<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, 2000
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 by check mark whether the registrant has filed all documents and
reports required to be filed by Sections 12, 13 or 15(d) of the Securities
Exchange Act of 1934 subsequent to the distribution of securities under a plan
confirmed by a court.
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.
<TABLE>
<CAPTION>
Class Outstanding at November 10, 2000
---------------------------- --------------------------------
<S> <C>
Common Stock, $.01 par value 18,714,175
</TABLE>
<PAGE> 2
INDEX
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Report of Independent Public Accountants 3
Condensed Consolidated Balance Sheets -
December 31, 1999 and September 30, 2000 4
Condensed Consolidated Statements of Operations -
three and nine months ended September 30, 1999 and 2000 5
Condensed Consolidated Statement of Shareholders' Equity -
nine months ended September 30, 2000 6
Condensed Consolidated Statements of Cash Flows -
nine months ended September 30, 1999 and 2000 7
Notes to Condensed Consolidated Financial Statements 8
Item 2. Management's Discussion and Analysis of Financial
Financial Condition and Results of Operations 17
Item 3. Quantitative and Qualitative Disclosures About Market Risk 28
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 30
Item 2. Changes in Securities 30
Item 3. Defaults Upon Senior Securities 30
Item 4. Submission of Matters to a Vote of Security Holders 30
Item 5. Other Information 30
Item 6. Exhibits and Reports on Form 8-K 30
Signatures 31
</TABLE>
<PAGE> 3
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
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) and subsidiaries as of September 30,
2000, and the related condensed consolidated statements of operations for the
three-month and nine-month periods ended September 30, 2000 and 1999, and the
condensed consolidated statements of cash flows for the nine-month periods ended
September 30, 2000 and 1999. 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 financial statements referred to above for them to be in
conformity with accounting principles generally accepted in the United States.
We have previously audited, in accordance with auditing standards
generally accepted in the United States, the consolidated balance sheet of Coho
Energy, Inc. and subsidiaries as of December 31, 1999 (not presented herein)
and, in our report dated March 3, 2000, dual dated March 20, 2000 for a
subsequent event, we expressed an unqualified opinion with a going concern
modification on that statement. In our opinion, the information set forth in the
accompanying condensed consolidated balance sheet as of December 31, 1999, is
fairly stated, in all material respects, in relation to the balance sheet from
which it has been derived.
ARTHUR ANDERSEN LLP
Dallas, Texas
November 8, 2000
3
<PAGE> 4
COHO ENERGY, INC.
AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
DECEMBER 31 SEPTEMBER 30
1999 2000
----------- ------------
(UNAUDITED)
<S> <C> <C>
ASSETS
Current assets
Cash and cash equivalents $ 18,805 $ 13,537
Cash in escrow 78 27
Accounts receivable 11,158 12,208
Other current assets 1,428 1,076
--------- ---------
31,469 26,848
Property and equipment, at cost net of accumulated depletion and
depreciation, based on full cost accounting method (note 3) 311,788 315,109
Other assets 5,544 30,623
--------- ---------
$ 348,801 $ 372,580
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities not subject to compromise:
Current liabilities
Accounts payable, principally trade $ 1,294 $ 6,865
Accrued liabilities and other payables 3,751 12,787
Accrued interest 10,175 4,085
Current portion of long term debt (note 4) -- 1,036
--------- ---------
Total current liabilities 15,220 24,773
Liabilities subject to compromise:
Accounts payable, principally trade 4,166 --
Accrued liabilities and other payables 5,373 --
Accrued interest 21,379 --
Accrued state income taxes payable 4,136 --
Current portion of long term debt (note 4) 388,685 --
--------- ---------
Total liabilities subject to compromise 423,739 --
--------- ---------
438,959 24,773
--------- ---------
Long term debt, excluding current portion (note 4) -- 293,142
--------- ---------
Commitments and contingencies (note 8) 1,800 520
--------- ---------
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 640,088 (restated) and 18,714,175 shares,
respectively 256 187
Additional paid-in capital 137,812 323,967
Retained deficit (230,026) (270,009)
--------- ---------
Total shareholders' equity (91,958) 54,145
--------- ---------
$ 348,801 $ 372,580
========= =========
</TABLE>
SEE ACCOMPANYING NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
4
<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
--------------------------- --------------------------
1999 2000 1999 2000
---------- ----------- --------- --------
<S> <C> <C> <C> <C>
Operating revenues
Net crude oil and natural gas production $ 37,957 $ 68,451 $ 16,829 $ 21,947
Operating expenses
Crude oil and natural gas production 13,200 17,330 5,456 6,087
Taxes on oil and gas production 1,863 4,122 940 1,516
General and administrative (note 3) 7,574 5,408 2,188 1,703
State income tax penalties 1,048 -- 46 --
Allowance for bad debt -- 765 -- --
Depletion and depreciation 10,213 11,173 3,441 3,777
Writedown of crude oil and natural gas properties 5,433 -- 5,433 --
-------- -------- -------- --------
Total operating expenses 39,331 38,798 17,504 13,083
-------- -------- -------- --------
Operating income (loss) (1,374) 29,653 (675) 8,864
-------- -------- -------- --------
Other income and expenses
Interest and other income 241 322 55 181
Interest expense (note 4) (26,030) (26,611) (9,229) (9,307)
Interest expense related to embedded derivative
(note 4) -- (26,460) -- (22,500)
-------- -------- -------- --------
(25,789) (52,749) (9,174) (31,626)
-------- -------- -------- --------
Loss from operations before reorganization costs,
income taxes and extraordinary item (27,163) (23,096) (9,849) (22,762)
Reorganization costs (note 2) (2,685) (12,459) (910) (277)
-------- -------- -------- --------
Loss before income taxes and extraordinary item (29,848) (35,555) (10,759) (23,039)
Income tax expense (benefit) (26) -- (26) --
-------- -------- -------- --------
Loss before extraordinary item (29,822) (35,555) (10,733) (23,039)
-------- -------- -------- --------
Extraordinary item - loss on extinguishment of
indebtedness (note 2) -- (4,428) -- --
-------- -------- -------- --------
Net loss $(29,822) $(39,983) $(10,733) $(23,039)
======== ======== ======== ========
Basic and diluted loss per common share
Loss before extraordinary item $ (46.59) $ (2.78) $ (16.77) $ (1.23)
Extraordinary item $ -- $ (.35) $ -- $ --
Net loss $ (46.59) $ (3.13) $ (16.77) $ (1.23)
</TABLE>
SEE ACCOMPANYING NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
5
<PAGE> 6
COHO ENERGY, INC.
AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
NUMBER OF
COMMON ADDITIONAL RETAINED
SHARES COMMON PAID-IN EARNINGS
OUTSTANDING STOCK CAPITAL (DEFICIT) TOTAL
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Balance at December 31, 1999 25,603,512 $ 256 $ 137,812 $ (230,026) $ (91,958)
Issued on
(i) Retirement of old common
shares (25,603,512) (256) 256 -- --
(ii) Issuance of new common
shares to old common
shareholders 640,088 6 (6) -- --
(iii) Issuance of new common
shares to extinguish old bond
debt 15,362,107 154 161,481 -- 161,635
(iv) Issuance of new common
shares to standby lenders 2,694,841 27 24,219 -- 24,246
(v) Issuance of new common
shares for rights offering 17,139 -- -- -- --
(vi) Stock option compensation -- -- 205 -- 205
Net loss -- -- -- (39,983) (39,983)
----------- ----------- ----------- ----------- -----------
Balance at September 30, 2000 18,714,175 $ 187 $ 323,967 $ (270,009) $ 54,145
----------- ----------- ----------- ----------- -----------
</TABLE>
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6
<PAGE> 7
COHO ENERGY, INC.
AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30
---------------------------
1999 2000
--------- ---------
<S> <C> <C>
Cash flows from operating activities
Net loss $ (29,822) $ (39,983)
Adjustments to reconcile net loss to net cash provided by operating
activities:
Depletion and depreciation 10,213 11,173
Writedown of crude oil and natural gas properties 5,433 --
Extraordinary item - loss on extinguishment of debt -- 4,428
Standby loan interest -- 6,523
Standby loan related to embedded derivative -- 26,460
Amortization of debt issuance costs and other 679 5,240
Changes in operating assets and liabilities:
Accounts receivable and other assets 483 (1,870)
Accounts payable and accrued liabilities 17,697 (7,331)
--------- ---------
Net cash provided by operating activities 4,683 4,640
--------- ---------
Cash flows from investing activities
Property and equipment (4,995) (15,545)
Changes in accounts payable and accrued liabilities related to
exploration and development (1,031) 1,790
--------- ---------
Net cash used in investing activities (6,026) (13,755)
--------- ---------
Cash flows from financing activities
Increase in long term debt 4,600 255,000
Repayment of long term debt (20) (239,600)
Debt issuance costs -- (9,427)
Debt extinguishment costs -- (2,126)
--------- ---------
Net cash provided by financing activities 4,580 3,847
--------- ---------
Net increase (decrease) in cash and cash equivalents 3,237 (5,268)
Cash and cash equivalents at beginning of period 6,901 18,805
--------- ---------
Cash and cash equivalents at end of period $ 10,138 $ 13,537
========= =========
Cash paid (received) during the period for:
Interest $ 8,058 $ 28,721
Income taxes $ 33 $ --
Reorganization costs (includes prepayments) $ 3,320 $ 6,730
Reorganization receipts (interest income) $ (30) $ (260)
</TABLE>
SEE ACCOMPANYING NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
7
<PAGE> 8
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NINE MONTHS ENDED SEPTEMBER 30, 2000
(TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED)
(UNAUDITED)
1. BASIS OF PRESENTATION
The accompanying condensed consolidated financial statements of Coho
Energy, Inc. (the "Company") and subsidiaries 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
other than reorganization accruals, adjustments to effect the Company's plan of
reorganization and contingent interest expense associated with the standby loan
related to the embedded derivative, 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, 2000, 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,
1999.
