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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, 2002
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
- ------------------------------- ---------------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
5200 Stoneham Road
North Canton, Ohio 44720
- ------------------------------- ---------------------------
(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, 2002, Belden & Blake Corporation had outstanding
10,332,794 shares of common stock, without par value, which is its only class of
stock.
BELDEN & BLAKE CORPORATION
INDEX
PAGE
----
PART I Financial Information:
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2002 and
December 31, 2001..................................................... 1
Consolidated Statements of Operations for the three and nine
months ended September 30, 2002 and 2001 ............................. 2
Consolidated Statements of Shareholders' Equity
(Deficit) for the nine months ended September
30, 2002 and the years ended
December 31, 2001 and 2000............................................ 3
Consolidated Statements of Cash Flows for the nine
months ended September 30, 2002 and 2001 ............................. 4
Notes to Consolidated Financial Statements................................ 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations................................... 9
Item 3. Quantitative and Qualitative Disclosures About Market Risk................ 19
Item 4. Controls and Procedures................................................... 20
PART II Other Information
Item 6. Exhibits and Reports on Form 8-K......................................... 21
BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
SEPTEMBER 30, DECEMBER 31,
2002 2001
--------- ---------
(UNAUDITED)
ASSETS
- ------
CURRENT ASSETS
Cash and cash equivalents $ 1,738 $ 1,935
Accounts receivable, net 13,435 14,160
Inventories 993 1,695
Other current assets 1,847 1,094
Derivative fair value 1,103 19,965
--------- ---------
TOTAL CURRENT ASSETS 19,116 38,849
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties (successful efforts method) 463,784 446,977
Gas gathering systems 14,537 14,094
Land, buildings, machinery and equipment 24,739 24,113
--------- ---------
503,060 485,184
Less accumulated depreciation, depletion and amortization 248,891 233,396
--------- ---------
PROPERTY AND EQUIPMENT, NET 254,169 251,788
DERIVATIVE FAIR VALUE 614 3,748
OTHER ASSETS 9,051 10,964
--------- ---------
$ 282,950 $ 305,349
========= =========
LIABILITIES AND SHAREHOLDERS' DEFICIT
- -------------------------------------
CURRENT LIABILITIES
Accounts payable $ 4,997 $ 5,253
Accrued expenses 24,568 14,465
Current portion of long-term liabilities 334 156
Derivative fair value 2,343 --
Deferred income taxes 59 5,470
--------- ---------
TOTAL CURRENT LIABILITIES 32,301 25,344
LONG-TERM LIABILITIES
Bank and other long-term debt 33,163 59,415
Senior subordinated notes 225,000 225,000
Other 116 330
--------- ---------
258,279 284,745
DERIVATIVE FAIR VALUE 1,445 --
DEFERRED INCOME TAXES 24,550 22,539
SHAREHOLDERS' DEFICIT
Common stock without par value; $.10 stated value per share; authorized
58,000,000 shares; issued 10,490,440 and 10,425,103 shares
(which includes 155,126 and 135,369 treasury shares, respectively) 1,034 1,029
Paid in capital 107,461 107,402
Deficit (145,630) (150,797)
Accumulated other comprehensive income 3,510 15,087
--------- ---------
TOTAL SHAREHOLDERS' DEFICIT (33,625) (27,279)
--------- ---------
$ 282,950 $ 305,349
========= =========
See accompanying notes.
1
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS)
(UNAUDITED)
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
-------------------------- -------------------------
2002 2001 2002 2001
-------- -------- -------- --------
REVENUES
Oil and gas sales $ 23,645 $ 22,952 $ 71,334 $ 72,293
Gas gathering, marketing and oilfield service 7,474 7,421 24,192 25,652
Other 546 533 2,136 1,431
-------- -------- -------- --------
31,665 30,906 97,662 99,376
EXPENSES
Production expense 5,125 6,043 15,666 17,209
Production taxes 403 546 1,373 1,982
Gas gathering, marketing and oilfield service 6,695 6,081 20,831 22,176
Exploration expense 4,242 2,296 10,107 5,956
General and administrative expense 1,065 1,099 3,441 3,261
Franchise, property and other taxes 135 93 290 297
Depreciation, depletion and amortization 5,832 6,489 18,341 18,666
Derivative fair value (gain) loss (64) -- 134 --
Severance and other nonrecurring expense 127 312 292 1,813
-------- -------- -------- --------
23,560 22,959 70,475 71,360
-------- -------- -------- --------
OPERATING INCOME 8,105 7,947 27,187 28,016
OTHER (INCOME) EXPENSE
Interest expense 6,253 6,819 18,749 20,866
-------- -------- -------- --------
INCOME BEFORE INCOME TAXES 1,852 1,128 8,438 7,150
Provision for income taxes 709 446 3,271 614
-------- -------- -------- --------
NET INCOME $ 1,143 $ 682 $ 5,167 $ 6,536
======== ======== ======== ========
See accompanying notes.
2
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (DEFICIT)
(IN THOUSANDS)
ACCUMULATED
OTHER TOTAL
COMMON COMMON PAID IN COMPREHENSIVE EQUITY
SHARES STOCK CAPITAL DEFICIT INCOME (DEFICIT)
--------- --------- --------- --------- --------- ----------
JANUARY 1, 2000 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 6,467 6,467
Other comprehensive income, net of tax:
Cumulative effect of accounting change (6,691) (6,691)
Change in derivative fair value 24,667 24,667
Reclassification adjustment for derivative
(gain) loss reclassified into oil and gas sales (2,889) (2,889)
--------
Total comprehensive income 21,554
--------
Stock options exercised 68 7 (1) 6
Stock-based compensation 275 275
Repurchase of stock options (772) (772)
Tax benefit of repurchase of stock options
and stock options exercised 260 260
Treasury stock (81) (8) (281) (289)
- ------------------------------------------------- --------- --------- --------- --------- --------- ----------
DECEMBER 31, 2001 10,290 1,029 107,402 (150,797) 15,087 (27,279)
Comprehensive income:
Net income 5,167 5,167
Other comprehensive income, net of tax:
Change in derivative fair value (434) (434)
Reclassification adjustment for derivative
(gain) loss reclassified into oil
and gas sales (11,143) (11,143)
--------
Total comprehensive income (6,410)
--------
Stock options exercised 65 7 (2) 5
Stock-based compensation 62 62
Repurchase of stock options (13) (13)
Tax benefit of repurchase of stock options
and stock options exercised 51 51
Treasury stock (20) (2) (39) (41)
- ------------------------------------------------- --------- --------- --------- --------- --------- ----------
SEPTEMBER 30, 2002 (UNAUDITED) 10,335 $ 1,034 $ 107,461 $(145,630) $ 3,510 $ (33,625)
================================================= ========= ========= ========= ========= ========= =========
See accompanying notes.
