<PAGE> 1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
---------
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to ________.
Commission file number 0-22576
COHO ENERGY, INC.
(Exact name of registrant as specified in its charter)
Texas 75-2488635
- ------------------------------- ----------------------
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification Number)
14785 Preston Road, Suite 860
Dallas, Texas 75240
- ----------------------------- ----------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:
(972) 774-8300
--------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding twelve months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
--- ---
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at November 11, 1998
---------------------------- --------------------------------
Common Stock, $.01 par value 25,603,512
<PAGE> 2
INDEX
<TABLE>
<CAPTION>
PAGE
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<S> <C>
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Report of Independent Public Accountants .............................................. 1
Condensed Consolidated Balance Sheets -
December 31, 1997 and September 30, 1998 .............................................. 2
Condensed Consolidated Statements of Operations -
three and nine months ended September 30, 1997 and 1998 ............................... 3
Condensed Consolidated Statements of Cash Flows -
nine months ended September 30, 1997 and 1998 ......................................... 4
Notes to Condensed Consolidated Financial Statements .................................. 5
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations ......................................... 7
Item 3. Quantitative and Qualitative Disclosures About Market Risk ........................... 13
PART II. OTHER INFORMATION
Item 1. Legal Proceedings .................................................................... 14
Item 2. Changes in Securities ................................................................ 14
Item 3. Defaults Upon Senior Securities ...................................................... 14
Item 4. Submission of Matters to a Vote of Security Holders .................................. 14
Item 5. Other Information .................................................................... 14
Item 6. Exhibits and Reports on Form 8-K ..................................................... 14
Signatures .................................................................................... 15
</TABLE>
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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. and subsidiaries as of September 30, 1998 and the related
condensed consolidated statements of operations for the three month and nine
month periods ended September 30, 1998 and the condensed statement of cash flows
for the nine month period ended September 30, 1998, in accordance with
Statements on Standards for Accounting and Review Services issued by the
American Institute of Certified Public Accountants. All information included in
these financial statements is the representation of the management of Coho
Energy, Inc. and subsidiaries.
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 financial statements referred to above for them to be in
conformity with generally accepted accounting principles.
We have previously audited, in accordance with generally accepted
auditing standards, the consolidated balance sheet of Coho Energy, Inc. as of
December 31, 1997 included in the Company's 1997 annual report on Form 10-K, and
in our report dated March 20, 1998, we expressed an unqualified opinion on that
statement. In our opinion, the information set forth in the accompanying
condensed consolidated balance sheet as of December 31, 1997 is fairly stated,
in all material respects, in relation to the consolidated balance sheet included
in the Company's 1997 annual report on Form 10-K from which it has been derived.
Arthur Andersen LLP
Dallas, Texas
November 13, 1998
1
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
COHO ENERGY, INC.
AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
ASSETS
DECEMBER 31 SEPTEMBER 30
1997 1998
---------- ----------
(UNAUDITED)
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents ................................................. $ 3,817 $ 1,889
Accounts receivable, principally trade .................................... 10,724 15,830
Deferred income taxes ..................................................... 1,818 --
Other current assets ...................................................... 715 765
---------- ----------
17,074 18,484
PROPERTY AND EQUIPMENT, at cost net of accumulated depletion and
depreciation, based on full cost accounting method (note 2) ............... 531,409 498,826
OTHER ASSETS ................................................................ 6,645 7,523
---------- ----------
$ 555,128 $ 524,833
========== ==========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable, principally trade ....................................... $ 4,888 $ 7,407
Accrued liabilities and other payables .................................... 14,169 18,189
Current portion of long term debt ......................................... 38 26
---------- ----------
19,095 25,622
LONG TERM DEBT, excluding current portion ................................... 369,924 424,488
DEFERRED INCOME TAXES ....................................................... 20,306 --
---------- ----------
409,325 450,110
---------- ----------
COMMITMENTS AND CONTINGENCIES (note 4) ...................................... 3,700 3,700
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 25,603,512 shares ................................ 256 256
Additional paid-in capital ................................................ 137,812 137,812
Retained earnings (deficit) ............................................... 4,035 (67,045)
---------- ----------
Total shareholders' equity ............................................ 142,103 71,023
---------- ----------
$ 555,128 $ 524,833
========== ==========
</TABLE>
SEE ACCOMPANYING NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
2
<PAGE> 5
COHO ENERGY, INC.
AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
NINE MONTHS ENDED THREE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
----------------------- ------------------------
1997 1998 1997 1998
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
OPERATING REVENUES
Net crude oil and natural gas production ................... $ 45,506 $ 55,829 $ 15,985 $ 16,539
---------- ---------- ---------- ----------
OPERATING EXPENSES
Crude oil and natural gas production ....................... 10,012 18,282 3,899 5,698
Taxes on oil and gas production ............................ 1,629 2,728 559 844
General and administrative ................................. 5,048 4,752 1,425 1,437
Depletion and depreciation ................................. 14,072 22,235 5,112 7,216
Writedown of crude oil and natural gas properties .......... --- 73,000 --- ---
---------- ---------- ---------- ----------
Total operating expenses ............................... 30,761 120,997 10,995 15,195
---------- ---------- ---------- ----------
OPERATING INCOME (LOSS) ...................................... 14,745 (65,168) 4,990 1,344
---------- ---------- ---------- ----------
OTHER INCOME AND EXPENSES
Interest and other income .................................. 169 168 20 50
Interest expense ........................................... (7,396) (24,512) (2,714) (8,548)
---------- ---------- ---------- ----------
(7,227) (24,344) (2,694) (8,498)
---------- ---------- ---------- ----------
EARNINGS (LOSS) FROM OPERATIONS BEFORE
INCOME TAXES ............................................... 7,518 (89,512) 2,296 (7,154)
INCOME TAX PROVISION (BENEFIT) ............................... 2,932 (18,432) 895 14
---------- ---------- ---------- ----------
NET EARNINGS (LOSS) .......................................... $ 4,586 $ (71,080) $ 1,401 $ (7,168)
========== ========== ========== ==========
BASIC EARNINGS (LOSS) PER COMMON SHARE
(note 3) ................................................... $ 0.22 $ (2.78) $ 0.07 $ (0.28)
========== ========== ========== ==========
DILUTED EARNINGS (LOSS) PER COMMON SHARE
(note 3) ................................................... $ 0.22 $ (2.78) $ 0.07 $ (0.28)
========== ========== ========== ==========
</TABLE>
SEE ACCOMPANYING NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
3
<PAGE> 6
COHO ENERGY, INC.
AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30
----------------------
1997 1998
-------- ---------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net earnings (loss) .......................................................... $ 4,586 $ (71,080)
Adjustments to reconcile net earnings (loss) to net cash provided by operating
activities:
Depletion and depreciation ................................................. 14,072 22,235
Writedown of crude oil and natural gas properties .......................... -- 73,000
Deferred income taxes provision (benefit) .................................. 2,857 (18,488)
Amortization of debt issue costs and other ................................. 390 633
Changes in operating assets and liabilities:
Accounts receivable and other assets ....................................... 3,294 (6,855)
Accounts payable and accrued liabilities ................................... 935 7,902
Investment in marketable securities ........................................ 1,962 --
-------- ---------
Net cash provided by operating activities ...................................... 28,096 7,347
-------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Property and equipment ....................................................... (55,302) (62,464)
Changes in accounts payable and accrued liabilities related to
exploration and development ................................................ 4,096 (1,363)
-------- ---------
Net cash used in investing activities .......................................... (51,206) (63,827)
-------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in long term debt ................................................... 33,000 54,585
Repayment of long term debt .................................................. (11,229) (33)
Proceeds from exercised stock options ........................................ 720 --
-------- ---------
Net cash provided by financing activities ...................................... 22,491 54,552
-------- ---------
NET DECREASE IN CASH AND CASH EQUIVALENTS ...................................... (619) (1,928)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ............................... 1,864 3,817
-------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD ..................................... 1.245 1,889
======== =========
CASH PAID DURING THE PERIOD FOR:
Interest ................................................................... $ 6,897 $ 16,364
Income taxes ............................................................... 639 $ --
</TABLE>
SEE ACCOMPANYING NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
4
<PAGE> 7
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NINE MONTHS ENDED SEPTEMBER 30, 1998
(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 with the exception of
the adjustment to write down the carrying value of the crude oil and natural gas
properties discussed in Note 2 below, 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 nine month period ended September
30, 1998, 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, which are included as
part of the Company's annual report on Form 10-K for the year ended December 31,
1997.
2. PROPERTY AND EQUIPMENT
<TABLE>
<CAPTION>
December 31 September 30
1997 1998
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<S> <C> <C>
Crude oil and natural gas leases and rights including exploration,
development and equipment thereon, at cost ..................... $ 669,247 $ 731,898
Accumulated depletion and depreciation ........................... (137,838) (233,072)
--------- ---------
$ 531,409 $ 498,826
========= =========
</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 $2,834,000 and
$4,227,000 for the nine months ended September 30, 1997 and 1998, respectively.
