rating Decline may be limited by the Company's then existing
financial resources. There can be no assurance that sufficient funds will be
available when necessary to make any required repurchases.
The provisions under the Indenture relating to the Company's obligation to
make an offer to repurchase the Notes as a result of a Change of Control and
corresponding Rating Decline may be waived or modified with the written consent
of the holders of a majority in principal amount of the Notes.
The Company will not be required to make an offer to purchase the Notes as
a result of a Change of Control and corresponding Rating Decline if a third
party (i) makes such offer in the manner, at the times and otherwise in
compliance with the requirements set forth in the Indenture relating to the
Company's obligations to make such an offer and (ii) purchases all Notes validly
tendered and not withdrawn under such an offer.
Limitation on the Sale or Issuance of Capital Stock of Restricted
Subsidiaries. The Company shall not sell or otherwise dispose of any shares of
Capital Stock of a Restricted Subsidiary, and shall not permit any Restricted
Subsidiary, directly or indirectly, to issue or sell or otherwise dispose of any
shares of its Capital Stock except (i) to the Company or a Wholly Owned
Subsidiary, (ii) if, immediately after giving effect to such issuance, sale or
other disposition, the Company and its Restricted Subsidiaries would own less
than 20% of the Voting Stock of such Restricted Subsidiary and have no greater
economic interest in such Restricted Subsidiary, (iii) if, immediately after
giving effect to such issuance, sale or other disposition, the Company and its
Restricted Subsidiaries would own greater than 80% of the Voting Stock of such
Restricted Subsidiary and have no lesser economic interest in such Restricted
Subsidiary or (iv) to the extent such shares represent directors' qualifying
shares or shares required by applicable law to be held by a Person other than
the Company or Restricted Subsidiary.
Limitation on Liens. (a) The Company shall not, directly or indirectly,
Incur or permit to exist any Lien (other than Permitted Liens) of any nature
whatsoever on any of its properties (including Capital Stock of a Restricted
Subsidiary), whether owned at the Issue Date or thereafter acquired, to secure
any Indebtedness of the Company, without effectively providing that the Notes
shall be secured equally and ratably with (or prior to) the obligations so
secured for so long as such obligations are so secured.
(b) The Company shall not permit any Subsidiary Guarantor, directly or
indirectly, to incur or permit to exist any Lien (other than Permitted Liens) of
any nature whatsoever on any of its properties (including Capital Stock of a
Restricted Subsidiary), whether owned on the Issue Date or thereafter acquired,
to secure any Indebtedness of such Subsidiary Guarantor that is not Senior
Indebtedness of such Subsidiary Guarantor without effectively providing that
such Subsidiary Guarantor's Subsidiary Guaranty shall be secured equally and
ratably with (or prior to) the obligations so secured for so long as such
obligations are so secured.
Limitation on Sale/Leaseback Transactions. The Company shall not, and shall
not permit any Restricted Subsidiary to, enter into any Sale/Leaseback
Transaction with respect to any property unless (i) the
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Company or such Restricted Subsidiary would be entitled to (A) Incur
Indebtedness in an amount equal to the Attributable Debt with respect to such
Sale/Leaseback Transaction pursuant to the covenant described under
"-- Limitation on Indebtedness" and (B) create a Lien on such property securing
such Attributable Debt without equally and ratably securing the Notes or the
applicable Subsidiary Guaranty pursuant to the covenant described under
"-- Limitation on Liens," (ii) the net proceeds received by the Company or any
Restricted Subsidiary in connection with such Sale/Leaseback Transaction are at
least equal to the fair value (as determined by the Board of Directors) of such
property and (iii) the Company applies the proceeds of such transaction in
compliance with the covenant described under "-- Limitation on Sales of Assets
and Subsidiary Stock."
Future Guarantors. Promptly after the end of the first fiscal year in which
any Restricted Subsidiary, at the end of such fiscal year, has total net assets
(exclusive of the Capital Stock of other Restricted Subsidiaries) (as set forth
on the balance sheet of such Subsidiary prepared in accordance with GAAP) equal
to or greater than the greater of $2.5 million and one percent (1%) of Adjusted
Consolidated Net Tangible Assets, the Company shall cause such Restricted
Subsidiary to issue a Subsidiary Guaranty for the benefit of the holders of the
Notes.
Merger and Consolidation. The Company shall not consolidate with or merge
with or into, or convey, transfer or lease, in one transaction or a series of
related transactions, all or substantially all its assets to, any Person,
unless: (i) the resulting, surviving or transferee Person (the "Successor
Company") shall be a Person organized and existing under the laws of the United
States of America, any State thereof or the District of Columbia and the
Successor Company (if not the Company) shall expressly assume, by an indenture
supplemental thereto, executed and delivered to the Trustee, in form
satisfactory to the Trustee, all the obligations of the Company under the Notes
and the Indenture; (ii) immediately after giving effect to such transaction (and
treating any Indebtedness which becomes an obligation of the Successor Company
or any Subsidiary as a result of such transaction as having been Incurred by
such Successor Company or such Subsidiary at the time of such transaction), no
Default shall have occurred and be continuing, (iii) immediately after giving
effect to such transaction, the Successor Company would be able to Incur an
additional $1.00 of Indebtedness pursuant to paragraph (a) or, if applicable,
paragraph (b)(14), of the covenant described under "-- Limitation on
Indebtedness," (iv) immediately after giving effect to such transaction, the
Successor Company shall have Adjusted Consolidated Net Tangible Assets in an
amount that is not less than the Adjusted Consolidated Net Tangible Assets of
the Company prior to such transaction; and (v) the Company shall have complied
with certain additional conditions set forth in the Indenture; provided,
however, that clauses (iii) and (iv) shall not be applicable to any such
transaction solely between the Company and any Restricted Subsidiary.
The Successor Company shall be the successor to the Company and shall
succeed to, and be substituted for, and may exercise every right and power of,
the Company under the Indenture, but the predecessor Company in the case of a
lease shall not be released from the obligation to pay the principal of and
interest on the Notes.
