<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 June 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)
<TABLE>
<S> <C>
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)
</TABLE>
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 August 10, 2000
---------------------------- ------------------------------
<S> <C>
Common Stock, $.01 par value 18,714,175
</TABLE>
<PAGE> 2
INDEX
<TABLE>
<CAPTION>
PAGE
<S> <C> <C> <C>
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Report of Independent Public Accountants..............................1
Condensed Consolidated Balance Sheets -
December 31, 1999 and June 30, 2000...................................2
Condensed Consolidated Statements of Operations -
three and six months ended June 30, 1999 and 2000.................... 3
Condensed Consolidated Statement of Shareholders' Equity -
six months ended June 30, 2000........................................4
Condensed Consolidated Statements of Cash Flows -
six months ended June 30, 1999 and 2000.............................. 5
Notes to Condensed Consolidated Financial Statements................. 6
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations........................15
Item 3. Quantitative and Qualitative Disclosures About Market Risk...........24
PART II. OTHER INFORMATION
Item 1. Legal Proceedings....................................................26
Item 2. Changes in Securities................................................26
Item 3. Defaults Upon Senior Securities......................................26
Item 4. Submission of Matters to a Vote of Security Holders..................26
Item 5. Other Information....................................................26
Item 6. Exhibits and Reports on Form 8-K.....................................26
Signatures....................................................................27
</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 June 30, 2000,
and the related condensed consolidated statements of operations for the
three-month and six-month periods ended June 30, 2000 and 1999, and the
condensed consolidated statements of cash flows for the six-month periods ended
June 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
August 11, 2000
1
<PAGE> 4
COHO ENERGY, INC.
AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31 JUNE 30
1999 2000
------------ -----------
(UNAUDITED)
<S> <C> <C>
Current assets
Cash and cash equivalents.................................................. $ 18,805 $ 14,376
Cash in escrow............................................................. 78 27
Accounts receivable........................................................ 11,158 10,970
Other current assets....................................................... 1,428 1,276
---------- ---------
31,469 26,649
Property and equipment, at cost net of accumulated depletion and
depreciation, based on full cost accounting method (note 3)................ 311,788 310,458
Other assets.................................................................. 5,544 31,843
---------- ---------
$ 348,801 $ 368,950
========== =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities not subject to compromise:
Current liabilities
Accounts payable, principally trade...................................... $ 1,294 $ 6,858
Accrued liabilities and other payables................................... 3,751 12,211
Accrued interest......................................................... 10,175 3,960
Current portion of long term debt (note 4)............................... -- 1,036
---------- ---------
Total current liabilities.............................................. 15,220 24,065
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 24,065
---------- ---------
Long term debt, excluding current portion (note 4)............................ -- 267,386
---------- ---------
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................................................. 137,812 323,762
Retained deficit........................................................... (230,026) (246,970)
---------- ---------
Total shareholders' equity............................................. (91,958) 76,979
---------- ---------
$ 348,801 $ 368,950
========== ==========
</TABLE>
SEE ACCOMPANYING NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
2
<PAGE> 5
COHO ENERGY, INC.
AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED THREE MONTHS ENDED
JUNE 30 JUNE 30
-------------------- --------------------
1999 2000 1999 2000
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Operating revenues
Net crude oil and natural gas production .......... $ 21,128 $ 46,504 $ 12,161 $ 23,858
-------- -------- -------- --------
Operating expenses
Crude oil and natural gas production .............. 7,744 11,243 4,257 5,783
Taxes on oil and gas production ................... 923 2,606 637 1,334
General and administrative (note 3) ............... 5,386 3,705 2,659 1,542
State income tax penalties ........................ 1,002 -- 1,002 --
Allowance for bad debt ............................ -- 765 -- --
Depletion and depreciation ........................ 6,772 7,396 3,178 3,770
-------- -------- -------- --------
Total operating expenses ...................... 21,827 25,715 11,733 12,429
-------- -------- -------- --------
Operating income (loss) .............................. (699) 20,789 428 11,429
-------- -------- -------- --------
Other income and expenses
Interest and other income ......................... 186 141 97 138
Interest expense (note 4) ......................... (16,801) (17,304) (9,149) (9,240)
Interest expense embedded derivative (note 4) ..... -- (3,960) -- (3,960)
-------- -------- -------- --------
(16,615) (21,123) (9,052) (13,062)
-------- -------- -------- --------
Loss from operations before reorganization costs,
income taxes and extraordinary item ............... (17,314) (334) (8,624) (1,633)
Reorganization costs (note 2) ........................ (1,775) (12,182) (1,478) (682)
-------- -------- -------- --------
Loss before income taxes and extraordinary item ...... (19,089) (12,516) (10,102) (2,315)
Income tax expense (benefit) ......................... -- -- -- --
-------- -------- -------- --------
Loss before extraordinary item ....................... (19,089) (12,516) (10,102) (2,315)
-------- -------- -------- --------
Extraordinary item - loss on extinguishment of
indebtedness (note 2) ................................ -- (4,428) -- --
-------- -------- -------- --------
Net loss ............................................. $(19,089) $(16,944) $(10,102) $ (2,315)
======== ======== ======== ========
Basic and diluted loss per common share
Loss before extraordinary item .................... $ (.75) $ (1.28) $ (.40) $ (.12)
Extraordinary item ................................ $ -- $ (.45) $ -- $ --
Net loss .......................................... $ (.75) $ (1.73) $ (.40) $ (.12)
</TABLE>
SEE ACCOMPANYING NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
3
<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 -- -- -- --
Net loss ................................... -- -- -- (16,944) (16,944)
----------- ----------- ----------- ----------- -----------
Balance at June 30, 2000 ...................... 18,714,175 $ 187 $ 323,762 $ (246,970) $ 76,979
=========== =========== =========== =========== ===========
</TABLE>
SEE ACCOMPANYING NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
4
<PAGE> 7
COHO ENERGY, INC.
AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30
----------------------
1999 2000
--------- ---------
<S> <C> <C>
Cash flows from operating activities
Net loss ........................................................... $ (19,089) $ (16,944)
Adjustments to reconcile net loss to net cash used in operating
activities:
Depletion and depreciation ....................................... 6,772 7,396
Extraordinary item - loss on extinguishment of debt .............. -- 4,428
Standby loan interest ............................................ -- 3,268
Standby loan embedded derivative ................................. -- 3,960
Amortization of debt issuance costs and other .................... 520 3,502
Changes in operating assets and liabilities:
Accounts receivable and other assets ............................. 1,257 (797)
Accounts payable and accrued liabilities ......................... 6,425 (7,203)
--------- ---------
Net cash used in operating activities ................................. (4,115) (2,390)
--------- ---------
Cash flows from investing activities
Property and equipment ............................................. (602) (7,116)
Changes in accounts payable and accrued liabilities related to
exploration and development ...................................... (1,616) 952
--------- ---------
Net cash used in investing activities ................................. (2,218) (6,164)
--------- ---------
Cash flows from financing activities
Increase in long term debt ......................................... 4,600 255,000
Repayment of long term debt ........................................ (16) (239,600)
Debt issuance costs ................................................ -- (9,149)
Debt extinguishment costs .......................................... -- (2,126)
--------- ---------
Net cash provided by financing activities ............................. 4,584 4,125
--------- ---------
Net decrease in cash and cash equivalents ............................. (1,749) (4,429)
Cash and cash equivalents at beginning of period ...................... 6,901 18,805
--------- ---------
Cash and cash equivalents at end of period ............................ $ 5,152 $ 14,376
========= =========
Cash paid (received) during the period for:
Interest ......................................................... $ 7,058 $ 24,326
Income taxes ..................................................... $ 33 $ --
Reorganization costs (includes prepayments) ...................... $ 920 $ 4,816
Reorganization receipts (interest income) ........................ $ -- $ (260)
</TABLE>
SEE ACCOMPANYING NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
5
<PAGE> 8
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SIX MONTHS ENDED JUNE 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 and adjustments to effect the Company's plan
of reorganization, which, in the opinion of management, were necessary for a
fair presentation of the results for the interim periods, have been made. The
results of operations for the six month period ended June 30, 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 June 30, 2000, respectively) based on expected
collectibility.
Other assets include debt issuance costs related to the Company's standby
loan and new credit facility of $26.0 million and $5.8 million, respectively.
These costs are amortized using the straight line method over the remaining
terms of the related financing.
Statement of Financial Accounting Standards 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. At this time, the Company is
unable to determine the impact on its results of operations; however, it may be
significant.
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 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
6
<PAGE> 9
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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,
Inc. 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 $1.8 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 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.
