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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 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 period ended September 30, 2000
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from ______________________to _____________________
Commission File Number: 0-20100
BELDEN & BLAKE CORPORATION
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(Exact name of registrant as specified in its charter)
Ohio 34-1686642
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
5200 Stoneham Road
North Canton, Ohio 44720
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(Address of principal executive offices) (Zip Code)
(330) 499-1660
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(Registrant's telephone number, including area code)
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(Former name, former address and former fiscal year, if changed
since last report.)
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 12 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.
[X] Yes [ ] No
As of October 31, 2000, Belden & Blake Corporation had outstanding 10,290,872
shares of common stock, without par value, which is its only class of stock.
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BELDEN & BLAKE CORPORATION
INDEX
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Page
----
PART I Financial Information:
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2000 and
December 31, 1999..........................................1
Consolidated Statements of Operations for the three and nine
months ended September 30, 2000 and 1999...................2
Consolidated Statements of Shareholders' Equity (Deficit)
for the nine months ended September 30, 2000 and the
years ended December 31, 1999 and 1998.....................3
Consolidated Statements of Cash Flows for the nine
months ended September 30, 2000 and 1999...................4
Notes to Consolidated Financial Statements....................5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations........................9
PART II Other Information
Item 6. Exhibits and Reports on Form 8-K.............................17
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BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
2000 1999
-------------- --------------
(UNAUDITED)
<S> <C> <C>
ASSETS
------
CURRENT ASSETS
Cash and cash equivalents $ 5,396 $ 4,536
Accounts receivable, net 22,676 25,301
Inventories 2,172 2,106
Deferred income taxes 2,044 2,006
Other current assets 2,129 1,154
---------------- ----------------
TOTAL CURRENT ASSETS 34,417 35,103
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties (successful efforts method) 410,750 534,515
Gas gathering systems 13,497 22,193
Land, buildings, machinery and equipment 23,014 24,242
---------------- ----------------
447,261 580,950
Less accumulated depreciation, depletion and amortization 204,449 280,047
---------------- ----------------
PROPERTY AND EQUIPMENT, NET 242,812 300,903
OTHER ASSETS 14,634 14,689
---------------- ----------------
$ 291,863 $ 350,695
================ ================
LIABILITIES AND SHAREHOLDERS' DEFICIT
-------------------------------------
CURRENT LIABILITIES
Accounts payable $ 6,623 $ 4,132
Accrued expenses 26,486 23,024
Current portion of long-term liabilities 175 50,979
---------------- ----------------
TOTAL CURRENT LIABILITIES 33,284 78,135
LONG-TERM LIABILITIES
Bank and other long-term debt 60,104 78,161
Senior subordinated notes 225,000 225,000
Other 354 570
---------------- ----------------
285,458 303,731
DEFERRED INCOME TAXES 21,080 20,419
SHAREHOLDERS' DEFICIT
Common stock without par value; $.10 stated value per share;
authorized 58,000,000 shares; issued 10,304,013 (which
includes 52,516 treasury shares) and 10,260,457 shares 1,030 1,026
Paid in capital 107,725 107,609
Deficit (156,714) (160,225)
---------------- ----------------
TOTAL SHAREHOLDERS' DEFICIT (47,959) (51,590)
---------------- ----------------
$ 291,863 $ 350,695
================ ================
See accompanying notes.
</TABLE>
1
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BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
----------------------------------- ------------------------------------
2000 1999 2000 1999
---------------- ---------------- --------------- ----------------
<S> <C> <C> <C> <C>
REVENUES
Oil and gas sales $ 18,782 $ 20,274 $ 55,663 $ 57,996
Gas gathering, marketing, and oilfield sales and
service 8,158 10,410 24,114 40,044
Other 682 1,118 2,535 3,326
---------------- ---------------- --------------- ----------------
27,622 31,802 82,312 101,366
EXPENSES
Production expense 5,221 5,654 15,287 16,030
Production taxes 583 834 1,865 2,375
Gas gathering, marketing, and oilfield sales and
service 7,109 9,341 21,094 36,578
Exploration expense 1,940 1,622 4,901 4,840
General and administrative expense 1,243 1,230 3,244 3,846
Franchise, property and other taxes 117 176 401 535
Depreciation, depletion and amortization 6,242 10,815 21,539 32,492
Other nonrecurring expense -- 2,889 24 2,889
---------------- ---------------- --------------- ----------------
22,455 32,561 68,355 99,585
---------------- ---------------- --------------- ----------------
OPERATING INCOME (LOSS) 5,167 (759) 13,957 1,781
Gain (loss) on sale of subsidiaries and other income 86 (2,803) 14,512 (2,803)
Interest expense (7,098) (8,679) (22,114) (25,668)
---------------- ---------------- --------------- ----------------
(LOSS) INCOME BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM (1,845) (12,241) 6,355 (26,690)
(Benefit) provision for income taxes (670) (4,550) 1,484 (9,988)
---------------- ---------------- --------------- ----------------
(LOSS) INCOME BEFORE EXTRAORDINARY ITEM (1,175) (7,691) 4,871 (16,702)
Extraordinary item - early extinguishment of debt,
net of tax benefit (1,360) -- (1,360) --
---------------- ---------------- --------------- ----------------
NET (LOSS) INCOME $ (2,535) $ (7,691) $ 3,511 $ (16,702)
================ ================ =============== ================
</TABLE>
See accompanying notes.