3
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(IN THOUSANDS)
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------
2002 2001
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 5,167 $ 6,536
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 18,341 18,666
Loss on disposal of property and equipment 613 142
Net monetization of derivatives 22,091 --
Amortization of derivatives and other non-cash
hedging adjustments (14,524) --
Exploration expense 10,107 5,956
Deferred income taxes 3,271 521
Stock-based compensation 62 379
Change in operating assets and liabilities, net of
effects of acquisition and disposition of
businesses:
Accounts receivable and other operating assets (41) 7,371
Inventories 294 107
Accounts payable and accrued expenses 10,086 2,939
--------- ---------
NET CASH PROVIDED BY OPERATING ACTIVITIES 55,467 42,617
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of businesses, net of cash acquired (2,835) (2,130)
Disposition of businesses 8,161 400
Proceeds from property and equipment disposals 1,497 1,162
Exploration expense (10,107) (5,956)
Additions to property and equipment (26,508) (28,826)
Decrease (increase) in other assets 749 (72)
--------- ---------
NET CASH USED IN INVESTING ACTIVITIES (29,043) (35,422)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving line of credit 107,960 137,921
Repayment of long-term debt and other obligations (134,451) (144,367)
Debt issue costs (81) (210)
Proceeds from stock options exercised 5 6
Repurchase of stock options (13) (670)
Purchase of treasury stock (41) (169)
--------- ---------
NET CASH USED IN FINANCING ACTIVITIES (26,621) (7,489)
--------- ---------
NET DECREASE IN CASH AND CASH EQUIVALENTS (197) (294)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 1,935 1,798
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 1,738 $ 1,504
========= =========
CASH PAID DURING THE PERIOD FOR:
Interest $ 13,331 $ 15,530
Income taxes, net of refunds 8 359
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Acquisition of assets in exchange for long-term liabilities 263 443
See accompanying notes.
4
BELDEN & BLAKE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
SEPTEMBER 30, 2002
- --------------------------------------------------------------------------------
(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, 2002
are not necessarily indicative of the results that may be expected for the year
ended December 31, 2002. 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, 2001. Certain reclassifications have
been made to conform to the current presentation.
(2) NEW ACCOUNTING PRONOUNCEMENTS
On January 1, 2002, the Company adopted Statement of Financial Accounting
Standards No. (SFAS) 142, "Goodwill and Other Intangible Assets" which was
issued in June 2001 by the Financial Accounting Standards Board (FASB). 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. Separately identifiable 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).
At December 31, 2001, the Company had $2.7 million of unamortized goodwill
which was subject to the transition provisions of SFAS 142. Amortization expense
related to goodwill amounted to $130,000 and $132,000 for the years ended
December 31, 2001 and 2000, respectively. The Company assessed the impact of
SFAS 142 and has determined that adoption of SFAS 142 did not have a material
effect on the Company's financial position, results of operations or cash flows,
including any transitional impairment losses.
In June 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 the Company's financial statements
beginning January 1, 2003. This statement would require the Company to recognize
a liability for the fair value of its plugging and abandoning liability
(excluding salvage value) with the associated costs included as part of the
Company's oil and gas properties balance. Due to the significant number of
producing oil and gas properties operated by the Company, and the number of
documents that must be reviewed and estimates that must be made to assess the
effects of SFAS 143, it has not yet been determined whether adoption of SFAS 143
will have a material effect on the Company's financial position, results of
operations or cash flows.
In August 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 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
5
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
supersede the provisions of Accounting Principles Board Opinion No. (APB) 30,
"Reporting Results of Operations - Reporting the Effects of Disposal of a
Segment of Business," with regard to reporting the effects of a disposal of a
segment of a business and 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 previously required by APB 30. In addition, more dispositions may qualify for
discontinued operations treatment in the income statement. SFAS 144 was
effective as of January 1, 2002. The adoption of this standard did not have a
material effect on the Company's financial position, results of operations or
cash flows.
In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from
Extinguishment of Debt," SFAS 44, "Accounting for Intangible Assets of Motor
Carriers" and SFAS 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund
Requirements" and amends SFAS No. 13, "Accounting for Leases". Statement 145
also makes technical corrections to other existing pronouncements. SFAS 4
required gains and losses from extinguishment of debt to be classified as an
extraordinary item, net of the related income tax effect. As a result of the
rescission of SFAS 4, the criteria for extraordinary items in APB Opinion No.
30, "Reporting the Results of Operations - Reporting the Effects of Disposal of
a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions," now will be used to classify those gains and losses.
SFAS 145 is effective for the Company's financial statements beginning January
1, 2003. The adoption of SFAS 145 is not expected to have a material effect on
the Company's financial position, results of operations or cash flows.
In July 2002, the FASB issued SFAS 146, "Accounting for Costs Associated
with Exit or Disposal Activities." SFAS 146 will be effective for the Company
for disposal activities initiated after December 31, 2002. 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) DERIVATIVES AND HEDGING
The Company recognizes all derivative financial instruments as either
assets or liabilities at fair value. The changes in fair value of derivative
instruments not qualifying for designation as cash flow hedges that occur prior
to maturity are initially reported in expense in the consolidated statements of
operations as derivative fair value (gain) loss. All amounts recorded in this
line item are ultimately reversed within the same line item and included in oil
and gas sales revenues over the respective contract terms. 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 at least on a
quarterly 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.
6
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 and support the Company's
capital expenditure plans. 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, 2002, the Company's derivative contracts were comprised of natural
gas swaps and natural gas collars. Qualifying NYMEX based derivative contracts
are designated as cash flow hedges.