The Company will not permit any Subsidiary Guarantor to consolidate with or
merge with or into, or convey, transfer or lease, in one transaction or series
of transactions, all or substantially all of its assets to any Person unless:
(i) the resulting, surviving or transferee Person (except in the case of a
Subsidiary Guarantor (other than CRI) that has been disposed of in its entirety
to another Person, whether through the merger, consolidation or sale of Capital
Stock or assets, if in connection therewith the Company provides an Officer's
Certificate to the Trustee to the effect that the Company will comply with its
obligations under "-- Limitation on Sales of Assets and Capital Stock" in
respect of such disposition) shall expressly assume by a guaranty agreement, in
a form acceptable to the Trustee, all the obligations of such Subsidiary
Guarantor, if any, under its Subsidiary Guaranty; (ii) immediately after giving
effect to such transaction or transactions on a pro forma basis (and treating
any Indebtedness which becomes an obligation of the resulting, surviving or
transferee Person as a result of such transaction as having been issued by such
Person at the time of such transaction), no Default shall have occurred and be
continuing; and (iii) the Company delivers to the Trustee an Officer's
Certification and an Opinion of Counsel, each stating that such consolidation,
merger or transfer and such guaranty agreement, if any, complies with the
Indenture.
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SEC Reports. Notwithstanding that the Company may not at any time be
subject to the reporting requirements of Section 13 or 15(d) of the Exchange
Act, the Company shall file with the SEC and provide the Trustee and Noteholders
with such annual reports and such information, documents and other reports as
are specified in Sections 13 and 15(d) of the Exchange Act and applicable to a
U.S. corporation subject to such Sections, such information, documents and other
reports to be so filed and provided at the times specified for the filing of
such information, documents and reports under such Sections.
DEFAULTS
An Event of Default is defined in the Indenture as (i) a default in the
payment of interest on the Notes when due, continued for 30 days, (ii) a default
in the payment of principal of any Note when due at its Stated Maturity, upon
optional redemption, upon required repurchase, upon declaration or otherwise,
(iii) the failure by the Company to comply with its obligations under
"-- Certain Covenants -- Merger and Consolidation" above, (iv) the failure by
the Company to comply for 30 days after notice with any of its obligations in
the covenants described above under "-- Certain Covenants," "-- Limitation on
Indebtedness," "-- Limitation on Restricted Payments," "-- Limitation on
Restrictions on Distributions from Restricted Subsidiaries," "-- Limitation on
Sales of Assets and Subsidiary Stock" (other than a failure to purchase Notes),
"-- Limitation on Affiliate Transactions," "-- Limitation on the Sale or
Issuance of Capital Stock of Restricted Subsidiaries," "-- Change of Control"
(other than a failure to purchase Notes), "-- Limitation on Liens,"
"-- Limitation on Sale/Leaseback Transactions," "-- Future Guarantors" or
"-- SEC Reports," (v) the failure by the Company to comply for 60 days after
notice with its other agreements contained in the Indenture, (vi) Indebtedness
of the Company or any Subsidiary Guarantor (other than Limited Recourse
Indebtedness) is not paid within any applicable grace period after final
maturity or the maturity of such Indebtedness is accelerated by the holders
thereof because of a default (and such acceleration is not rescinded or
annulled) and the total amount of such Indebtedness unpaid or accelerated
exceeds $10 million (the "cross acceleration provision"), (vii) certain events
of bankruptcy, insolvency or reorganization of the Company or a Significant
Subsidiary (the "bankruptcy provisions"), (viii) any judgment or decree for the
payment of money in excess of $10 million is rendered against the Company or a
Significant Subsidiary, remains outstanding for a period of 60 days following
such judgment and is not discharged, waived or stayed within 10 days after
notice (the "judgment default provision") or (ix) a Subsidiary Guaranty of a
Significant Subsidiary ceases to be in full force and effect (other than in
accordance with the terms of such Subsidiary Guaranty) or a Significant
Subsidiary denies or disaffirms its obligations under its Subsidiary Guaranty if
such default continues for a period of ten days after notice thereof to the
Company. However, a default under clauses (iv), (v) and (viii) will not
constitute an Event of Default until the Trustee or the holders of 25% in
principal amount of the outstanding Notes notify the Company of the default and
the Company does not cure such default within the time specified after receipt
of such notice.
If an Event of Default occurs and is continuing, the Trustee or the holders
of at least 25% in principal amount of the outstanding Notes may declare the
principal of and accrued but unpaid interest on all the Notes to be due and
payable. Upon such a declaration, such principal and interest shall be due and
payable immediately. If an Event of Default relating to certain events of
bankruptcy, insolvency or reorganization of the Company occurs and is
continuing, the principal of and interest on all the Notes will ipso facto
become and be immediately due and payable without any declaration or other act
on the part of the Trustee or any holders of the Notes. Under certain
circumstances, the holders of a majority in principal amount of the outstanding
Notes may rescind any such acceleration with respect to the Notes and its
consequences.
Subject to the provisions of the Indenture relating to the duties of the
Trustee, in case an Event of Default occurs and is continuing, the Trustee will
be under no obligation to exercise any of the rights or powers under the
Indenture at the request or direction of any of the holders of the Notes unless
such holders have offered to the Trustee reasonable indemnity or security
against any loss, liability or expense. Except to enforce the right to receive
payment of principal, premium (if any) or interest when due, no holder of a Note
may pursue any remedy with respect to the Indenture or the Notes unless (i) such
holder has previously given the Trustee notice that an Event of Default is
continuing, (ii) holders of at least 25% in principal amount of the outstanding
Notes have requested the Trustee to pursue the remedy, (iii) such holders have
offered the
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Trustee reasonable security or indemnity against any loss, liability or expense,
(iv) the Trustee has not complied with such request within 60 days after the
receipt thereof and the offer of security or indemnity and (v) the holders of a
majority in principal amount of the outstanding Notes have not given the Trustee
a direction inconsistent with such request within such 60-day period. Subject to
certain restrictions, the holders of a majority in principal amount of the
outstanding Notes are given the right to direct the time, method and place of
conducting any proceeding for any remedy available to the Trustee or of
exercising any trust or power conferred on the Trustee. The Trustee, however,
may refuse to follow any direction that conflicts with law or the Indenture or
that the Trustee determines is unduly prejudicial to the rights of any other
holder of a Note or that would involve the Trustee in personal liability.