2
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BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (DEFICIT)
(IN THOUSANDS)
<TABLE>
<CAPTION>
TOTAL
COMMON COMMON PAID IN EQUITY
SHARES STOCK CAPITAL DEFICIT (DEFICIT)
------------ -------------- -------------- -------------- --------------
<S> <C> <C> <C> <C> <C>
JANUARY 1, 1998 10,000 $ 1,000 $ 107,230 $ (11,372) $ 96,858
Employee stock bonus 111 11 667 678
Net loss (130,550) (130,550)
----------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1998 10,111 1,011 107,897 (141,922) (33,014)
Employee stock bonus 118 12 (288) (276)
Stock options exercised 31 3 3
Net loss (18,303) (18,303)
----------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1999 10,260 1,026 107,609 (160,225) (51,590)
Stock options exercised 44 4 (4) --
Other 139 139
Treasury stock (53) (19) (19)
Net income 3,511 3,511
----------------------------------------------------------------------------------------------------------------
SEPTEMBER 30, 2000 (UNAUDITED) 10,251 $ 1,030 $ 107,725 $ (156,714) $ (47,959)
================================================================================================================
</TABLE>
See accompanying notes.
3
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BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(IN THOUSANDS)
<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------------
2000 1999
---------------- ------------------
CASH FLOWS FROM OPERATING ACTIVITIES:
<S> <C> <C>
Net Income (loss) $ 3,511 $ (16,702)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Net loss on early extinguishment of debt 1,360 --
Depreciation, depletion and amortization 21,539 32,492
(Gain) loss on sale of subsidiaries (13,241) 2,803
Loss on disposal of property and equipment 295 391
Exploration expense 4,901 4,840
Deferred income taxes 1,397 (9,988)
Deferred compensation and stock grants (49) (500)
Change in operating assets and liabilities, net of
effects of disposition of subsidiaries:
Accounts receivable and other operating assets (6,860) 5,635
Inventories (366) 1,962
Accounts payable and accrued expenses 7,696 (1,231)
---------------- ------------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 20,183 19,702
CASH FLOWS FROM INVESTING ACTIVITIES:
Disposition of subsidiaries, net of cash 69,031 --
Proceeds from property and equipment disposals 157 5,883
Exploration expense (4,901) (4,840)
Additions to property and equipment (14,363) (1,921)
(Increase) decrease in other assets (164) 320
---------------- ------------------
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES 49,760 (558)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving line of credit and term loan 80,161 21,000
Repayment of long-term debt and other obligations (149,244) (37,607)
---------------- ------------------
NET CASH USED IN FINANCING ACTIVITIES (69,083) (16,607)
---------------- ------------------
NET INCREASE IN CASH AND CASH EQUIVALENTS 860 2,537
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 4,536 10,691
---------------- ------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 5,396 $ 13,228
================ ==================
CASH PAID DURING THE PERIOD FOR:
Interest $ 17,677 $ 20,046
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Acquisition of assets in exchange for long-term liabilities 239 125
Non-compete agreement and related obligation -- 705
See accompanying notes.
</TABLE>
4
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BELDEN & BLAKE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
SEPTEMBER 30, 2000
--------------------------------------------------------------------------------
(1) BASIS OF PRESENTATION
The accompanying unaudited consolidated financial statements of Belden
& Blake Corporation (the "Company") have been prepared in accordance with
generally accepted accounting principles for interim financial information and
with the instructions to Form 10-Q and Article 10 of Regulation S-X.
Accordingly, they do not include all of the information and footnotes required
by generally accepted accounting principles for complete financial statements.
In the opinion of management, all adjustments (consisting of normal recurring
accruals) considered necessary for a fair presentation have been included.
Operating results for the three and nine month periods ended September 30, 2000
are not necessarily indicative of the results that may be expected for the year
ended December 31, 2000. For further information, refer to the consolidated
financial statements and footnotes included in the Company's annual report on
Form 10-K for the year ended December 31, 1999. Certain reclassifications have
been made to conform to the current presentation.
(2) NEW ACCOUNTING PRONOUNCEMENTS
In March 2000, the Financial Accounting Standards Board issued FASB
Interpretation No. 44, Accounting for Certain Transactions involving Stock
Compensation, an interpretation of APB Opinion No. 25. The Interpretation, which
has been adopted prospectively as of July 1, 2000, requires that stock options
that have been modified to reduce the exercise price be accounted for as
variable. The Company repriced 318,892 stock options (298,392 outstanding prior
to July 1, 2000) in October 1999, and reduced the exercise price to $.01 per
share. Under the Interpretation, the options are accounted for as variable from
July 1, 2000 until the options are exercised, forfeited or expire unexercised.
Prior to the adoption of the Interpretation, the Company accounted for these
repriced stock options as fixed. Because the value of the Company's stock
increased since July 1, 2000, the effect of adopting the Interpretation was to
increase compensation expense by $104,000 in the third quarter ended September
30, 2000.
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. (SFAS) 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS 133 establishes accounting
and reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities. SFAS 133,
as amended by SFAS 137, "Accounting for Derivative Instruments and Hedging
Activities - Deferral of Effective Date of SFAS 133," is effective for fiscal
years beginning after June 15, 2000. In June 2000, the FASB issued SFAS 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities."
This pronouncement amended portions of SFAS 133 and will be applied
prospectively as the cumulative effect of an accounting change with SFAS 133
effective January 1, 2001.
The Company expects to qualify for special hedge accounting treatment
under SFAS 133, whereby changes in fair value will be recorded in the balance
sheet as either an asset or liability at its fair value and recognized in other
comprehensive income until settled, when the resulting gains and losses will be
recorded in earnings. Any hedge ineffectiveness will be charged currently to
earnings. The Company believes that any ineffectiveness will be immaterial. The
effect on earnings and other comprehensive income as a result of the adoption of
SFAS 133 will vary from period to period and will be dependent upon prevailing
oil and gas prices, the volatility of forward prices for such commodities, the
volumes of production the company hedges and the time periods covered by such
hedges. The
5
<PAGE> 8
Company does not expect SFAS 133 to have a material impact on the financial
statements as a result of other contractual arrangements.
