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, 2001
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, 2001, Belden & Blake Corporation had outstanding
10,293,039 shares of common stock, without par value, which is its only class of
stock.
BELDEN & BLAKE CORPORATION
INDEX
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PAGE
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PART I Financial Information:
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2001 and
December 31, 2000.................................................. 1
Consolidated Statements of Operations for the three and nine
months ended September 30, 2001 and 2000 .......................... 2
Consolidated Statements of Shareholders' Equity (Deficit) for
the nine months ended September 30, 2001 and the years ended
December 31, 2000 and 1999......................................... 3
Consolidated Statements of Cash Flows for the nine
months ended September 30, 2001 and 2000 .......................... 4
Notes to Consolidated Financial Statements........................... 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations................................ 8
PART II Other Information
Item 6. Exhibits and Reports on Form 8-K..................................... 15
BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
SEPTEMBER 30, DECEMBER 31,
2001 2000
--------- ---------
(UNAUDITED)
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 1,504 $ 1,798
Accounts receivable, net 14,737 22,620
Inventories 2,115 2,222
Deferred income taxes -- 1,475
Other current assets 1,970 1,448
Fair value of derivatives 20,559 --
--------- ---------
TOTAL CURRENT ASSETS 40,885 29,563
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties (successful efforts method) 440,889 413,824
Gas gathering systems 13,402 13,445
Land, buildings, machinery and equipment 25,526 23,469
--------- ---------
479,817 450,738
Less accumulated depreciation, depletion and amortization 224,451 208,435
--------- ---------
PROPERTY AND EQUIPMENT, NET 255,366 242,303
FAIR VALUE OF DERIVATIVES 7,462 --
OTHER ASSETS 11,390 13,251
--------- ---------
$ 315,103 $ 285,117
========= =========
LIABILITIES AND SHAREHOLDERS' DEFICIT
CURRENT LIABILITIES
Accounts payable $ 5,217 $ 5,926
Accrued expenses 22,974 19,316
Current portion of long-term liabilities 189 141
Deferred income taxes 6,608 --
--------- ---------
TOTAL CURRENT LIABILITIES 34,988 25,383
LONG-TERM LIABILITIES
Bank and other long-term debt 55,264 61,535
Senior subordinated notes 225,000 225,000
Other 435 323
--------- ---------
280,699 286,858
DEFERRED INCOME TAXES 24,417 21,189
SHAREHOLDERS' DEFICIT
Common stock without par value; $.10 stated value per share;
authorized 58,000,000 shares; issued 10,423,853 and
10,357,255 shares (which includes 100,971 and 53,972
treasury shares, respectively) 1,032 1,030
Paid in capital 107,465 107,921
Deficit (150,728) (157,264)
Accumulated other comprehensive income 17,230 --
--------- ---------
TOTAL SHAREHOLDERS' DEFICIT (25,001) (48,313)
--------- ---------
$ 315,103 $ 285,117
========= =========
See accompanying notes.
1
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS)
(UNAUDITED)
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------- -------------------------------
2001 2000 2001 2000
-------------- ------------- ----------- ------------------
REVENUES
Oil and gas sales $ 22,952 $ 18,782 $ 72,293 $ 55,663
Gas gathering, marketing, and oilfield service 7,421 7,726 25,652 25,328
Other 533 682 1,431 2,535
-------- -------- -------- --------
30,906 27,190 99,376 83,526
EXPENSES
Production expense 6,043 5,221 17,209 15,287
Production taxes 546 583 1,982 1,865
Gas gathering, marketing, and oilfield service 6,081 6,677 22,176 22,308
Exploration expense 2,296 1,940 5,956 4,901
General and administrative expense 1,099 1,243 3,261 3,244
Franchise, property and other taxes 93 117 297 401
Depreciation, depletion and amortization 6,489 6,242 18,666 21,539
Severance and other nonrecurring expense 312 -- 1,813 24
-------- -------- -------- --------
22,959 22,023 71,360 69,569
-------- -------- -------- --------
OPERATING INCOME 7,947 5,167 28,016 13,957
OTHER (INCOME) EXPENSE
Gain on sale of subsidiary and other income -- (86) -- (14,512)
Interest expense 6,819 7,098 20,866 22,114
-------- -------- -------- --------
INCOME (LOSS) BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM 1,128 (1,845) 7,150 6,355
Provision (benefit) for income taxes 446 (670) 614 1,484
-------- -------- -------- --------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM 682 (1,175) 6,536 4,871
Extraordinary item - early extinguishment
of debt, net of tax benefit -- (1,360) -- (1,360)
-------- -------- -------- --------
NET INCOME (LOSS) $ 682 $ (2,535) $ 6,536 $ 3,511
======== ======== ======== ========
See accompanying notes.