The Indenture provides that if a Default occurs and is continuing and is
known to the Trustee, the Trustee must mail to each holder of the Notes notice
of the Default within 90 days after it occurs. Except in the case of a Default
in the payment of principal of or interest on any Note, the Trustee may withhold
notice if and so long as a committee of its trust officers determines that
withholding notice is not opposed to the interest of the holders of the Notes.
In addition, the Company is required to deliver to the Trustee, within 120 days
after the end of each fiscal year, a certificate indicating whether the signers
thereof know of any Default that occurred during the previous year. The Company
also is required to deliver to the Trustee, within 30 days after the occurrence
thereof, written notice of any event which would constitute certain Defaults,
their status and what action the Company is taking or proposes to take in
respect thereof.
AMENDMENTS AND WAIVERS
Subject to certain exceptions, the Indenture may be amended with the
consent of the holders of a majority in principal amount of the Notes then
outstanding (including consents obtained in connection with a tender offer or
exchange for the Notes) and any past default or compliance with any provisions
may also be waived with the consent of the holders of a majority in principal
amount of the Notes then outstanding. However, without the consent of each
holder of an outstanding Note affected thereby, no amendment may, among other
things, (i) reduce the amount of Notes whose holders must consent to an
amendment, (ii) reduce the rate of or extend the time for payment of interest on
any Note, (iii) reduce the principal of or extend the Stated Maturity of any
Note, (iv) reduce the premium payable upon the redemption of any Note or change
the time at which any Note may be redeemed as described under "-- Optional
Redemption," (v) make any Note payable in money other than that stated in the
Note, (vi) impair the right of any holder of the Notes to receive payment of
principal of and interest on such holder's Notes on or after the due dates
therefor or to institute suit for the enforcement of any payment on or with
respect to such holder's Notes, (vii) make any change in the amendment
provisions which require each holder's consent or in the waiver provisions,
(viii) make any change to the subordination provisions of the Indenture that
would adversely affect the Noteholders or (ix) make any change in any Subsidiary
Guaranty that could adversely affect such holder.
Without the consent of any holder of the Notes, the Company, the Subsidiary
Guarantors and Trustee may amend the Indenture to cure any ambiguity, omission,
defect or inconsistency, to provide for the assumption by a successor
corporation of the obligations of the Company or a Subsidiary Guarantor under
the Indenture, to provide for uncertificated Notes in addition to or in place of
certificated Notes (provided that the uncertificated Notes are issued in
registered form for purposes of Section 163(f) of the Code, or in a manner such
that the uncertificated Notes are described in Section 163(f)(2)(B) of the
Code), to add guarantees with respect to the Notes, to secure the Notes, to add
to the covenants of the Company or a Subsidiary Guarantor for the benefit of the
holders of the Notes or to surrender any right or power conferred upon the
Company or a Subsidiary Guarantor, to make any change that does not adversely
affect the rights of any holder of the Notes or to comply with any requirement
of the SEC in connection with the qualification of the Indenture under the Trust
Indenture Act. However, no amendment may be made to the subordination provisions
of the Indenture that adversely affects the rights of any holder of Senior
Indebtedness of a Subsidiary Guarantor then outstanding unless the holders of
such Senior Indebtedness (or their Representative) consents to such change.
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The consent of the holders of the Notes is not necessary under the
Indenture to approve the particular form of any proposed amendment. It is
sufficient if such consent approves the substance of the proposed amendment.
After an amendment under the Indenture becomes effective, the Company is
required to mail to holders of the Notes a notice briefly describing such
amendment. However, the failure to give such notice to all holders of the Notes,
or any defect therein, will not impair or affect the validity of the amendment.
TRANSFER
The Notes will be issued in registered form and will be transferable only
upon the surrender of the Notes being transferred for registration of transfer.
The Company may require payment of a sum sufficient to cover any tax, assessment
or other governmental charge payable in connection with certain transfers and
exchanges.
DEFEASANCE
The Company at any time may terminate all its obligations under the Notes
and the Indenture ("legal defeasance"), except for certain obligations,
including those respecting the defeasance trust and obligations to register the
transfer or exchange of the Notes, to replace mutilated, destroyed, lost or
stolen Notes and to maintain a registrar and paying agent in respect of the
Notes. The Company at any time may terminate its obligations under the covenants
described under "-- Certain Covenants" (other than the covenant described under
"-- Merger and Consolidation"), the operation of the cross acceleration
provision, the bankruptcy provisions with respect to Significant Subsidiaries
and the judgment default provision described under "-- Defaults" above and the
limitations contained in clauses (iii) and (iv) under the first paragraph of,
and in the third paragraph of, "-- Certain Covenants -- Merger and
Consolidation" above ("covenant defeasance").
The Company may exercise its legal defeasance option notwithstanding its
prior exercise of its covenant defeasance option. If the Company exercises its
legal defeasance option, payment of the Notes may not be accelerated because of
an Event of Default with respect thereto. If the Company exercises its covenant
defeasance option, payment of the Notes may not be accelerated because of an
Event of Default specified in clause (iv), (vi), (vii) (with respect only to
Significant Subsidiaries) or (viii) under "-- Defaults" above or because of the
failure of the Company to comply with clause (iii) or (iv) under the first of
paragraph of, or with the third paragraph of, "-- Certain Covenants -- Merger
and Consolidation" above. If the Company exercises its legal defeasance option
or its covenant defeasance option each Subsidiary Guarantor, if any, will be
released from all its obligations with respect to its Subsidiary Guaranty.
In order to exercise either defeasance option, the Company must irrevocably
deposit in trust (the "defeasance trust") with the Trustee money or U.S.