The Company performs ongoing reviews with respect to accounts receivable
and maintains an allowance for doubtful accounts receivable ($885,000 and
$684,000 at December 31, 1999 and September 30, 2000, respectively) based on
expected collectibility.
Other assets at September 30, 2000 include debt issuance costs related to
the Company's standby loan and new credit facility of $25.0 million and $5.5
million, respectively. These costs are amortized using the straight line method
over the terms of the related financing.
Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"),
"Accounting for Derivative Instruments and Hedging Activities", as amended, is
effective for fiscal years beginning after June 15, 2000. The Company has not
yet completed its evaluation of the impact of this statement; however, it will
impact the Company's accounting treatment of the embedded derivative instrument
contained in the standby loan agreement as discussed in Note 4 and the financial
arrangements which act as a hedge against price fluctuations in future crude oil
and natural gas production as discussed in Note 8. The Company will adopt SFAS
No. 133 on January 1, 2001. As discussed in Note 4, the Company currently
records the contingent interest on the standby loan based on estimated
undiscounted future contingent interest using the forward price curves for crude
oil and natural gas. Under SFAS No. 133, this contingent interest is considered
an embedded derivative and it will be recorded based on estimated fair value.
Changes in fair value will be recorded through earnings. In addition, under SFAS
No. 133 changes in the ineffective portion of cash flow hedges will be recorded
in earnings. Accordingly, the results of adopting and applying SFAS No. 133 may
have a significant impact on the Company's results of operations and
comprehensive income, although the Company is unable to quantify the impact at
this time.
The Company has elected to follow Accounting Principles Board Opinion
("APB") No. 25, "Accounting for Stock Issued to Employees" and related
interpretations in accounting for its stock option plans. Pursuant to APB25, no
compensation expense is recognized for stock option awards when the exercise
price of the Company's stock options equals the market price of the underlying
stock on the measurement date. On April 1, 2000, the Company awarded
approximately 491,000 stock options with an exercise price less than the market
price on the measurement date by $1.68 per share. Compensation costs are being
amortized using the straight line method over the two-year vesting period of the
stock options. The Company has recognized $205,000 of compensation expense
related to such stock options at September 30, 2000. Pursuant to the Company's
plan of reorganization, discussed below, on March 31, 2000, all previously
issued stock options and warrants were extinguished.
2. BANKRUPTCY PROCEEDINGS
On August 23, 1999 (the "Petition Date"), the Company and its wholly-owned
subsidiaries, Coho Resources, Inc., Coho Oil & Gas, Inc., Coho Exploration,
Inc., Coho Louisiana Production Company and Interstate Natural Gas
8
<PAGE> 9
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NINE MONTHS ENDED SEPTEMBER 30, 2000
(TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED)
(UNAUDITED)
Company, filed a voluntary petition for relief under Chapter 11 of the U.S.
Bankruptcy Code (the "Chapter 11 filing") in the U.S. District Court for the
Northern District of Texas (the "Bankruptcy Court"). On November 30, 1999, the
Company filed a plan of reorganization and subsequently filed an amended plan of
reorganization on February 14, 2000 (the "Plan of Reorganization"). On March 20,
2000, the Bankruptcy Court entered an order confirming the Plan of
Reorganization and on March 31, 2000, the Plan of Reorganization was consummated
and the Company emerged from bankruptcy.
Prior to March 31, 2000, the effective date of the Plan of Reorganization,
the Company had 25,603,512 shares of old common stock issued and outstanding.
Old shareholders received shares representing 4% of new common stock on a basis
of one share of new common stock for 40 shares of old common stock as of the
effective date without giving effect to dilution from shares issued in
connection with the standby loan or shares issued under the rights offering
discussed below. Additionally, shareholders as of February 7, 2000, are eligible
to receive their pro rata share of 20% of any proceeds available from the
lawsuit filed against five affiliates of Hicks, Muse, Tate & Furst (the "Hicks
Muse Lawsuit") after fees and expenses and 40% of any proceeds of the
disposition of the Company's interest in, or the assets of, Coho Anaguid, Inc.
Coho Anaguid owns a 45.83% interest in a permit in Tunisia, North Africa. At
March 31, 2000, the Company charged 40% of the carrying value of Coho Anaguid,
Inc., approximately $1.1 million, to reorganization expense. The Company's
remaining carrying value of Coho Anaguid, Inc. is $1.9 million.
On May 2, 2000, the Company distributed stock rights to the holders of its
old common stock as of the record date of March 6, 2000, to purchase up to an
aggregate of 8,663,846 shares of its new common stock. Each holder of old common
stock received 0.338 rights for every share of old common stock held by such
holder. Each right allowed a holder to buy one share of new common stock at a
price of $10.40 per share. There were 14,669 rights exercised under the
offering; however, pursuant to an antidilution feature which applied to shares
issued in the rights offering, 1.17 shares were issued for each right exercised.
Unexercised rights expired May 31, 2000. The Company received $153,000 upon
completion of the offering on May 31, 2000. Proceeds from the rights offering
were used to pay offering costs; however, offering costs exceeded the proceeds
from the rights offering and the excess costs were charged to accrued
reorganization costs.
The reorganized value of the Company's assets exceeded the total of all
postpetition liabilities and allowed claims; therefore, the Company did not
qualify for fresh-start accounting. The Company has recorded the following
transactions to effect the Company's Plan of Reorganization consummated on March
31, 2000:
o The borrowing of $183.0 million under the Company's new credit
facility.
o The borrowing of $72.0 million under the standby loan and the issuance
of 2,694,841 shares of new common stock as debt issuance costs at a
diluted reorganization value of approximately $9.00 per share for a
total of $24.2 million. The diluted reorganization value of $9.00 per
share was caused by the old bondholders accepting a dilution in the
value of their new common stock to obtain the standby loan financing
for the reorganized company. The dilution is a result of the issuances
of additional shares to the standby lenders.
o Repayment of borrowings outstanding under the old bank credit facility
together with accrued interest and reasonable fees totaling $260.2
million, resulting in a $303,000 loss on extinguishment of debt.
o Conversion of the old bonds into 15,362,107 shares of new common
stock, representing 96% of the new common stock without giving effect
to dilution from shares issued in connection with the standby loan or
shares issued under the rights offering, at a reorganization value of
approximately $10.52 per share resulting in a $4.1 million loss on
extinguishment of debt. Although the old bonds were paid no more than
in full, the Company did realize a loss on extinguishment of debt
because the Company's carrying value of the old bonds was less than
the allowed claim, primarily due to unamortized debt issuance costs.
9
<PAGE> 10
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NINE MONTHS ENDED SEPTEMBER 30, 2000
(TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED)
(UNAUDITED)
o Provision of $1.6 million to allow for settlement of disputed claims.
o Payment of all allowed senior secured claims and all other allowed
claims less than $1,000, aggregating approximately $500,000.
All other allowed claims will be or have been paid in full as follows:
o General unsecured claims are being paid in full in four quarterly
installments, the first and second installments were paid on May 1,
2000 and July 3, 2000, respectively, and subsequent installments are
due the first business day of each subsequent calendar quarter.
o Priority tax claims will receive five-year, interest-bearing
promissory notes.
o Payment of costs associated with the bankruptcy were paid upon court
approval during the six months following the consummation of the Plan
of Reorganization.
In conjunction with its Plan of Reorganization, the Company terminated 19
corporate office employees and seven officers in April 2000. Costs of $438,000
associated with termination benefits for the 19 corporate office employees were
accrued as of March 31, 2000 and charged to reorganization expense and
subsequently paid in the quarter ended June 30, 2000. Additionally, the Company
rejected all of its officer employment agreements and officer severance
agreements in connection with the Plan of Reorganization, including the seven
terminated officers. The Company has negotiated settlement agreements related to
the claims for these rejected contracts. Approximately $3.0 million was accrued
and charged to reorganization expense for these claims settlements which are
being paid during the nine months following the consummation of the Plan of
Reorganization.
The Company's Plan of Reorganization provided for a retention plan under
which employees are provided with additional incentives to continue their
employment with the Company throughout 2000. The amount of cash awards to be
paid under the retention plan, based on the current number of continuing
employees, is $1.2 million, of which 33% was payable upon the effective date of
the Plan of Reorganization and 67% is to be paid January 1, 2001. Costs of
$419,000 payable upon the effective date of the Plan of Reorganization were
accrued and charged to reorganization expense at March 31, 2000 and subsequently
paid on April 14, 2000. Payments of approximately $805,000 to be paid January 1,
2001, are being amortized monthly over the subsequent nine-month period and
charged to reorganization expense.
3. PROPERTY AND EQUIPMENT
<TABLE>
<CAPTION>
December 31 September 30
1999 2000
----------- ------------
<S> <C> <C>
Crude oil and natural gas leases and rights including exploration,
development and equipment thereon, at cost ................................... $ 684,896 $ 699,389
Accumulated depletion and depreciation ......................................... (373,108) (384,280)
--------- ---------
$ 311,788 $ 315,109
========= =========
</TABLE>
Due to the cessation of exploration and development of crude oil and
natural gas reserves in 1998, all overhead expenditures incurred during 1999 and
the first quarter of 2000 were charged to general and administrative expense.
Subsequent to the first quarter of 2000, the Company has increased development
work, therefore related overhead and expenditures of $510,000 have been
capitalized.
10
<PAGE> 11
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NINE MONTHS ENDED SEPTEMBER 30, 2000
(TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED)
(UNAUDITED)
During the nine months ended September 30, 1999 and 2000, the Company did
not capitalize any interest or other financing charges on funds borrowed to
finance unproved properties or major development projects.