2
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (DEFICIT)
(in thousands)
ACCUMULATED
OTHER
COMMON COMMON PAID IN COMPREHENSIVE TOTAL
SHARES STOCK CAPITAL DEFICIT INCOME DEFICIT
---------- ---------- ---------- ----------- ---------- -----------
JANUARY 1, 1999 10,111 $ 1,011 $ 107,897 $(141,922) $ -- $ (33,014)
Net loss (18,303) (18,303)
Stock options exercised 31 3 3
Stock-based compensation 118 12 (288) (276)
- ----------------------------------------------- ---------- ---------- ---------- ---------- --------- ---------
DECEMBER 31, 1999 10,260 1,026 107,609 (160,225) -- (51,590)
Net income 2,961 2,961
Stock options exercised 97 10 (9) 1
Stock-based compensation 336 336
Treasury stock (54) (6) (15) (21)
- ----------------------------------------------- ---------- ---------- ---------- ---------- --------- ---------
DECEMBER 31, 2000 10,303 1,030 107,921 (157,264) -- (48,313)
Comprehensive income:
Net income 6,536 6,536
Other comprehensive income, net of tax:
Cumulative effect of accounting change (6,691) (6,691)
Change in derivative fair value 23,178 23,178
Reclassification adjustments - contract settlements 743 743
---------
Total comprehensive income 23,766
---------
Stock options exercised 67 7 (1) 6
Stock-based compensation 379 379
Repurchase of stock options (670) (670)
Treasury stock (47) (5) (164) (169)
- ----------------------------------------------- ---------- ---------- ---------- ---------- --------- ---------
SEPTEMBER 30, 2001 (UNAUDITED) 10,323 $ 1,032 $ 107,465 $(150,728) $ 17,230 $ (25,001)
=============================================== ========== ========== ========== ========== ========= =========
Total comprehensive income in the quarter ended September 30, 2001, was $7.3
million.
A net gain of $3.2 million was reclassified to earnings from accumulated other
comprehensive income in the quarter ended September 30, 2001.
See accompanying notes.
3
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(IN THOUSANDS)
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------
2001 2000
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 6,536 $ 3,511
Adjustments to reconcile net income to net cash
provided by operating activities:
Net loss on early extinguishment of debt -- 1,360
Depreciation, depletion and amortization 18,666 21,539
Gain on sale of subsidiary -- (13,241)
Loss on disposal of property and equipment 142 295
Exploration expense 5,956 4,901
Deferred income taxes 521 1,397
Stock-based compensation 379 (30)
Change in operating assets and liabilities, net of
effects of disposition of subsidiary:
Accounts receivable and other operating assets 7,371 (1,848)
Inventories 107 (366)
Accounts payable and accrued expenses 2,939 7,696
--------- ---------
NET CASH PROVIDED BY OPERATING ACTIVITIES 42,617 25,214
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of businesses, net of cash acquired (2,130) --
Disposition of businesses, net of cash 400 69,031
Proceeds from property and equipment disposals 1,162 157
Exploration expense (5,956) (4,901)
Additions to property and equipment (28,826) (14,363)
Increase in other assets (72) (164)
--------- ---------
NET CASH (USED IN) PROVIDED BY INVESTING ACTIVITIES (35,422) 49,760
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving line of credit 137,921 80,161
Repayment of long-term debt and other obligations (144,367) (149,244)
Debt issue costs (210) (5,012)
Proceeds from stock options exercised 6 --
Repurchase of stock options (670) --
Purchase of treasury stock (169) (19)
--------- ---------
NET CASH USED IN FINANCING ACTIVITIES (7,489) (74,114)
--------- ---------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS (294) 860
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 1,798 4,536
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 1,504 $ 5,396
========= =========
CASH PAID DURING THE PERIOD FOR:
Interest $ 15,530 $ 17,677
Income taxes, net of refunds 359 --
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Acquisition of assets in exchange for long-term liabilities 443 239
See accompanying notes.
4
BELDEN & BLAKE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
SEPTEMBER 30, 2001
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(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, 2001
are not necessarily indicative of the results that may be expected for the year
ended December 31, 2001. 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, 2000. Certain reclassifications have
been made to conform to the current presentation.
(2) NEW ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board (FASB) issued
Statements of Financial Accounting Standards No. (SFAS) 141, "Business
Combinations," and SFAS 142, "Goodwill and Other Intangible Assets." Adoption of
these standards is not expected to have a material effect on the Company's
financial position, results of operations or cash flows. SFAS 141 eliminates the
pooling-of-interests method of accounting for business combinations except for
qualifying business combinations that were initiated prior to July 1, 2001. SFAS
141 further clarifies the criteria to recognize intangible assets separately
from goodwill. The requirements of SFAS 141 are effective for any business
combination accounted for by the purchase method that is completed after June
30, 2001.