During the first nine months of 2002 and 2001, a net gain of $17.5 million
($11.1 million after tax) and a net loss of $1.0 million ($743,000 after tax),
respectively, were reclassified from accumulated other comprehensive income to
earnings. The fair value of open hedges decreased $682,000 ($434,000 after tax)
in the first nine months of 2002 and increased $37.5 million ($23.2 million
after tax) in the first nine months of 2001. At September 30, 2002, the
estimated net gain in accumulated other comprehensive income that is expected to
be reclassified into earnings within the next 12 months is approximately $5.8
million. The Company has partially hedged its exposure to the variability in
future cash flows through March 2005.
On January 17 and 18, 2002, the Company monetized 9,350 Bbtu (billion
British thermal units) of its 2002 natural gas hedge position at a weighted
average NYMEX price of $2.53 per Mmbtu (million British thermal units) and 3,840
Bbtu of its 2003 natural gas hedge position at a NYMEX price of $3.01 per Mmbtu.
The Company received net proceeds of $22.7 million that are recognized as
increases to natural gas sales revenues during the same periods in which the
underlying forecasted transactions are recognized in net income (loss).
In January 2002, the Company entered into a collar for 9,350 Bbtu of its
natural gas production in 2002 with a ceiling price of $4.00 per Mmbtu and a
floor price of $2.25 per Mmbtu which qualified and was designated as a cash flow
hedge under SFAS 133. The Company also sold a floor at $1.75 per Mmbtu on this
volume of gas which was designated as a non-qualifying cash flow hedge under
SFAS 133. The changes in fair value of the $1.75 floor will be initially
reported in expense in the consolidated statements of operations as derivative
fair value (gain) loss and will ultimately be reversed within the same line item
and included in oil and gas sales over the respective contract terms.
This aggregate structure has the effect of: 1) setting a maximum price of
$4.00 per Mmbtu; 2) floating at prices from $2.25 to $4.00 per Mmbtu; 3) locking
in a price of $2.25 per Mmbtu if prices are between $1.75 and $2.25 per Mmbtu;
and 4) receiving a price of $0.50 per Mmbtu above the price if the price is
$1.75 or less. All prices are based on monthly NYMEX settle. The Company paid
$1.0 million for the options. The Company used the net proceeds of $21.7 million
from the two transactions above to pay down on its credit facility.
From August 30, 2002 through September 20, 2002, the Company placed
additional hedge positions covering 16,860 Bbtu of its natural gas production
for the period from October 2002 through March 2005. The hedges are in the form
of swaps based on a NYMEX equivalent weighted average price of $3.88 per Mmbtu.
7
The following table summarizes, as of September 30, 2002, the Company's
net deferred gains on terminated natural gas hedges. Cash has been received and
the deferred gains recorded in accumulated other comprehensive income. The
deferred gains are recognized as increases to gas sales revenues during the
periods in which the underlying forecasted transactions are recognized in net
income (loss).
2002 2003
-------------------------------------------- -------
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
------- ------- ------- -------
(IN THOUSANDS)
Deferred Gains $ 4,521 $ 5,599 $ 5,495 $ 4,631 $ 2,851
(4) ACQUISITIONS
On July 11, 2002, the Company acquired 77 gross (71.7 net) wells located
in Ohio and Pennsylvania with net reserves totaling 4.2 Bcfe (billion cubic feet
of natural gas equivalent) for a cash payment of $1.2 million.
(5) DISPOSITIONS
On August 1, 2002, the Company sold oil and gas properties consisting of
1,138 wells in Ohio. The properties had reserves of approximately 12 Bcfe. The
proceeds of approximately $8.0 million were used to pay down the Company's
revolving credit facility.
On September 5, 2002, the Company completed the sale of three natural gas
compressors in Michigan to a compression services company. The proceeds of
approximately $1.2 million were used to pay down the Company's revolving credit
facility. The Company also entered into an agreement to leaseback the
compressors from the compression services company, which will provide full
compression services including maintenance and repair on these and other
compressors. Certain compressors will also be relocated to maximize compression
efficiency. The Company plans to sell and leaseback additional compression units
during the fourth quarter.
(6) CREDIT AGREEMENT
On July 25, 2002, the Company amended its $100 million revolving credit
facility ("the Revolver"). The amendment extended the Revolver's final maturity
date to April 22, 2005, from April 22, 2004 and permitted the Company to enter
into the transaction to sell, transfer and assign oil and gas properties
consisting of 1,138 wells in Ohio. The Revolver, as amended, is subject to
certain financial covenants. These include a quarterly senior debt interest
coverage ratio of 3.2 to 1 through March 31, 2005; and a senior debt leverage
ratio of 2.7 to 1 through March 31, 2005. The amendment extended the early
termination fee, equal to .125% of the Revolver, through November 30, 2003.
There is no termination fee after November 30, 2003.
(7) SETTLEMENT AGREEMENT
In April 2002, the Company and one of its gas purchasers signed a
settlement agreement resolving gas measurement disputes related to a gathering
system in New York. Under the terms of the agreement, the Company received a
cash payment to settle all issues associated with gas measurement disputes prior
to December 31, 2001. The agreement also amended a prior agreement that governed
the measurement of the Company's gas supply delivered into the purchaser's
distribution system. The Company's net share of the settlement amount, $591,000,
was recorded in the second quarter of 2002 as other revenue.
8
(8) COMMITMENTS AND CONTINGENCIES
In April 2002, the Company was notified of a claim by an overriding
royalty interest owner in Michigan alleging the underpayment of royalty
resulting from disputes as to the interpretation of the terms of several farmout
agreements. The Company believes the claim is without merit and will vigorously
defend its position. The Company believes that the result of this issue will not
have a material adverse effect on its financial position, results of operation
or cash flows.
(9) 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 marketing and gathering natural gas for
delivery to intrastate and interstate gas transmission pipelines. The Company's
operations are conducted entirely in the United States.
(10) SUBSEQUENT EVENTS
On October 10, 2002, the Company combined its Pennsylvania/New York
District with its Ohio District to form a new "Appalachian District". A total of
28 positions were eliminated in the Ohio and Pennsylvania/New York Districts and
in the corporate office. These actions were necessary to capitalize on
operational and administrative efficiencies and bring the Company's employment
level in line with current and anticipated future staffing. The Company expects
to record a nonrecurring charge of approximately $700,000 in the fourth quarter
of 2002 related to severance and other costs associated with these actions. The
Company expects to reduce its future expenses by approximately $1.7 million
annually beginning in the fourth quarter of 2002 as a result of the combined
district and staff reductions.