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 will be paid in full in four quarterly
installments, the first installment was paid on May 1, 2000, 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.
7
<PAGE> 10
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
o Payment of costs associated with the bankruptcy are being paid upon
court approval.
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, 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 June 30
1999 2000
----------- ----------
<S> <C> <C>
Crude oil and natural gas leases and rights including exploration,
development and equipment thereon, at cost.......................... $ 684,896 $ 690,961
Accumulated depletion and depreciation.................................. (373,108) (380,503)
----------- ----------
$ 311,788 $ 310,458
=========== ==========
</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 have been charged to general and administrative
expense. The Company has increased development work during the second quarter of
2000; therefore, related overhead and expenditures of $255,000 have been
capitalized.
During the six months ended June 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
$39,769,000 at December 31, 1999 and June 30, 2000, respectively, were excluded
from costs subject to depletion. These costs are anticipated to be included in
costs subject to depletion during the next three to five years.
8
<PAGE> 11
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
4. LONG-TERM DEBT
<TABLE>
<CAPTION>
December 31 June 30
1999 2000
----------- ----------
<S> <C> <C>
Old bank group loan ............................................. $ 239,600 $ --
Old bonds ....................................................... 150,000 --
New credit facility ............................................. -- 183,000
Standby loan .................................................... -- 72,000
Standby loan interest to be paid-in-kind ........................ -- 3,268
Standby loan embedded derivative ................................ -- 3,960
Promissory notes ................................................ -- 5,194
Other ........................................................... 3 1,000
--------- ---------
389,603 268,422
Unamortized original issue discount on old bonds ................ (918) --
Current maturities of long-term debt ............................ (388,685) (1,036)
--------- ---------
$ -- $ 267,386
========= =========
</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 borrowing base is
subject to semiannual review based on reserve reports. The new credit facility
is subject to semiannual borrowing base redeterminations, each April 1 and
October 1, and will be made at the sole discretion of the lenders. 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
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.
9
<PAGE> 12
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The new credit agreement contains financial and other covenants including:
o maintenance of required ratios of cash flow to interest expense (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
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 interest accrued for the three months ended
June 30, 2000 will be paid-in-kind when due in October and has been reflected as
an increase in long-term debt and 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 using the then current future crude
oil and natural gas price 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 is reflected as an increase in the
standby loan debt and a charge to interest expense during the three months ended
June 30, 2000. The additional interest expense may have significant volatility
from period to period based on the changes in the future price curves from
period to period.
10
<PAGE> 13
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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, $4.2 million included in long term debt and approximately
$1 million 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 six months ended June 30, 1999 and
2000 of 640,088 and 9,769,619, respectively, and for the three months ended June
30, 1999 and 2000 of 640,088 and 18,700,753, respectively. The weighted average
number of shares outstanding of 640,088 for the six months ended June 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. The weighted average number
of shares outstanding of 9,769,619 for the six months ended June 30, 2000,
represents the weighted average of the old common shares of 25,603,512 restated
for the 40 for 1 conversion of old common stock for new common stock outstanding
for 90 days and the new shares issued outstanding for 91 days. 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 six months ended
June 30, 1999 and 2000 of 640,088 and 9,769,619,
11
<PAGE> 14
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
respectively and for the three months ended June 30, 1999 and 2000 of 640,088
and 18,700,753, respectively. In 1999 and 2000, conversion of stock options and
warrants would have been anti-dilutive and, therefore, was not considered in
diluted EPS. On March 31, 2000, pursuant to the Plan of Reorganization, all
previously issued stock options and warrants were extinguished.
6. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental noncash financing activities for the six months ended June 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 ......................................... (12,473)
Additional paid-in capital ............................. (24,245)
Interest expense ....................................... 3,268
Interest expense embedded derivative ................... 3,960
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
=========
</TABLE>
7. RELATED PARTY TRANSACTIONS
(a) On March 31, 2000, the Company issued $72.0 million of senior
subordinated notes (see Note 4), of which $65.5 million was 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>
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:
12
<PAGE> 15
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
<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 June 30, 2000, the Company has accrued approximately
$668,000 related to such costs, of which $148,000 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, 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 to have a material adverse effect on the
Company's financial position.
The Company has entered into certain financial arrangements which act as a
hedge against price fluctuations in future crude oil and natural gas production.