During the nine months ended September 30, 1997 and 1998, the Company did
not capitalize any interest or other financing charges on funds borrowed to
finance unproved properties or major development projects.
At December 31, 1997 and September 30, 1998, unproved crude oil and natural
gas properties totalling $82,872,000 and $86,726,000 (including $70,000,000 and
$71,600,000, respectively, for the recently acquired Oklahoma properties),
respectively, 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.
At June 30, 1998, capitalized costs of crude oil and natural gas properties
exceeded the estimated present value of future net revenues for the Company's
proved reserves, net of related income tax considerations, resulting in a
writedown in the carrying value of crude oil and natural gas properties of $73
million. The writedown resulted from the decline in crude oil prices during
1998. No additional writedown was required as of September 30, 1998.
5
<PAGE> 8
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
3. EARNINGS PER SHARE
Basic earnings per share ("EPS") have been calculated based on the weighted
average number of shares outstanding for the nine months ended September 30,
1997 and 1998 of 20,414,372 and 25,603,512, respectively, and for the three
months ended September 30, 1997 and 1998 of 20,462,340 and 25,603,512,
respectively. Diluted EPS have been calculated based on the weighted average
number of shares outstanding (including common shares plus, when their effect is
dilutive, common stock equivalents consisting of stock options and warrants) for
the nine months ended September 30, 1997 and 1998 of 21,143,059 and 25,603,512,
respectively, and for the three months ended September 30, 1997 and 1998 of
21,409,178 and 25,603,512, respectively. In 1998, conversion of stock options
and warrants would have been anti-dilutive and, therefore, was not considered in
diluted EPS.
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.
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 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; however, an unfavorable outcome
could have a material adverse effect on the current year results.
The Company has entered into certain financial arrangements which act as a
hedge against price fluctuations in future crude oil and natural gas production.
Gains and losses on these transactions are recorded in operating revenues when
the future production sale occurs. Currently, the Company has no crude oil or
natural gas production hedged.
In connection with the acquisition of oil and gas properties in Oklahoma
from Amoco Production Company ("Amoco") on December 18, 1997, the Company
assumed the responsibility for costs and expenses associated with the
assessment, remediation, removal, transportation and disposal of the asbestos or
naturally occurring radioactive materials associated with such properties.
Additionally, the Company is responsible for all other environmental claims up
to approximately $10.3 million and all environmental claims not identified and
presented to Amoco by December 18, 1998. The Company is not currently aware of
any such claims and is performing an ongoing assessment of the properties to
identify all potential environmental claims.
5. PROPOSED EQUITY CONTRIBUTION
The Company has entered into an agreement to issue shares of its common
stock at $6.00 per share, for a total purchase price of approximately $250
million, to HM4 Coho L.P., a limited partnership managed by Hicks, Muse, Tate &
Furst Incorporated. The issuance of the shares is subject to shareholder
approval at a meeting scheduled for December 4, 1998, and, if approved, will be
issued at a closing expected to be held during the fourth quarter of 1998. HM4
Coho L.P. will own approximately 62% of the outstanding shares of the Company
following the issuance of shares.
Currently, the Company intends to use the net proceeds of approximately
$234 million initially to repay a portion of its borrowings under the Company's
bank credit facility.
6
<PAGE> 9
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion should be read in conjunction with the Company's
Condensed Consolidated Financial Statements and notes thereto included elsewhere
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. During the nine months
ended September 30, 1998, 78% of production revenues were attributable to the
sale of crude oil and the remaining 22% were derived from natural gas as
compared to 68% from crude oil sales and 32% from natural gas sales during the
same period in 1997.
The Company increased its crude oil and natural gas production in the first
nine months of 1998 as a result of ongoing development activities on its
existing properties in Mississippi during the first nine months of 1998 and as a
result of the December 1997 acquisition of certain crude oil and natural gas
properties located primarily in Oklahoma ("Oklahoma Properties"). Average net
daily barrel of oil equivalent ("BOE") production was 18,495 BOE (11,612 BOE
excluding the Oklahoma Properties) for the nine months ended September 30, 1998,
as compared to 10,904 BOE for the same period in 1997. For purposes of
determining BOE herein, natural gas is converted to barrels ("Bbl") on a 6
thousand cubic feet ("Mcf") to 1 Bbl basis.