Unproved crude oil and natural gas properties totaling $56,296,000 and
$39,900,000 at December 31, 1999 and September 30, 2000, respectively, were
excluded from costs subject to depletion. These costs are anticipated to be
included in costs subject to depletion within the next five years.
4. LONG-TERM DEBT
<TABLE>
<CAPTION>
December 31 September 30
1999 2000
----------- ------------
<S> <C> <C>
Old bank group loan ............................... $ 239,600 $ --
Old bonds ......................................... 150,000 --
New credit facility ............................... -- 183,000
Standby loan ...................................... -- 77,358
Standby loan interest to be paid-in-kind .......... -- 1,165
Standby loan related to embedded derivative ....... -- 26,460
Promissory notes .................................. -- 5,195
Other ............................................. 3 1,000
--------- ---------
389,603 294,178
Unamortized original issue discount on old bonds .. (918) --
Current maturities of long-term debt .............. (388,685) (1,036)
--------- ---------
$ -- $ 293,142
========= =========
</TABLE>
The Company and some of its subsidiaries were parties to an old bank group
loan agreement. Borrowings outstanding under the old bank group loan together
with accrued interest and reasonable fees totaling $260.2 million were paid on
March 31, 2000. The Company obtained the funds necessary for the payment of the
old bank group loan through the combination of borrowings under its new senior
revolving credit facility, borrowings under the standby loan and from cash on
hand.
Additionally, the Company owed approximately $162 million of principal and
accrued interest under its old bonds. Under the Plan of Reorganization, these
old bonds and accrued interest were converted into 15,362,107 shares of new
common stock.
The new senior revolving credit facility was obtained from a syndicate of
lenders led by The Chase Manhattan Bank, as agent for the new lenders, and has a
principal amount of up to $250 million. The new credit facility limits advances
to the amount of the borrowing base, which has been set initially at $205
million. The borrowing base is the loan value assigned to the proved reserves
attributable to the Company's oil and gas properties. The new credit facility is
subject to semiannual borrowing base redeterminations each April 1 and October
1, based on the Company's reserve reports, and will be made at the sole
discretion of the lenders. The lenders' October 1 analysis of the current
borrowing base is still pending. The Company or Chase may each request one
additional borrowing base redetermination during any calendar year.
Interest on advances under the new credit facility will be payable on the
earlier of the expiration of any interest period under the new credit facility
or quarterly, beginning the first quarter after the effective date. Amounts
outstanding under the new credit facility will accrue interest at the Company's
option at either the Eurodollar rate, which is the annual interest rate equal to
the London interbank offered rate for deposits in United States dollars that is
determined by reference to the Telerate Service or offered to Chase plus an
applicable margin (currently 3%), or the prime rate, which is the floating
annual interest rate established by Chase from time to time as its prime rate of
11
<PAGE> 12
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NINE MONTHS ENDED SEPTEMBER 30, 2000
(TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED)
(UNAUDITED)
interest plus an applicable margin (currently 2%). All outstanding advances
under the new credit facility are due and payable in full three years from the
effective date. The new credit facility has been secured by substantially all of
the Company's assets.
The new credit agreement contains financial and other covenants including:
o maintenance of required ratios of cash flow to interest expense paid
or payable in cash (initially 2 to 1), senior debt to cash flow
required (initially not to exceed 5 to 1), and current assets to
current liabilities required (throughout the term of the credit
agreement, to be 1 to 1 as of the end of each quarter),
o restrictions on the payment of dividends and
o limitations on the incurrence of additional indebtedness, the creation
of liens and the incurrence of capital expenditures.
The lenders received $5.8 million of closing fees in addition to expense
reimbursements.
The standby loan was made under a senior subordinated note facility under
which the Company issued $72 million of senior subordinated notes to PPM
America, Inc., Appaloosa Management, L.P., Oaktree Capital Management, L.L.C.,
Pacholder Associates, Inc. and their respective assignees. The Company's rights
and responsibilities and those of the standby lenders are governed by a standby
loan agreement which was executed and delivered on March 31, 2000.
Debt under the standby loan agreement is evidenced by notes maturing March
31, 2007 and bearing interest at a minimum annual rate of 15% and payable in
cash semiannually. After March 31, 2001, additional semiannual interest payments
will be payable in an amount equal to 1/2% for every $0.25 that the "actual
price" for the Company's oil and gas production exceeds $15 per barrel of oil
equivalent during the applicable semiannual interest period, up to a maximum of
10% additional interest per year. The "actual price" for the Company's oil and
gas production is the weighted average price received by the Company for all its
oil and gas production, including hedged and unhedged production, net of hedging
costs, in dollars per barrel of oil equivalent using a 6:1 conversion ratio for
natural gas. The actual price will be calculated over a six-month measurement
period ending on the date two months before the applicable interest payment
date. Additionally, upon an event of default occurring under the standby loan,
interest will be payable in cash, unless otherwise required to be paid-in-kind,
at a rate equal to 2% per year over the applicable interest rate. Interest
payments under the standby loan may be paid-in-kind subject to the requirements
of the intercreditor arrangement between the standby lenders and the lenders
under the new credit agreement. "Paid-in-kind" refers to the payment of interest
owed under the standby loan by increasing the amount of principal outstanding
through the issuance of additional standby loan notes, rather than paying the
interest in cash. The standby loan semi-annual interest payment was paid-in-kind
when due on September 29, 2000 and has been reflected as an increase in
long-term debt in an adjustment to reconcile net loss to cash provided by
operating activities in these financial statements.
The additional semiannual interest payment feature of the standby loan
agreement based on the actual price received for the Company's oil and gas
production, as discussed above, is considered an embedded derivative instrument.
The additional interest cost associated with this embedded derivative instrument
is calculated at the origination of the loan and at each future balance sheet
date. The aggregate amount of the additional interest payments were estimated at
March 31, 2000, the inception date of the standby loan, using the future crude
oil and natural gas price curves as of such date. These estimated additional
interest payments were added to interest payments due based on the minimum
annual rate at 15% to determine the effective interest rate of 18.04% for the
term of the standby loan. The aggregate amount of the additional interest
payments was redetermined at June 30, 2000 and September 30, 2000 using the then
current future crude oil and natural gas price curves. The difference of $4
million in the aggregate amount of additional interest payments based on the
June 30, 2000 price curves as
12
<PAGE> 13
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NINE MONTHS ENDED SEPTEMBER 30, 2000
(TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED)
(UNAUDITED)
compared to the aggregate amount of additional interest payments based on the
March 31, 2000 price curves was reflected as an increase in the standby loan
debt and a charge to interest expense during the three months ended June 30,
2000. The aggregate amount of additional interest payments based on the
September 30, 2000 price curves increased $22.5 million over the amount using
the June 30, 2000 price curves, which is reflected as an increase in the standby
loan debt and a charge to interest expense during the three months ended
September 30, 2000. The interest expense may continue to have significant
volatility from period to period based on changes in future price curves from
period to period.
Payment of the standby loan notes will be expressly subordinate to payments
in full in cash of all obligations arising in connection with the new credit
facility. After the initial 12-month period, cash interest payments may be made
only to the extent by which EBITDA, or earnings before interest, tax,
depreciation and amortization expense, on a trailing four-quarter basis exceeds
$65 million. The new credit agreement also prohibits the Company from making any
cash interest payments on the standby loan indebtedness if the outstanding
indebtedness under both the new credit facility and the standby loan exceeds
3.75 times the EBITDA for the trailing four quarters. The Company may prepay the
standby loan notes at the face amount, in whole or in part, in minimum
denominations of $1,000,000, plus either a standard make-whole payment at 300
basis points over the "treasury rate" for the first four years, or beginning in
the fifth year, a prepayment fee of 7.5% of the principal amount being prepaid;
in the sixth year, a prepayment fee of 3.75% of the principal amount being
prepaid; and after the sixth year there is no prepayment fee. The "treasury
rate" is the yield of U.S. Treasury securities with a term equal to the
then-remaining term of the standby loan notes that has become publicly available
on the third business day before the date fixed for repayment.
When the standby loan notes were issued on March 31, 2000, the standby
lenders became entitled to 14.4% of the Company's fully diluted new common
stock. The shares were registered with the Securities and Exchange Commission in
connection with the rights offering and were issued on June 1, 2000. The shares
of new common stock issued to the standby lenders were in addition to the shares
of new common stock issued to holders of the old bonds, to the Company's
shareholders prior to reorganization and to persons participating in the rights
offering. Additionally, the standby lenders received closing fees of
approximately $2.5 million as well as expense reimbursements.
Claims for tax, penalty and interest were filed against the Company by the
State of Louisiana and the State of Mississippi. The Company currently has
appeals pending with both taxing authorities for portions of the filed claims.
The Company has accrued an estimated $5.2 million for settlement of these
priority tax claims, of which $4.2 million is included in long term debt and
approximately $1 million is included in current portion of long-term debt.
Five-year, interest-bearing promissory notes will be issued to satisfy these
claims; however, all terms have not yet been agreed upon by the taxing
authorities.
The Company has settled the claims of Chevron Corp. and Chevron USA for
indemnification of any environmental liabilities in the Brookhaven field. The
terms of this settlement require the Company to fund $2.5 million over the next
two years to partially finance the implementation of a remediation plan. The
Company paid $1.0 million in June 2000, $500,000 is due on January 1, 2001 and
is included in current liabilities and the remaining $1.0 million, due on
January 1, 2002, is included in long-term debt.
5. EARNINGS PER SHARE
On March 31, 2000, pursuant to the Plan of Reorganization, old shareholders
of the Company's common stock received one share of the Company's new common
stock for each forty shares of the Company's old common stock. All per-share
amounts have been restated based on the new number of shares outstanding
subsequent to the issuance of the new shares. See Note 2 for further discussion
on the dilution of current equity interests.