Gains and losses on these hedging transactions are recorded in operating
revenues when the future production sale occurs. The Company has 4.8 million
barrels of crude oil production hedged through March 31, 2002 and 1.1 million
MMbtus of natural gas production hedged through May 31, 2001. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Results of Operations" for discussion on hedging arrangements.
13
<PAGE> 16
COHO ENERGY, INC.
AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
14
<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. and affiliates, Appaloosa Management, L.P. and affiliates and Oaktree
Capital Management, LLC and 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 sales representing approximately 93% of production revenues and natural gas
sales representing approximately 7% of production revenues during the six months
ended June 30, 2000, compared to 87% from crude oil sales and 13% from natural
gas sales during the same period in 1999.
Our crude oil and natural gas production increased in the first six 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 10,637 BOE for the six
months ended June 30, 2000 as compared to 10,310 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 after fees
and expenses and 40% of any proceeds from the disposition of our interest in, or
the assets of, Coho Anaguid, Inc. Coho Anaguid,Inc. owns a 45.83% interest in a
permit in Tunisia, North Africa. At March 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 $1.8 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
15
<PAGE> 18
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 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 installment was paid on May 1, 2000, 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 are being paid upon
court approval.
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
16
<PAGE> 19
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 six months ended June 30, 2000, cash flow used by
operating activities was $2.4 million compared with cash flow used by operating
activities of $4.1 million for the same period in 1999. Operating revenues, net
of lease operating expenses, production taxes and general and administrative
expenses, increased $21.9 million from $7.1 million in the first six months of
1999 to $29.0 million in the first six months of 2000. These increases were
primarily due to price increases between such comparable periods of 118% and 59%
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 $12.2 million in the first six months
of 2000 related to reorganization costs. Changes in operating assets and
liabilities used $8.0 million of cash for operating activities for the six
months ended June 30, 2000, compared to $7.7 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 $2.6 million at June 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 $14.4 million at June 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 $24.1 million at June 30, 2000 due to several factors including:
o the reclassification of approximately $2.9 million of liabilities
subject to compromise to current liabilities as a result of our
emergence from bankruptcy,
o the accrual of $4.0 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 $1.8 million in current environmental liabilities
related to the bankruptcy claims,
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 and
o an increase of $1.6 million in accrued liabilities related to
operations.
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.
17
<PAGE> 20
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 borrowing base is subject to
semiannual review based on reserve reports. The new credit facility is subject
to semiannual borrowing base redeterminations, each April 1 and October 1, and
will be made at the sole discretion of the lenders. 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, beginning the first quarter after the effective date. 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 9.5% (6.5% LIBOR plus 3% margin) for the six-month period from April
10, 2000 through October 10, 2000 on the outstanding $183 million advance. 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.
The new credit agreement contains financial and other covenants including:
o maintenance of required ratios of cash flow to interest expense (2
to1), 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 $72.0 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.
18
<PAGE> 21
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 interest accrued for the three months ended
June 30, 2000 will be paid-in-kind when due in October 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 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 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 is reflected as an increase in the standby loan debt and a
charge to interest expense during the three months ended June 30, 2000. The
additional interest expense may have significant volatility from period to
period based on the changes in the 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 exceed
$65.0 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 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 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 assuming conservative growth in production during the period based on
budgeted capital expenditures, discussed below, 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:
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.
19
<PAGE> 22
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 six months of 2000, we incurred
capital expenditures of $7.1 million compared with $602,000 for the first six
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 six months of 2000 we have increased capital
expenditure activities and we expect to continue work on capital projects
throughout 2000. Currently, a $30.0 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. 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 six months 1999 compared with $170,000 of capitalized costs for the
first six months of 2000.