Under SFAS 142, goodwill and indefinite lived intangible assets are no
longer amortized but are reviewed for impairment annually or if certain
impairment indicators arise. Separable intangible assets that are not deemed to
have an indefinite life will continue to be amortized over their useful lives
(but with no maximum life). The amortization provisions of SFAS 142 apply to
goodwill and intangible assets acquired after June 30, 2001. With respect to
goodwill and intangible assets acquired prior to July 1, 2001, companies are
required to adopt SFAS 142 in their fiscal year beginning after December 15,
2001. Early adoption is not permitted for calendar year companies. Because of
the different transition dates for goodwill and intangible assets acquired on or
before June 30, 2001 and those acquired after that date, pre-existing goodwill
and intangibles will be amortized during this transition period until adoption
whereas new goodwill and indefinite lived intangible assets acquired after June
30, 2001 will not.
In August 2001, the FASB issued SFAS 143, "Accounting for Asset
Retirement Obligations." SFAS 143 addresses obligations associated with the
retirement of tangible, long-lived assets and the associated asset retirement
costs. This statement amends SFAS 19, "Financial Accounting and Reporting by Oil
and Gas Producing Companies", and is effective for financial statements issued
for fiscal years beginning after June 15, 2002. The Company is currently
assessing the impact of SFAS 143 and has not yet determined whether adoption
will have a material effect on the Company's financial position, results of
operations or cash flows.
In October 2001, the FASB issued SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which establishes a single
accounting model to be used for long-lived assets, to be
5
disposed of. The new rules supersede SFAS 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." Although
retaining many of the fundamental recognition and measurement provisions of SFAS
121, the new rules significantly change the criteria that would have to be met
to classify an asset as held-for-sale. This distinction is important because
assets to be disposed of are stated at the lower of their fair values or
carrying amounts and depreciation is no longer recognized. The new rules also
will supersede the provisions of APB Opinion 30 with regard to reporting the
effects of a disposal of a segment of a business and will require the expected
future operating losses from discontinued operations to be displayed in
discontinued operations in the periods in which the losses are incurred rather
than as of the measurement date as presently required by APB 30. In addition,
more dispositions will qualify for discontinued operations treatment in the
income statement. SFAS 144 is effective for fiscal years beginning after
December 15, 2001. The adoption of this standard is not expected to have a
material effect on the Company's financial position, results of operations or
cash flows.
(3) CREDIT AGREEMENT
On June 29, 2001, the Company amended its $100 million revolving credit
facility ("the Revolver") from Ableco Finance LLC and Foothill Capital
Corporation. The amendment extended the Revolver's final maturity date to April
22, 2004, from August 23, 2002, increased the letter of credit sub-limit from
$20 million to $30 million and eliminated the effects of SFAS 133, "Accounting
for Derivative Instruments and Hedging Activities," from covenant calculations.
The Company paid approximately $200,000 in fees and expenses related to the
amendment.
The amendment extended the financial covenant for the senior interest
coverage ratio of 3.2 to 1 for the quarters ending September 30, 2002, through
March 31, 2004; and the senior debt leverage ratio of 2.7 to 1 was extended for
the quarters ending September 30, 2002, through March 31, 2004. These ratios
will be calculated quarterly based on the financial results of the previous four
quarters.
The amendment added an early termination fee equal to .25% of the
facility if terminated between the effective date and May 31, 2002. If
termination is after May 31, 2002 but on or before May 31, 2003, the termination
fee is .125% of the facility. There is no termination fee after May 31, 2003.
The Company is required to hedge at least 20% but not more than 80% of its
estimated hydrocarbon production, on an Mcfe (thousand cubic feet of natural gas
equivalent) basis, for the succeeding 12 months on a rolling 12 month basis.
Based on the Company's hedges currently in place and its expected production
levels, the Company is in compliance with this hedging requirement through June
2003.
(4) SEVERANCE AND OTHER NONRECURRING EXPENSE
Effective April 1, 2001, certain senior management members of the
Company accepted early retirements. These retirements will result in a cash
charge of approximately $760,000 and an additional non-cash charge of $100,000
related to the acceleration of certain stock options.
The Company recorded severance and other nonrecurring expense of $1.8
million in the first nine months of 2001 related to these retirement agreements
and other severance charges incurred which included non-cash charges totaling
approximately $200,000 due to the acceleration of certain related stock options.
