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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 quarterly period ended March 31, 2004
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
- --------------------------------------------------------------------------------
(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
- --------------------------------------------------------------------------------
(Registrant's telephone number, including area code)
- --------------------------------------------------------------------------------
(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
Indicate by check mark whether the Registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). [ ] Yes [X] No
As of April 30, 2004, Belden & Blake Corporation had outstanding
10,454,644 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 March 31, 2004 and
December 31, 2003............................................. 1
Consolidated Statements of Operations for the three
months ended March 31, 2004 and 2003 ......................... 2
Consolidated Statements of Shareholders' Equity (Deficit) for
the three months ended March 31, 2004 and the years ended
December 31, 2003 and 2002.................................... 3
Consolidated Statements of Cash Flows for the three
months ended March 31, 2004 and 2003 ......................... 4
Notes to Consolidated Financial Statements...................... 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations........................... 7
Item 3. Quantitative and Qualitative Disclosures About Market Risk...... 14
Item 4. Controls and Procedures......................................... 15
PART II Other Information
Item 6. Exhibits and Reports on Form 8-K................................ 16
BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
MARCH 31, DECEMBER 31,
2004 2003
----------- ------------
(UNAUDITED)
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 1,673 $ 1,440
Accounts receivable, net 17,689 17,597
Inventories 894 786
Deferred income taxes 9,021 6,853
Other current assets 2,361 2,415
Fair value of derivatives 615 319
--------- ---------
TOTAL CURRENT ASSETS 32,253 29,410
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties (successful efforts method) 471,912 464,262
Gas gathering systems 15,256 15,264
Land, buildings, machinery and equipment 23,069 23,107
--------- ---------
510,237 502,633
Less accumulated depreciation, depletion and amortization 260,576 256,050
--------- ---------
PROPERTY AND EQUIPMENT, NET 249,661 246,583
FAIR VALUE OF DERIVATIVES 794 755
OTHER ASSETS 6,942 7,163
--------- ---------
$ 289,650 $ 283,911
========= =========
LIABILITIES AND SHAREHOLDERS' DEFICIT
CURRENT LIABILITIES
Accounts payable $ 4,213 $ 5,496
Accrued expenses 19,498 15,393
Current portion of long-term liabilities 729 729
Fair value of derivatives 20,880 14,765
--------- ---------
TOTAL CURRENT LIABILITIES 45,320 36,383
LONG-TERM LIABILITIES
Bank and other long-term debt 45,437 47,503
Senior subordinated notes 225,000 225,000
Other 4,727 4,629
--------- ---------
275,164 277,132
FAIR VALUE OF DERIVATIVES 10,320 9,723
DEFERRED INCOME TAXES 18,698 18,013
SHAREHOLDERS' DEFICIT
Common stock without par value; $.10 stated value per share; authorized
58,000,000 shares; issued 10,674,803 and 10,610,450 shares
(which includes 220,784 and 214,593 treasury shares, respectively) 1,045 1,040
Paid in capital 107,565 107,633
Deficit (148,604) (150,656)
Accumulated other comprehensive loss (19,858) (15,357)
--------- ---------
TOTAL SHAREHOLDERS' DEFICIT (59,852) (57,340)
--------- ---------
$ 289,650 $ 283,911
========= =========
See accompanying notes.