Government Obligations for the payment of principal and interest on the Notes to
redemption or maturity, as the case may be, and must comply with certain other
conditions, including delivery to the Trustee of an Opinion of Counsel to the
effect that holders of the Notes will not recognize income, gain or loss for
Federal income tax purposes as a result of such deposit and defeasance and will
be subject to Federal income tax on the same amount and in the same manner and
at the same times as would have been the case if such deposit and defeasance had
not occurred (and, in the case of legal defeasance only, such Opinion of Counsel
must be based on a ruling of the Internal Revenue Service or other change in
applicable Federal income tax law).
CONCERNING THE TRUSTEE
is to be the Trustee under the Indenture and
has been appointed by the Company as Registrar and Paying Agent with regard to
the Notes.
The Holders of a majority in principal amount of the outstanding Notes will
have the right to direct the time, method and place of conducting any proceeding
for exercising any remedy available to the Trustee, subject to certain
exceptions. The Indenture provides that if an Event of Default occurs (and is
not cured), the Trustee will be required, in the exercise of its power, to use
the degree of care of a prudent man in the conduct of his own affairs. Subject
to such provisions, the Trustee will be under no obligation to exercise any of
its
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rights or powers under the Indenture at the request of any Holder of Notes,
unless such Holder shall have offered to the Trustee security and indemnity
satisfactory to it against any loss, liability or expense and then only to the
extent required by the terms of the Indenture.
GOVERNING LAW
The Indenture provides that it (including the Subsidiary Guarantees) and
the Notes and will be governed by, and construed in accordance with, the laws of
the State of New York without giving effect to applicable principles of
conflicts of law to the extent that the application of the law of another
jurisdiction would be required thereby.
DESCRIPTION OF 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 oil and 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 oil and 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 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 oil and natural
gas properties and changes in 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 mature 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.
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, restricts the payment of dividends, limits the Company's ability to
incur additional debt, and provides that the Company must maintain minimum
amounts of shareholders equity and financial ratio coverages. See "Management's
Discussion and Analysis of Financial Results and Operations -- Liquidity and
Capital Resources."
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CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS
The following is a general discussion of the principal United States
federal income tax consequences of the purchase, ownership and disposition of
the Notes to initial purchasers thereof who are United States Holders (as
defined below) and the principal United States federal income and estate tax
consequences of the purchase, ownership and disposition of the Notes to initial
purchasers who are Foreign Holders (as described below). This discussion is
based on currently existing provisions of the Code, existing, temporary and
proposed Treasury regulations promulgated thereunder, and administrative and
judicial interpretations thereof, all as in effect or proposed on the date
hereof and all of which are subject to change, possibly with retroactive effect,
or different interpretations. This discussion does not address the tax
consequences to subsequent purchasers of Notes and is limited to purchasers who
hold the Notes as capital assets, within the meaning of section 1221 of the
Code. This discussion also does not address the tax consequences to Foreign
Holders that are subject to United States federal income tax on a net basis on
income realized with respect to a Note because such income is effectively
connected with the conduct of a United States trade or business. Such Foreign
Holders are generally taxed in a similar manner to United States Holders, but
certain special rules do apply. Moreover, this discussion is for general
information only and does not address all of the tax consequences that may be
relevant to particular initial purchasers in light of their personal
circumstances or to certain types of initial purchasers (such as certain
financial institutions, insurance companies, tax-exempt entities, dealers in
securities or persons who have hedged the risk of owning a Note).
PROSPECTIVE PURCHASERS ARE URGED TO CONSULT THEIR OWN TAX ADVISORS AS TO
THE PARTICULAR TAX CONSEQUENCES TO THEM OF THE PURCHASE, OWNERSHIP AND
DISPOSITION OF THE NOTES, INCLUDING THE APPLICABILITY OF ANY FEDERAL TAX LAWS OR
ANY STATE, LOCAL OR FOREIGN TAX LAWS, AND ANY CHANGES (OR PROPOSED CHANGES) IN
APPLICABLE TAX LAWS OR INTERPRETATIONS THEREOF.
UNITED STATES FEDERAL INCOME TAXATION OF UNITED STATES HOLDERS
As used herein, the term "United States Holder" means a holder of a Note
that is, for United States federal income tax purposes, (a) a citizen or
resident of the United States, (b) a corporation, partnership or other entity
created or organized in or under the laws of the United States or any political
subdivision thereof, (c) an estate the income of which is subject to United
States federal income taxation regardless of source, or (iv) a trust subject to
the primary supervision of a court within the United States and the control of a
United States fiduciary as described in Section 7701(a)(30) of the Code.
Payment of Interest on Notes. Interest paid or payable on a Note will be
taxable to a United States Holder as ordinary interest income, generally at the
time it is received or accrued, in accordance with such holder's regular method
of accounting for United States federal income tax purposes.
Sale, Exchange or Retirement of the Notes. Upon the sale, exchange,
redemption, retirement at maturity or other disposition of a Note, a United
States Holder generally will recognize taxable gain or loss equal to the
difference between the sum of cash plus the fair market value of all other
property received on such disposition (except to the extent such cash or
property is attributable to accrued but unpaid interest, which will be taxable
as ordinary income) and such United States Holder's adjusted tax basis in the
Note. A United States Holder's adjusted tax basis in a Note generally will equal
the cost of the Note to such United States Holder, less any principal payments
received by such United States Holder.
Gain or loss recognized on the disposition of a Note generally will be
capital gain or loss and will be long-term capital gain or loss if, at the time
of such disposition, the United States Holder's holding period for the Note is
more than one year. Under the Taxpayer Relief Act of 1997, lower tax rates apply
to the sale or exchange of capital assets by individuals who have held such
assets for more than 18 months.
Backup Withholding and Information Reporting. Backup withholding and
information reporting requirements may apply to certain payments of principal,
premium, if any, and interest on a Note, and to proceeds of the sale or
redemption of a Note before maturity. The Company, its agent, a broker, the
Trustee or any paying
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<PAGE> 173
agent, as the case may be, will be required to withhold from any payment that is
subject to backup withholding a tax equal to 31% of such payment if a United
States Holder fails to furnish his, her or its taxpayer identification number
(social security or employer identification number), certify that such number is
correct, certify that such holder is not subject to backup withholding or
otherwise comply with the applicable requirements of the backup withholding
rules. Certain United States Holders, including all corporations, are not
subject to backup withholding and information reporting requirements. Any
amounts withheld under the backup withholding rules from a payment to a United
States Holder will be allowed as a credit against such United States Holder's
United States federal income tax liability and may entitle the holder to a
refund, provided that the required information is furnished to the Internal
Revenue Service ("IRS").
