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 March 31, 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
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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 April 29, 2002, Belden & Blake Corporation had outstanding
10,325,218 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 March 31, 2002 and
December 31, 2001................................................................ 1
Consolidated Statements of Operations for the three
months ended March 31, 2002 and 2001 ............................................ 2
Consolidated Statements of Shareholders' Equity (Deficit)
for the three months ended March 31, 2002 and the
years ended December 31, 2001 and 2000........................................... 3
Consolidated Statements of Cash Flows for the three
months ended March 31, 2002 and 2001 ............................................ 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.................................................... 17
BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
MARCH 31, DECEMBER 31,
2002 2001
--------- ---------
(UNAUDITED)
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 1,646 $ 1,935
Accounts receivable, net 13,929 14,160
Inventories 1,608 1,695
Other current assets 1,414 1,094
Derivative fair value 1,890 19,965
--------- ---------
TOTAL CURRENT ASSETS 20,487 38,849
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties (successful efforts method) 452,554 446,977
Gas gathering systems 14,289 14,094
Land, buildings, machinery and equipment 24,536 24,113
--------- ---------
491,379 485,184
Less accumulated depreciation, depletion and amortization 239,215 233,396
--------- ---------
PROPERTY AND EQUIPMENT, NET 252,164 251,788
DERIVATIVE FAIR VALUE 1,384 3,748
OTHER ASSETS 10,588 10,964
--------- ---------
$ 284,623 $ 305,349
========= =========
LIABILITIES AND SHAREHOLDERS' DEFICIT
CURRENT LIABILITIES
Accounts payable $ 5,749 $ 5,253
Accrued expenses 19,199 14,465
Current portion of long-term liabilities 391 156
Derivative fair value 3,306 --
Deferred income taxes 4,831 5,470
--------- ---------
TOTAL CURRENT LIABILITIES 33,476 25,344
LONG-TERM LIABILITIES
Bank and other long-term debt 33,370 59,415
Senior subordinated notes 225,000 225,000
Other 301 330
--------- ---------
258,671 284,745
DEFERRED INCOME TAXES 21,959 22,539
SHAREHOLDERS' DEFICIT
Common stock without par value; $.10 stated value per share; authorized
58,000,000 shares; issued 10,451,237 and 10,425,103 shares
(which includes 137,808 and 135,369 treasury shares, respectively) 1,031 1,029
Paid in capital 107,437 107,402
Deficit (149,353) (150,797)
Accumulated other comprehensive income 11,402 15,087
--------- ---------
TOTAL SHAREHOLDERS' DEFICIT (29,483) (27,279)
--------- ---------
$ 284,623 $ 305,349
========= =========
See accompanying notes.
1
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
(unaudited)
THREE MONTHS ENDED MARCH 31,
----------------------------
2002 2001
---------- ----------
Revenues
Oil and gas sales $ 22,752 $ 25,779
Gas gathering, marketing and oilfield service 8,320 8,875
Other 501 487
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31,573 35,141
EXPENSES
Production expense 5,162 5,458
Production taxes 462 688
Gas gathering, marketing and oilfield service 6,689 8,388
Exploration expense 2,596 1,426
General and administrative expense 1,202 1,124
Franchise, property and other taxes 78 105
Depreciation, depletion and amortization 6,328 6,070
Derivative fair value (gain) loss 427 --
Severance and other nonrecurring expense -- 1,446
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22,944 24,705
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OPERATING INCOME 8,629 10,436
OTHER (INCOME) EXPENSE
Interest expense 6,278 7,202
---------- ----------
INCOME BEFORE INCOME TAXES 2,351 3,234
Provision for income taxes 907 1,172
---------- ----------
NET INCOME $ 1,444 $ 2,062
========== ==========
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 1,444 1,444
Other comprehensive income, net of tax:
Change in derivative fair value 485 485
Reclassification adjustment for derivative
(gain) loss reclassified into oil and gas sales (4,170) (4,170)
-----------
Total comprehensive income (2,241)
-----------
Stock options exercised 26 2 -- 2
Stock-based compensation 21 21
Tax benefit of stock options exercised 19 19
Treasury stock (3) (5) (5)
- ------------------------------------------------- --------- ----------- ----------- ------------ --------------- -----------
March 31, 2002 (unaudited) 10,313 $ 1,031 $ 107,437 $ (149,353) $ 11,402 $ (29,483)
================================================= ========= =========== =========== ============ =============== ===========
See accompanying notes.