1
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED, IN THOUSANDS)
THREE MONTHS ENDED MARCH 31,
----------------------------
2004 2003
-------- --------
REVENUES
Oil and gas sales $ 23,244 $ 19,427
Gas gathering, marketing, and oilfield service 5,774 8,104
Other 168 183
-------- --------
29,186 27,714
EXPENSES
Production expense 5,419 4,503
Production taxes 664 673
Gas gathering, marketing, and oilfield service 5,177 7,514
Exploration expense 2,077 2,242
General and administrative expense 1,235 1,174
Franchise, property and other taxes 86 71
Depreciation, depletion and amortization 4,947 4,331
Accretion expense 112 86
Derivative fair value (gain) loss (332) 277
-------- --------
19,385 20,871
-------- --------
OPERATING INCOME 9,801 6,843
OTHER EXPENSE
Interest expense 6,543 6,216
-------- --------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 3,258 627
Provision for income taxes 1,206 232
-------- --------
INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 2,052 395
Loss from discontinued operations, net of tax -- (24)
-------- --------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 2,052 371
Cumulative effect of change in accounting principle, net of tax -- 2,397
-------- --------
NET INCOME $ 2,052 $ 2,768
======== ========
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, 2002 10,290 $ 1,029 $ 107,402 $ (150,797) $ 15,087 $ (27,279)
Comprehensive income (loss):
Net income 2,465 2,465
Other comprehensive income, net of tax:
Change in derivative fair value (5,518) (5,518)
Reclassification adjustment for derivative (gain)
loss reclassified into oil and gas sales (14,030) (14,030)
-----------
Total comprehensive loss (17,083)
-----------
Stock options exercised 65 7 (2) 5
Stock-based compensation 82 82
Repurchase of stock options (29) (29)
Tax benefit of repurchase of stock options
and stock options exercised 57 57
Treasury stock (59) (6) (392) (398)
------ ------- --------- ---------- ------------- -----------
DECEMBER 31, 2002 10,296 1,030 107,118 (148,332) (4,461) (44,645)
Comprehensive (loss) income:
Net loss (2,324) (2,324)
Other comprehensive income, net of tax:
Change in derivative fair value (17,439) (17,439)
Reclassification adjustment for derivative (gain)
loss reclassified into oil and gas sales 6,543 6,543
-----------
Total comprehensive loss (13,220)
-----------
Stock options exercised 120 12 108 120
Stock-based compensation 326 326
Repurchase of stock options (48) (48)
Tax benefit of repurchase of stock options
and stock options exercised 170 170
Treasury stock (20) (2) (41) (43)
------ ------- --------- ---------- ------------- -----------
DECEMBER 31, 2003 10,396 1,040 107,633 (150,656) (15,357) (57,340)
Comprehensive income (loss):
Net income 2,052 2,052
Other comprehensive income, net of tax:
Change in derivative fair value (6,985) (6,985)
Reclassification adjustment for derivative (gain)
loss reclassified into oil and gas sales 2,484 2,484
-----------
Total comprehensive loss (2,449)
-----------
Stock options exercised 64 6 104 110
Stock-based compensation 19 19
Repurchase of stock options (283) (283)
Tax benefit of repurchase of stock options
and stock options exercised 116 116
Treasury stock (6) (1) (24) (25)
------ ------- --------- ---------- ------------- -----------
MARCH 31, 2004 (UNAUDITED) 10,454 $ 1,045 $ 107,565 $ (148,604) $ (19,858) $ (59,852)
====== ======= ========= ========== ============= ===========
See accompanying notes.
3
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED, IN THOUSANDS)
THREE MONTHS ENDED MARCH 31,
----------------------------
2004 2003
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Income from continuing operations $ 2,052 $ 395
Adjustments to reconcile income from continuing operations
to net cash provided by operating activities:
Depreciation, depletion and amortization 4,947 4,331
Accretion 112 86
Loss on disposal of property and equipment 325 277
Amortization of derivatives and other noncash hedging activities (697) (446)
Exploration expense 2,077 2,242
Deferred income taxes 1,206 206
Stock-based compensation 19 18
Change in operating assets and liabilities, net of
effects of acquisition and disposition of businesses:
Accounts receivable and other operating assets (286) (5,366)
Inventories (108) (3)
Accounts payable and accrued expenses 2,822 6,095
-------- --------
NET CASH PROVIDED BY CONTINUING OPERATIONS 12,469 7,835
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of businesses, net of cash acquired -- (3,752)
Disposition of businesses, net of cash -- 100
Proceeds from property and equipment disposals 41 118
Exploration expense (2,077) (2,242)
Additions to property and equipment (8,024) (7,253)
Decrease (increase) in other assets 144 (18)
-------- --------
NET CASH USED IN INVESTING ACTIVITIES (9,916) (13,047)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving line of credit 42,366 47,443
Repayment of long-term debt and other obligations (44,488) (43,549)
Proceeds from stock options exercised 110 3
Repurchase of stock options (283) (22)
Purchase of treasury stock (25) (10)
-------- --------
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES (2,320) 3,865
-------- --------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
FROM CONTINUING OPERATIONS 233 (1,347)
NET INCREASE IN CASH AND CASH EQUIVALENTS
FROM DISCONTINUED OPERATIONS -- 683
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 1,440 1,722
-------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 1,673 $ 1,058
======== ========
See accompanying notes.