Subsequent to September 30, 2002, the Company has classified $18 million
of oil and gas properties and acreage as assets held-for-sale in property and
equipment.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
FORWARD-LOOKING INFORMATION
The information in this document includes forward-looking statements that
are made pursuant to Safe Harbor Provisions of the Private Securities Litigation
Reform Act of 1995. Statements preceded by, followed by or that otherwise
include the statements "should," "believe," "expect," "anticipate," "intend,"
"will," "continue," "estimate," "plan," "outlook," "may," "future,"
"projection," variations of these statements and similar expressions are
forward-looking statements. These forward-looking statements are based on
current expectations and projections about future events. Forward-looking
statements, and the business prospects of the Company are subject to a number of
risks and uncertainties which may cause the Company's actual results in future
periods to differ materially from the forward-looking statements contained
herein. These risks and uncertainties include, but are not limited to, the
Company's access to capital, the market demand for and prices of oil and natural
gas, the Company's oil and gas production and costs of operation, results of the
Company's future drilling activities, the uncertainties of reserve estimates,
general economic conditions, new legislation or regulatory changes, changes in
accounting principles, policies or guidelines and environmental risks. These and
other risks are described in the Company's 10-K and 10-Q reports and other
filings with the Securities and Exchange Commission ("SEC").
CRITICAL ACCOUNTING POLICIES
The Company prepares its consolidated financial statements in accordance
with accounting principles generally accepted in the United States ("GAAP") and
SEC guidance. See the "Notes to
9
Consolidated Financial Statements" included in "Item 8. Financial Statements and
Supplementary Data" in the Company's 2001 Form 10-K annual report filed with the
SEC for a comprehensive discussion of the Company's significant accounting
policies. GAAP requires information in financial statements about the accounting
principles and methods used and the risks and uncertainties inherent in
significant estimates including choices between acceptable methods. Following is
a discussion of the Company's most critical accounting policies:
SUCCESSFUL EFFORTS METHOD OF ACCOUNTING
The accounting for and disclosure of oil and gas producing activities
requires the Company's management to choose between GAAP alternatives and to
make judgments about estimates of future uncertainties.
The Company utilizes the "successful efforts" method of accounting for oil
and gas producing activities as opposed to the alternate acceptable "full cost"
method. Under the successful efforts method, property acquisition and
development costs and certain productive exploration costs are capitalized while
non-productive exploration costs, which include certain geological and
geophysical costs, exploratory dry hole costs and costs of carrying and
retaining unproved properties, are expensed as incurred.
The major difference between the successful efforts method of accounting
and the full cost method is under the full cost method of accounting, these
non-productive exploration costs and expenses are capitalized as assets, pooled
with the costs of successful wells and charged against the net income (loss) of
future periods as a component of depletion expense.
OIL AND GAS RESERVES
The Company's proved developed and proved undeveloped reserves are all
located within the Appalachian and Michigan Basins in the United States. 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. In addition, estimates of new discoveries are more
imprecise than those of properties with a production history. Accordingly, these
estimates are expected to change as future information becomes available.
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
assumptions used. Proved reserves represent estimated quantities of natural gas
and oil 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.
Proved developed reserves are proved reserves expected to be recovered through
wells and equipment in place and under operating methods being utilized at the
time the estimates were made. The accuracy of a reserve estimate is a function
of:
-- the quality and quantity of available data;
-- the interpretation of that data;
-- the accuracy of various mandated economic assumptions; and
-- the judgment of the persons preparing the estimate.
The Company's proved reserve information is based on estimates it
prepared. Estimates prepared by others may be higher or lower than the Company's
estimates. The Company's estimates of proved reserves have been reviewed by
independent petroleum engineers.
10
CAPITALIZATION, DEPRECIATION, DEPLETION AND IMPAIRMENT OF LONG-LIVED ASSETS
See the "Successful Efforts Method of Accounting" discussion above.
Capitalized costs related to proved properties are depleted using the
unit-of-production method. Depreciation, depletion and amortization of proved
oil and gas properties is calculated on the basis of estimated recoverable
reserve quantities. These estimates can change based on economic or other
factors. No gains or losses are recognized upon the disposition of oil and gas
properties except in extraordinary transactions. Sales proceeds are credited to
the carrying value of the properties. Maintenance and repairs are expensed, and
expenditures which enhance the value of properties are capitalized.
Unproved oil and gas properties are stated at cost and consist of
undeveloped leases. These costs are assessed periodically to determine whether
their value has been impaired, and if impairment is indicated, the costs are
charged to expense.
Gas gathering systems are stated at cost. Depreciation expense is computed
using the straight-line method over 15 years.
Property and equipment are stated at cost. Depreciation of non-oil and gas
properties is computed using the straight-line method over the useful lives of
the assets ranging from 3 to 15 years for machinery and equipment and 30 to 40
years for buildings. When assets other than oil and gas properties are retired
or otherwise disposed of, the cost and related accumulated depreciation are
removed from the accounts, and any resulting gain or loss is reflected in income
for the period. The cost of maintenance and repairs is expensed as incurred, and
significant renewals and betterments are capitalized.
Long-lived assets are reviewed for impairment whenever events or changes
in circumstances indicate that the carrying amount may not be recoverable. If
the sum of the expected future undiscounted cash flows is less than the carrying
amount of the asset, a loss is recognized for the difference between the fair
value and the carrying amount of the asset. Fair value is based on management's
outlook of future oil and natural gas prices and estimated future cash flows to
be generated by the assets, discounted at a market rate of interest.
DERIVATIVES AND HEDGING
The Company recognizes all derivative financial instruments as either
assets or liabilities at fair value. The changes in fair value of derivative
instruments not qualifying for designation as cash flow hedges that occur prior
to maturity are initially reported in expense in the consolidated statements of
operations as derivative fair value (gain) loss. All amounts recorded in this
line item are ultimately reversed within the same line item and included in oil
and gas sales revenues over the respective contract terms. 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 at least on a
quarterly 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.
11
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 and support the Company's
capital expenditure plans. The Company employs a policy of hedging gas
production sold under 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. Qualifying NYMEX based derivative
contracts are designated as cash flow hedges.