3
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(IN THOUSANDS)
THREE MONTHS ENDED MARCH 31,
------------------------
2002 2001
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CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 1,444 $ 2,062
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 6,328 6,070
Loss (gain) on disposal of property and equipment 74 (51)
Net monetization of derivatives 21,734 --
Amortization of derivatives and other non-cash hedging adjustments (3,780) --
Exploration expense 2,596 1,426
Deferred income taxes 907 1,172
Stock-based compensation 21 271
Change in operating assets and liabilities, net of
effects of disposition of businesses:
Accounts receivable and other operating assets (92) 4,762
Inventories 87 38
Accounts payable and accrued expenses 5,230 6,959
-------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES 34,549 22,709
CASH FLOWS FROM INVESTING ACTIVITIES:
Disposition of businesses, net of cash 250 --
Proceeds from property and equipment disposals 28 380
Exploration expense (2,596) (1,426)
Additions to property and equipment (6,383) (9,930)
Increase in other assets (31) (1)
-------- --------
NET CASH USED IN INVESTING ACTIVITIES (8,732) (10,977)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving line of credit 28,671 44,576
Repayment of long-term debt and other obligations (54,774) (55,967)
Proceeds from stock options exercised 2 --
Purchase of treasury stock (5) (12)
-------- --------
NET CASH USED IN FINANCING ACTIVITIES (26,106) (11,403)
-------- --------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS (289) 329
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 1,935 1,798
-------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 1,646 $ 2,127
======== ========
CASH PAID DURING THE PERIOD FOR:
Interest $ 864 $ 1,754
Income taxes, net of refunds 1 --
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Acquisition of assets in exchange for long-term liabilities 263 --
See accompanying notes.
4
BELDEN & BLAKE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
MARCH 31, 2002
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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 month period ended March 31, 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 July 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. 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).
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 no material effect on the
Company's financial position, results of operations or cash flows, including any
transitional impairment losses, would be required to be recognized as the effect
of a change in accounting principle.
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 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. 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 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
5
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 is 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.
(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.
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
March 31, 2002, the Company's derivative contracts were comprised of natural gas
collars. Qualifying NYMEX based derivative contracts are designated as cash flow
hedges.
During the first quarters of 2002 and 2001, a net gain of $6.6 million
($4.2 million after tax) and a net loss of $2.8 million ($1.8 million after
tax), respectively, were reclassified from accumulated other comprehensive
income to earnings. The fair value of open hedges increased $763,000 ($485,000
after tax) in the first quarter of 2002 and $5.0 million ($3.2 million after
tax) in the first quarter of 2001. At March 31, 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 $14.9 million. The Company
has partially hedged its exposure to the variability in future cash flows
through December 2003.
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 will be recognized as
increases to
6
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. The following table
summarizes, as of March 31, 2002, the Company's deferred gains on terminated
natural gas hedges. Cash has been received and the deferred gains recorded in
accumulated other comprehensive income. The deferred gains will be 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)
Natural Gas Hedges Terminated in January 2002 $4,521 $ 5,620 $ 5,188 $ 4,560 $ 2,851
In March 2002, the Company terminated 1,700 Bbtu of its 2002 collar
($4.00 per Mmbtu ceiling price and $2.25 per Mmbtu floor price) for the months
of April and May 2002. The Company also terminated its $1.75 floor on this
volume of gas.
(4) 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.
(5) SUBSEQUENT EVENTS
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
7
Company's net share of the settlement amount, approximately $580,000, will be
recorded in the second quarter of 2002 as other revenue.
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.
On April 11, 2002, the Company terminated 2,100 Bbtu of its 2002 collar
($4.00 per Mmbtu ceiling price and $2.25 per Mmbtu floor price) for the months
of June through October 2002. The Company also terminated its $1.75 floor on
this volume of gas. The Company paid $262,500 to its counterparty for these
terminations. The Company recently placed 2,400 Bbtu of natural gas swaps for
the months of May 2002 through October 2002 at a weighted average price of
$3.70 per Mmbtu.
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 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.
8
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,
such 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.
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.
9
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.
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.