LIQUIDITY AND CAPITAL RESOURCES
Capital Sources. For the nine months ended September 30, 1998, cash flow
provided by operating activities was $7.3 million compared with $28.1 million
for the same period in 1997. Operating revenues, net of lease operating
expenses, production taxes and general and administrative expenses, increased
only $1.3 million (4%) during the first nine months of 1998 over the first nine
months of 1997, despite a 70% increase in equivalent production between periods,
primarily due to price decreases between such comparable periods of 34% and 7%
for crude oil and natural gas, respectively. Additionally, interest expense
increased $17.1 million between periods as a result of borrowings to finance the
Company's capital expenditure program and the December 1997 acquisition of the
Oklahoma Properties. Changes in operating assets and liabilities provided $1.0
million of cash for operating activities for the nine months ended September 30,
1998, primarily due to the increase in trade payables and accrued interest
payable, partially offset by the increase in trade receivables, including
approximately $3.3 million related to the final closing settlement on the
acquisition of the Oklahoma Properties. See "Results of Operations" for a
discussion of operating results.
The Company's net loss of $71.1 million for the nine months ended September
30, 1998 includes non-cash writedowns totalling $73 million on the Company's
crude oil and natural gas properties. These writedowns and the partially
offsetting related deferred tax benefit significantly increased the Company's
net loss for the nine months ended September 30, 1998. See "Results of
Operations" for a detailed discussion on the writedowns of the crude oil and
natural gas properties.
At September 30, 1998, the Company had a working capital deficit of $7.1
million compared to a working capital deficit of $2.0 million at December 31,
1997. The working capital deficits are primarily due to current payables and
accrued liabilities associated with drilling and recompletion activities and
accrued interest payable at the end of each period.
At September 30, 1998, the $1.4 million increase in current assets is
primarily due to increased receivables related to the Oklahoma Properties
acquired in December 1997, partially offset by a decrease in oil and gas
purchaser receivables, due to declining crude oil and natural gas prices, and a
reduction in the deferred tax receivable.
7
<PAGE> 10
At September 30, 1998, the $6.5 million increase in current liabilities is
primarily due to the increase in trade payables associated with the Company's
assumption of operator responsibilities relating to the acquisition of the
Oklahoma Properties and accrued interest payable, partially offset by a
reduction of accrued liabilities related to compensation, capital expenditures
and costs related to the acquisition of the Oklahoma Properties.
As of September 30, 1998, the amount available to the Company ("Borrowing
Base") under its revolving credit facility (the "Restated Credit Agreement") for
general corporate purposes was $300 million. Outstanding advances under the
Restated Credit Agreement at September 30, 1998 were $276 million, all of which
are classified as long term. The Restated Credit Agreement is scheduled to
terminate January 2, 2003. Amounts outstanding up to $270 million under the
Restated Credit Agreement accrue interest at the option of the Company at (i)
Libor plus a maximum of 1.50% or (ii) the prime rate. Amounts outstanding in
excess of $270 million accrue interest at the option of the Company at (i) Libor
plus 2.50% or (ii) the prime rate plus 1.0%. At September 30, 1998, the Restated
Credit Agreement lenders were Banque Paribas, Houston Agency; Bank One, Texas,
N.A.; MeesPierson Capital Corp.; Bank of Scotland; Den Norske Bank; Christiania
Bank; Credit Lyonnais; and Toronto Dominion Bank.
The Restated Credit Agreement contains certain financial and other
covenants including (i) the maintenance of minimum amounts of shareholders'
equity ($108 million plus 50% of the accumulated consolidated net income
beginning in 1998 for the cumulative period excluding adjustments for any
writedown of property, plant and equipment, plus 75% of the cash proceeds of any
sales of capital stock of the Company), (ii) maintenance of minimum ratios of
cash flow to interest expense (1.35 : 1) as well as current assets (including
unused Borrowing Base) to current liabilities (1 : 1), (iii) limitations on the
Company's ability to incur additional debt and (iv) restrictions on the payment
of dividends. In the third quarter, the minimum ratio of cash flow to interest
expense was amended whereby the coverage ratio on September 30, 1998 was
decreased from 1.5 to 1 to 1.35 to 1, increasing thereafter on a periodic basis
to 2.5 to 1 on June 30, 2000.