UNITED STATES FEDERAL INCOME TAXATION OF FOREIGN HOLDERS
As used herein, the term "Foreign Holder" means a holder of a Note that is,
for United States federal income tax purposes, (a) a nonresident alien
individual, (b) a foreign corporation, (c) a nonresident alien fiduciary of a
foreign estate or trust or (d) a foreign partnership.
Payment of Interest on Notes. In general, payments of interest received by
a Foreign Holder will not be subject to a United States federal withholding tax,
provided that (i)(a) the Foreign Holder does not actually or constructively own
10% or more of the total combined voting power of all classes of stock of the
Company entitled to vote, (b) the Foreign Holder is not a controlled foreign
corporation that is related to the Company actually or constructively through
stock ownership, and (c) either (I) the beneficial owner of the Note, under
penalties of perjury, provides the Company or its agent with such beneficial
owner's name and address and certifies on IRS Form W-8 (or a suitable substitute
form) that it is not a United States Holder or (II) a securities clearing
organization, bank or other financial institution that holds customers'
securities in the ordinary course of its trade or business (a "financial
institution") holds the Note and provides a statement to the Company or its
agent under penalties of perjury in which it certifies that such an IRS Form W-8
(or a suitable substitute) has been received by it from the beneficial owner of
the Notes or qualifying intermediary and furnishes the Company or its agent a
copy thereof or (ii) the Foreign Holder is entitled to the benefits of an income
tax treaty under which interest on the Notes is exempt from United States
withholding tax and the Foreign Holder or such Foreign Holder's agent provides a
properly executed IRS Form 1001 claiming the exemption. Payments of interest not
exempt from United States federal withholding tax as described above will be
subject to such withholding tax at the rate of 30% (subject to reduction under
an applicable income tax treaty).
Sale, Exchange or Retirement of the Notes. A Foreign Holder generally will
not be subject to United States federal income tax (and generally no tax will be
withheld) with respect to gain realized on the sale, exchange, redemption,
retirement at maturity or other disposition of a Note unless the Foreign Holder
is an individual who is present in the United States for a period or periods
aggregating 183 or more days in the taxable year of the disposition and,
generally, either has a "tax home" or an "office or other fixed place of
business" in the United States.
Backup Withholding and Information Reporting. Backup withholding and
information reporting requirements do not apply to payments of interest made by
the Company or a paying agent to Foreign Holders if the certification described
above under "-- United States Federal Income Taxation of Foreign Holders --
Payment of Interest on Notes" is received, provided that the payor does not have
actual knowledge that the holder is a United States Holder. If any payments of
principal and interest are made to the beneficial owner of a Note by or through
the foreign office of a foreign custodian, foreign nominee or other foreign
agent of such beneficial owner, or if the foreign office of a foreign "broker"
(as defined in applicable Treasury regulations) pays the proceeds of the sale of
a Note to the seller thereof, backup withholding and information reporting will
not apply. Information reporting requirements (but not backup withholding) will
apply, however, to a payment by a foreign office of a broker that is a United
States person, that derives 50% or more of its gross income for certain periods
from the conduct of a trade or business in the United States, or that is a
"controlled foreign corporation" (generally, a foreign corporation controlled by
certain United States shareholders) with respect to the United States unless the
broker has documentary evidence in its records that the holder is a Foreign
Holder and certain other conditions are met or the holder otherwise establishes
an exemption. Payment by a
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<PAGE> 174
United States office of a broker is subject to both backup withholding at a rate
of 31% and information reporting unless the holder certifies under penalties of
perjury that it is a Foreign Holder or otherwise establishes an exemption.
The procedures described above for withholding tax on interest 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
Subject to applicable estate tax treaty provisions, Notes held at the time
of death (or Notes transferred before death but subject to certain retained
rights or powers) by an individual who at the time of death is a Foreign Holder
will not be included in such Foreign Holder's gross estate for United States
federal estate tax purposes provided that the individual does not actually or
constructively own 10% or more of the total combined voting power of all classes
of stock of the Company entitled to vote or hold the Notes in connection with a
United States trade or business.
UNDERWRITERS
Under the terms and subject to the conditions in an Underwriting Agreement
dated the date hereof (the "Underwriting Agreement"), the Underwriters named
below have severally agreed to purchase, and the Company has agreed to sell to
them, severally, the respective principal amounts of Notes set forth opposite
their respective names below:
<TABLE>
<CAPTION>
PRINCIPAL
AMOUNT OF
UNDERWRITER NOTES
----------- ----------
<S> <C>
Morgan Stanley & Co. Incorporated........................... $
Jefferies & Company, Inc. ..................................
----------
Total............................................. $
==========
</TABLE>
The Underwriting Agreement provides that the obligations of the
Underwriters to pay for and accept delivery of the Notes is 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 the Notes if
any are taken.
The Underwriters initially propose to offer the Notes directly to the
public at the public offering price set forth or the cover page hereof and to
certain dealers at a price that represents a concession not in excess of %
of the principal amount of the Notes. Each Underwriter may allow, and such
dealers may reallow, a concession to certain other dealers not in excess of
% of the principal amount of the Notes. After the initial offering of the
Notes, the offering price and other selling terms may from time to time be
varied by the Underwriters.
The Company does not intend to apply for listing of the Notes on any
national securities exchange, but has been advised by the Underwriters that they
presently intend to make a market in the Notes, as permitted by applicable laws
and regulations. The Underwriters are not obligated, however, to make a market
in the Notes and any such market making may be discontinued at any time at the
sole discretion of the Underwriters. Accordingly, no assurance can be given as
to the liquidity of, or the existence of trading markets for, the Notes.