10
NEW ACCOUNTING PRONOUNCEMENTS
On January 1, 2002, the Company adopted SFAS 142, "Goodwill and Other
Intangible Assets" which was issued in July 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.
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).
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 no material effect on the
Company's financial position, results of operations or cash flows, including any
transitional impairment losses, would be required to be recognized as the effect
of a change in accounting principle.
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 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. 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 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 is 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.
11
RESULTS OF OPERATIONS - FIRST QUARTERS OF 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
MARCH 31,
--------------------------
2002 2001
----------- ------------
PRODUCTION
Gas (Mmcf) 4,543 4,483
Oil (Mbbls) 148 156
Total production (Mmcfe) 5,431 5,416
AVERAGE PRICE
Gas (per Mcf) $ 4.41 $ 4.85
Oil (per Bbl) 18.48 25.85
Mcfe 4.19 4.76
AVERAGE COSTS (PER MCFE)
Production expense 0.95 1.01
Production taxes 0.09 0.13
Depletion 0.90 0.76
OPERATING MARGIN (PER MCFE) 3.15 3.62
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
Operating income decreased $1.8 million (17%) from $10.4 million in the
first quarter of 2001 to $8.6 million in the first quarter of 2002. This
decrease was primarily a result of a $1.4 million (7%) decrease in operating
margins, a $1.2 million increase in exploration expense and a $427,000
derivative fair value loss in the first quarter of 2002. This decrease was
partially offset by $1.4 million of severance and other nonrecurring expense in
the first quarter of 2001. Net income decreased $618,000 from $2.1 million in
the first quarter of 2001 to $1.4 million in the first quarter of 2002. This
decrease was a result of the decrease in operating income discussed above
partially offset by a $924,000 decrease in interest expense and a $265,000
decrease in the provision for income taxes.
The $1.4 million decrease in operating margins was primarily due to a
$2.5 million decrease in the operating margin from oil and gas sales resulting
primarily from a decrease in the average prices realized for the Company's oil
and natural gas. This decrease was partially offset by a $1.1 million increase
in the operating margin from gas gathering, marketing and oilfield services
primarily due to a higher margin on a gathering system in Pennsylvania.
Earnings before interest expense; income taxes; depreciation, depletion
and amortization; exploration expense; derivative fair value (gain) loss; and
severance and other nonrecurring items ("EBITDAX") decreased $1.4 million (7%)
from $19.4 million in the first quarter of 2001 to $18.0 million in the first
quarter of 2002 primarily due to the decreased operating margins discussed
above.
Total revenues decreased $3.6 million (10%) in the first quarter of
2002 compared to the first quarter of 2001 primarily due to a decrease in the
average prices realized for the Company's oil and natural gas.
12
Gas volumes sold in the first quarter of 2002 were 4.5 Bcf (billion
cubic feet), an increase of 60 Mmcf (1%), compared to the first quarter of 2001.
The increase in gas volumes sold resulted in an increase in gas sales revenues
of approximately $300,000. Oil volumes sold decreased 8,000 Bbls (5%) from
156,000 Bbls in the first quarter of 2001 to 148,000 Bbls in the first quarter
of 2002 primarily due to mechanical problems experienced on one significant oil
well in Michigan during a period when the well was inaccessible due to weather
conditions. This resulted in a decrease in oil sales revenues of approximately
$200,000.
The average price realized for the Company's natural gas decreased
$0.44 per Mcf to $4.41 per Mcf in the first quarter of 2002 compared to the
first quarter of 2001 which decreased gas sales revenues in the first quarter of
2002 by approximately $2.0 million. As a result of the Company's hedging
activities, gas sales revenues for the first quarter of 2002 increased by
approximately $6.4 million or $1.42 per Mcf compared to a decrease of
approximately $2.8 million or $0.63 per Mcf for the first quarter of 2001. The
average price realized for the Company's oil decreased from $25.85 per Bbl in
the first quarter of 2001 to $18.48 per Bbl in the first quarter of 2002 which
decreased oil sales revenues by approximately $1.1 million.
Production expense decreased $296,000 (5%) from $5.5 million in the
first quarter of 2001 to $5.2 million in the first quarter of 2002. The average
production cost decreased from $1.01 per Mcfe in the first quarter of 2001 to
$0.95 per Mcfe in the first quarter of 2002 primarily due to additional costs
incurred in the first quarter of 2001 to minimize production declines in order
to take advantage of higher gas prices. Production taxes decreased $226,000 from
$688,000 in the first quarter of 2001 to $462,000 in the first quarter of 2002.