Earnings per share ("EPS") have been calculated based on the weighted
average number of shares outstanding for the nine months ended September 30,
1999 and 2000 of 640,088 and 12,772,900, respectively, and for the three
13
<PAGE> 14
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NINE MONTHS ENDED SEPTEMBER 30, 2000
(TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED)
(UNAUDITED)
months ended September 30, 1999 and 2000 of 640,088 and 18,714,175,
respectively. The weighted average number of shares outstanding of 640,088 for
the three and nine months ended September 30, 1999, represents the old common
shares of 25,603,512 restated for the 40 for 1 conversion of old common stock
for new common stock. 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, 1999 and 2000 of 640,088 and
12,772,900, respectively, and for the three months ended September 30, 1999 and
2000 of 640,088 and 18,714,175, respectively. In 1999 and 2000, conversion of
stock options and warrants would have been antidilutive and, therefore, was not
considered in diluted EPS.
6. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental noncash financing activities for the nine months ended
September 30, 2000 are as follows:
<TABLE>
<S> <C>
New borrowing:
Accounts receivable ........................................... $ (499)
Debt issuance costs ........................................... 24,245
Changes in accounts payable and accrued liabilities ........... 5,847
Long-term debt ................................................ (5,245)
Additional paid-in capital .................................... (24,245)
Reorganization expense ........................................ (103)
---------
$ 0
---------
Extinguishment of debt:
Debt issuance costs ........................................... $ (5,231)
Accrued interest .............................................. 15,484
Current long-term debt ........................................ 149,081
Issuance of common stock ...................................... (161,636)
Loss on extinguishment of debt ................................ 4,428
---------
Total cash paid ................................................... $ 2,126
---------
Embedded derivative and standby loan interest:
Long-term debt ................................................ (32,983)
Interest expense .............................................. 6,523
Interest expense related to embedded derivative ............... 26,460
---------
$ 0
=========
</TABLE>
7. RELATED PARTY TRANSACTIONS
(a) On March 31, 2000, the Company issued $72 million of senior
subordinated notes (see Note 4), of which $65.5 million were issued to the
Company's major shareholders and their affiliates. In addition, participants
purchasing the notes were entitled to a cash origination fee equal to 3 1/2% of
the face amount of the notes purchased plus 2,694,841 shares of the Company's
common stock. Share information, loan origination fees and notes purchased by
the Company's major shareholders are as follows:
<TABLE>
<CAPTION>
Loan Origination Senior Notes
Common Shares Fee (in 000's) Purchased (in 000's)
------------- ------------------ --------------------
<S> <C> <C> <C>
PPM America, Inc. and affiliates ............... 1,466,723 $ 1,382 $ 39,500
Appaloosa Management, L.P. and affiliates ...... 587,157 $ 560 $ 16,000
Oaktree Capital Management, LLC and
affiliates ................................... 374,283 $ 350 $ 10,000
</TABLE>
14
<PAGE> 15
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NINE MONTHS ENDED SEPTEMBER 30, 2000
(TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED)
(UNAUDITED)
In addition, during April 2000, certain officers of the Company were entitled,
pursuant to their employment contracts to participate in the senior note loans
and receive the benefit of the loan origination fee and additional shares of
common stock issued by purchasing senior notes at face value from Appaloosa
Management, L.P. and PPM America, Inc. and affiliates. Share information, loan
origination fees and senior notes purchased from the major shareholders by
officers of the Company are as follows:
<TABLE>
<CAPTION>
Loan Origination Senior Notes
Common Shares Fee (in 000's) Purchased (in 000's)
------------- --------------- --------------------
<S> <C> <C> <C>
Michael McGovern 13,100 $ 12.5 $ 350
Gary L. Pittman 6,550 $ 6.0 $ 175
Gerald E. Ruley 3,743 $ 3.5 $ 100
</TABLE>
(b) In 1990, the Company made a non-interest bearing loan in the amount of
$205,000 to Jeffrey Clarke, the Company's former President and Chief Executive
Officer, to assist him in the purchase of a house in Dallas. The Company has
entered into an executive employment severance agreement with Mr. Clarke in
which he will receive a forbearance of the loan from the Company in exchange for
his assistance in the Hicks Muse lawsuit. The loan will be forgiven on the date
the Hicks Muse lawsuit is settled or otherwise completed. At March 31, 2000, the
Company provided an allowance for this loan and charged reorganization expense.
8. COMMITMENTS AND CONTINGENCIES
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. At September 30, 2000, the Company has accrued
approximately $586,000 related to such costs, of which $66,000 is included in
current liabilities and $520,000 is included in contingent liabilities. At this
time, 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.
On May 27, 1999, the Company filed a lawsuit against five affiliates of
Hicks, Muse, Tate & Furst. The lawsuit alleges (1) breach of the written
contract terminated by HM4 Coho L.P. ("HM4"), a limited partnership formed by
Hicks Muse on behalf of the Hicks, Muse, Tate & Furst Equity Fund IV, in
December 1998, (2) breach of the oral agreements reached with HM4 on the
restructured transaction in February 1999 and (3) promissory estoppel. In the
lawsuit, the Company seeks monetary damages of approximately $300 million.
Discovery is substantially complete and both sides have filed motions for
summary judgement, which are currently scheduled to be heard during January
2001, the outcome of which could have a material effect on the litigation. The
Company believes that the lawsuit has merit and that the actions of HM4 in
December 1998 and February 1999 were the primary cause of the Company's
liquidity crisis; however, there can be no assurance as to the outcome of this
litigation.
On June 9, 2000, Energy Investment Partnership No. 1, an affiliate of
Hicks, Muse, Tate & Furst, filed a lawsuit against certain former officers of
the Company alleging, among other things, such officers made or caused to be
made false and misleading statements as to the proved oil and gas reserves
purportedly owned by the Company. The plaintiffs are asking for compensatory and
punitive damages. Pursuant to the Company's bylaws, the Company may be required
to indemnify such former officers against damages incurred by them as a result
of the lawsuit not otherwise covered by the Company's directors' and officers'
liability insurance policy. The Company believes the lawsuit is without merit
and does not expect the outcome of the lawsuit to have a material adverse effect
on the Company's financial position or results of operations.
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 hedging transactions are recorded in operating
15
<PAGE> 16
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NINE MONTHS ENDED SEPTEMBER 30, 2000
(TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED)
(UNAUDITED)
revenues when the future production sale occurs. The Company has hedged a
substantial amount of its crude oil production through December 31, 2002 and a
substantial amount of its natural gas production through May 31, 2001. At
September 30, 2000, the Company had $22.5 million in unrealized hedging losses
related to such financial arrangements. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Results of
Operations" for discussion on hedging arrangements.
During June 1999, the Company extended its Anaguid permit in Tunisia, North
Africa through June 2001. The Company has a commitment to drill two additional
wells during this two-year period
16
<PAGE> 17
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion should be read in conjunction with our condensed
consolidated financial statements and related notes included elsewhere in this
report. Some of this information with respect to our plans and strategy for our
business, are forward-looking statements. These statements are based on certain
assumptions and analyses made by our management in light of their perception of
expected future developments and other factors they believe are appropriate.
Such statements are not guarantees of future performance and actual results may
differ materially from those projected in the forward-looking statements.
GENERAL
As discussed more fully below, we emerged from bankruptcy on March 31,
2000. As a result of the reorganization, our former principal bondholders and
their affiliates own approximately 88% of the new common stock, with PPM
America, Inc., Appaloosa Management, L.P. and Oaktree Capital Management, LLC
and their respective affiliates owning 36% , 28% and 24%, respectively. A new
management team and a new board of directors were selected by the new owners to
lead us as we emerged from bankruptcy.
Our direction in the near term will be to increase production and cash flow
from existing properties to provide a stable base of future working capital. Our
existing Oklahoma and Mississippi properties offer numerous oil and gas
recompletion and drilling opportunities with favorable economics to achieve this
cash flow growth. We intend to use cash flow from operations to fund these
development activities.
Our only operating revenues are crude oil and natural gas sales with crude
oil representing approximately 92% of production revenues and natural gas sales
representing approximately 8% of production revenues during the nine months
ended September 30, 2000, compared to 88% from crude oil sales and 12% from
natural gas sales during the same period in 1999.
Our crude oil and natural gas production increased in the first nine months
of 2000 due to overall production increases on our operated properties as
discussed below under "Results of Operations - Operating Revenues." Average net
daily barrel of oil equivalent ("BOE") production was 10,675 BOE for the nine
months ended September 30, 2000 as compared to 10,311 BOE for the same period in
1999. For purposes of determining BOE herein, natural gas is converted to
barrels ("Bbl") on a 6 thousand cubic feet ("Mcf") to 1 Bbl basis.
BANKRUPTCY PROCEEDINGS
On August 23, 1999, we and our wholly-owned subsidiaries, Coho Resources,
Inc., Coho Oil & Gas, Inc., Coho Exploration, Inc., Coho Louisiana Production
Company and Interstate Natural Gas Company, made a Chapter 11 filing with the
bankruptcy court. On November 30, 1999 we filed a plan of reorganization and
subsequently filed an amended plan of reorganization on February 14, 2000. On
March 20, 2000, the bankruptcy court entered an order confirming our plan of
reorganization and on March 31, 2000, the plan of reorganization was consummated
and we emerged from bankruptcy.