The Company's 8 7/8% Senior Subordinated Notes due 2007 ("Senior Notes")
bear interest of 8 7/8% per annum payable semi-annually on April 15 and October
15. Currently, $150 million of Senior Notes are outstanding. The indenture
issued in conjunction with the Company's Senior Notes also contains certain
covenants, including covenants that limit (i) indebtedness, (ii) restricted
payments, (iii) distributions from restricted subsidiaries, (iv) transactions
with affiliates, (v) sales of assets and subsidiary stock (including sale and
leaseback transactions), (vi) dividends and other payment restrictions affecting
restricted subsidiaries and (vii) mergers or consolidations.
The Company will be required to adopt SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" for fiscal year ended 2000. If
the Company had adopted SFAS No. 133 during 1998 there would be no effect as the
Company has no hedges outstanding at September 30, 1998. Although the future
impact of adopting SFAS No. 133 has not been determined yet, the Company
believes that the impact will not be material.
Capital Expenditures. During the first nine months of 1998, the Company
incurred capital expenditures of $62.5 million, including $5.9 million to
acquire additional working interests in the Oklahoma fields, compared with $55.3
million for the first nine months of 1997. The capital expenditures incurred
during the first nine months of 1998 were largely in connection with the
development efforts, including recompletions, workovers and waterfloods, on
existing wells in the Company's Brookhaven, Laurel, Martinville, Summerland,
Bumpass, Tatums, East Fitts, North Alma Deese and Sholem Alechem fields. In
addition, during the first nine months of 1998, the Company drilled 31 wells as
follows: seven producing oil wells in the Laurel field, four producing oil wells
in the Martinville field, two producing oil wells in the Summerland field, three
producing oil wells and one dry hole in the Brookhaven field, four producing oil
wells in the East Fitts field, three producing oil wells in the Tatums field,
one producing gas well in the Bumpass field, one producing gas well in the
Cranfield field and two producing gas wells and three dry holes in the Monroe
field. The Company also had two drilling wells at September 30, 1998, one in the
East Fitts field and one in the Cranfield field. General and administrative
costs directly associated with the Company's exploration and development
activities were $4.2 million for the first nine months of 1998, compared with
$2.8 million for the first nine months of 1997, and are included in total
capital expenditures. The increase in capitalized general and administrative
cost is primarily due to
8
<PAGE> 11
increased capitalization of the Company's exploitation department resulting from
an increased staff combined with a greater percentage of time allocation of
existing staff to meet the requirements of the Company's increased exploration
and development activities.
The Company has no material capital commitments and is consequently able to
adjust the level of its expenditures as circumstances warrant. During the latter
part of the third quarter of 1998, the Company reduced capital expenditures
pending approval of the Transaction. As a result, the Company is beginning to
experience production declines due to normal depletion. The Company's assets are
comprised of reserves which deplete with production. For the Company to
experience growth and create increasing value it must find significant new
quantities of oil and gas reserves. Therefore, for the Company to replace
production and grow reserves, it must raise additional capital for future
significant amounts of capital expenditures.
As discussed above, significant amounts of capital expenditures are
required to replace production and grow reserves. While the Company has
identified many capital expenditure opportunities that accomplish the "growth"
objective, it must balance the timing of such capital expenditures with the
availability of capital raised and cash flow generated by the Company. The
Company's short-term capital needs will be for its base capital budget for 1999
of approximately $60 million and for an acquisition or series of acquisitions
with purchase prices ranging from $10 million to $500 million. Funds for these
capital plans are expected to be derived from cash flow from operations,
especially to the extent crude oil prices begin increasing, and availability
under the Company's bank credit facilities. The longer term capital needs of the
Company will be for future development of properties currently owned by the
Company and properties that may be acquired during 1999. If the shareholders of
the Company do not approve the Transaction, the Company's ability to find an
alternative transaction to the Transaction, such as other equity issuances or
asset dispositions, will impact greatly upon the Company's ability to fulfill
its short and long-term capital spending program and there can be no assurances
that the Company will be able to find or enter into an appropriate alternative
transaction.
The Company's borrowing base is based upon the agent banks' consensus
pricing strip, which uses escalating future prices. This consensus pricing strip
is not directly related to current New York Mercantile Exchange ("NYMEX")
pricing. Each individual bank has its own internal forecast of product prices,
based upon their own beliefs. These forecasts of "price strips" are used for
determining borrowing bases for their customers' loans. The three agent banks
for the Company's credit facility meet and develop a compromise "consensus
pricing strip". Sustained periods of low product prices usually affect forward
outlooks. The lower the "pricing strip", the lower the present worth of future
production and thus a lower borrowing base for commercial bank loans. So long as
such consensus pricing strip combined with the Company's proved reserves
calculate a borrowing base in excess of the current borrowings and future
capital expenditures of the Company, then the Company would not have any
limitations to the available capital resources. However, the sustained low crude
oil price environment may have an adverse affect on the consensus pricing strip.