(3) LONG-TERM DEBT
On August 23, 2000, the Company obtained a $125 million credit facility
("the Facility") comprised of a $100 million revolving credit facility ("the
Revolver") and a $25 million term loan from Ableco Finance LLC and Foothill
Capital Corporation. The Facility has a two year term. The Facility allows for
up to $40 million to be used to purchase the Company's outstanding 9 7/8% senior
subordinated notes due 2007 ("the Notes"). To date, the Company has not
purchased any of the outstanding Notes.
The Revolver bears interest at the prime rate plus two percentage
points, payable monthly. At September 30, 2000, the interest rate was 11.5%. Up
to $20 million in letters of credit may be issued pursuant to the conditions of
the Revolver. At September 30, 2000, the Company had $7 million of outstanding
letters of credit. Up to $15 million of funds borrowed under the Revolver may be
used to purchase the Company's outstanding Notes.
Initial proceeds from the Revolver of approximately $66 million were
used to pay outstanding loans and interest due under the Company's former credit
facility of approximately $46 million; repay a term loan of $14 million to Chase
Manhattan Bank; pay fees and expenses associated with the new credit facility of
approximately $4 million; and to close out certain natural gas hedging
transactions with Chase Manhattan Bank. Due to the payment of the outstanding
loans under the former credit facility the Company took a charge of $2.1 million
($1.4 million net of tax benefit) representing the unamortized deferred loan
costs pertaining to the former credit facility. The charge was recorded as an
extraordinary item. As of September 30, 2000, the outstanding balance under the
Revolver was $60 million with $33 million of borrowing capacity available for
general corporate purposes.
No amounts were drawn under the term loan as of September 30, 2000. The
term loan commitment will terminate if not drawn by December 26, 2000. Proceeds
from the term loan may only be used to purchase the Company's outstanding Notes.
The Company will pay an additional 2% fee on funds borrowed under the term loan
(if any) and such funds will bear interest at three percentage points above the
prime rate, payable monthly. Funds repaid against borrowings from the term loan
may not be reborrowed.
The Facility is secured by security interests and mortgages against
substantially all of the Company's assets and is subject to periodic borrowing
base determinations. The borrowing base is the lesser of $125 million or the sum
of (i) 65% of the value of the Company's proved developed producing reserves
subject to a mortgage; (ii) 45% of the value of the Company's proved developed
non-producing reserves subject to a mortgage; and (iii) 40% of the value of the
Company's proved undeveloped reserves subject to a mortgage. The price forecast
used for calculation of the future net income from proved reserves is the
three-year NYMEX strip for oil and natural gas as of the date of the reserve
report. Prices beyond three years are held constant. Prices are adjusted for
basis differential, fixed price contracts and financial hedges in place. The
present value (using a 10% discount rate) of the Company's future net income at
September 30, 2000, under this formula was approximately $271 million for all
proved reserves of the Company and $216 million for properties secured by a
mortgage.
The Facility is subject to certain financial covenants. These include a
senior debt interest coverage ratio ranging from 6.0 to 1 at September 30, 2000,
to 3.2 to 1 at June 30, 2002; and a senior debt leverage ratio ranging from 2.7
to 1 at September 30, 2000 to 3.2 to 1 at June 30, 2002. EBITDA, as defined in
the Facility, and consolidated interest expense on senior debt in these ratios
are calculated
6
<PAGE> 9
quarterly based on the financial results of the previous four quarters. In
addition, the Company is required to maintain a current ratio (including
available borrowing capacity in current assets and excluding current debt and
accrued interest from current liabilities) of at least 1.0 to 1 and maintain
liquidity of at least $5 million (cash and cash equivalents including available
borrowing capacity). As of September 30, 2000, the Company's working capital
ratio including the above adjustments was 2.6 to 1. The Company has satisfied
all financial covenants as of September 30, 2000.
The new credit facility required an evaluation of the Company's proved
oil and natural gas reserves at July 1, 2000. These reserves have been evaluated
by Wright & Company, Inc., independent petroleum engineers. Projections of the
reserves and cash flow to the evaluated interests were based on economic
parameters and operating conditions considered applicable as of July 1, 2000,
and were prepared in accordance with the financial reporting requirements of the
Securities and Exchange Commission. At July 1, 2000, the Company's average
wellhead oil price was $29.69 per Bbl (barrel) and the Company's average
wellhead price for natural gas was $4.22 per Mcf (thousand cubic feet).
The following table is a summary of the total proved reserves evaluated
effective July 1, 2000:
PROVED OIL AND NATURAL GAS RESERVES
Total Proved Total Proved Total
Developed Undeveloped Proved
Reserves Reserves Reserves
------------------ ------------------- -----------------
Net Reserves to the
Evaluated Interests
Oil (Bbls) 6,058,801 2,897,705 8,956,506
Gas (Mcf) 251,873,700 111,637,200 363,510,900
Before Tax Cash Flow
Undiscounted: $ 866,881,300 $ 367,731,100 $ 1,234,612,400
Discounted at 10%
Per Annum: 400,307,800 120,141,200 520,449,000
The Company's proved developed and proved undeveloped reserves are all
located in Michigan, Ohio, Pennsylvania and New York. The Company cautions that
there are many uncertainties inherent in estimating proved reserve quantities
and in projecting future production rates and the timing of development
expenditures. Material revisions of reserve estimates may occur in the future,
development and production of the oil and gas reserves may not occur in the
periods assumed and actual prices realized and actual costs incurred may vary
significantly from those used to arrive at the reserve estimates. Proved
reserves represent estimated quantities of natural gas, crude oil and condensate
that geological and engineering data demonstrate, with reasonable certainty, to
be recoverable in future years from known reservoirs under economic and
operating conditions existing at the time the estimates were made.