REVENUE RECOGNITION
Oil and gas production revenue is recognized as production and delivery
take place. Oil and gas marketing revenues are recognized when title passes.
Oilfield service revenues are recognized when services have been provided.
DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures are controls and other procedures of
the Company that are designed to ensure that information required to be
disclosed by the Company in the reports filed or submitted by the Company under
the Securities Exchange Act of 1934 ("Exchange Act") is recorded, processed,
summarized and reported, within the time periods specified in the SEC's rules
and forms. Disclosure controls and procedures include, without limitation,
controls and procedures designed to ensure that information required to be
disclosed by the Company in its Exchange Act reports is accumulated and
communicated to the Company's management, including its principal executive and
financial officers, as appropriate to allow timely decisions regarding required
disclosures.
NEW ACCOUNTING PRONOUNCEMENTS
On January 1, 2002, the Company adopted SFAS 142, "Goodwill and Other
Intangible Assets" which was issued in June 2001 by the FASB. 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.
Separately identifiable assets that are not deemed to have an indefinite life
will continue to be amortized over their useful lives (but with no maximum
life).
At December 31, 2001, the Company had $2.7 million of unamortized
goodwill which was subject to the transition provisions of SFAS 142.
Amortization expense related to goodwill amounted to $130,000 and $132,000 for
the years ended December 31, 2001 and 2000, respectively. The Company assessed
the impact of SFAS 142 and has determined that adoption of SFAS 142 did not
have a material effect on the Company's financial position, results of
operations or cash flows, including any transitional impairment losses.
In June 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 the Company's financial
statements beginning January 1, 2003. This statement would require the Company
to recognize a liability for the fair value of its plugging and abandoning
liability (excluding salvage value) with the associated costs included as part
of the Company's oil and gas properties balance. Due to the significant number
of producing oil and gas properties operated by the Company, and the number of
documents that must be reviewed and estimates that must be made to assess the
effects of SFAS 143, it has not yet been determined whether adoption of SFAS 143
will have a material effect on the Company's financial position, results of
operations or cash flows.
12
In August 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 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 supersede the
provisions of APB 30, "Reporting Results of Operations - Reporting the Effects
of Disposal of a Segment of Business," with regard to reporting the effects of a
disposal of a segment of a business and 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 previously required by APB 30. In addition, more
dispositions may qualify for discontinued operations treatment in the income
statement. SFAS 144 was effective as of January 1, 2002. The adoption of this
standard did not have a material effect on the Company's financial position,
results of operations or cash flows.
In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from
Extinguishment of Debt," SFAS 44, "Accounting for Intangible Assets of Motor
Carriers" and SFAS 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund
Requirements" and amends SFAS No. 13, "Accounting for Leases". Statement 145
also makes technical corrections to other existing pronouncements. SFAS 4
required gains and losses from extinguishment of debt to be classified as an
extraordinary item, net of the related income tax effect. As a result of the
rescission of SFAS 4, the criteria for extraordinary items in APB Opinion No.
30, "Reporting the Results of Operations - Reporting the Effects of Disposal of
a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions," now will be used to classify those gains and losses.
SFAS 145 is effective for the Company's financial statements beginning January
1, 2003. The adoption of SFAS 145 is not expected to have a material effect on
the Company's financial position, results of operations or cash flows.
In July 2002, the FASB issued SFAS 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS 146 will be effective for the
Company for disposal activities initiated after December 31, 2002. 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.
13
RESULTS OF OPERATIONS - THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2002 AND 2001
COMPARED
The following table sets forth certain information regarding the
Company's net oil and natural gas production, revenues and expenses for the
quarters indicated:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------- -------------
2002 2001 2002 2001
------- ------- ------- -------
PRODUCTION
Gas (Mmcf) 4,291 4,680 13,238 13,713
Oil (Mbbls) 139 173 431 490
Total production (Mmcfe) 5,126 5,717 15,822 16,653
AVERAGE PRICE
Gas (per Mcf) $ 4.70 $ 4.03 $ 4.67 $ 4.39
Oil (per Bbl) 24.91 23.55 22.20 24.74
Mcfe 4.61 4.01 4.51 4.34
AVERAGE COSTS (PER Mcfe)
Production expense 1.00 1.06 0.99 1.03
Production taxes 0.08 0.10 0.09 0.12
Depletion 0.86 0.86 0.88 0.79
OPERATING MARGIN (PER Mcfe) 3.53 2.85 3.43 3.19
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
OPERATING MARGIN (PER Mcfe) - AVERAGE PRICE LESS PRODUCTION EXPENSE AND
PRODUCTION TAXES
RESULTS OF OPERATIONS - THIRD QUARTERS OF 2002 AND 2001 COMPARED
Operating income increased $158,000 (2%) from $7.9 million in the third
quarter of 2001 to $8.1 million in the third quarter of 2002. This increase was
primarily a result of a $1.2 million (7%) increase in operating margins; a
$657,000 decrease in depreciation, depletion and amortization; and a $185,000
decrease in severance and other nonrecurring expense offset by a $1.9 million
increase in exploration expense.
Net income increased $461,000 from $682,000 in the third quarter of
2001 to $1.1 million in the third quarter of 2002. This increase was a result of
a $566,000 decrease in interest expense and the increase in operating income
discussed above offset by a $263,000 increase in the provision for income taxes.
The increase in the provision for income taxes was primarily due to the increase
in income before income taxes.
The $1.2 million increase in operating margins was primarily due to a
$1.8 million increase in the operating margin from oil and gas sales offset by a
$561,000 decrease in the operating margin from gas gathering, marketing and
oilfield services. The increase in the operating margin from oil and gas sales
was due to an increase in the average prices realized for the Company's oil and
natural gas and a $918,000 decrease in production expense partially offset by
lower oil and gas volumes. The decrease in the operating margin from gas
gathering, marketing and oilfield services was primarily due to a decrease in
gas gathering revenue in Pennsylvania.
Earnings before interest expense; income taxes; depreciation, depletion
and amortization; exploration expense; derivative fair value loss (gain); and
severance and other nonrecurring items ("EBITDAX") increased $1.2 million (7%)
from $17.0 million in the third quarter of 2001 to $18.2 million in the third
quarter of 2002 primarily due to the increased operating margins discussed
above.