Average per unit production taxes decreased from $0.13 per Mcfe in the first
quarter of 2001 to $0.09 per Mcfe in the first quarter of 2002 primarily due to
lower oil and gas prices in Michigan, where production taxes are based on a
percentage of revenues.
Exploration expense increased $1.2 million (82%) from $1.4 million in
the first quarter of 2001 to $2.6 million in the first quarter of 2002 primarily
due to increases in leasing activity and geophysical expenses associated with
the Company's planned drilling activity in 2002 and a $506,000 increase in dry
hole expense.
General and administrative expense increased $78,000 (7%) from $1.1
million in the first quarter of 2001 to $1.2 million in the first quarter of
2002 primarily due to increases in compensation related expenses.
Depreciation, depletion and amortization increased by $258,000 (4%)
from $6.1 million in the first quarter of 2001 to $6.3 million in the first
quarter of 2002. Depletion expense increased $773,000 (19%) from $4.1 million in
the first quarter of 2001 to $4.9 million in the first quarter of 2002.
Depletion per Mcfe increased from $0.76 per Mcfe in the first quarter of 2001 to
$0.90 per Mcfe in the first quarter 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.
The Company incurred severance and other nonrecurring expense of $1.4
million in the first quarter of 2001 related to employee reduction costs.
Interest expense decreased $924,000 (13%) from $7.2 million in the
first quarter of 2001 to approximately $6.3 million in the first quarter of 2002
due to a decrease in average outstanding borrowings and lower blended interest
rates.
13
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 March 31, 2002 was .61 to 1. During the
first three months of 2002, working capital decreased $26.5 million from $13.5
million at December 31, 2001 to a deficit of $13.0 million at March 31, 2002.
The decrease was primarily due to a $21.4 million decrease in the fair value of
derivatives in the first three months of 2002, primarily as a result of the
Company's monetization of derivatives, and a $4.7 million increase in accrued
expenses. The Company's operating activities provided cash flows of $34.5
million during the first three months of 2002.
The Company has a $100 million revolving credit facility ("the
Revolver") from Ableco Finance LLC and Foothill Capital Corporation which
matures in April 2004. The Revolver bears interest at the prime rate plus two
percentage points, payable monthly. At March 31, 2002, the interest rate was
6.75%. Up to $30 million in letters of credit may be issued pursuant to the
Revolver. At March 31, 2002, the Company had $2.3 million of outstanding letters
of credit. At March 31, 2002, the outstanding balance under the credit agreement
was $33.3 million with $64.4 million of borrowing capacity available for general
corporate purposes.
The Revolver has 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 March 2003.
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 March 31, 2002, under the borrowing base formula above was
approximately $224 million for all proved reserves of the Company and $161
million for properties secured by a mortgage.
The Revolver is subject to certain financial covenants. These include a
senior debt interest coverage ratio ranging from 3.4 to 1 at March 31, 2002, to
3.2 to 1 at March 31, 2004; and a senior debt leverage ratio ranging from 2.7 to
1 and 3.2 to 1 for the periods from March 31, 2002, 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 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 least 1.0 to 1 and maintain liquidity of at least
$5 million (cash and cash equivalents including available borrowing capacity).
As of
14
March 31, 2002, the Company's current ratio including the above adjustments was
4.55 to 1. The Company had satisfied all financial covenants as of March 31,
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 three months of
2002 or 2001.
During the first three months of 2002, the Company invested $4.0
million, including $515,000 of exploratory dry hole expense, to drill 20
development wells and one exploratory well. Of these wells, all 20 development
wells were successfully completed as producers in the target formation and the
exploratory well was a dry hole for an overall completion rate of 95%.
The Company currently expects to spend approximately $44 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 March 31, 2002, the
Company had approximately $64.4 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 a net pretax gain on its
hedging activities of $6.4 million in the first three months of 2002 and a net
pretax loss $2.8 million in the first three months of 2001.
In March 2002, the Company terminated 1,700 Bbtu of its 2002 collar
($4.00 per Mmbtu ceiling price and $2.25 per Mmbtu floor price) for the months
of April and May 2002. The Company also terminated its $1.75 floor on this
volume of gas.