(5) DERIVATIVES AND HEDGING
As of January 1, 2001, the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended. As a result of the
adoption of SFAS 133, the Company recognizes all derivative financial
instruments as either assets or liabilities at fair value. Derivative
instruments that are not hedges must be adjusted to fair value through net
income (loss). Under the provisions of SFAS
6
133, changes in the fair value of derivative instruments that are fair value
hedges are offset against changes in the fair value of the hedged assets,
liabilities, or firm commitments, through net income (loss). Changes in the fair
value of derivative instruments that are cash flow hedges are recognized in
other comprehensive income (loss) until such time as the hedged items are
recognized in net income (loss). The hedging relationship between the hedging
instruments and hedged item must be highly effective in achieving the offset of
changes in fair values or cash flows attributable to the hedged risk both at the
inception of the contract and on an ongoing basis. The Company measures
effectiveness on a monthly basis. Ineffective portions of a derivative
instrument's change in fair value are immediately recognized in net income
(loss). If there is a discontinuance of a cash flow hedge because it is probable
that the original forecasted transaction will not occur, deferred gains or
losses are recognized in earnings immediately.
From time to time the Company may enter into a combination of futures
contracts, commodity derivatives and fixed-price physical contracts to manage
its exposure to natural gas or oil price volatility. The Company employs a
policy of hedging gas production sold under New York Mercantile Exchange
("NYMEX") based contracts 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, collars or options. At September 30, 2001, the Company's derivative
contracts consist of natural gas swaps and natural gas costless collars. All of
these NYMEX based derivative contracts are designated as cash flow hedges.
Adoption of SFAS 133 resulted in recording a $10.5 million ($6.7 million
net of tax) decline in fair value to accumulated other comprehensive loss,
consisting of $11.8 million to current fair value of derivative liabilities and
$1.3 million to current fair value of derivative assets. The fair value of
derivative assets represent the difference between hedged prices and market
prices on hedged volumes of natural gas as of September 30, 2001. During the
first nine months of 2001, a net loss on contract settlements of $1.0 million
($743,000 after tax) was reclassified from accumulated other comprehensive
income to earnings and the fair value of open hedges increased by $37.5 million
($23.2 million after tax). At September 30, 2001, the estimated net gains in
accumulated other comprehensive income that are expected to be reclassified into
earnings within the next 12 months are approximately $20.6 million. The Company
has partially hedged its exposure to the variability in future cash flows
through December 2003.
(6) INCOME TAX
During the second quarter, the Company concluded an IRS income tax
examination of the years 1994 through 1997. A federal income tax benefit of $1.5
million was recorded during the quarter as a result of the examination. Also, in
the second quarter, a federal income tax benefit was recorded for approximately
$700,000 along with a corresponding reduction in the valuation allowance as a
result of certain net operating loss carryforwards which the Company now
believes it can fully utilize.
(7) 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.
7
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
On March 17, 2000, the Company sold the stock of Peake Energy, Inc.
("Peake"), a wholly owned subsidiary, to 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.
The following table presents certain information with respect to the oil
and gas operations of the Company. The last column in the table excludes Peake:
EXCLUDING PEAKE
---------------
THREE MONTHS ENDED NINE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30,
------------------ ----------------- -----------------
2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
PRODUCTION
Gas (Mmcf) 4,680 4,815 13,713 15,369 13,713 14,215
Oil (Mbbls) 173 144 490 450 490 434
Total production (Mmcfe) 5,717 5,677 16,653 18,071 16,653 16,818
AVERAGE PRICE
Gas (per Mcf) $ 4.03 $ 3.04 $ 4.39 $ 2.84 $ 4.39 $ 2.85
Oil (per Bbl) 23.55 28.70 24.74 26.80 24.74 26.87
Mcfe 4.01 3.31 4.34 3.08 4.34 3.10
AVERAGE COSTS (PER MCFE)
Production expense 1.06 0.92 1.03 0.85 1.03 0.87
Production taxes 0.10 0.10 0.12 0.10 0.12 0.09
Depletion 0.86 0.75 0.79 0.83 0.79 0.84
GROSS MARGIN (PER MCFE) 2.85 2.29 3.19 2.13 3.19 2.14
MMCF - MILLION CUBIC FEET MBBLS - THOUSAND BARRELS
MMCFE - MILLION CUBIC FEET OF NATURAL GAS EQUIVALENT
MCF - THOUSAND CUBIC FEET BBL - BARREL
MCFE - THOUSAND CUBIC FEET OF NATURAL GAS EQUIVALENT
RESULTS OF OPERATIONS - THIRD QUARTERS OF 2001 AND 2000 COMPARED
Operating income increased $2.7 million (54%) from $5.2 million in the
third quarter of 2000 to $7.9 million in the third quarter of 2001. This
increase was primarily a result of a $3.7 million (26%) increase in operating
margins partially offset by a $356,000 increase in exploration expense, a
$247,000 increase in depreciation, depletion and amortization, and $312,000 of
severance and other nonrecurring expense in the third quarter of 2001. The
increase in operating margins was primarily due to a $3.4 million increase in
the operating margin from oil and gas sales primarily due to a $.99 per Mcf
increase in the average price realized for the Company's natural gas. Net income
increased $3.2 million from a net loss of $2.5 million in the third quarter of
2000 to net income of $682,000 in the third quarter of 2001. This increase was
primarily a result of the increase in operating income discussed above, a
$279,000 decrease in interest expense and a $1.4 million (net of tax benefit)
extraordinary loss from the early extinguishment of debt in 2000 offset by a
$1.1 million increase in the provision for income taxes.