From time to time, the Company may enter into interest rate swaps to
hedge the interest rate exposure associated with a credit facility, whereby a
portion of the Company's floating rate exposure is exchanged for a fixed
interest rate. At December 31, 1999, the Company had interest rate swap
arrangements covering $120 million of debt. On March 21, 2000, the Company
terminated swaps totaling $80 million which resulted in a gain of $1.3 million.
At September 30, 2000, the Company had remaining swap arrangements covering $40
million of debt which expired in October 2000.
7
<PAGE> 10
(4) SALE OF PEAKE ENERGY, INC.
On March 17, 2000, the Company sold the stock of Peake Energy, Inc.
("Peake"), a wholly owned subsidiary, to North Coast Energy, Inc., an
independent oil and gas company, with an effective date of January 1, 2000. The
sale included substantially all of the Company's oil and gas properties in West
Virginia and Kentucky. The sale resulted in net proceeds of approximately $69
million. The Company recorded a $13.2 million gain on the sale in the first
quarter of 2000.
At December 31, 1999, using SEC pricing parameters, Peake had proved
developed reserves of approximately 66.5 Bcfe (billion cubic feet of natural gas
equivalent) and proved undeveloped reserves of approximately 3.7 Bcfe. Peake's
reserves represented 20.2% of the Company's total proved reserves. The unaudited
pro forma results of operations for the nine month periods ended September 30,
2000 and 1999 are as follows: revenues of $78.2 million and $88.8 million,
respectively. The pro forma effects on net income were not material. The
unaudited pro forma information presented above assumes the disposition occurred
prior to each period presented and does not purport to be indicative of the
results that actually would have been obtained and is not intended to be a
projection of future results or trends.
(5) INDUSTRY SEGMENT FINANCIAL INFORMATION
The Company operates in one reportable segment, as an independent
energy company engaged in producing oil and natural gas; exploring for and
developing oil and gas reserves; acquiring and enhancing the economic
performance of producing oil and gas properties and gathering natural gas for
delivery to intrastate and interstate gas transmission pipelines. The Company's
operations are conducted entirely in the United States.
8
<PAGE> 11
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following table presents certain information with respect to the
oil and gas operations of the Company:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------- ---------------------
2000 1999 2000 1999
----------- ----------- --------- ---------
PRODUCTION
GAS (MMCF) 4,815 6,751 15,369 20,440
OIL (MBBLS) 144 180 450 548
TOTAL PRODUCTION (MMCFE) 5,677 7,832 18,071 23,726
AVERAGE PRICE
GAS (PER MCF) $ 3.04 $ 2.50 $ 2.84 $ 2.43
OIL (PER BBL) 28.70 18.77 26.80 15.02
MCFE 3.31 2.59 3.08 2.44
AVERAGE COSTS (PER MCFE)
PRODUCTION EXPENSE 0.92 0.72 0.85 0.68
PRODUCTION TAXES 0.10 0.11 0.10 0.10
DEPLETION 0.75 1.05 0.83 1.06
GROSS MARGIN (PER MCFE) 2.29 1.76 2.13 1.66
The following table presents certain information with respect to the
oil and gas operations of the Company excluding Peake (see Note 4):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------- ---------------------
2000 1999 2000 1999
----------- ----------- --------- ---------
PRODUCTION
GAS (MMCF) 4,815 5,328 14,215 16,300
OIL (MBBLS) 144 160 434 495
TOTAL PRODUCTION (MMCFE) 5,677 6,288 16,818 19,269
AVERAGE PRICE
GAS (PER MCF) $ 3.04 $ 2.46 $ 2.85 $ 2.45
OIL (PER BBL) 28.70 18.72 26.87 14.98
MCFE 3.31 2.56 3.10 2.46
AVERAGE COSTS (PER MCFE)
PRODUCTION EXPENSE 0.92 0.76 0.87 0.71
PRODUCTION TAXES 0.10 0.07 0.09 0.07
DEPLETION 0.75 1.15 0.84 1.15
GROSS MARGIN (PER MCFE) 2.29 1.73 2.14 1.68
MMCF-MILLION CUBIC FEET MBBLS-MILLION BARRELS MMCFE-MILLION CUBIC FEET OF
NATURAL GAS EQUIVALENT
MCF-THOUSAND CUBIC FEET BBL-BARREL MCFE-THOUSAND CUBIC FEET OF
NATURAL GAS EQUIVALENT
9
<PAGE> 12
RESULTS OF OPERATIONS - THIRD QUARTERS OF 2000 AND 1999 COMPARED
Operating income increased $5.9 million from an operating loss of
$759,000 in the third quarter of 1999 to operating income of $5.2 million in the
third quarter of 2000. This increase was a result of a $4.6 million decrease in
depreciation, depletion and amortization expense, a $2.9 million decrease in
nonrecurring expense partially offset by a $436,000 decrease in other income, a
$318,000 increase in exploration expense and a $828,000 decrease in operating
margins. The decrease in operating margins was due to a decrease in oil and gas
volumes sold as a result of the sale of Peake and the natural production decline
of the wells partially offset by increases in the average price paid for the
Company's oil and gas. The operating margin from oil and gas sales on a per unit
basis increased 30% from $1.76 per Mcfe in the third quarter of 1999 to $2.29
per Mcfe in the third quarter of 2000. The decrease in other income was
primarily due to a reduction in income from the monetization of nonconventional
fuel source tax credits as a result of the Peake sale.