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<PAGE> 175
In order to facilitate this Offering, the Underwriters may engage in
transactions that stabilize, maintain or otherwise affect the price of the
Notes. Specifically, the Underwriters may overallot in connection with this
Offering, creating a short position in the Notes for their own account. In
addition, to cover overallotments or to stabilize the price of the Notes, the
Underwriters may bid for, and purchase, shares of Notes in the open market.
Finally, the underwriting syndicate may reclaim selling concessions allowed to
an underwriter or a dealer for distributing the Notes in this Offering, if the
syndicate repurchases previously distributed Notes 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 Notes above
independent market levels. The Underwriters are not required to engage in these
activities, and may end any of these activities at any time.
The Company and the Underwriters have agreed to indemnify each other
against certain liabilities, including liabilities under the Securities Act of
1933.
MSLEF II, an affiliate of Morgan Stanley & Co. Incorporated, prior to the
Offerings owned common stock of the Company representing 27.4% of the Common
Stock of the Company. In addition, Mr. Howard Hoffen, currently a Principal of
Morgan Stanley & Co. Incorporated, is a member of the Board of Directors of
MSLEF II.
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.
LEGAL MATTERS
Certain legal matters with respect to the validity of the Notes 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 of 1933 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.
81
<PAGE> 176
AVAILABLE INFORMATION
Coho Energy, Inc. is subject to the informational requirements of the
Securities Exchange Act of 1934, as amended (the "Exchange Act"), and, in
accordance therewith, files reports, proxy statements and other information with
the Securities and Exchange Commission (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 Act of 1933 (the "Securities
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.
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<PAGE> 177
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.
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<PAGE> 178
EXPLANATORY NOTE
The financial statements and summary reserve report to be included in this
Prospectus appear in this Registration Statement as part of the prospectus for
the Equity Offering that is also part of this Registration Statement.
<PAGE> 179
[COHO LOGO]
<PAGE> 180
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION
The following sets forth the estimated expenses and costs (other than
underwriting discounts and commissions) expected to be incurred in connection
with the issuance and distribution of the securities registered hereby:
<TABLE>
<S> <C>
Securities and Exchange Commission registration fee......... $67,046.52
NASD filing fee............................................. 22,625.35
Printing and engraving costs................................ *
Transfer agent, trustee and registrar fees.................. *
Legal fees and expenses..................................... *
Accounting fees and expenses................................ *
Miscellaneous............................................... *
----------
Total............................................. $ *
</TABLE>
- ---------------
* To be filed by amendment.
INDEMNIFICATION OF DIRECTORS AND OFFICERS
Article 2.02-1 of the Texas Business Corporation Act provides that any
director or officer of a Texas corporation may be indemnified against judgments,
penalties, fines, settlements and reasonable expenses actually incurred by him
in connection with or in defending any action, suit or proceeding in which he is
a party by reason of his position. With respect to any proceeding arising from
actions taken in his official capacity as a director or officer, he may be
indemnified so long as it shall be determined that he conducted himself in good
faith and that he reasonably believed that such conduct was in the corporation's
best interests. In cases not concerning conduct in his official capacity as a
director or officer, a director may be indemnified as long as he reasonably
believed that his conduct was not opposed to the corporation's best interests.
In the case of any criminal proceeding, a director or officer may be indemnified
if he had no reasonable cause to believe his conduct was unlawful. If a director
or officer is wholly successful, on the merits or otherwise, in connection with
such a proceeding, such indemnification is mandatory. The Registrant's Bylaws
provide for indemnification of its present and former directors and officers to
the fullest extent provided by Article 2.02-1.
The Registrant's Bylaws further provide for indemnification of officers and
directors against reasonable expenses incurred in connection with the defense of
any such action, suit or proceeding in advance of the final disposition of the
proceeding.
The Registrant's Articles of Incorporation eliminate or limit liabilities
of directors for breaches of their duty of care. The Articles do not limit or
eliminate the right of the Registrant or any shareholder to pursue equitable
remedies such as an action to enjoin or rescind a transaction involving a breach
of a director's duty of care, nor does it affect director liability to parties
other than the Registrant or its shareholders. In addition, directors will
continue to be liable for (i) breach of their duty of loyalty, (ii) acts or
omissions not in good faith or which involve intentional misconduct or a knowing
violation of the law, (iii) declaring an illegal dividend or stock repurchase,
(iv) any transaction in which the directors received an improper personal
benefit, or (v) acts or omissions for which the liability of directors is
expressly provided by statute. In addition, the amendment applies only to claims
under Texas law against a director arising out of his role as a director and
not, if he is also an officer, his role as an officer or in any other capacity
and does not limit a director's liability under any other law, such as federal
securities law.
Texas corporations are also authorized to obtain insurance to protect
officers and directors from certain liabilities, including liabilities against
which the corporation cannot indemnify its directors and officers. The
Registrant currently has in effect a director's and officer's liability
insurance policy, which provides coverage in the maximum amount of $15,000,000,
subject to a $150,000 deductible.
II-1
<PAGE> 181
EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
*1.1 -- Underwriting Agreement for Common Stock.
*1.2 -- Underwriting Agreement for Notes.
4.1 -- Articles of Incorporation of the Company (incorporated by
reference to Exhibit 3.1 to the Company's Registration
Statement on Form S-4 (Registration No. 33-65620)).
4.2 -- Statement of Resolution Establishing Series of Shares of
Series A Preferred Stock dated December 8, 1994
(incorporated by reference to the Company's Form 8-K
filed on December 16, 1984).
4.3 -- First Amendment to Statement of Resolution Establishing
Series of Shares of Series A Preferred Stock dated August
23, 1995 (incorporated by reference to Exhibit 3(i).1 to
the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1995).
4.4 -- Bylaws of the Company (incorporated by reference to
Exhibit 3.2 to the Company's Registration Statement on
Form S-4 (Registration No. 33-65620)).
4.4 -- Rights Agreement dated September 13, 1994 between Coho
Energy, Inc. and Chemical Bank (incorporated by reference
to Exhibit 1 to the Company's Form 8-A dated September
13, 1994).