8
Earnings before interest expense, income taxes, depreciation, depletion,
amortization, exploration expense and severance and other nonrecurring items
("EBITDAX") increased $3.7 million (28%) from $13.3 million in the third quarter
of 2000 to $17.0 million in the third quarter of 2001 primarily due to the
increased operating margins discussed above.
Total revenues increased $3.7 million (14%) in the third quarter of 2001
compared to the third quarter of 2000 primarily due to a $.99 per Mcf increase
in the average price realized for the Company's natural gas.
Oil volumes increased 29,000 Bbls (20%) from 144,000 Bbls in the third
quarter of 2000 to 173,000 Bbls in the third quarter of 2001 resulting in an
increase in oil sales of approximately $840,000. The increased oil volumes were
primarily due to new wells drilled in 2000 and 2001. Gas volumes decreased 135
Mmcf (3%) from 4.8 Bcf (billion cubic feet) in the third quarter of 2000 to 4.7
Bcf in the third quarter of 2001 resulting in a decrease in gas sales of
approximately $410,000.
The average price paid for the Company's oil decreased from $28.70 per
Bbl in the third quarter of 2000 to $23.55 per Bbl in the third quarter of 2001
which decreased oil sales by approximately $890,000. The average price realized
for the Company's natural gas increased $.99 per Mcf to $4.03 per Mcf in the
third quarter of 2001 compared to the third quarter of 2000 which increased gas
sales in the third quarter of 2001 by approximately $4.6 million. As a result of
the Company's hedging activities, gas sales revenue for the third quarter of
2001 increased by approximately $3.2 million or $.67 per Mcf compared to a
decrease of approximately $4.4 million or $.92 per Mcf for the third quarter of
2000.
Production expense increased $822,000 (16%) from $5.2 million in the
third quarter of 2000 to $6.0 million in the third quarter of 2001. The average
production cost increased from $.92 per Mcfe in the third quarter of 2000 to
$1.06 per Mcfe in the third quarter of 2001 primarily due to additional costs
incurred in the third quarter of 2001 to minimize production declines in order
to take advantage of higher gas prices and general cost increases due to current
market conditions. Production taxes were $583,000 in the third quarter of 2000
compared to $546,000 in the third quarter of 2001.
Exploration expense increased $356,000 (18%) from $1.9 million in the
third quarter of 2000 to $2.3 million in the third quarter of 2001 primarily due
to a $379,000 increase in dry hole expense.
General and administrative expense decreased $144,000 (12%) from $1.2
million in the third quarter of 2000 to $1.1 million in the third quarter of
2001 primarily due to decreases in employment and compensation related expenses.
Depreciation, depletion and amortization increased by $247,000 (4%) from
$6.2 million in the third quarter of 2000 to $6.5 million in the third quarter
of 2001. Depletion expense increased $650,000 (15%) from $4.3 million in the
third quarter of 2000 to $4.9 million in the third quarter of 2001. Depletion
per Mcfe increased from $.75 per Mcfe in the third quarter of 2000 to $.86 per
Mcfe in the third quarter of 2001. These increases were primarily the result of
a higher amortization rate per Mcfe due to lower reserves resulting from lower
oil and gas prices at mid-year 2001, excluding the effect of hedging.
The Company incurred severance and other nonrecurring expense of
$312,000 in the third quarter of 2001 related to employee reduction costs.
9
Interest expense decreased $279,000 (4%) from $7.1 million in the third
quarter of 2000 to approximately $6.8 million in the third quarter of 2001 due
to a decrease in average outstanding borrowings and lower blended interest
rates.
RESULTS OF OPERATIONS - NINE MONTHS OF 2001 AND 2000 COMPARED
Operating income increased $14.0 million from $14.0 million in the first
nine months of 2000 to $28.0 million in the first nine months of 2001. This
increase was primarily a result of a $15.0 million (36%) increase in operating
margins and a $2.8 million (13%) decrease in depreciation, depletion and
amortization expense partially offset by a $1.1 million decrease in other
income, a $1.1 million (22%) increase in exploration expense and the $1.8
million of severance and other nonrecurring expense recorded in the first nine
months of 2001.