Prior to March 31, 2000, the effective date of the plan of reorganization,
we had 25,603,512 shares of old common stock issued and outstanding. Old
shareholders received shares representing 4% of new common stock on a basis of
one share of new common stock for 40 shares of old common stock as of the
effective date without giving effect to dilution from shares issued in
connection with the standby loan or shares issued under the rights offering
discussed below. Additionally, shareholders as of February 7, 2000, are eligible
to receive their pro rata share of 20% of any proceeds available from the
lawsuit filed against five affiliates of Hicks, Muse, Tate & Furst (the "Hicks
Muse Lawsuit") after fees and expenses and 40% of any proceeds of the
disposition of our interest in, or the assets of, Coho Anaguid Inc. Coho Anaguid
owns a 45.83% interest in a permit in Tunisia, North Africa. At March
17
<PAGE> 18
31, 2000, we charged 40% of the carrying value of Coho Anaguid, Inc.,
approximately $1.1 million, to reorganization expense. The Company's remaining
carrying value of Coho Anaguid, Inc. is $1.9 million.
On May 2, 2000, we distributed stock rights to the holders of our old
common stock as of the record date of March 6, 2000, to purchase up to an
aggregate of 8,663,846 shares of our new common stock. Each holder of old common
stock received 0.338 rights for every share of old common stock held by such
holder. Each right allowed a holder to buy one share of new common stock at a
price of $10.40 per share. There were 14,669 rights exercised under the
offering; however, pursuant to an antidilution feature which applied to shares
issued in the rights offering, 1.17 shares were issued for each right exercised.
Unexercised rights expired May 31, 2000. We received $153,000 upon completion of
the offering on May 31, 2000. Proceeds from the rights offering were used to pay
offering costs; however, offering costs exceeded the proceeds from the rights
offering and the excess costs were charged to accrued reorganization costs.
The reorganized value of our assets exceeded the total of all postpetition
liabilities and allowed claims; therefore, we did not qualify for fresh-start
accounting. We recorded the following transactions to effect our plan of
reorganization consummated on March 31, 2000:
o The borrowing of $183.0 million under our new credit facility.
o The borrowing of $72.0 million under the standby loan and the issuance
of 2,694,841 shares of new common stock as debt issuance costs at a
diluted reorganization value of approximately $9.00 per share for a
total of $24.2 million. The diluted reorganization value of $9.00 per
share was caused by the old bondholders accepting a dilution in the
value of their new common stock to obtain the standby loan financing
for the reorganized company. The dilution is a result of the issuance
of additional shares to the standby lenders.
o Repayment of borrowings outstanding under the old bank credit facility
together with accrued interest and reasonable fees totaling $260.2
million, resulting in a $303,000 loss on extinguishment of debt.
o Conversion of the old bonds into 15,362,107 shares of new common
stock, representing 96% of the new common stock without giving effect
to dilution from shares issued in connection with the standby loan or
shares issued under the rights offering, at a reorganization value of
approximately $10.52 per share, resulting in a $4.1 million loss on
extinguishment of debt. Although the old bonds were paid no more than
in full, we did realize a loss on extinguishment of debt because our
carrying value of the old bonds was less than the allowed claim,
primarily due to unamortized debt issuance costs.
o Provision of $1.6 million to allow for settlement of disputed claims.
o Payment of all allowed senior secured claims and all other allowed
claims less than $1,000, aggregating approximately $500,000.
All other allowed claims will be or have been paid in full as follows:
o General unsecured claims are being paid in full in four quarterly
installments, the first and second installments were paid on May 1,
2000 and July 3, 2000, respectively, and subsequent installments are
due the first business day of each subsequent calendar quarter.
o Priority tax claims will receive five-year, interest-bearing
promissory notes.
o Payment of costs associated with the bankruptcy were paid upon court
approval during the six months following the consummation of the plan
of reorganization.
18
<PAGE> 19
In conjunction with our plan of reorganization, we terminated 19 corporate
office employees and seven officers in April 2000. Costs of $438,000 associated
with termination benefits for the 19 corporate office employees were accrued as
of March 31, 2000 and charged to reorganization expense and subsequently paid in
the quarter ended June 30, 2000. Additionally, we rejected all of our officer
employment agreements and officer severance agreements in connection with the
plan of reorganization, including the seven terminated officers. We have
negotiated settlement agreements related to the claims for these rejected
contracts. Approximately $3.0 million was accrued and charged to reorganization
expense for these claims settlements which are being paid during the nine months
following the consummation of the plan of reorganization.
Our plan of reorganization provided for a retention plan under which
employees are provided with additional incentives to continue their employment
with us throughout 2000. The amount of cash awards to be paid under the
retention plan, based on the current number of continuing employees, is $1.2
million, 33% was payable upon the effective date of our plan of reorganization
and 67% is to be paid on January 1, 2001. Costs of $419,000 payable upon the
effective date of the plan of reorganization were accrued and charged to
reorganization expense at March 31, 2000 and subsequently paid on April 14,
2000. Payments of approximately $805,000 to be paid on January 1, 2001, are
being amortized monthly over the subsequent nine-month period and charged to
reorganization expense.
LIQUIDITY AND CAPITAL RESOURCES
Capital Sources. For the nine months ended September 30, 2000, cash flow
provided by operating activities was $4.6 million compared with cash flow
provided by operating activities of $4.7 million for the same period in 1999.
Operating revenues, net of lease operating expenses, production taxes and
general and administrative expenses, increased $26.3 million from $15.3 million
in the first nine months of 1999 to $41.6 million in the first nine months of
2000, primarily due to price increases between such comparable periods of 74%
and 62% for crude oil and natural gas, respectively, increases in crude oil
production and reductions in general and administrative expenses, partially
offset by increases in production expenses and production taxes between
comparable periods. We also incurred costs totaling $12.5 million in the first
nine months of 2000 related to reorganization costs. Changes in operating assets
and liabilities used $9.2 million of cash for operating activities for the nine
months ended September 30, 2000, compared to $18.2 million of cash for operating
activities provided for the same period in 1999, primarily due to payment of
$18.5 million in accrued interest payable, partially offset by increases in
accrued reorganization costs, trade payables and other accrued liabilities and
increased accounts receivables from purchasers due to higher crude oil and
natural gas prices. See "Results of Operations" for a discussion of operating
results.
We had working capital of $2.1 million at September 30, 2000 compared to
working capital, before liabilities subject to compromise, of $16.2 million at
December 31, 1999. The decrease in working capital relates to several factors
including the following:
o Cash balances on hand decreased from $18.8 million at December 31,
1999 to $13.5 million at September 30, 2000. The decrease in cash is
primarily due to the utilization of cash on hand to consummate the
reorganization, partially offset by an increase in cash due to higher
crude oil and natural gas prices.
o Current liabilities increased from $15.2 million at December 31, 1999
to $24.8 million at September 30, 2000 due to several factors
including:
o the reclassification of $2.6 million of liabilities subject to
compromise to current liabilities as a result of our emergence
from bankruptcy,
o the accrual of $2.6 million of reorganization costs,
o an increase of $1.0 million in current long-term debt related to
the priority tax claims
o an increase of $1.1 million in current environmental liabilities
related to the bankruptcy claims
19
<PAGE> 20
o an increase of $1.2 million in accrued liabilities related to a
reserve established for disputed claims settlements,
o an increase of $4.0 million in accrued interest on our borrowings
under the new credit facility,
o an increase of $2.4 million in accrued liabilities related to
operations and
o an increase of $2.1 million in accrued liabilities related to
hedging losses.
The above factors were partially offset by the reduction in accrued interest
resulting from settlement of the old bank group claim discussed below.
We and some of our subsidiaries were parties to an old bank group loan
agreement. Borrowings outstanding under the old bank group loan, together with
accrued interest and reasonable fees totaling $260.2 million, were paid on March
31, 2000. We obtained the funds necessary for the payment of the old bank group
loan through the combination of borrowings under the new senior revolving credit
facility, borrowings under the standby loan and from cash on hand.
Additionally, we owed approximately $162 million of principal and accrued
interest under our old bond indenture. Under the plan of reorganization, these
old bonds and accrued interest were converted into 15,362,107 shares of new
common stock.
The new senior revolving credit facility was obtained from a syndicate of
lenders led by The Chase Manhattan Bank, as agent for the new lenders, and has a
principal amount of up to $250 million. The new credit facility limits advances
to the amount of the borrowing base, which has been set initially at $205
million. The borrowing base is the loan value assigned to the proved reserves
attributable to our oil and gas properties. The new credit facility is subject
to semiannual borrowing base redeterminations each April 1 and October 1, based
on the Company's reserve report, and will be made at the sole discretion of the
lenders. The lenders' October 1 analysis of the current borrowing base is still
pending. We or Chase may each request one additional borrowing base
redetermination during any calendar year.
Interest on advances under the new credit facility will be payable on the
earlier of the expiration of any interest period under the new credit facility
or quarterly. Amounts outstanding under the new credit facility will accrue
interest at our option at either the Eurodollar rate, which is the annual
interest rate equal to the London interbank offered rate ("LIBOR") for deposits
in United States dollars that is determined by reference to the Telerate Service
or offered to Chase plus an applicable margin (currently 3%), or the prime rate,
which is the floating annual interest rate established by Chase from time to
time as its prime rate of interest plus an applicable margin (currently 2%).
Currently, we have locked in a rate of 9.75% (6.75% LIBOR plus 3% margin) for
the six-month period October 10, 2000 through April 9, 2001 on $180 million
outstanding under the new credit facility. All outstanding advances under the
new credit facility are due and payable in full three years from the effective
date.
The new credit facility has been secured by granting Chase the following
collateral for the benefit of the lenders:
o first and prior security interests in the issued and outstanding
capital stock and other equity interests of our material subsidiaries,
o first and prior mortgage liens and security interests covering proved
mineral interests selected by Chase having a present value, as
determined by Chase, of not less than 85% of the present value of all
our proved mineral interests evaluated by the lenders for purposes of
determining the borrowing base and
o first and prior security interests in our other tangible and
intangible assets.