14
Total revenues increased $759,000 (2%) in the third quarter of 2002
compared to the third quarter of 2001 primarily due to an increase in the
average prices realized for the Company's oil and natural gas partially offset
by lower oil and gas volumes.
Gas volumes sold decreased approximately 389 Mmcf (8%) from 4.7 Bcf
(billion cubic feet) in the third quarter of 2001 to 4.3 Bcf in the third
quarter of 2002. The decrease in gas volumes sold resulted in a decrease in gas
sales revenues of approximately $1.6 million. Oil volumes sold decreased
approximately 34,000 Bbls (19%) from 173,000 Bbls in the third quarter of 2001
to 139,000 Bbls in the third quarter of 2002 which resulted in a decrease in oil
sales revenues of approximately $790,000. The decrease in oil and gas volumes
sold was primarily due to the sale of wells in Ohio in the first and third
quarters of 2002 and natural production declines partially offset by a reduction
in oil inventory in the third quarter of 2002.
The average price realized for the Company's natural gas increased
$0.67 per Mcf to $4.70 per Mcf in the third quarter of 2002 compared to the
third quarter of 2001 which increased gas sales revenues in the third quarter of
2002 by approximately $2.9 million. As a result of the Company's hedging
activities, gas sales revenues for the third quarter of 2002 increased by
approximately $5.3 million or $1.23 per Mcf compared to an increase of
approximately $3.2 million or $0.67 per Mcf for the third quarter of 2001. The
average price realized for the Company's oil increased from $23.55 per Bbl in
the third quarter of 2001 to $24.91 per Bbl in the third quarter of 2002 which
increased oil sales revenues by approximately $189,000.
Production expense decreased $918,000 (15%) from $6.0 million in the
third quarter of 2001 to $5.1 million in the third quarter of 2002. The average
production cost decreased from $1.06 per Mcfe in the third quarter of 2001 to
$1.00 per Mcfe in the third quarter of 2002. These decreases were primarily due
to decreased compensation related expenses as a result of staff reductions in
2002. Production taxes decreased $143,000 from $546,000 in the third quarter of
2001 to $403,000 in the third quarter of 2002. Average per unit production taxes
decreased from $0.10 per Mcfe in the third quarter of 2001 to $0.08 per Mcfe in
the third quarter of 2002. The decreases in production taxes were primarily due
to lower oil and gas sales volumes and the sale of wells in Ohio during 2002.
Exploration expense increased $1.9 million (85%) from $2.3 million in
the third quarter of 2001 to $4.2 million in the third quarter of 2002 primarily
due to increases in leasing activity associated with the Company's planned
future drilling activity, a $898,000 increase in dry hole expense and $413,000
associated with the expiration of a farm-in agreement in the third quarter of
2002.
General and administrative expense of $1.1 million in the third quarter
of 2002 was consistent compared to the third quarter of 2001.
Depreciation, depletion and amortization decreased $657,000 (10%) from
$6.5 million in the third quarter of 2001 to $5.8 million in the third quarter
of 2002. Depletion expense decreased $524,000 (11%) from $4.9 million in the
third quarter of 2001 to $4.4 million in the third quarter of 2002 due to the
decreased oil and gas sales volumes discussed above. Depletion was $0.86 per
Mcfe in the third quarter of 2001 and the third quarter of 2002.
Interest expense decreased $566,000 (8%) from $6.8 million in the third
quarter of 2001 to $6.3 million in the third quarter of 2002 due to a decrease
in average outstanding borrowings and lower blended interest rates.
15
RESULTS OF OPERATIONS - NINE MONTHS OF 2002 AND 2001 COMPARED
Operating income decreased $829,000 (3%) from $28.0 million in the
first nine months of 2001 to $27.2 million in the first nine months of 2002.
This decrease was primarily a result of a $4.1 million increase in exploration
expense partially offset by a $1.5 million decrease in severance and other
nonrecurring expense, a $1.1 million increase in operating margins and a
$705,000 increase in other revenue. The increase in other revenue was primarily
due to the settlement of a gas measurement dispute with one of the Company's gas
purchasers related to a gathering system in New York. See Note 7 to the
Consolidated Financial Statements.
Net income decreased $1.3 million from $6.5 million in the first nine
months of 2001 to $5.2 million in the first nine months of 2002. This decrease
was a result of the decrease in operating income discussed above and a $2.7
million increase in the provision for income taxes partially offset by a $2.2
million decrease in interest expense. The increase in the provision for income
taxes was due to the increase in income before income taxes and federal income
tax benefits recorded in the second quarter of 2001. A federal income tax
benefit of $1.5 million was recorded during the second quarter of 2001 due to
the conclusion of an IRS income tax examination for the years 1994 through 1997.
Also, in the second quarter of 2001, 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 believes it can fully utilize.
Operating margins in the first nine months of 2002 increased $1.1
million compared to the operating margins in the first nine months of 2001. The
operating margin from oil and gas sales increased $1.2 million primarily due to
an increase in the average price realized for the Company's natural gas and
decreases in production expense and production taxes offset by decreases in the
volumes of oil and natural gas sold and a decrease in the average price realized
for the Company's oil. The increase in the margin from oil and gas sales was
partially offset by a $115,000 decrease in the operating margin from gas
gathering, marketing and oilfield services.
EBITDAX increased $1.6 million (3%) from $54.5 million in the first
nine months of 2001 to $56.1 million in the first nine months of 2002 primarily
due to the increased operating margins discussed above and the increase in other
revenue discussed above.
Total revenues decreased $1.7 million (2%) in the first nine months of
2002 compared to the first nine months of 2001 primarily due to a decrease in
the volumes of oil and natural gas sold, a decrease in the average price
realized for the Company's oil and a decrease in gas gathering, marketing and
oilfield services revenue. These decreases were partially offset by an increase
in the average price realized for the Company's natural gas and the increase in
other revenue discussed above.
Gas volumes sold decreased approximately 475 Mmcf (3%) from 13.7 Bcf in
the first nine months of 2001 to 13.2 Bcf in the first nine months of 2002. The
decrease in gas volumes sold resulted in a decrease in gas sales revenues of
approximately $2.1 million. Oil volumes sold decreased 59,000 Bbls (12%) from
490,000 Bbls in the first nine months of 2001 to 431,000 Bbls in the first nine
months of 2002. The decrease in oil volumes sold resulted in a decrease in oil
sales revenues of approximately $1.5 million. The decreases in oil and gas
volumes were primarily due to the sale of wells in Ohio during the first and
third quarters of 2002 and natural production declines partially offset by a
reduction in oil inventory in the third quarter of 2002.