The increase in operating margins was primarily due to a $14.6 million
increase in the operating margin from oil and gas sales primarily as a result of
a $1.55 per Mcf increase in the average price realized for the Company's natural
gas. 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 and proceeds received in the second quarter of 2000 from the
settlement of a lawsuit.
Net income increased $3.0 million from $3.5 million in the first nine
months of 2000 to $6.5 million in the first nine months of 2001. Gain on sale of
subsidiary and other income in the first nine months of 2000 was $14.5 million
as discussed below. Significant changes in the first nine months of 2001
compared to the first nine months of 2000 were the $14.0 million increase in
operating income discussed above, a $1.2 million decrease in interest expense,
favorable adjustments to income tax expense in the second quarter of 2001 (see
Note 6 to the Consolidated Financial Statements) and a $1.4 million (net of tax
benefit) extraordinary loss from the early extinguishment of debt in the first
nine months of 2000.
EBITDAX increased $14.1 million (35%) from $40.4 million in the first
nine months of 2000 to $54.5 million in the first nine months of 2001. This
increase was primarily due to the $15.0 million increase in operating margins
offset by the decrease in other income discussed above.
Total revenues increased $15.9 million (19%) in the first nine months of
2001 compared to the first nine months of 2000 primarily due to a $1.55 per Mcf
increase in the average price realized for the Company's natural gas, an
increase in the volume of oil sold and an increase in oilfield service revenue
partially offset by a decrease in the volume of natural gas sold, a decrease in
the price paid for the Company's oil and the decrease in other income discussed
above.
Oil volumes increased approximately 40,000 Bbls (9%) from 450,000 Bbls
in the first nine months of 2000 to 490,000 Bbls in the first nine months of
2001 resulting in an increase in oil sales of approximately $1.1 million. Gas
volumes decreased 1.7 Bcf (11%) from 15.4 Bcf in the first nine months of 2000
to 13.7 Bcf in the first nine months of 2001 resulting in a decrease in gas
sales of approximately $4.7 million. These volume decreases were due to the sale
of Peake in the first quarter of 2000 and the natural production decline of the
wells partially offset by production from wells drilled in 2000 and 2001.
The average price paid for the Company's oil decreased from $26.80 per
Bbl in the first nine months of 2000 to $24.74 per Bbl in the first nine months
of 2001 which decreased oil sales by approximately $1.0 million. The average
price realized for the Company's natural gas increased $1.55 per Mcf (55%) to
$4.39 per Mcf in the first nine months of 2001 compared to the first nine months
of 2000 which increased gas sales in the first nine months of 2001 by
approximately $21.3 million. As a
10
result of the Company's hedging activities, gas sales revenue for the first nine
months of 2001 decreased by approximately $1.0 million or $.07 per Mcf compared
to a decrease of approximately $7.3 million or $.47 per Mcf for the first nine
months of 2000.
Production expense increased approximately $1.9 million (13%) from $15.3
million in the first nine months of 2000 to $17.2 million in the first nine
months of 2001. The average production cost increased from $.85 per Mcfe in the
first nine months of 2000 to $1.03 per Mcfe in the first nine months of 2001.
The per unit increase was primarily due to the sale of Peake, increased
compensation related expenses, additional costs incurred in the first nine
months of 2001 to minimize production declines in order to take advantage of
higher gas prices and general cost increases due to current market conditions.
Production taxes increased $117,000 (6%) from $1.9 million in the first nine
months of 2000 to $2.0 million in the first nine months of 2001 primarily due to
higher natural gas prices in 2001 partially offset by decreased production taxes
from lower oil and gas sales due to the sale of Peake.
Exploration expense increased by $1.1 million (22%) from $4.9 million in
the first nine months of 2000 to $6.0 million in the first nine months of 2001
primarily due to increases in leasing activity and geophysical expenses
associated with the Company's planned drilling activity in 2001 and 2002. The
Company currently expects to spend $26 million to drill 175 gross (152.4 net)
wells in 2001.
General and administrative expense in the first nine months of 2001 was
consistent with the first nine months of 2000.
Depreciation, depletion and amortization decreased by $2.8 million (13%)
from $21.5 million in the first nine months of 2000 to $18.7 million in the
first nine months of 2001. Depletion expense decreased $1.8 million (12%) from
$15.0 million in the first nine months of 2000 to $13.2 million in the first
nine months of 2001. Depletion per Mcfe decreased from $.83 per Mcfe in the
first nine months of 2000 to $.79 per Mcfe in the first nine months of 2001.