Net loss decreased $5.2 million from $7.7 million in the third quarter
of 1999 to $2.5 million in the third quarter of 2000. This decrease was the
result of the changes in operating income discussed above, a $2.8 million loss
due to the sale of the Company's subsidiary, Target Oilfield Pipe and Supply
("TOPS"), in August 1999, and a $1.6 million decrease in interest expense
partially offset by a $1.4 million extraordinary loss from the early
extinguishment of debt, net of tax benefit (see Note 3), and a $3.9 million
decrease in the income tax benefit primarily due to the decrease in loss before
income taxes and extraordinary item.
Earnings before interest, income taxes, depreciation, depletion,
amortization, exploration expense and other nonrecurring items ("EBITDAX")
decreased $1.3 million (8%) from $14.6 million in the third quarter of 1999 to
$13.3 million in the third quarter of 2000 primarily due to the decreased
operating margins and the decrease in other income discussed above.
Total revenues decreased $4.2 million (13%) in the third quarter of
2000 compared to the third quarter of 1999 due to the sale of the Company's
subsidiaries, Belden Energy Services Company ("BESCO") and TOPS, in the second
half of 1999, the sale of Peake in the first quarter of 2000 and decreases in
the volume of oil and natural gas sold. These decreases were partially offset by
increases in the average price paid for the Company's oil and natural gas.
Oil volumes decreased 36,000 Bbls (20%) from 180,000 Bbls in the third
quarter of 1999 to 144,000 Bbls in the third quarter of 2000 resulting in a
decrease in oil sales of approximately $690,000. Gas volumes decreased 2.0 Bcf
(billion cubic feet) (29%) from 6.8 Bcf in the third quarter of 1999 to 4.8 Bcf
in the third quarter of 2000 resulting in a decrease in gas sales of
approximately $4.8 million. These volume decreases were due to the sale of Peake
in the first quarter of 2000, the natural production decline of the wells and
curtailment of drilling to minimum levels in 1999 due to capital constraints
caused by the reduction in the Company's borrowing base in 1999. The Company
expects fourth quarter 2000 oil and gas volumes to be slightly above third
quarter 2000 volumes.
The average price paid for the Company's oil increased from $18.77 per
barrel in the third quarter of 1999 to $28.70 per barrel in the third quarter of
2000 which increased oil sales by approximately $1.4 million. The average price
paid for the Company's natural gas increased $.54 per Mcf to $3.04 per Mcf in
the third quarter of 2000 compared to the third quarter of 1999 which increased
gas sales in the third quarter of 2000 by approximately $2.6 million. As a
result of the Company's hedging activities, gas sales for the third quarter of
2000 decreased by approximately $4.4 million or $.92 per Mcf compared to a
decrease of approximately $472,000 or $.07 per Mcf for the third quarter of
1999. At September 30, 2000, the Company had approximately 4.2 Bcf of expected
fourth quarter natural gas production and approximately 10.0 Bcf of expected
2001 natural gas production hedged or committed to
10
<PAGE> 13
be sold under fixed price contracts at estimated average wellhead prices of
$3.99 and $3.97 per Mcf, respectively.
Production expense decreased $433,000 (8%) from $5.7 million in the
third quarter of 1999 to $5.2 million in the third quarter of 2000 primarily due
to the sale of Peake partially offset by increased compensation related
expenses. The average production cost increased from $.72 per Mcfe in the third
quarter of 1999 to $.92 per Mcfe in the third quarter of 2000 primarily due to
increased compensation related expenses coupled with decreased production
volumes. The Company expects fourth quarter 2000 production expense per Mcfe to
be slightly lower than third quarter 2000. Production taxes decreased $251,000
(30%) from $834,000 in the third quarter of 1999 to $583,000 in the third
quarter of 2000 as a result of decreased oil and gas sales primarily due to the
sale of Peake.
Exploration expense increased by $318,000 (20%) from $1.6 million in
the third quarter of 1999 to $1.9 million in the third quarter of 2000 primarily
due to increases in geophysical expenses associated with the Company's active
drilling program in 2000 and planned drilling activity in 2001 partially offset
by decreased employment and compensation related expense due to staff reductions
in September 1999. Drilling activity in 1999 was severely curtailed due to
capital constraints caused by the reduction in the Company's borrowing base. The
Company currently expects to spend $18.2 million to drill 154 gross (109.4 net)
wells in 2000. This drilling activity is expected to replace 83% of production
in 2000 at a direct finding cost of $.91 per Mcfe.
General and administrative expense in the third quarter of 2000 was
consistent with the third quarter of 1999. The Company estimates that fourth
quarter 2000 general and administrative expense will be consistent with the
third quarter of 2000.
Depreciation, depletion and amortization decreased by $4.6 million
(42%) from $10.8 million in the third quarter of 1999 to $6.2 million in the
third quarter of 2000. Depletion expense decreased approximately $3.9 million
(48%) from $8.2 million in the third quarter of 1999 to $4.3 million in the
third quarter of 2000. Depletion per Mcfe decreased from $1.05 per Mcfe in the
third quarter of 1999 to $.75 per Mcfe in the third quarter of 2000. These
decreases were primarily the result of decreased production volumes and a lower
amortization rate per Mcfe due to higher reserves resulting from higher oil and
gas prices.
The Company incurred no other nonreccuring expense in the third
quarter of 2000 compared to $2.9 million in the third quarter of 1999 due to
$2.1 million in employee reduction costs and $830,000 in costs associated with
an abandoned acquisition effort and an abandoned public offering of a royalty
trust in the third quarter of 1999.