RESULTS OF OPERATIONS
<TABLE>
<CAPTION>
SIX MONTHS ENDED THREE MONTHS ENDED
JUNE 30 JUNE 30
-------------------- --------------------
1999 2000 1999 2000
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Selected Operating Data
Production
Crude Oil (Bbl/day) ................ 8,984 9,650 8,236 9,914
Natural Gas (Mcf/day) .............. 7,954 5,927 8,069 5,638
BOE (Bbl/day) ...................... 10,310 10,637 9,581 10,854
Average Sales Prices
Crude Oil per Bbl .................. $ 11.30 $ 24.61 $ 14.21 $ 24.40
Natural Gas per Mcf ................ $ 1.92 $ 3.05 $ 2.07 $ 3.60
Other
Production costs per BOE ........... $ 4.15 $ 5.81 $ 4.88 $ 5.86
Production taxes ................... $ 49 $ 1.35 $ .73 $ 1.35
Depletion per BOE .................. $ 3.63 $ 3.82 $ 3.65 $ 3.82
Production revenues (in thousands)
Crude Oil ......................... $18,367 $43,214 $10,648 $22,012
Natural Gas ....................... 2,761 3,290 1,513 1,846
------- ------- ------- -------
$21,128 $46,504 $12,161 $23,858
======= ======= ======= =======
</TABLE>
Operating Revenues. During the first six months of 2000, production
revenues increased 120% to $46.5 million as compared to $21.1 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 118% and 59%, respectively, and due to a 7% increase in
daily crude oil production, partially offset by a 25% decrease in daily natural
20
<PAGE> 23
gas production. For the three months ended June 30, 2000, production revenues
increased 96% to $23.9 million as compared to $12.2 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 72% and 74%, respectively, and due to a 20% increase in daily crude
oil production, partially offset by a 30% decrease in daily natural gas
production.
The 25% decrease in daily natural gas production during the first six
months of 2000 is primarily due to normal production declines on our Oklahoma
gas properties. The 7% increase in daily crude oil production during the first
six months of 2000 is due to overall production increases in our operated
Mississippi and Oklahoma oil 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 some of the shut-in
wells to production. Despite the repair work, we have not yet returned all
shut-in wells to production; however, due to our emergence from bankruptcy, we
increased the level of expenditures for capital projects and well maintenance in
the second quarter of 2000 which has improved crude oil 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 118% during the first six months of 2000 compared to the same
period in 1999. Crude oil prices increased 72% during the second quarter of 2000
as compared to the second 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 first half of 2000
represented a discount of 15% to the average NYMEX price for such period.
The realized price for the our natural gas increased 59% from $1.92 per Mcf
in the first six months of 1999 to $3.05 per Mcf in the first six months of
2000. Natural gas prices increased 74% from $2.07 per Mcf in the second quarter
of 1999 to $3.60 per Mcf in the second quarter of 2000. These price increases
are due to an increase in demand.
Production revenues for the three and six month periods ended June 30, 1999
included no crude oil hedging gains or losses compared to crude oil hedging
losses of $164,000 and natural gas hedging losses of $20,000 for the same
periods in 2000. 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 June 30,
2000, we had no deferred hedging gains or losses and $13.7 million in unrealized
hedging losses.
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 July 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 July 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.
21
<PAGE> 24
Natural Gas
o 3,000 MMbtus per day for the period July 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 $11.2 million for the first six months
of 2000 compared to $7.7 million for the first six months of 1999 and $5.8
million for the second quarter of 2000 compared to $4.3 million for the same
period in 1999. The increase in expenses for the comparable six 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 40%
to $5.81 per BOE in 2000 from $4.15 per BOE in 1999 for the comparable six month
periods. On a BOE basis, the 40% increase in production costs for the comparable
six month periods relates to several factors including $2.2 million of well
repair work performed in the first six months of 2000 as compared to $890,000
for the same period in 1999. On a BOE basis, the 20% increase in production
costs during the second quarter of 2000 over the second quarter of 1999 relates
to several factors including $1.1 million of well repair work performed in the
second quarter of 2000 as compared to $803,000 in the second quarter of 1999.
Additionally, we experienced lower than normal costs during the comparable six
month and three month periods 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 repair and production facility 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
capacity and all economical shut-in wells have been returned to production.
Production taxes increased $1.7 million or 182% for the first half of 2000
as compared to the first half of 1999 and increased $697,000 or 109% for the
second quarter of 2000 as compared to the second quarter of 1999. These
increases are due to increases in crude oil production and due to higher price
realization. On a BOE basis, production taxes increased 176% for the first half
of 2000 to $1.35 per BOE as compared to $0.49 per BOE for the same period last
year and increased 85% to $1.35 per BOE for the second quarter of 2000 as
compared to $0.73 per BOE for the same period in 1999 due to higher price
realizations.
General and administrative costs decreased $1.7 million or 31% between the
comparable six month periods and decreased $1.1 million or 42% 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 six month and three
month periods ended June 30, 1999 relate to approximately $4.0 million in
Louisiana state income taxes which were due April 15, 1999, in connection with
the gain on the December 1998 sale of the Monroe gas field.