These decreases were primarily the result of decreased production volumes due to
the sale of Peake and a lower amortization rate per Mcfe due to higher reserves
resulting from higher oil and gas prices at year-end 2000.
The Company recorded a nonrecurring charge of $1.8 million in the first
nine months of 2001 primarily related to the early retirement of certain senior
management members of the Company and other severance charges incurred which
included a non-cash charge of approximately $200,000 due to the acceleration of
certain related stock options. The Company expects to reduce its forecasted
future general and administrative expenses by over $500,000 annually as a result
of the retirements.
Gain on sale of subsidiary and other income in the first nine months of
2000 was the result of the $13.2 million gain on the sale of Peake and the $1.3
million gain on terminated interest rate swaps.
Interest expense decreased approximately $1.2 million (6%) from $22.1
million in the first nine months of 2000 to $20.9 million in the first nine
months of 2001 due to a decrease in average outstanding borrowings partially
offset by higher blended interest rates.
11
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, 2001 was 1.17 to 1. During
the first nine months of 2001, working capital increased $1.7 million from $4.2
million at December 31, 2000 to $5.9 million at September 30, 2001. The increase
was primarily due to an increase in the fair value of derivatives in the first
nine months of 2001 which increased working capital by $20.6 million, net of a
related increase in current deferred taxes of $8.1 million. This increase was
offset by a $7.9 million decrease in accounts receivable and a $3.7 million
increase in accrued expenses. The Company's operating activities provided cash
flows of $42.6 million during the first nine months of 2001.
On June 29, 2001, the Company amended its $100 million credit facility
from Ableco Finance LLC and Foothill Capital Corporation. The amendment extended
the Revolver's final maturity date to April 22, 2004, from August 23, 2002,
increased the letter of credit sub-limit from $20 million to $30 million and
eliminated the effects of SFAS 133 from covenant calculations. The Company paid
approximately $200,000 in fees and expenses related to the amendment.
The amendment extended the financial covenant for the senior interest
coverage ratio of 3.2 to 1 for the quarters ending September 30, 2002, through
March 31, 2004; and the senior debt leverage ratio of 2.7 to 1 was extended for
the quarters ending September 30, 2002, through March 31, 2004. These ratios
will be calculated quarterly based on the financial results of the previous four
quarters.
The amendment added an early termination fee equal to .25% of the
facility if terminated between the effective date and May 31, 2002. If
termination is after May 31, 2002 but on or before May 31, 2003, the termination
fee is .125% of the facility. There is no termination fee after May 31, 2003.
The Company is required to hedge at least 20% but not more than 80% of its
estimated hydrocarbon production, on an Mcfe basis, for the succeeding 12 months
on a rolling 12 month basis. Based on the Company's hedges currently in place
and its expected production levels, the Company is in compliance with this
hedging requirement through June 2003.
The Revolver bears interest at the prime rate plus two percentage
points, payable monthly. At September 30, 2001 the interest rate was 8.00%. At
September 30, 2001, the Company had $2.3 million of outstanding letters of
credit. At September 30, 2001, the outstanding balance under the credit
agreement was $55.1 million with $42.6 million of borrowing capacity available
for general corporate purposes.
The Revolver 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 $100 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, 2001, under the borrowing base formula above was approximately
$201 million for all proved reserves of the Company and $152 million for
properties secured by a mortgage.
12
The Revolver is subject to certain financial covenants. These include a
senior debt interest coverage ratio ranging from 4.0 to 1 at September 30, 2001,
to 3.2 to 1 at March 31, 2004; and a senior debt leverage ratio ranging from 2.6
to 1 and 3.2 to 1 for the periods from September 30, 2001, through March 31,
2004. EBITDA, as defined in the Revolver, and consolidated interest expense on
senior debt in these ratios are calculated quarterly based on the financial
results of the trailing four quarters. In addition, the Company is required to
maintain a current ratio (including available borrowing capacity in current
assets, excluding current debt and accrued interest from current liabilities and
excluding any effects from the application of SFAS 133 to other current assets
or 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, 2001, the Company's current ratio including the above
adjustments was 2.25 to 1. The Company has satisfied all financial covenants as
of September 30, 2001.
From time to time the Company may enter into interest rate swaps to
hedge the interest rate exposure associated with the credit facility, whereby a
portion of the Company's floating rate exposure is exchanged for a fixed
interest rate. At September 30, 2000, the Company had swap arrangements, which
expired in October 2000, covering $40 million of debt. The Company's interest
expense was reduced by $123,000 in the first nine months of 2000 due to interest
rate swaps. There were no interest rate swaps open in the first nine months of
2001.