Interest expense decreased $1.6 million from $8.7 million in the third
quarter of 1999 to approximately $7.1 million in the third quarter of 2000 due
to a decrease in average outstanding borrowings partially offset by higher
blended interest rates. The Company's interest expense was reduced by $68,000 in
the third quarter of 2000 and increased by $235,000 in the third quarter of 1999
due to interest rate swaps.
RESULTS OF OPERATIONS - NINE MONTHS OF 2000 AND 1999 COMPARED
Operating income increased $12.2 million from $1.8 million in the first
nine months of 1999 to $14.0 million in the first nine months of 2000. This
increase was primarily the result of a $11.0 million decrease in depreciation,
depletion and amortization expense and a $2.9 million decrease in nonrecurring
expense partially offset by a $1.5 million decrease in operating margins. The
decrease in operating margins was due to a decrease in oil and gas volumes sold
as a result of the sale of Peake and the natural production decline of the wells
partially offset by increases in the average price paid for the Company's
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<PAGE> 14
oil and gas. The operating margin from oil and gas sales on a per unit basis
increased 28% from $1.66 per Mcfe in the first nine months of 1999 to $2.13 per
Mcfe in the first nine months of 2000. The decrease in other income was
primarily due to a reduction in income from the monetization of nonconventional
fuel source tax credits as a result of the Peake sale.
Net income increased $20.2 million from a net loss of $16.7 million in
the first nine months of 1999 to net income of $3.5 million in the first nine
months of 2000. This increase was the result of the changes in operating income
discussed above, the $2.8 million loss on the sale of TOPS in August 1999, the
$13.2 million gain on the sale of Peake in the first quarter of 2000, a $3.6
million decrease in interest expense and a $1.3 million gain on terminated
interest rate swaps in March 2000 offset by a $1.4 million extraordinary loss
from the early extinguishment of debt, net of tax benefit (see Note 3), and an
increase in the provision for income tax of $11.5 million primarily due to the
increase in income before income taxes partially offset by a lower effective
state tax rate due to the sale of Peake. As a result of this rate decrease, a
deferred tax benefit of $817,000 was recorded in the first nine months of 2000
which reduced the effective tax rate from 36.2% to 16.8%.
EBITDAX decreased from $42.0 million in the first nine months of 1999
to $40.4 million in the first nine months of 2000 primarily due the decrease in
operating margins discussed above.
Total revenues decreased $19.1 million (19%) in the first nine months
of 2000 compared to the first nine months of 1999 due to the sale of BESCO and
TOPS in the second half of 1999, the sale of Peake in the first quarter of 2000
and decreases in the volume of oil and natural gas sold partially offset by
increases in the average price paid for the Company's oil and natural gas.
Oil volumes decreased approximately 98,000 Bbls (18%) from 548,000 Bbls
in the first nine months of 1999 to 450,000 Bbls in the first nine months of
2000 resulting in a decrease in oil sales of approximately $1.5 million. Gas
volumes decreased 5.0 Bcf (25%) from 20.4 Bcf in the first nine months of 1999
to 15.4 Bcf in the first nine months of 2000 resulting in a decrease in gas
sales of approximately $12.3 million. These volume decreases were due to the
sale of Peake in the first quarter of 2000, the natural production decline of
the wells and the curtailment of drilling to minimum levels in 1999 due to
capital constraints caused by the reduction in the Company's borrowing base in
1999.
The average price paid for the Company's oil increased from $15.02 per
barrel in the first nine months of 1999 to $26.80 per barrel in the first nine
months of 2000 which increased oil sales by approximately $5.3 million. The
average price paid for the Company's natural gas increased $.41 per Mcf to $2.84
per Mcf in the first nine months of 2000 compared to the first nine months of
1999 which increased gas sales in the first nine months of 2000 by approximately
$6.3 million. As a result of the Company's hedging activities, gas sales for the
first nine months of 2000 decreased by approximately $7.3 million or $.47 per
Mcf compared to an increase of approximately $1.4 million or $.07 per Mcf for
the first nine months of 1999.
Production expense decreased approximately $743,000 (5%) from $16.0
million in the first nine months of 1999 to $15.3 million in the first nine
months of 2000. This decrease was primarily due to the sale of Peake partially
offset by increased employment and compensation related expenses. The average
production cost increased from $.68 per Mcfe in the first nine months of 1999 to
$.85 per Mcfe in the first nine months of 2000 primarily due to increased
compensation related expenses coupled with decreased production volumes.
Production taxes decreased $510,000 (21%) from $2.4 million in the first nine
months of 1999 to $1.9 million in the first nine months of 2000 as a result of
decreased oil and gas sales primarily due to the sale of Peake.
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<PAGE> 15
Exploration expense was $4.8 million in the first nine months of 1999
compared to $4.9 million in the first nine months of 2000. Increased geophysical
expenses associated with the Company's active drilling program in 2000 and
planned drilling activity in 2001 were offset by decreased employment and
compensation related expense due to staff reductions in September 1999. Drilling
activity in 1999 was severely curtailed due to capital constraints caused by the
reduction in the Company's borrowing base.
General and administrative expense decreased by $602,000 (16%) from
$3.8 million in the first nine months of 1999 to $3.2 million in the first nine
months of 2000 due to decreases in employment and compensation related expenses
and a decrease in Year 2000 related costs.
Other nonrecurring expense decreased from $2.9 million in the first
nine months of 1999 to $24,000 in the first nine months of 2000 due to $2.1
million in employee reduction costs and $830,000 in costs associated with an
abandoned acquisition effort and an abandoned public offering of a royalty trust
in the third quarter of 1999.