In such a case, the Company could face limitations on its ability to provide
debt financings adequate to fund future capital expenditures, and if adverse
enough, could cause some repayment of excess borrowings over borrowing base to
occur. As discussed more fully under "Proposed Equity Contribution", the Company
has entered into an agreement to issue $250 million of equity subject to
shareholder approval. The Company intends to use the net proceeds of
approximately $234 million initially to repay a portion of its borrowings under
the Company's bank credit facility.
Proposed Equity Contribution. The Company has entered into an agreement to
issue shares of its common stock at $6.00 per share, for a total purchase price
of approximately $250 million (the "Transaction") to HM4 Coho L.P. ("HM4"), a
limited partnership managed by Hicks, Muse, Tate & Furst Incorporated. The
issuance of the shares is subject to shareholder approval at a meeting scheduled
for December 4, 1998, and, if approved, will be issued at a closing expected to
be held during the fourth quarter of 1998. Currently, the Company intends to use
the net proceeds of approximately $234 million initially to repay a portion of
its borrowings under the Company's bank credit facility. In connection with the
Transaction, the Company has paid an affiliate of HM4 a financial advisory fee
of $1.25 million and, if the Transaction is approved before December 31, 1998,
will pay such affiliate an additional fee of $8.75 million. If the shareholders
of the Company do not approve the Transaction before December 31, 1998, the
Company will be
9
<PAGE> 12
obligated to pay to HM4 on or before December 31, 1998 a fee of $8.75 million,
$5.0 million of which may, at the Company's option and subject to certain
conditions, be paid by issuing to HM4 1,000,000 shares of Common Stock.
Hedging Activities. Crude oil and natural gas prices are subject to
significant seasonal, political and other variables which are beyond the
Company's control. In an effort to reduce the effect on the Company of the
volatility of the prices received for crude oil and natural gas, the Company has
entered, and expects to continue to enter, into crude oil and natural gas
hedging transactions. The Company's hedging program is intended to stabilize
cash flow and thus allow the Company to minimize its exposure to price
fluctuations. Because all hedging transactions are tied directly to the
Company's crude oil and natural gas production, the Company does not believe
that such transactions are of a speculative nature. Gains and losses on these
hedging transactions are reflected in crude oil and natural gas revenues at the
time of sale of the hedged production. Any gain or loss on the Company's 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. At September 30, 1998, the
Company has no natural gas or crude oil production hedged and there were no
deferred or unrealized hedging gains or losses.
Year 2000 Issue. The Company has assessed and continues to assess the
impact of the "year 2000" issue on its reporting systems and operations. The
"year 2000" issue exists because main computer systems and applications
currently use two-digit date fields to designate a year. As the century date
occurs, date sensitive systems will recognize the year 2000 as 1900 or not at
all. This inability to recognize or properly treat the year 2000 may cause
systems to process critical financial and operational information incorrectly.
The Company expects the accounting computer systems to be year 2000 compliant by
year end. Year 2000 evaluation has been completed on all systems. All network
infrastructure is year 2000 compliant with all desktop systems in the corporate
headquarters expected to be year 2000 ready by year end 1998. The Company is in
the process of reviewing field operational systems and should complete year 2000
certification by mid-year 1999 and anticipates having a contingency plan in
place no later than the third quarter of 1999. In addition, the Company is in
the process of reviewing year 2000 compliance plans and progress with major
suppliers and purchasers. Management does not estimate future expenditures
related to the year 2000 exposure to be material.
10
<PAGE> 13
RESULTS OF OPERATIONS
<TABLE>
<CAPTION>
NINE MONTHS ENDED THREE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
------------------- -------------------
1997 1998 1997 1998
------- ------- ------- -------
(IN THOUSANDS, EXCEPT PER DAY, PER BBL AND PER MCF DATA)
<S> <C> <C> <C> <C>
Selected Operating Data
Production
Crude Oil (Bbl/day) ........... 7,466 14,501 8,219 14,271
Natural Gas (Mcf/day) ......... 20,628 23,966 22,685 23,310
BOE (Bbl/day) ................. 10,904 18,495 12,000 18,156
Average Sales Prices
Crude Oil per Bbl ............. $ 16.44 $ 10.81 $ 15.45 $ 9.67
Natural Gas per Mcf ........... $ 2.13 $ 1.99 $ 2.06 $ 1.79
Other
Production costs per BOE (1)... $ 3.91 $ 4.16 $ 4.04 $ 3.92
Depletion per BOE ............. $ 4.73 $ 4.40 $ 4.63 $ 4.32
Revenues
Production revenues
Crude Oil ................. $33,504 $42,785 $11,678 $12,690
Natural Gas ............... 12,002 13,044 4,307 3,849
------- ------- ------- -------
$45,506 $55,829 $15,985 $16,539
======= ======= ======= =======
</TABLE>
- --------------------------
(1) Includes lease operating expenses and production taxes.