During the first nine months of 2001, the Company invested $21.7 million
to drill 140 development wells and 9 exploratory wells. Of these wells, 131
development wells and 3 exploratory wells were successfully completed as
producers, for a completion success rate of 94% and 33%, respectively (an
overall success rate of 90%). In addition, $2.1 million was invested in proved
reserve acquisitions.
The Company currently expects to spend approximately $41 million during
2001 on its drilling activities, acquisitions and other capital expenditures.
The Company intends to finance its planned capital expenditures through its
available cash flow, available borrowing capacity under the Revolver and the
sale of non strategic assets. At September 30, 2001, the Company had
approximately $42.6 million available under the Revolver. The level of the
Company's future cash flow 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 or oil price volatility, the
Company may partially hedge its physical gas or oil sales prices by selling
futures contracts on the 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, collars or options. The Company had pretax losses on its
hedging activities of $1.0 million and $7.3 million in the first nine months of
2001 and 2000, respectively.
13
The Company's financial results and cash flows can be significantly
impacted as commodity prices fluctuate widely in response to changing market
conditions. Accordingly, the Company may modify its fixed price contract and
financial hedging positions by entering into new transactions or terminating
existing contracts. The following table reflects the natural gas volumes and the
weighted average prices under financial hedges (including settled hedges), fixed
price contracts and costless collars at September 30, 2001:
NATURAL GAS SWAPS FIXED PRICE CONTRACTS
------------------------------------------- ----------------------------
ESTIMATED ESTIMATED
NYMEX PRICE WELLHEAD ESTIMATED WELLHEAD
QUARTER ENDING BBTU PER MMBTU PRICE PER MCF MMCF PRICE PER MCF
- -------------- ---- --------- ------------- ---- -------------
December 31, 2001 2,400 $ 4.77 $ 4.99 1,000 $ 4.42
======= ====== ====== ====== ======
March 31, 2002 2,550 $ 4.95 $ 5.20 1,050 $ 4.57
June 30, 2002 2,550 4.61 4.76 780 4.25
September 30, 2002 2,550 4.61 4.76 630 4.30
December 31, 2002 2,550 4.63 4.84 560 4.45
------- ------ ------ ------ ------
10,200 $ 4.70 $ 4.89 3,020 $ 4.41
======= ====== ====== ====== ======
March 31, 2003 960 $ 3.79 $ 4.04 65 $ 2.50
June 30, 2003 960 3.79 3.94 65 2.50
September 30, 2003 960 3.79 3.94 65 2.50
December 31, 2003 960 3.79 3.99 65 2.50
------- ------ ------ ------ ------
3,840 $ 3.79 $ 3.98 260 $ 2.50
======= ====== ====== ====== ======
NATURAL GAS COLLARS
--------------------------------------------
NYMEX PRICE ESTIMATED
PER MMBTU WELLHEAD
QUARTER ENDING BBTU FLOOR/CAP PRICE PER MCF
- -------------- ------- ------------ -------------
March 31, 2003 1,650 $3.40 - 5.23 $ 3.60 - 5.43
June 30, 2003 1,650 3.40 - 5.23 3.60 - 5.43
September 30, 2003 1,650 3.40 - 5.23 3.60 - 5.43
December 31, 2003 1,650 3.40 - 5.23 3.60 - 5.43
------- ------------ -------------
6,600 $3.40 - 5.23 $ 3.60 - 5.43
======= ============ =============
BBTU - BILLION BRITISH THERMAL UNITS MMCF - MILLION CUBIC FEET
MMBTU - MILLION BRITISH THERMAL UNITS MCF - THOUSAND CUBIC FEET
At September 30, 2001, the natural gas swaps and collars above
represented approximately $28.0 million in unrealized gains.
14
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.
- -------------------------------------------------------------------------------
PART II OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
(b) Reports on Form 8-K
On July 5, 2001, the Company filed a Current Report on Form 8-K dated
June 29, 2001 related to the amendment of the Company's revolving credit
facility and Regulation FD disclosures.
On July 11, 2001, the Company filed a Current Report on Form 8-K dated
June 29, 2001 related to an exploration agreement and joint operating agreement.
On August 9, 2001, the Company filed a Current Report on Form 8-K dated
August 8, 2001 related to Regulation FD disclosures.
On September 19, 2001, the Company filed a Current Report on Form 8-K
dated September 12, 2001 related to the resignation of certain directors.
15
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 12, 2001 By: /s/ John L. Schwager
----------------- --------------------------------------
John L. Schwager, Director, President
and Chief Executive Officer
Date: November 12, 2001 By: /s/ Robert W. Peshek
----------------- ---------------------------------------
Robert W. Peshek, Vice President
and Chief Financial Officer
16