20
<PAGE> 21
The new credit agreement contains financial and other covenants including:
o maintenance of required ratios of cash flow to interest expense paid
or payable in cash (initially 2 to 1), senior debt to cash flow
required (initially not to exceed 5 to 1), and current assets to
current liabilities required (throughout the term of the credit
agreement to be 1 to 1 as of the end of each quarter),
o restrictions on the payment of dividends and
o limitations on the incurrence of additional indebtedness, the creation
of liens and the incurrence of capital expenditures.
The lenders received an additional $5.8 million of closing fees in addition to
expense reimbursements.
The standby loan was made under a senior subordinated note facility under
which we issued $72 million of senior subordinated notes to PPM America, Inc.,
Appaloosa Management, L.P., Oaktree Capital Management, L.L.C., Pacholder
Associates, Inc. and their respective assignees. Our rights and responsibilities
and those of the standby lenders are governed by a standby loan agreement which
was executed and delivered on March 31, 2000.
Debt under the standby loan agreement is evidenced by notes maturing March
31, 2007 and bearing interest at a minimum annual rate of 15% and payable in
cash semiannually. After March 31, 2001, additional semiannual interest payments
will be payable in an amount equal to 1/2% for every $0.25 that the "actual
price" for our oil and gas production exceeds $15 per barrel of oil equivalent
during the applicable semiannual interest period, up to a maximum of 10%
additional interest per year. The "actual price" for our oil and gas production
is the weighted average price received by us for all our oil and gas production,
including hedged and unhedged production, net of hedging costs, in dollars per
barrel of oil equivalent using a 6:1 conversion ratio for natural gas. The
actual price will be calculated over a six-month measurement period ending on
the date two months before the applicable interest payment date. Additionally,
upon an event of default occurring under the standby loan, interest will be
payable in cash, unless otherwise required to be paid-in-kind, at a rate equal
to 2% per year over the applicable interest rate. Interest payments under the
standby loan may be paid-in-kind subject to the requirements of the
intercreditor arrangement between the standby lenders and the lenders under the
new credit agreement. "Paid-in-kind" refers to the payment of interest owed
under the standby loan by increasing the amount of principal outstanding through
the issuance of additional standby loan notes, rather than paying the interest
in cash. The semiannual standby loan interest payment due on September 29, 2000
was paid-in-kind and has been reflected as an increase in long-term debt.
The additional semiannual interest payment feature of the standby loan
agreement based on the actual price received for our oil and gas production, as
discussed above, is considered an embedded derivative instrument. The additional
interest cost associated with this embedded derivative instrument is calculated
at the origination of the loan and at each future balance sheet date. The
aggregate amount of the additional interest payments was estimated at March 31,
2000, the inception date of the standby loan, using the future crude oil and
natural gas price curves as of such date. These estimated additional interest
payments were added to interest payments due based on the minimum annual rate at
15% to determine the effective interest rate of 18.04% for the term of the
standby loan. The aggregate amount of the additional interest payments was
redetermined at June 30, 2000 and September 30, 2000 using the then current
future crude oil and natural gas price curves. The difference of $4.0 million in
the amount of additional interest payments based on the June 30, 2000 price
curves as compared to the aggregate amount of additional interest payments based
on the March 31, 2000 price curves was reflected as an increase in the standby
loan debt and a charge to interest expense during the three months ended June
30, 2000. The aggregate amount of additional interest payments based on the
September 30, 2000 price curves increased $22.5 million over the aggregate
amount of additional interest payments using the June 30, 2000 price curves,
which is reflected as an increase in the standby loan debt and a charge to
interest expense during the three months ended September 30, 2000. The
additional interest
21
<PAGE> 22
expense may continue to have significant volatility from period to period based
on the changes in the futures price curves from period to period.
Payment of the standby loan notes will be expressly subordinate to payments
in full in cash of all obligations arising in connection with the new credit
facility. After the initial 12-month period, cash interest payments may be made
only to the extent by which EBITDA, or earnings before interest, tax,
depreciation and amortization expense, on a trailing four-quarter basis exceed
$65 million. The new credit agreement may also prohibit us from making any cash
interest payments on the standby loan indebtedness if the outstanding
indebtedness under both the new credit facility and the standby loan exceeds
3.75 times EBITDA for the trailing four quarters. We may prepay the standby loan
notes at the face amount, in whole or in part, in minimum denominations of
$1,000,000, plus either a standard make-whole payment at 300 basis points over
the "treasury rate" for the first four years, beginning in the fifth year, a
prepayment fee of 7.5% of the principal amount being prepaid; in the sixth year,
a prepayment fee of 3.75% of the principal amount being prepaid; and after the
sixth year there is no prepayment fee. The "treasury rate" is the yield of U.S.
Treasury securities with a term equal to the then-remaining term of the standby
loan notes that has become publicly available on the third business day before
the date fixed for repayment.
When the standby loan notes were issued on March 31, 2000, the standby
lenders became entitled to receive 14.4% of our fully diluted new common stock.
The shares were registered with the Securities and Exchange Commission in
connection with the rights offering and were issued June 1, 2000. The shares of
new common stock issued to the standby lenders were in addition to the shares of
new common stock issued to holders of the old bonds, to our shareholders prior
to reorganization and to persons participating in the rights offering.
Additionally, the standby lenders received closing fees of approximately $2.5
million as well as expense reimbursements.
Our new management team has prepared cash flow forecasts through the end of
the year 2001 assuming conservative growth in production during the period based
on budgeted capital expenditures and conservative commodity prices as compared
to current commodity prices. The forecasted operating revenues and availability
under the new credit facility are sufficient to fund the following forecasted
expenditures through the end of the year 2001:
o operating expenses, including well repair costs to return all shut-in
wells to production,
o general and administrative expenses as reduced for the April 2000
staff reductions,
o interest due under the bank credit facility,
o capital expenditures, and
o other current obligations, primarily consisting of accrued
reorganization costs, general unsecured claims and payments due under
the promissory notes related to priority tax claims.
Interest owed under the standby loan will be "paid-in-kind" by increasing the
amount of principal outstanding through the issuance of additional standby loan
notes.
Capital Expenditures. During the first nine months of 2000, we incurred
capital expenditures of $15.5 million compared with $5 million for the first
nine months of 1999. We ceased substantially all of our capital projects in 1999
due to our liquidity problems and our bankruptcy filing, as discussed above;
however, during the first nine months of 2000 we have increased capital
expenditure activities and we expect to continue work on capital projects
throughout 2000. The expenditures incurred during the first nine months of 2000
were largely in connection with development efforts, including recompletions,
workovers and waterfloods on existing wells throughout the Oklahoma and
Mississippi fields. In addition, during the first nine months of 2000, the
Company drilled 16 wells as follows:
22
<PAGE> 23
<TABLE>
<S> <C>
Mississippi Fields:
Brookhaven - 1 producing oil; 1 dry hole
Martinville - 1 producing oil
Oklahoma Fields:
Tatums - 5 producing oil; 1 service well
Cox Penn - 2 producing oil
East Fitts - 1 producing oil
Jennings-Deese - 1 producing gas; 1 dry hole
Eola - 1 dry hole
Non-operated fields - 1 producing gas.
</TABLE>
Currently, a $15.6 million capital expenditures budget for the remainder of the
year has been approved by our board of directors, which will be funded by
working capital from operations. We have also increased our capital maintenance
budget to return all shut-in wells to production and to promptly repair our
existing wells as future maintenance is required. Additionally, we anticipate
increasing our capital expenditure budget for the higher commodity prices and if
cash flow from successful capital projects exceeds our current budgeted cash
flow amounts. We have no material capital commitments and are consequently able
to adjust the level of our expenditures as circumstances warrant. No general and
administrative costs associated with our exploration and development activities
were capitalized for the first nine months 1999 compared with $510,000 of
capitalized costs for the first nine months of 2000.
RESULTS OF OPERATIONS
<TABLE>
<CAPTION>
Nine Months Ended Three Months Ended
September 30 September 30
----------------------- -----------------------
1999 2000 1999 2000
-------- -------- -------- -------
<S> <C> <C> <C> <C>
Selected Operating Data
Production
Crude Oil (Bbl/day) 9,054 9,698 9,190 9,795
Natural Gas (Mcf/day) 7,547 5,860 6,744 5,726
BOE (Bbl/day) 10,311 10,675 10,314 10,749
Average Sales Prices
Crude Oil per Bbl $ 13.59 $ 23.68 $ 18.00 $ 21.89
Natural Gas per Mcf $ 2.12 $ 3.43 $ 2.60 $ 4.23
Other
Production expenses $ 4.69 $ 5.92 $ 5.75 $ 6.16
Production taxes $ .66 $ 1.41 $ .99 $ 1.53
Depletion per BOE $ 3.63 $ 3.82 $ 3.63 $ 3.82
Production revenues (in thousands)
Crude Oil $33,587 $62,935 $15,219 $19,721
Natural Gas 4,370 5,516 1,610 2,226
------- ------- ------- -------
$37,957 $68,451 $16,829 $21,947
======= ======= ======= =======
</TABLE>
23
<PAGE> 24
Operating Revenues. During the first nine months of 2000, production
revenues increased 80% to $68.5 million as compared to $38.0 million for the
same period in 1999. This increase was primarily due to increases in the prices
received for crude oil and natural gas (including hedging gains and losses
discussed below) of 74% and 62%, respectively, and due to a 7% increase in daily
crude oil production, partially offset by a 22% decrease in daily natural gas
production. For the three months ended September 30, 2000, production revenues
increased 30% to $19.7 million as compared to $16.8 million for the same period
in 1999. This increase was principally due to increases in the prices received
for crude oil and natural gas (including hedging gains and losses discussed
below) of 22% and 63%, respectively, and due to a 7% increase in daily crude oil
production, partially offset by a 15% decrease in daily natural gas production.