Operating Revenues. During the first nine months of 1998, production
revenues increased 23% to $55.8 million as compared to $45.5 million for the
same period in 1997. This increase was due to a 94% increase in crude oil
production and a 16% increase in natural gas production, substantially offset by
decreases in the prices received for crude oil and natural gas (including
hedging gains and losses discussed below) of 34% and 7%, respectively. For the
three months ended September 30, 1998, production revenue increased 3% to $16.5
million as compared to $16.0 million for the same period in 1997. This increase
was principally due to a 74% increase in crude oil production and a 3% increase
in natural gas production, substantially offset by a decrease in the prices
received for crude oil and natural gas (including hedging gains and losses
discussed below) of 37% and 13%, respectively.
The 16% increase in daily natural gas production during the first nine
months of 1998 is primarily due to a 26% increase in production as a result of
the December 1997 acquisition of the Oklahoma Properties, partially offset by
production declines on the Company's Brookhaven, Martinville, North Padre and
Monroe fields. The 94% increase in daily crude oil production during the first
nine months of 1998 is primarily due to an 80% increase in production as a
result of the acquisition of the Oklahoma Properties and a 13% increase in
production due to significant production increases made in the Martinville and
Brookhaven fields, with production from such fields increasing by 33% and 43%,
respectively.
11
<PAGE> 14
Average crude oil prices, including hedging gains and losses, decreased
during the first nine months of 1998 compared to the same period in 1997 due to
declining oil prices which can be attributed to several factors, including: lack
of cold weather, increased storage inventories and perceptions of the effects of
increased quotas or lack of adherence to quotas from the Organization of
Petroleum Exporting Countries. The posted price for the Company's crude oil
averaged $11.92 per Bbl for the nine months ended September 30, 1998, a 36%
decrease from the average posted price of $18.61 per Bbl experienced in the
first nine months of 1997. 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, decreased 7% during the first nine months of 1998 as compared to the
first nine months of 1997 from $2.13 per Mcf in the first nine months of 1997 to
$1.99 per Mcf in the first nine months of 1998, due to a lack of cold weather
and market volatility.
Production revenues for the nine months ended September 30, 1998 included
no crude oil hedging gains or losses compared to crude oil hedging losses of
$396,000 ($0.19 per Bbl) for the same period in 1997. Production revenues in
1998 included natural gas hedging gains of $488,000 ($0.07 per Mcf) compared to
natural gas hedging gains of $142,000 ($0.03 per Mcf) for the same period in
1997. 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 on the 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 for the last three days during the month in which the hedge is
in place. Consequently, hedging activities do not affect the actual sales price
received for the Company's crude oil and natural gas.
Expenses. Production expenses (including production taxes) were $21.0
million for the first nine months of 1998 compared to $11.6 million for the
first nine months of 1997 and $6.5 million for the third quarter of 1998
compared to $4.5 million for the same period in 1997. On a BOE basis, production
costs increased 6% to $4.16 per BOE in 1998 compared to $3.91 per BOE in 1997
for the nine month periods and decreased 3% to $3.92 per BOE in 1998 compared to
$4.04 per BOE in 1997 for the three month periods. The increase in expenses for
the comparable nine month periods is primarily due to increased production and
an increase of approximately $8.4 million relating to the recently acquired
Oklahoma Properties, partially offset by reduced operating costs per BOE on the
Company's Mississippi properties due to improved operating efficiencies and due
to a reduction of repairs during the third quarter of 1998. Due to the decline
in oil prices, the Company has significantly reduced both minor and major well
repairs.