4.5 -- First Amendment to Rights Agreement made as of December
8, 1994 between Coho Energy, Inc. and Chemical Bank
(incorporated by reference to Exhibit 4.5 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1994).
4.6 -- Second Amendment to Rights Agreement as of August 30,
1995 between Coho Energy, Inc. and Chemical Bank
(incorporated by reference to Exhibit 4.1 to the
Company's Quarterly Report on Form 10-Q for the quarter
ended September 30, 1995).
*4.7 -- Indenture for Notes.
*5.1 -- Opinion of Fulbright & Jaworski L.L.P.
**12.1 -- Statement of computation of ratios.
**15.1 -- Letter regarding unaudited interim financial information.
**23.1 -- Consent of KPMG Peat Marwick LLP.
**23.2 -- Consent of Arthur Andersen LLP.
**23.3 -- Consent of Ryder Scott Company Petroleum Engineers.
*23.4 -- Consent of Fulbright & Jaworski L.L.P. (included in
Exhibit 5.1).
**25.1 -- Statement of eligibility of trustee.
</TABLE>
- ---------------
* To be filed by amendment.
** Filed herewith.
UNDERTAKINGS
The undersigned registrant hereby undertakes that, for purposes of
determining any liability under the Securities Act of 1933, each filing of the
registrant's annual report pursuant to section 13(a) or section 15(d) of the
Securities Exchange Act of 1934 that is incorporated by reference in the
registration statement
II-2
<PAGE> 182
shall be deemed to be a new registration statement relating to the securities
offered therein, and the offering of such securities at that time shall be
deemed to be the initial bona fide offering thereof.
Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers, and controlling persons of the
Registrant pursuant to the foregoing provisions, or otherwise, the Registrant
has been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Act and is,
therefore, unenforceable. In the event that a claim for indemnification against
such liabilities (other than the payment by the Registrant of expenses incurred
or paid by a director, officer, or controlling person of the Registrant in the
successful defense of any action, suit, or proceeding) is asserted by such
director, officer, or controlling person in connection with the securities being
registered, the Registrant will, unless in the opinion of its counsel the matter
has been settled by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by it is against public
policy as expressed in the Act and will be governed by the final adjudication of
such issue.
The undersigned Registrant hereby undertakes that:
(1) For purposes of determining any liability under the Securities Act of
1933, the information omitted from the form of prospectus filed as part of this
Registration Statement in reliance upon Rule 430A and contained in a form of
prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h)
under the Securities Act shall be deemed to be part of this Registration
Statement as of the time it was declared effective.
(2) For the purpose of determining any liability under the Securities Act
of 1933, each post-effective amendment that contains a form of prospectus shall
be deemed to be a new registration statement relating to the securities offered
therein, and the offering of such securities at that time shall be deemed to be
the initial bona fide offering thereof.
II-3
<PAGE> 183
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the registrant
certifies that it has reasonable grounds to believe it meets all of the
requirements for filing on Form S-3 and has duly caused this registration
statement to be signed on its behalf by the undersigned, thereunto duly
authorized, in the City of Dallas, State of Texas on August 20, 1997.
COHO ENERGY, INC.
By: /s/ JEFFREY CLARKE
----------------------------------
Jeffrey Clarke
President and Chief Executive
Officer
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears
below hereby constitutes and appoints Jeffrey Clark, Eddie M. LeBlanc, III and
Anne Marie O'Gorman, or any of them, each with power to act without the other,
his true and lawful attorney-in-fact and agent, with full power of substitution
and resubstitution, for him and in his name, place and stead, in any and all
capacities, to sign any or all subsequent pre- and post-effective amendments and
supplements to this Registration Statement, and to file the same, or cause to be
filed the same, with all exhibits thereto, and other documents in connection
therewith, with the Securities and Exchange Commission, granting unto each said
attorney-in-fact and agent full power to do and perform each and every act and
thing requisite and necessary to be done in and about the premises, as fully to
all intents and purposes as he might or could do in person, hereby ratifying and
confirming all that any said attorney-in-fact and agent or his substitute or
substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, this
registration statement has been signed by the following persons in the
capacities and on the dates indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ JEFFREY CLARKE President, Chief Executive August 20, 1997
- ----------------------------------------------------- Officer and Director
Jeffrey Clarke (Principal Executive
Officer)
/s/ EDDIE M. LEBLANC, III Sr. Vice President and Chief August 20, 1997
- ----------------------------------------------------- Financial Officer (Principal
Eddie M. LeBlanc, III Financial Officer)
/s/ SUSAN J. MCADEN Controller (Principal August 20, 1997
- ----------------------------------------------------- Accounting Officer)
Susan J. McAden
/s/ ROBERT B. ANDERSON Director August 20, 1997
- -----------------------------------------------------
Robert B. Anderson
/s/ ROY R. BAKER Director August 20, 1997
- -----------------------------------------------------
Roy R. Baker
/s/ FREDERICK K. CAMPBELL Director August 20, 1997
- -----------------------------------------------------
Frederick K. Campbell
</TABLE>
II-4
<PAGE> 184
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ LOUIS F. CRANE Director August 20, 1997
- -----------------------------------------------------
Louis F. Crane
/s/ HOWARD I. HOFFEN Director August 20, 1997
- -----------------------------------------------------
Howard I. Hoffen
/s/ KENNETH H. LAMBERT Director August 20, 1997
- -----------------------------------------------------
Kenneth H. Lambert
/s/ DOUGLAS R. MARTIN Director August 20, 1997
- -----------------------------------------------------
Douglas R. Martin
/s/ CARL S. QUINN Director August 20, 1997
- -----------------------------------------------------
Carl S. Quinn
Director
- -----------------------------------------------------
Jake Taylor
</TABLE>
II-5
<PAGE> 185
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
*1.1 -- Underwriting Agreement for Common Stock.
*1.2 -- Underwriting Agreement for Notes.
4.1 -- Articles of Incorporation of the Company (incorporated by
reference to Exhibit 3.1 to the Company's Registration
Statement on Form S-4 (Registration No. 33-65620)).