The 7% increase in daily crude oil production during the first nine months
of 2000 is due to overall production increases in our operated Mississippi and
Oklahoma properties. The 22% decrease in daily natural gas production during the
first nine months of 2000 is primarily due to production declines on our
Oklahoma gas properties. Due to our capital constraints in conjunction with the
decline in crude oil prices during 1998, we significantly reduced both minor and
major well repairs and drilling activity on our operated properties during the
last five months of 1998, ceased all well repairs and drilling activity in
December 1998 and halted production on wells which were uneconomical due to
depressed crude oil prices, all of which contributed to overall production
declines. In response to improved crude oil prices in the second quarter of
1999, since May 1999 we have been utilizing working capital provided by
operations to perform well repair work to return the shut-in wells to
production. Due to our emergence from bankruptcy, we increased the level of
expenditures for capital projects and well maintenance in the second and third
quarters of 2000 which has improved crude oil production and returned
substantially all of the shut in wells to production. See "Liquidity and Capital
Resources - Capital Expenditures" for discussion on future expenditures.
Average crude oil prices (including hedging gains and losses discussed
below) increased 74% during the first nine months of 2000 compared to the same
period in 1999. Crude oil prices increased 22% during the third quarter of 2000
as compared to the third quarter of 1999. During the first quarter of 1999,
substantially all of our crude oil was sold under contracts which were keyed off
of posted crude oil prices. Beginning in April 1999, we entered into a new crude
oil contract for substantially all of our Oklahoma crude oil which is now keyed
off of the New York Mercantile Exchange price, which resulted in a net increase
in our realized price. The price per Bbl received is adjusted for the quality
and gravity of the crude oil and is generally lower than the NYMEX price. Our
overall average crude oil price received during the nine months of 2000
represented a discount of 20% to the average NYMEX price for such period.
The realized price for our natural gas (including hedging losses discussed
below) increased 62% from $2.12 per Mcf in the first nine months of 1999 to
$3.43 per Mcf in the first nine months of 2000. Natural gas prices increased 63%
from $2.60 per Mcf in the third quarter of 1999 to $4.23 per Mcf in the third
quarter of 2000. These price increases are due to an increase in demand.
Production revenues for the three and nine month periods ended September
30, 1999 included no crude oil or natural gas hedging gains or losses compared
to crude oil hedging losses for the three and nine month periods ended September
30, 2000 of $4.8 million ($5.27 per Bbl) and $4.9 million ($1.85 per Bbl),
respectively, and natural gas hedging losses for the three and nine month
periods ended September 30, 2000 of $124,000 ($0.23 per Mcf) and $144,000 ($0.09
per Mcf), respectively. Any gain or loss on our crude oil hedging transactions
is determined as the difference between the contract price and the average
closing price for West Texas Intermediate crude oil on the New York Mercantile
Exchange for the contract period. Any gain or loss on our natural gas hedging
transactions is determined as the difference between the contract price and the
New York Mercantile Exchange Henry Hub settlement price the next to last
business day of the contract period. Consequently, hedging activities do not
affect the actual price received for our crude oil and natural gas. At September
30, 2000, we had no deferred hedging gains or losses and $22.5 million in
unrealized hedging losses.
24
<PAGE> 25
We have hedged a portion of our future crude oil production and natural gas
production by entering into certain arrangements that fix a minimum and maximum
price range per barrel as follows:
Crude Oil
o 6,000 barrels per day for the period October 1, 2000 to June 30, 2001,
with a minimum price of $21.00 and a maximum price of $24.50.
o 1,220 barrels per day for the period October 1, 2000 to December 31,
2000, with a minimum price of $21.00 and a maximum price of $23.90.
o 250 barrels per day for the period January 1, 2001 to June 30, 2001,
with a minimum price of $20.00 and a maximum price of $22.65.
o 6,250 barrels per day for the period July 1, 2001 to December 31,
2001, with a minimum price of $20.00 and a maximum price of $22.80.
o 500 barrels per day for the period January 1, 2002 to December 31,
2002, with a minimum price of $22.00 and a maximum price of $28.00.
o 500 barrels per day for the period January 1, 2002 to December 31,
2002, with a minimum price of $22.00 and a maximum price of $29.60.
Natural Gas
o 3,000 MMbtus per day for the period October 1, 2000 to May 31, 2001,
with a minimum price of $3.35 and a maximum price of $4.01.
In addition, we entered into a swap agreement for the period January 1, 2002 to
March 31, 2002 to fix the price on 5,500 barrels of crude oil production per day
at $20.40 per barrel.
Expenses. Production expenses were $17.3 million for the first nine months
of 2000 compared to $13.2 million for the first nine months of 1999 and $6.1
million for the third quarter of 2000 compared to $5.5 million for the same
period in 1999. The increase in expenses for the comparable nine month and three
month periods is primarily due to an accelerated well repair program along with
repairs and upgrades to water injection facilities to be made capable of
handling expected increased fluid volumes and higher injection pressures in an
effort to stabilize production. On a BOE basis, production costs increased 26%
to $5.92 per BOE in 2000 from $4.69 per BOE in 1999 for the comparable nine
month periods and increased 7% to $6.16 per BOE in 2000 from $5.75 per BOE in
1999 for the comparable three month periods. On a BOE basis, the 24% increase in
production costs for the comparable nine month periods relates to several
factors including $3.0 million of well repair work performed in the first nine
months of 2000 as compared to $2.4 million in the same period of 1999.
Additionally, we experienced lower than normal costs during the nine month
period ended September 30, 1999 resulting from the cessation of all repair work
and shut-in of uneconomical wells during the end of 1998 and the first quarter
of 1999. The current well repair work represents an accumulation of projects
because we had ceased substantially all well repair work in December 1998 and
the subsequent four month period due to depressed oil prices. We intend to
continue well and production facility repair work throughout 2000 to improve
production. In addition, operating expenses are expected to remain high until
all water injection facilities have been restored to maximum volume and
pressure.
Production taxes increased $2.3 million or 121% for the first nine months
of 2000 as compared to the first nine months of 1999 and increased $576,000 or
61% for the third quarter of 2000 as compared to the third quarter of 1999.
These increases are due to increases in crude oil production and due to higher
price realization. On a BOE basis,
25
<PAGE> 26
production taxes increased 114% for the first nine months of 2000 to $1.41 per
BOE as compared to $0.66 per BOE for the same period last year and increased 55%
to $1.53 per BOE for the third quarter of 2000 as compared to $0.99 per BOE for
the same period in 1999 due to higher price realizations.
General and administrative costs decreased $2.2 million or 29% between the
comparable nine month periods and decreased $485,000 or 22% between the
comparable three month periods. These decreases are primarily due to reductions
in employee-related costs due to staff attrition and the termination of
corporate office employees and officers in April 2000 and due to increases in
capitalized general and administrative costs and operator overhead charges, both
of which reduce general and administrative expense.
State income tax penalties of $1.0 million for the nine month period ended
September 30, 1999 relate to approximately $4 million in Louisiana state income
taxes which were due April 15, 1999, related to the gain on the December 1998
sale of the Monroe gas field.
Allowance for bad debt of $765,000 for the nine month period ended
September 30, 2000 primarily represents an allowance for uncollectible accounts
receivable from working interest owners.
Depletion and depreciation expense increased 9% to $11.2 million for the
nine months ended September 30, 2000 from $10.2 million for the comparable nine
month period in 1999 and increased 10% to $3.8 million for the three months
ended September 30, 2000 from $3.4 million for the comparable three month period
in 1999. These increases are the result of an increased rate per BOE due to the
inclusion of $15.9 million in unproved oil and gas properties in our costs
subject to depletion, which increased to $3.82 for the nine month and three
month periods ending September 30, 2000 as compared to $3.63 for the comparable
nine month and three month periods ending September 30, 1999.
Interest expense increased 2% for the nine month period ended September 30,
2000 to $26.6 million compared to $26.0 million for the same period in 1999 and
increased 1% for the three month period ended September 30, 2000 to $9.3 million
compared to $9.2 million for the same period in 1999. Following is a summary of
interest expense between comparable periods:
<TABLE>
<CAPTION>
NINE MONTHS ENDED THREE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
----------------------- ----------------------
1999 2000 1999 2000
-------- ------- -------- -------
(in thousands) (in thousands)
<S> <C> <C> <C> <C>
Old bank group loan $15,759 $ 7,983 $ 6,678 $ --
Old bonds 9,275 -- 2,292 --
New Credit facility -- 9,001 -- 4,491
Standby loan -- 6,523 -- 3,255
Amortization of debt issuance costs 604 3,048 144 1,533
Miscellaneous 392 56 115 28
------- ------- ------- -------
$26,030 $26,611 $ 9,229 $ 9,307
------- ------- ------- -------
</TABLE>
The increase for the comparable nine month periods relates to several factors
including the following:
o higher interest rates on our old bank group loan during the first
quarter of 2000 due to payment defaults and debt acceleration,
o interest on past due interest payments on our old bank group loan
during the first quarter of 2000,
o an effective interest rate of 18.04% on the standby loan issued March
31, 2000 and
26
<PAGE> 27
o higher debt issuance amortization expense resulting from $33.6 million
in debt issuance costs on our new debt.
These increases were partially offset by:
o lower interest expense due to a reduction in our debt on March 31,
2000 resulting from the reorganization and
o discontinuance of the accrual of interest on our old unsecured bonds
during the first quarter of 2000 as a result of our bankruptcy filing.
Approximately $3.5 million of additional interest expense would have
been recognized during the first quarter of 2000 if not for the
discontinuance of such interest expense accrual.