Depreciation, depletion and amortization decreased by $11.0 million
(34%) from $32.5 million in the first nine months of 1999 to $21.5 million in
the first nine months of 2000. Depletion expense decreased $10.0 million (40%)
from $25.0 million in the first nine months of 1999 to $15.0 million in the
first nine months of 2000. Depletion per Mcfe decreased from $1.06 per Mcfe in
the first nine months of 1999 to $.83 per Mcfe in the first nine months of 2000.
These decreases were primarily the result of decreased production volumes and a
lower amortization rate per Mcfe due to higher reserves resulting from higher
oil and gas prices.
Interest expense decreased $3.6 million (14%) from $25.7 million in the
first nine months of 1999 to $22.1 million in the first nine months of 2000 due
to a decrease in average outstanding borrowings partially offset by higher
blended interest rates. The Company's interest expense was reduced by $123,000
in the first nine months of 2000 and increased by $920,000 in the first nine
months of 1999 due to interest rate swaps.
LIQUIDITY AND CAPITAL RESOURCES
The Company's liquidity and capital resources are closely related to
and dependent on the current prices paid for its oil and natural gas.
The Company's current ratio at September 30, 2000 was 1.03 to 1. During
the first nine months of 2000, working capital increased $44.1 million from a
deficit of $43.0 million to working capital of $1.1 million at September 30,
2000. The increase was primarily due to a decrease in the current portion of
long-term liabilities of $50.8 million. The Company's operating activities
provided cash flows of $20.2 million during the first nine months of 2000.
On August 23, 2000, the Company obtained a $125 million credit facility
("the Facility") comprised of a $100 million revolving credit facility ("the
Revolver") and a $25 million term loan from Ableco Finance LLC and Foothill
Capital Corporation. The Facility has a two year term. The Facility allows for
up to $40 million to be used to purchase the Company's outstanding 9 7/8% senior
subordinated notes due 2007 ("the Notes"). To date, the Company has not
purchased any of the outstanding Notes.
The Revolver bears interest at the prime rate plus two percentage
points, payable monthly. At September 30, 2000, the interest rate was 11.5%. Up
to $20 million in letters of credit may be issued pursuant to the conditions of
the Revolver. At September 30, 2000, the Company had $7 million of
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<PAGE> 16
outstanding letters of credit. Up to $15 million of funds borrowed under the
Revolver may be used to purchase the Company's outstanding Notes.
Initial proceeds from the Revolver of approximately $66 million were
used to pay outstanding loans and interest due under the Company's former credit
facility of approximately $46 million; repay a term loan of $14 million to Chase
Manhattan Bank; pay fees and expenses associated with the new credit facility of
approximately $4 million; and to close out certain natural gas hedging
transactions with Chase Manhattan Bank. Due to the payment of the outstanding
loans under the former credit facility the Company took a charge of $2.1 million
($1.4 million net of tax benefit) representing the unamortized deferred loan
costs pertaining to the former credit facility. The charge was recorded as an
extraordinary item. As of September 30, 2000, the outstanding balance under the
Revolver was $60 million with $33 million of borrowing capacity available for
general corporate purposes.
No amounts were drawn under the term loan as of September 30, 2000. The
term loan commitment will terminate if not drawn by December 26, 2000. Proceeds
from the term loan may only be used to purchase the Company's outstanding Notes.
The Company will pay an additional 2% fee on funds borrowed under the term loan
(if any) and such funds will bear interest at three percentage points above the
prime rate, payable monthly. Funds repaid against borrowings from the term loan
may not be reborrowed.
The Facility is secured by security interests and mortgages against
substantially all of the Company's assets and is subject to periodic borrowing
base determinations. The borrowing base is the lesser of $125 million or the sum
of (i) 65% of the value of the Company's proved developed producing reserves
subject to a mortgage; (ii) 45% of the value of the Company's proved developed
non-producing reserves subject to a mortgage; and (iii) 40% of the value of the
Company's proved undeveloped reserves subject to a mortgage. The price forecast
used for calculation of the future net income from proved reserves is the
three-year NYMEX strip for oil and natural gas as of the date of the reserve
report. Prices beyond three years are held constant. Prices are adjusted for
basis differential, fixed price contracts and financial hedges in place. The
present value (using a 10% discount rate) of the Company's future net income at
September 30, 2000, under this formula was approximately $271 million for all
proved reserves of the Company and $216 million for properties secured by a
mortgage.
The Facility is subject to certain financial covenants. These include a
senior debt interest coverage ratio ranging from 6.0 to 1 at September 30, 2000,
to 3.2 to 1 at June 30, 2002; and a senior debt leverage ratio ranging from 2.7
to 1 at September 30, 2000 to 3.2 to 1 at June 30, 2002. EBITDA, as defined in
the Facility, and consolidated interest expense on senior debt in these ratios
are calculated quarterly based on the financial results of the previous four
quarters. In addition, the Company is required to maintain a current ratio
(including available borrowing capacity in current assets and excluding current
debt and accrued interest from current liabilities) of at least 1.0 to 1 and
maintain liquidity of at least $5 million (cash and cash equivalents including
available borrowing capacity). As of September 30, 2000, the Company's working
capital ratio including the above adjustments was 2.6 to 1. The Company has
satisfied all financial covenants as of September 30, 2000.
The new credit facility required an evaluation of the Company's proved
oil and natural gas reserves at July 1, 2000. These reserves have been evaluated
by Wright & Company, Inc., independent petroleum engineers. Projections of the
reserves and cash flow to the evaluated interests were based on economic
parameters and operating conditions considered applicable as of July 1, 2000,
and were prepared in accordance with the financial reporting requirements of the
Securities and Exchange Commission. At July 1, 2000, the Company's average
wellhead oil price was $29.69 per Bbl (barrel) and the Company's average
wellhead price for natural gas was $4.22 per Mcf (thousand cubic feet).