4.2 -- Statement of Resolution Establishing Series of Shares of
Series A Preferred Stock dated December 8, 1994
(incorporated by reference to the Company's Form 8-K
filed on December 16, 1984).
4.3 -- First Amendment to Statement of Resolution Establishing
Series of Shares of Series A Preferred Stock dated August
23, 1995 (incorporated by reference to Exhibit 3(i).1 to
the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1995).
4.4 -- Bylaws of the Company (incorporated by reference to
Exhibit 3.2 to the Company's Registration Statement on
Form S-4 (Registration No. 33-65620)).
4.4 -- Rights Agreement dated September 13, 1994 between Coho
Energy, Inc. and Chemical Bank (incorporated by reference
to Exhibit 1 to the Company's Form 8-A dated September
13, 1994).
4.5 -- First Amendment to Rights Agreement made as of December
8, 1994 between Coho Energy, Inc. and Chemical Bank
(incorporated by reference to Exhibit 4.5 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1994).
4.6 -- Second Amendment to Rights Agreement as of August 30,
1995 between Coho Energy, Inc. and Chemical Bank
(incorporated by reference to Exhibit 4.1 to the
Company's Quarterly Report on Form 10-Q for the quarter
ended September 30, 1995).
*4.7 -- Indenture for Notes.
*5.1 -- Opinion of Fulbright & Jaworski L.L.P.
**12.1 -- Statement of computation of ratios.
**15.1 -- Letter regarding unaudited interim financial information.
**23.1 -- Consent of KPMG Peat Marwick LLP.
**23.2 -- Consent of Arthur Andersen LLP.
**23.3 -- Consent of Ryder Scott Company Petroleum Engineers.
*23.4 -- Consent of Fulbright & Jaworski L.L.P. (included in
Exhibit 5.1).
*25.1 -- Statement of eligibility of trustee.
</TABLE>
- ---------------
* To be filed by amendment.
** Filed herewith.
<PAGE> 1
EXHIBIT 12.1
COMPUTATION OF RATIOS
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
-------------------------------------------------- --------------------
1992 1993 1994 1995 1996 1996 1997
------- -------- ------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
RATIO OF EARNINGS TO FIXED CHARGES
Earnings (loss) before taxes............... $ 5,967 $(18,668) $(1,277) $ 281 $ 9,389 $ 3,591 $ 5,222
Fixed charges in earnings:
Interest expense......................... 3,270 3,571 4,190 8,140 8,476 4,233 4,682
Debt amortization........................ -- 6 52 222 379 205 122
------- -------- ------- -------- -------- -------- --------
Earnings (loss) before taxes and fixed
charges.................................. $ 9,237 $(15,091) $ 2,965 $ 8,643 $ 18,244 $ 8,029 $ 10,026
======= ======== ======= ======== ======== ======== ========
Fixed charges:
Interest expense......................... $ 3,270 $ 3,571 $ 4,190 $ 8,140 $ 8,476 $ 4,233 $ 4,682
Debt amortization........................ -- 6 52 222 379 205 122
Pretax preferred dividends............... -- -- 113 1,570 -- -- --
------- -------- ------- -------- -------- -------- --------
Total fixed charges........................ $ 3,270 $ 3,577 $ 4,355 $ 9,932 $ 8,855 $ 4,438 $ 4,804
======= ======== ======= ======== ======== ======== ========
Ratio of earnings to fixed charges......... 2.8x NM NM NM 2.1x 1.8x 2.1x
======= ======== ======== ========
Earnings coverage deficiency............... -- $ 18,668 $ 1,390 $ 1,289 -- -- --
======== ======= ========
RATIO OF EBITDA TO INTEREST EXPENSE
EBITDA(a).................................. $16,886 $ 15,493 $12,684 $ 23,046 $ 33,133 $ 15,199 $ 18,715
Interest expense........................... $ 3,270 $ 3,571 $ 4,190 $ 8,140 $ 8,476 $ 4,233 $ 4,682
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
Long-term debt(a).......................... $52,000 $ 54,000 $86,567 $107,671 $122,938 $ 96,242 $132,411
EBITDA(b).................................. $16,886 $ 15,493 $12,684 $ 23,046 $ 33,133 $ 15,199 $ 18,715
Ratio of long-term debt to EBITDA.......... 3.1x 3.5x 6.8x 4.7x 3.7x 3.2x(c) 3.5x(c)
======= ======== ======= ======== ======== ======== ========
</TABLE>
- ---------------
(a) Includes current maturities of long-term debt.
(b) Earnings before interest, taxes, depreciation, depletion and amortization.
(c) EBITDA for these periods has been annualized.
<PAGE> 1
EXHIBIT 15.1
August 20, 1997
We are aware that Coho Energy, Inc. has incorporated by reference in its
Registration Statement dated August 20, 1997, its Financial Statements for the
six months ended June 30, 1997, which includes our report dated August 14, 1997
covering the unaudited interim financial information contained therein. Pursuant
to Regulation C of the Securities Act of 1933, that report is not considered a
part of the registration statement prepared or certified by our firm or a report
prepared or certified by our firm within the meaning of Sections 7 and 11 of the
Act.
Very truly yours,
ARTHUR ANDERSEN LLP
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
The Board of Directors
Coho Energy, Inc.:
We consent to the use of our reports included and incorporated by reference
herein and to the reference to our firm under the heading "Experts" in the
prospectus.
KPMG PEAT MARWICK LLP
Dallas, Texas
August 18, 1997
<PAGE> 1
EXHIBIT 23.2
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the use in this
registration statement of our reports dated February 21, 1997 included herein
and to all references to our Firm included in this registration statement.
ARTHUR ANDERSEN LLP
Dallas, Texas
August 19, 1997
<PAGE> 1
EXHIBIT 23.3
CONSENT OF PETROLEUM ENGINEERS
As independent petroleum engineers, we hereby consent to the inclusion in
the registration statement of Coho Energy, Inc. of our letter report dated
February 6, 1997 regarding our review of proved oil and gas reserve quantities
as of December 31, 1996 and to all references to such letters and to our Firm
included in this registration statement.
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
Houston, Texas
August 19, 1997