The average price realized for the Company's natural gas increased
$0.28 per Mcf to $4.67 per Mcf in the first nine months of 2002 compared to the
first nine months of 2001 which increased gas sales revenues in the first nine
months of 2002 by approximately $3.7 million. As a result of the Company's
16
hedging activities, gas sales revenues for the first nine months of 2002
increased by approximately $17.2 million or $1.30 per Mcf compared to a decrease
of approximately $1.0 million or $0.07 per Mcf for the first nine months of
2001. The average price realized for the Company's oil decreased from $24.74 per
Bbl in the first nine months of 2001 to $22.20 per Bbl in the first nine months
of 2002 which decreased oil sales revenues by approximately $1.1 million.
Production expense decreased $1.5 million (9%) from $17.2 million in
the first nine months of 2001 to $15.7 million in the first nine months of 2002.
The average production cost decreased from $1.03 per Mcfe in the first nine
months of 2001 to $0.99 per Mcfe in the first nine months of 2002. These
decreases were primarily due to decreased compensation related expenses as a
result of staff reductions in 2002. Production taxes decreased $609,000 from
$2.0 million in the first nine months of 2001 to $1.4 million in the first nine
months of 2002. Average per unit production taxes decreased from $0.12 per Mcfe
in the first nine months of 2001 to $0.09 per Mcfe in the first nine months of
2002. The decreases in production taxes are primarily due to lower oil and gas
sales volumes in Michigan coupled with lower oil and gas prices in Michigan,
where production taxes are based on a percentage of revenues.
Exploration expense increased $4.1 million (70%) from $6.0 million in
the first nine months of 2001 to $10.1 million in the first nine months of 2002
primarily due to increases in leasing activity and geophysical expenses
associated with the Company's planned future drilling activity, a $1.8 million
increase in dry hole expense and $413,000 associated with the expiration of a
farm-in agreement in the third quarter of 2002.
General and administrative expense increased $180,000 (6%) from $3.3
million in the first nine months of 2001 to $3.4 million in the first nine
months of 2002 primarily due to increases in compensation related expenses.
Depreciation, depletion and amortization decreased by $325,000 (2%)
from $18.7 million in the first nine months of 2001 to $18.3 million in the
first nine months of 2002. This decrease was primarily due to a $579,000
reduction in amortization of loan costs from the extension of the Revolver's
final maturity date, a $424,000 reduction in the amortization of nonconventional
fuel source tax credits in 2002 and a $173,000 reduction in amortization of
non-compete covenants due to expiration of the covenants in 2001 partially
offset by an increase in depletion expense. Depletion expense increased $728,000
(6%) from $13.2 million in the first nine months of 2001 to $13.9 million in the
first nine months of 2002. Depletion per Mcfe increased from $0.79 per Mcfe in
the first nine months of 2001 to $0.88 per Mcfe in the first nine months of
2002. These increases were primarily the result of a higher depletion rate per
Mcfe due to lower reserves resulting from lower oil and gas prices at year-end
2001, excluding the effect of hedging.
Severance and other nonrecurring expense decreased by $1.5 million from
$1.8 million in the first nine months of 2001 to $292,000 in the first nine
months of 2002 primarily due to costs associated with the early retirement of
certain senior management members of the Company and other severance charges
incurred in the first nine months of 2001.
Interest expense decreased $2.2 million (10%) from $20.9 million in the
first nine months of 2001 to $18.7 million in the first nine months of 2002 due
to a decrease in average outstanding borrowings and lower blended interest
rates.
17
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, 2002 was .59 to 1. During
the first nine months of 2002, working capital decreased $26.7 million from
$13.5 million at December 31, 2001 to a deficit of $13.2 million at September
30, 2002. The decrease was primarily due to a $21.2 million decrease in the fair
value of derivatives in the first nine months of 2002, primarily as a result of
the Company's monetization of derivatives in January 2002 and a $10.1 million
increase in accrued expenses partially offset by a $5.4 million decrease in the
current deferred tax liability. The Company's operating activities provided cash
flows of $55.5 million during the first nine months of 2002.
On July 25, 2002, the Company amended its $100 million Revolver. The
amendment extended the Revolver's final maturity date to April 22, 2005, from
April 22, 2004 and permitted the Company to enter into the transaction to sell,
transfer and assign oil and gas properties consisting of 1,138 wells in Ohio.
The Revolver bears interest at the prime rate plus two percentage
points, payable monthly. At September 30, 2002, the interest rate was 6.75%. Up
to $30 million in letters of credit may be issued pursuant to the Revolver. At
September 30, 2002, the Company had $10.8 million of outstanding letters of
credit. At September 30, 2002, the outstanding balance under the credit
agreement was $33.1 million with $56.1 million of borrowing capacity available
for general corporate purposes.
The Revolver, as amended, has an early termination fee equal to .125%
of the facility if termination is on or before November 30, 2003. There is no
termination fee after November 30, 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 in place at September 30, 2002, and its expected production
levels, the Company is in compliance with this hedging requirement through March
2005.
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 present value of the Company's proved developed producing
reserves subject to a mortgage; (ii) 45% of the present value of the Company's
proved developed non-producing reserves subject to a mortgage; and (iii) 40% of
the present 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, 2002, under the borrowing base formula above was
approximately $233.4 million for all proved reserves of the Company and $163.2
million for properties secured by a mortgage.
The Revolver, as amended, is subject to certain financial covenants.
These include a quarterly senior debt interest coverage ratio of 3.2 to 1
through March 31, 2005; and a senior debt leverage ratio of 2.7 to 1 through
March 31, 2005. 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 previous 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
18
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, 2002,
the Company's current ratio including the above adjustments was 3.24 to 1. The
Company had satisfied all financial covenants as of September 30, 2002.
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. There were no interest rate swaps in the first nine months of
2002 or 2001.