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<PAGE> 17
The following table is a summary of the total proved reserves evaluated
effective July 1, 2000:
PROVED OIL AND NATURAL GAS RESERVES
Total Proved Total Proved Total
Developed Undeveloped Proved
Reserves Reserves Reserves
------------------- ------------------ -----------------
Net Reserves to the
Evaluated Interests
Oil (Bbls) 6,058,801 2,897,705 8,956,506
Gas (Mcf) 251,873,700 111,637,200 363,510,900
Before Tax Cash Flow
Undiscounted: $ 866,881,300 $ 367,731,100 $ 1,234,612,400
Discounted at 10%
Per Annum: 400,307,800 120,141,200 520,449,000
The Company's proved developed and proved undeveloped reserves are all
located in Michigan, Ohio, Pennsylvania and New York. The Company cautions that
there are many uncertainties inherent in estimating proved reserve quantities
and in projecting future production rates and the timing of development
expenditures. Material revisions of reserve estimates may occur in the future,
development and production of the oil and gas reserves may not occur in the
periods assumed and actual prices realized and actual costs incurred may vary
significantly from those used to arrive at the reserve estimates. Proved
reserves represent estimated quantities of natural gas, crude oil and condensate
that geological and engineering data demonstrate, with reasonable certainty, to
be recoverable in future years from known reservoirs under economic and
operating conditions existing at the time the estimates were made.
From time to time the Company may enter into interest rate swaps to
hedge the interest rate exposure associated with a credit facility, whereby a
portion of the Company's floating rate exposure is exchanged for a fixed
interest rate. At December 31, 1999, the Company had interest rate swap
arrangements covering $120 million of debt. On March 21, 2000, the Company
terminated swaps totaling $80 million which resulted in a gain of $1.3 million.
At September 30, 2000, the Company had remaining swap arrangements covering $40
million of debt which expired in October 2000.
The Company currently expects to spend approximately $22 million during
2000 on its drilling activities and other capital expenditures. The Company
intends to finance such activities, as well as its acquisition program, through
its available cash flow, the sale of non strategic assets, available revolving
credit line and additional debt. The level of the Company's cash flow in the
future will depend on a number of factors including the demand for and price
levels of oil and gas, the scope and success of its drilling activities and its
ability to acquire additional producing properties.
To manage its exposure to natural gas price volatility, the Company may
partially hedge its physical gas sales prices by selling futures contracts on
the New York Mercantile Exchange ("NYMEX") or by selling NYMEX based commodity
derivative contracts which are placed with major financial institutions that the
Company believes are minimal credit risks. The contracts may take the form of
futures contracts, swaps or options. The Company had a pretax losses on its
hedging activities of $4.4 million in the third quarter of 2000 and $472,000 in
the third quarter of 1999.
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At September 30, 2000, the Company had open futures contracts covering
940 Mmcf of fourth quarter natural gas production and 5.1 Bcf of 2001 natural
gas production at a weighted average NYMEX price of $4.24 per Mcf which in
aggregate represented an unrealized loss of $2.9 million.
The following table reflects the natural gas volumes and the weighted
average prices under financial hedges and fixed price contracts (including
settled hedges) at September 30, 2000:
FINANCIAL HEDGES FIXED PRICE CONTRACTS
----------------------------- ---------------------
ESTIMATED ESTIMATED
NYMEX WELLHEAD WELLHEAD
QUARTER ENDING MMCF PRICE PRICE MMCF PRICE
-------------------------- --------- -------- -------- ------- --------
December 31, 2000 940 $ 4.49 $ 4.64 3,280 $ 3.81
March 31, 2001 1,250 4.75 4.90 2,100 3.75
June 30, 2001 1,800 3.56 3.71 1,265 3.50
September 30, 2001 1,050 4.40 4.55 1,050 3.55
December 31, 2001 1,000 4.43 4.58 470 3.10
FORWARD-LOOKING INFORMATION
The forward-looking statements regarding future operating and financial
performance contained in this report involve risks and uncertainties that
include, but are not limited to, the Company's availability of capital,
production and costs of operation, the market demand for and prices of oil and
natural gas, results of the Company's future drilling, the uncertainties of
reserve estimates, environmental risks, availability of financing and other
factors detailed in the Company's filings with the Securities and Exchange
Commission. Actual results may differ materially from forward-looking statements
made in this report.
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--------------------------------------------------------------------------------
PART II OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
10.1 Credit Agreement dated as of August 23, 2000
by and among the Company, Ableco Finance LLC
and Foothill Capital Corporation.
27 Financial Data Schedule
(b) Reports on Form 8-K
On July 27, 2000, the Company filed a Current Report
on Form 8-K dated July 18, 2000 relating to a non-binding letter agreement to
obtain a credit facility of up to $125 million and to the evaluation of the
Company's proved oil and natural gas reserves at July 1, 2000 by Wright &
Company, Inc., independent petroleum engineers.
On August 24, 2000, the Company filed a Current
Report on Form 8-K dated August 23, 2000 relating to the Company's new $125
million credit facility.
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SIGNATURES
--------------------------------------------------------------------------------
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, the Registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
BELDEN & BLAKE CORPORATION
Date: November 7, 2000 By: /s/ John L. Schwager
-------------------------------- ---------------------------------
John L. Schwager, Director, President
and Chief Executive Officer
Date: November 7, 2000 By: /s/ Robert W. Peshek
-------------------------------- ---------------------------------
Robert W. Peshek, Vice President
and Chief Financial Officer
18