The increase in expense for the comparable three month periods relates to an
effective interest rate of 18.04% on the standby loan and higher debt issuance
amortization expense on our new debt during 2000, partially offset by lower
interest expense due to a reduction in our debt on March 31, 2000 and higher
interest rates during the second and third quarters of 1999 on our old bank
group loan due to payment defaults and debt acceleration and interest on past
due payments.
Interest expense related to the embedded derivative for the nine month
period and three month period ended September 30, 2000 of $26.5 million and
$22.5 million, respectively, relates to the change in estimated future
additional interest payments calculated on the standby loan. The aggregate
amount of the additional interest payments were estimated at March 31, 2000
using the future crude oil and natural gas price curves as of such date. The
aggregate amount of additional interest payments was redetermined at June 30,
2000 and September 30, 2000 using the then current crude oil and natural gas
curves. The difference of $4.0 million in the aggregate amount of additional
interest payments based on the June 30, 2000 price curves as compared to the
aggregate amount of additional interest payments based on the March 31, 2000
price curves was charged to interest expense during the three months ended June
30, 2000 and the difference of $22.5 million in the aggregate amount of
additional interest payments based on the September 30, 2000 price curves as
compared to the aggregate amount of additional interest payments based on the
June 30, 2000 price curves was charged to interest expense during the three
months ended September 30, 2000.
Reorganization costs increased from $2.7 million for the nine months ending
September 30, 2000 to $12.5 million for the comparable period in 2000. This
increase relates to:
o professional fees for consultants and attorneys assisting in the
negotiations associated with financing and reorganization alternatives
and approval and implementation of our plan of reorganization,
o termination benefits for severed employees,
o payments and accrual of settlement amounts of officer employment
agreements and officer severance agreements which were rejected in the
plan of reorganization,
o payments and accrual of amounts made under our retention bonus plan
and
o provisions for settlements of disputed bankruptcy claims and other
costs to effect the plan of reorganization.
The above factors were partially offset by interest income earned on accumulated
cash during the first quarter of 2000. Reorganization costs for the three months
ended September 30, 2000 relate the accrual of amounts under our employee
retention plan.
27
<PAGE> 28
Loss on extinguishment of debt of $4.4 million for the nine months ended
September 30, 2000 resulted from the settlement of the old bank group and
bondholders' claims. The loss on settlement of the old bank group claim was
$303,000 and represents the difference in our carrying value of the debt and the
cash settlement amount. The loss on settlement of the bondholders' claims was
$4.1 million and represents the difference in our carrying value of the debt and
the reorganization value of $10.52 per share for the common stock received by
the bondholders.
Due to the factors discussed above, our net losses for the three and nine
months ended September 30, 2000 were $23.0 million and $40.0 million,
respectively, as compared to net losses of $10.7 million and $29.8 million,
respectively, for the same periods in 1999.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We use financial instruments which inherently have some degree of market
risk. The primary sources of market risk include fluctuations in commodity
prices and interest rate fluctuations.
PRICE FLUCTUATIONS
Our results of operations are highly dependent upon the prices received for
crude oil and natural gas production. We have entered, and expect to continue to
enter, into forward sale agreements or other arrangements for a portion of our
crude oil and natural gas production to hedge our exposure to price
fluctuations. At September 30, 2000, we have hedged a portion on our crude oil
and natural gas production through December 31, 2002. To calculate the potential
effect of the hedging contracts on our revenues, we applied prices from
September 30, 2000 future oil and gas price curves for the remainder of 2000 and
for 2001 and 2002 to the quantity of our oil and gas production hedged for these
periods. In addition, we applied September 30, 2000 future oil and gas pricing
from the price curves assuming a 10% increase in prices and assuming a 10%
decrease in prices. The estimated decreases in our revenue resulting from the
hedging contracts are as follows:
<TABLE>
<CAPTION>
Remainder of
2000 2001 2002
------------ ----------- -----------
<S> <C> <C> <C>
Decrease based on current price curve $ 5,142,000 $14,299,000 $ 3,069,000
Decrease based on 10% decrease in price curve $ 3,121,000 $ 7,447,000 $ 1,752,000
Decrease based on 10% increase in price curve $ 7,388,000 $21,152,000 $ 4,386,000
</TABLE>
Total debt as of September 30, 2000 included $77.4 million in debt under
our standby loan agreement, which represents the original $72 million standby
loan issued March 31, 2000 and a subsequent issuance made on September 29, 2000
of $5.4 million. The standby loan bears interest at a minimum rate of 15%
payable semiannually and after March 31, 2001, additional semiannual interest
payments payable in an amount equal to 1/2% for every $0.25 that the actual
price, net of hedging costs, for our oil and gas production exceeds $15.00 per
barrel of oil equivalent during the applicable semiannual interest period, up to
a maximum of 10% additional interest per year. The estimated fair value of the
standby loan at September 30, 2000 of $84.9 million represents the discounted
value of total future estimated payments due under the original standby loan
issued on March 31, 2000, using the future crude oil and natural gas price
curves at September 30, 2000 and the face amount of $5.4 million for the standby
loan note issued September 29, 2000, which approximated fair value. The discount
factor of 18.04% used in this valuation was determined based on the discount
applied at the inception of the loan on March 31, 2000. The applied discount of
18.04% was calculated at March 31, 2000 by using the total future estimated
payments due under the standby loan including additional interest payments
estimated over the life of the standby loan, using the future crude oil and
natural price curves at March 31, 2000 as compared to the initial borrowings of
$72.0 million under the standby loan.
At each balance sheet date, the future additional interest payments are
calculated using the then current future crude oil and natural gas price curves.
The change in the total future additional interest payments is charged to
interest expense; therefore, changes in crude oil and natural gas prices can
cause a significant change in earnings.
28
<PAGE> 29
At September 30, 2000, we calculated the future interest payments due
under the standby loan, including the minimum payments due at 15% and the
estimated additional interest payments, as discussed above, using the September
30, 2000 price curve. In addition, we applied the September 30, 2000 price curve
assuming a 10% decrease in prices and a 10% increase in prices. The estimated
decreases in cash flow through September 30, 2001 relating to standby loan
interest are as follows:
<TABLE>
<S> <C>
Decrease based on current price curve ............................... $15,472,000
Decrease based on 10% decrease in price curve ....................... $15,472,000
Decrease based on 10% increase in price curve ....................... $15,472,000
</TABLE>
The current price curve at September 30, 2000 maximizes the additional interest
rate at 10% through September 30, 2001; therefore, changes in prices for this
period have no impact on cash flow. Interest payments under the standby loan may
be paid-in-kind by increasing the amount of principal outstanding through the
issuance of additional standby loan notes, rather than paying the interest in
cash. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Liquidity and Capital Resources" for discussion on
interest payments to be paid-in-kind.
INTEREST RATE RISK
Total debt as of September 30, 2000, included $183 million of floating-rate
debt attributed to bank credit facility borrowing. As a result, our annual
interest cost in 2000 will fluctuate based on short-term interest rates. The
impact on annual cash flow of a ten percent change in the floating interest rate
(approximately 95 basis points) would be approximately $1.7 million assuming
outstanding debt of $183 million throughout the year. We have locked in a rate
of 9.75% (6.75% LIBOR plus 3% margin) for the six month period from October 10,
2000 thru April 9, 2001 on $180 million of bank credit facility borrowings.
29
<PAGE> 30
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS [UPDATES TO COME]
Hicks Muse Lawsuit. We are the plaintiff in a lawsuit styled Coho Energy,
Inc. v. Hicks, Muse, et al, which was filed in the District Court of Dallas
County, Texas, 68th Judicial District (the "Hicks Muse Lawsuit"). This lawsuit
has been removed to the United States Bankruptcy Court for the Northern District
of Texas, Dallas Division, where it currently is pending.
We allege in the Hicks Muse lawsuit that Hicks Muse reneged on a commitment
to inject $250 million dollars of equity capital into our operations, which
would have given Hicks Muse control of Coho through the purchase of 41,666,666
shares of newly issued common stock at $6 per share.
We further allege that Hicks Muse waited until after the shareholders
approved the commitment, then reneged on the commitment at the last minute to
renegotiate the price down to $4 per share to increase the number of shares that
Hicks Muse would have received for the $250 million. We also allege that Hicks
Muse reneged on the new commitment to purchase stock. We seek damages against
Hicks Muse in excess of $300 million. This description is only a general
description of the Hicks Muse Lawsuit and should not be relied on as
conclusively stating all the alleged facts, claims or circumstances surrounding
the lawsuit. We are not able to evaluate the recovery we might receive in the
lawsuit and its outcome is contingent on trial or settlement.
On June 9, 2000, Energy Investment Partnership No. 1, an affiliate of
Hicks, Muse, Tate and Furst, filed a lawsuit against certain former officers of
the Company. The lawsuit was filed in the Northern District of Texas, Dallas
Division alleging, among other things, defendants made or caused to be made
false and misleading statements as to the proved oil and gas reserves
purportedly owned by the Company. The plaintiffs are asking for compensatory
damages, punitive damages, all pre-judgment and post-judgment interests to which
plaintiffs are entitled by law, attorneys' fees and costs, and for such
additional relief, both general and special, at law or in equity, to which
plaintiff may show themselves to be justly entitled. Pursuant to the Company's
Bylaws, the Company may be required to indemnify such former officers against
damages incurred by them as a result of the lawsuit not otherwise covered by the
Company's directors' and officers' liability insurance policy. The Company
believes the lawsuit is without merit and does not expect the outcome to have a
material adverse effect on the Company's financial position.
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
30
<PAGE> 31
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, 2000
By: /s/ Gary L. Pittman
----------------------------------------
Gary L. Pittman
(Vice President and Chief Financial Officer)
By: /s/ Susan J. McAden
----------------------------------------
Susan J. McAden
(Chief Accounting Officer and Controller)
31
<PAGE> 32
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------ -----------
<S> <C>
27 Financial Data Schedule
</TABLE>