During the first nine months of 2002, the Company invested $19.7
million, including $2.4 million of exploratory dry hole expense, to drill 81
development wells and 13 exploratory wells, five of which tested the Trenton
Black River ("TBR") formation. Of these wells, 78 development wells and three
exploratory wells were completed as producing wells. The status of three other
exploratory TBR wells has not yet been determined. Two of these exploratory TBR
wells were completed in the target formation and are currently being evaluated.
The other exploratory TBR well, which was dry in the target formation, was
completed in an uphole formation and is currently being evaluated. The total
cost of these three wells through September 30, 2002 was approximately $2.2
million.
Through September 30, 2002, drilling and other capital expenditures,
including exploratory dry hole expense, totaled approximately $29.3 million,
excluding acquisitions. The Company currently expects to spend approximately $37
million during 2002 on its drilling activities, including exploratory dry hole
expense, and other capital expenditures. The Company intends to finance its
planned capital expenditures through its available cash flow, available
revolving credit line, the sale of participating interests in its exploratory
Trenton Black River prospect areas and the sale of non-strategic assets. At
September 30, 2002, the Company had approximately $56.1 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.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 a net pretax gain on its
hedging activities of $17.2 million in the first nine months of 2002 and a net
pretax loss of $1.0 million in the first nine months of 2001.
19
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) and
fixed price contracts at September 30, 2002:
NATURAL GAS COLLARS FIXED PRICE CONTRACTS
--------------------------------------------------------------- ----------------------
MONTHLY NYMEX SETTLE OF $1.75 MONTHLY NYMEX SETTLE
OR HIGHER LOWER THAN $1.75
----------------------------- --------------------
ESTIMATED ESTIMATED
NYMEX PRICE ESTIMATED NYMEX WELLHEAD WELLHEAD
PER MMBTU WELLHEAD PRICE PRICE PER PRICE PER ESTIMATED PRICE PER
QUARTER ENDING BBTU FLOOR/CAP PER MCF MMBTU MCF MMCF MCF
- -------------- ---- ----------- -------------- ---------- --------- ---------- ---------
December 31, 2002 2,130 $ 2.25 - 4.00 $ 2.47 - 4.22 Monthly Monthly 830 $ 4.12
------ --------------- -------------- NYMEX NYMEX ----- --------
2,130 $ 2.25 - 4.00 $ 2.47 - 4.22 settle plus settle plus 830 $ 4.12
====== =============== ============== $0.50 $0.65 to ===== ========
$0.75
March 31, 2003 1,650 $ 3.40 - 5.23 $ 3.65 - 5.48 180 $ 3.48
June 30, 2003 1,650 3.40 - 5.23 3.55 - 5.38 110 3.12
September 30, 2003 1,650 3.40 - 5.23 3.55 - 5.38 75 2.68
December 31, 2003 1,650 3.40 - 5.23 3.62 - 5.45 70 2.59
------ --------------- -------------- ----- --------
6,600 $ 3.40 - 5.23 $ 3.59 - 5.42 435 $ 3.11
====== =============== ============== ===== ========
NATURAL GAS SWAPS
--------------------------------------------
ESTIMATED
NYMEX PRICE WELLHEAD PRICE
QUARTER ENDING BBTU PER MMBTU PER MCF
- -------------- ---- --------- -------
December 31, 2002 800 $ 3.82 $ 4.00
----- -------- -------
800 $ 3.82 $ 4.00
===== ======== =======
March 31, 2003 1,800 $ 3.92 $ 4.17
June 30, 2003 1,800 3.92 4.07
September 30, 2003 1,800 3.92 4.07
December 31, 2003 1,800 3.92 4.14
----- -------- -------
7,200 $ 3.92 $ 4.12
===== ======== =======
March 31, 2004 2,040 $ 3.84 $ 4.09
June 30, 2004 2,040 3.84 3.99
September 30, 2004 2,040 3.84 3.99
December 31, 2004 2,040 3.84 4.06
----- -------- -------
8,160 $ 3.84 $ 4.03
===== ======== =======
March 31, 2005 1,050 $ 3.87 $ 4.12
----- -------- -------
1,050 $ 3.87 $ 4.12
===== ======== =======
ITEM 4. CONTROLS AND PROCEDURES
DISCLOSURE CONTROLS AND PROCEDURES
The Company, under the supervision of the principal executive and
financial officers, has conducted an evaluation of the effectiveness of the
design and operation of the Company's disclosure controls and procedures within
90 days of the filing date of this report. Based on the Company's
20
evaluation, the disclosure controls and procedures in place are effective in
ensuring that information required to be disclosed by the Company in its
Exchange Act reports is accumulated and communicated to the Company's
management, including its principal executive and financial officers, as
appropriate, to allow timely decisions regarding required disclosures.
CHANGES IN INTERNAL CONTROLS
There were no significant changes in the Company's internal controls or
in other factors that could significantly affect these controls subsequent to
the date of their evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
- --------------------------------------------------------------------------------
PART II OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
99.1 Certification Pursuant to 18 U.S.C. Section 1350, as
Adopted Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.
99.2 Certification Pursuant to 18 U.S.C. Section 1350, as
Adopted Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.
(b) Reports on Form 8-K
On August 20, 2002, the Company filed a Current Report on Form
8-K dated August 15, 2002, reporting under Item 9 the
Company's operational outlook for 2002.
On September 13, 2002, the Company filed a Current Report on
Form 8-K dated August 30, 2002, reporting under Item 9 the
Company's natural gas hedging position.
On September 24, 2002, the Company filed a Current Report on
Form 8-K dated September 18, 2002, reporting under Item 9 the
Company's natural gas hedging position.
21
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, 2002 By: /s/ John L. Schwager
---------------------- ------------------------------
John L. Schwager, Director,
President and Chief
Executive Officer
Date: November 12, 2002 By: /s/ Robert W. Peshek
---------------------- ------------------------------
Robert W. Peshek, Vice President
and Chief Financial Officer
22
CERTIFICATIONS
- --------------------------------------------------------------------------------
I, John L. Schwager, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Belden & Blake
Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: November 12, 2002 /s/ John L. Schwager
---------------------- -----------------------------------
John L. Schwager, Director, President
and Chief Executive Officer
23
CERTIFICATIONS
- --------------------------------------------------------------------------------
I, Robert W. Peshek, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Belden & Blake
Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: November 12, 2002 /s/ Robert W. Peshek
---------------------- ------------------------------------
Robert W. Peshek, Vice President
and Chief Financial Officer
24