Allowance for bad debt of $765,000 for the six months ended June 30, 2000
primarily represents an allowance for uncollectible accounts receivable from
working interest owners.
Depletion and depreciation expense increased 9% to $7.4 million for the six
months ended June 30, 2000 from $6.8 million for the comparable period in 1999
and increased 19% to $3.8 million for the three months ended June 30, 2000 from
$3.2 million for the comparable 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 property costs in our costs subject to depletion, which increased to
$3.82 in 2000 from $3.63 for the comparable six month period in 1999 and from
$3.65 for the comparable three month period in 1999.
Interest expense increased 3% for the six month period ended June 30, 2000
to $17.3 million compared to $16.8 million for the same period in 1999 and
increased 1% for the three month period ended June 30, 2000 to $9.2 million
22
<PAGE> 25
compared to $9.1 million for the same period in 1999. The increase in expense
for the comparable six month and three month periods is as follows:
<TABLE>
<CAPTION>
SIX MONTHS ENDED THREE MONTHS ENDED
JUNE 30 JUNE 30
------------------- -------------------
1999 2000 1999 2000
------- ------- ------- -------
(in thousands) (in thousands)
<S> <C> <C> <C> <C>
Old bank group loan .................... $ 9,081 $ 7,983 $ 5,054 $ --
Old bonds .............................. 6,983 -- 3,626 --
New credit facility .................... -- 4,510 -- 4,455
Standby loan ........................... -- 3,268 -- 3,242
Amortization of debt issuance costs .... 460 1,515 232 1,515
Miscellaneous other .................... 277 28 237 28
------- ------- ------- -------
$16,801 $17,304 $ 9,149 $ 9,240
======= ======= ======= =======
</TABLE>
The increase for the comparable six 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
o higher debt issuance amortization expense resulting from $31.8 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 the second quarter of 1999 on our old bank group loan due to
payment defaults and debt acceleration and interest on past due payments.
Interest expense embedded derivative of $4.0 million for the three month
and six month periods ended June 30, 2000 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 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.
Reorganization costs increased from $1.8 million for the six months ending
June 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.
23
<PAGE> 26
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 June 30, 2000 relate to claims settlement adjustments and accrual of
amounts under our employee retention plan.
Loss on extinguishment of debt of $4.4 million for the six months ended
June 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 six
months ended June 30, 2000 were $2.3 million and $16.9 million, respectively, as
compared to net losses of $10.1 million and $19.1 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 June 30, 2000, we have hedged a portion on our crude oil and
natural gas production through March 31, 2002. To calculate the potential effect
of the hedging contracts on our revenues, we applied prices from June 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 June 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 ............ $ 7,500,000 $ 4,800,000 $ 1,100,000
Decrease based on 10% decrease in price curve .... $ 3,300,000 $ 433,000 $ 10,000
Decrease based on 10% increase in price curve .... $11,700,000 $10,700,000 $ 2,300,000
</TABLE>
Total debt as of June 30, 2000 included $72.0 million in debt under our
standby loan agreement. 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 June 30, 2000 of $75.0 million represents the discounted value
of total future estimated payments due under the standby loans using the future
crude oil and natural gas price curves at June 30, 2000. 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.
At June 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 June 30, 2000 price
24
<PAGE> 27
curve. In addition, we applied the June 30, 2000 price curve assuming a 10%
decrease in prices and a 10% increase in prices. The estimated decreases in cash
flow through June 30, 2001 relating to standby loan interest are as follows:
<TABLE>
<S> <C>
Decrease based on current price curve ....................... $12,600,000
Decrease based on 10% decrease in price curve ............... $12,420,000
Decrease based on 10% increase in price curve ............... $12,600,000
</TABLE>
The current price curve at June 30, 2000 maximizes the additional interest rate
at 10% through June 30, 2001; therefore, increases 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 June 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 9.5% (6.5% LIBOR plus 3% margin) for the six month period from April 10, 2000
thru October 10, 2000 on the $183 million outstanding advance.
25
<PAGE> 28
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
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 monetary damages
against Hicks Muse of approximately $300 million. Discovery is substantially
complete and both sides have filed motions for summary judgment, the outcome of
which could have a material effect on litigation. 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 & 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 and 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
26
<PAGE> 29
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: August 14, 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)
27
<PAGE> 30
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C>
27 FINANCIAL DATA SCHEDULE
</TABLE>