General and administrative costs decreased 6% between the comparable nine
month periods and increased 1% between the comparable three month periods. The
decrease for the comparable nine month periods is primarily due to operator
overhead charges to third parties related to the Oklahoma Properties, which are
reflected as a reduction in general and administrative costs, and an increase in
capitalization of salaries and other general and administrative costs directly
associated with the Company's increased exploration and development activities,
partially offset by increased personnel costs due to staff additions to handle
the increased capital activities in Mississippi and increased costs associated
with the acquisition of the Oklahoma Properties.
Interest expense increased 231% for the nine month period ended September
30, 1998 compared to the same period in 1997, due to higher borrowing levels
during 1998 as compared to 1997 and due to the sale of $150 million of the
Company's 8f% Senior Subordinated Notes due 2007 on October 3, 1997, which bear
a higher interest rate than borrowings under the Restated Credit Agreement. The
borrowing levels increased throughout 1997 and 1998 due to additional borrowings
to fund the Company's capital expenditure program and the December 1997
acquisition of the Oklahoma Properties.
Depletion and depreciation expense increased 58% to $22.2 million for the
nine months ended September 30, 1998 from $14.1 million for the comparable
period in 1997, due to increased production, partially offset by a lower rate
per BOE which decreased to $4.40 in 1998 from $4.73 in 1997. Depletion and
depreciation expense increased 41% to $7.2 million for the three months ended
September 30, 1998, as compared to $5.1 million for the comparable period in
1997,
12
<PAGE> 15
due to increased production volumes, partially offset by a lower rate per BOE
which decreased to $4.32 in 1998 from $4.63 in 1997.
In accordance with generally accepted accounting principles, at a point in
time coinciding with the quarterly and annual reporting periods, the Company
must test the carrying value of its crude oil and natural gas properties, net of
related deferred taxes, against a calculated amount based on estimated reserve
volumes valued at then current realized prices held flat for the life of the
properties discounted at 10% per annum plus the lower of cost or estimated fair
value of unproved properties (the "cost center ceiling"). At March 31, 1998 and
June 30, 1998, the carrying values exceeded the cost center ceilings, resulting
in non-cash writedowns of the crude oil and natural gas properties of $32
million and $41 million, respectively. These writedowns resulted from the
declines in crude oil prices in the first and second quarters of 1998. No
additional writedown was required as of September 30, 1998.
Due to the factors discussed above, the Company's net losses for the three
and nine months ended September 30, 1998 were $7.2 million and $71.1 million,
respectively, as compared to net incomes of $1.4 million and $4.6 million,
respectively, for the same periods in 1997. The 1998 losses include first and
second quarter writedowns of the crude oil and natural gas properties of $32
million and $41 million, respectively.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
None
13
<PAGE> 16
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
None
ITEM 2. CHANGES IN SECURITIES
None
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) EXHIBITS
27 Financial Data Schedule
(b) REPORTS ON FORM 8-K
The Company has filed with the Securities and Exchange Commission a
Current Report on Form 8-K dated September 4, 1998, related to an agreement to
issue approximately $250 of common equity at $6.00 per share to HM4 Coho L.P., a
limited partnership managed by Hicks, Muse, Tate & Furst Incorporated.
14
<PAGE> 17
COHO ENERGY, INC.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
COHO ENERGY, INC.
(Registrant)
Date: November 13, 1998
By: /s/ Jeffrey Clarke
------------------------------------------
Jeffrey Clarke
(Chairman, President, and Chief Executive
Officer)
By: /s/ Eddie M. LeBlanc,III
------------------------------------------
Eddie M. LeBlanc, III
(Sr. Vice President and Chief Financial
Officer)
15
<PAGE> 18
INDEX TO EXHIBITS
Exhibit
Number Description
- ------ -----------
27 Financial Data Schedule
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1998
<PERIOD-END> SEP-30-1998
<CASH> 1,889
<SECURITIES> 0
<RECEIVABLES> 15,830
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 18,484
<PP&E> 731,898
<DEPRECIATION> 233,072
<TOTAL-ASSETS> 524,833
<CURRENT-LIABILITIES> 25,622
<BONDS> 424,488
0
0
<COMMON> 256
<OTHER-SE> 70,767
<TOTAL-LIABILITY-AND-EQUITY> 524,833
<SALES> 55,829
<TOTAL-REVENUES> 55,829
<CGS> 21,010
<TOTAL-COSTS> 47,997
<OTHER-EXPENSES> 73,000
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 24,512
<INCOME-PRETAX> (89,512)
<INCOME-TAX> (18,432)
<INCOME-CONTINUING> (71,080)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (71,080)
<EPS-PRIMARY> (2.78)
<EPS-DILUTED> (2.78)
</TABLE>