On April 11, 2002, the Company terminated 2,100 Bbtu of its 2002 collar
($4.00 per Mmbtu ceiling price and $2.25 per Mmbtu floor price) for the months
of June through October 2002. The Company also terminated its $1.75 floor on
this volume of gas. The Company paid $262,500 to its counterparty for these
terminations. The Company recently placed 2,400 Bbtu of natural gas swaps for
the months of May 2002 through October 2002 at a weighted average price of
$3.70 per Mmbtu.
15
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 May 3, 2002:
NATURAL GAS SWAPS FIXED PRICE CONTRACTS
------------------------------------------------- -----------------------
ESTIMATED
ESTIMATED WELLHEAD
NYMEX PRICE WELLHEAD PRICE ESTIMATED PRICE PER
QUARTER ENDING Bbtu PER Mmbtu PER Mcf Mmcf Mcf
- ------------------ ---------- --------------- --------------- ---------- -----------
June 30, 2002 1,200 $ 3.67 $ 3.82 820 $ 4.20
September 30, 2002 900 3.72 3.87 690 4.32
December 31, 2002 300 3.72 3.87 570 4.49
----- ------ ------ ------ ------
2,400 $ 3.70 $ 3.85 2,080 $ 4.32
===== ====== ====== ====== ======
March 31, 2003 65 $ 2.50
June 30, 2003 65 2.50
September 30, 2003 65 2.50
December 31, 2003 65 2.50
--- ------
260 $ 2.50
==== ======
NATURAL GAS COLLARS
---------------------------------------------------------------------
MONTHLY NYMEX SETTLE OF $1.75 MONTHLY NYMEX SETTLE
OR HIGHER LOWER THAN $1.75
------------------------------ --------------------------
ESTIMATED
NYMEX PRICE ESTIMATED NYMEX WELLHEAD
PER Mmbtu WELLHEAD PRICE PRICE PER PRICE PER
QUARTER ENDING Bbtu FLOOR/CAP PER Mcf Mmbtu Mcf
- ------------------ ---------- ------------- ---------------- ---------- -----------
June 30, 2002 430 $ 2.25 - 4.00 $ 2.40 - 4.15 Monthly Monthly
September 30, 2002 1,290 2.25 - 4.00 2.40 - 4.15 NYMEX NYMEX
December 31, 2002 2,130 2.25 - 4.00 2.47 - 4.22 settle plus settle plus
------ -------------- ------------- $0.50 $0.65 to
3,850 $ 2.25 - 4.00 $ 2.44 - 4.19 $0.75
====== ============== =============
March 31, 2003 1,650 $ 3.40 - 5.23 $ 3.65 - 5.48
June 30, 2003 1,650 3.40 - 5.23 3.55 - 5.38
September 30, 2003 1,650 3.40 - 5.23 3.55 - 5.38
December 31, 2003 1,650 3.40 - 5.23 3.62 - 5.45
------ ------------- -------------
6,600 $ 3.40 - 5.23 $ 3.59 - 5.42
====== ============= =============
Bbtu - BILLION BRITISH THERMAL UNITS Mmcf - MILLION CUBIC FEET
Mmbtu - MILLION BRITISH THERMAL UNITS Mcf - THOUSAND CUBIC FEET
16
- -------------------------------------------------------------------------------
PART II OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
(b) Reports on Form 8-K
On January 8, 2002, the Company filed a Current Report on Form 8-K
dated January 7, 2002, reporting under Item 9 the Company's 2002 capital
expenditure plan and Enron exposure.
On January 23, 2002, the Company filed a Current Report on Form 8-K
dated January 17, 2002, reporting under Item 9 the Company's natural gas hedge
position monetization and restructuring.
On March 18, 2002, the Company filed a Current Report on Form 8-K dated
March 8, 2002, reporting under Item 9 the Company's 2001 results and operational
outlook for 2002.
17
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: May 6, 2002 By: /s/ John L. Schwager
--------------------------------------
John L. Schwager, Director, President
and Chief Executive Officer
Date: May 6, 2002 By: /s/ Robert W. Peshek
--------------------------------------
Robert W. Peshek, Vice President
and Chief Financial Officer
18