4
BELDEN & BLAKE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
MARCH 31, 2004
(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, 2004 are not
necessarily indicative of the results that may be expected for the year ended
December 31, 2004. 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, 2003. Certain reclassifications have been made
to conform to the current presentation.
(2) NEW ACCOUNTING PRONOUNCEMENTS
In 2003, the Company was made aware of an issue regarding the application
of provisions of Financial Accounting Standards Board (FASB) Statement of
Financial Accounting Standards No. (SFAS) 141, "Business Combinations" and SFAS
142, "Goodwill and Other Intangible Assets," to oil and gas companies. The issue
was whether SFAS 142 required registrants to reclassify costs associated with
mineral rights, including both proved and unproved leasehold acquisition costs,
as intangible assets in the balance sheet, apart from other capitalized oil and
gas property costs. Historically, the Company and other oil and gas companies
have included the cost of oil and gas leasehold interests as part of oil and gas
properties and provided the disclosures required by SFAS 69, "Disclosures about
Oil and Gas Producing Activities."
This matter was referred to the Emerging Issues Task Force (EITF) in late
2003. Although the EITF has not issued formal guidance for oil and gas
companies, at the March 2004 meeting, the Task Force reached a consensus that
mineral rights for mining companies should be accounted for as tangible assets.
In order to resolve this inconsistency, the Board directed the FASB staff to
prepare a FASB Staff Position (FSP) that amended SFAS 141 and SFAS 142. FSP FAS
141-1 and 142-1 is effective for the first reporting period beginning after
April 29, 2004. As the Company already includes these assets as part of its
capitalized oil and gas properties the application of this FSP will not have an
impact on the Company.
(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).
5
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, 2004, the Company's derivative contracts were comprised of natural gas
swaps, collars and options. Qualifying NYMEX based derivative contracts are
designated as cash flow hedges.
During the first quarters of 2004 and 2003, a net loss of $3.9 million
($2.5 million after tax) and a net loss of $6.1 million ($3.9 million after
tax), respectively, were reclassified from accumulated other comprehensive
income to earnings. The fair value of open hedges decreased $11.0 million ($7.0
million after tax) in the first quarter of 2004 and decreased $14.4 million
($9.1 million after tax) in the first quarter of 2003. At March 31, 2004, the
estimated net loss in accumulated other comprehensive income that is expected to
be reclassified into earnings within the next 12 months is approximately $20.5
million. The Company has partially hedged its exposure to the variability in
future cash flows through December 2005.
(4) STOCK-BASED COMPENSATION
The Company measures expense associated with stock-based compensation
under the provisions of Accounting Principles Board Opinion No. (APB) 25,
"Accounting for Stock Issued to Employees" and its related interpretations.
Under APB 25, no compensation expense is required to be recognized by the
Company upon the issuance of stock options to key employees as the exercise
price of the option is equal to the market price of the underlying common stock
at the date of grant.
For purposes of the pro forma disclosures required by SFAS 123, the
estimated fair value of the options is amortized to expense over the options'
vesting period. The changes in net income or loss as if the Company had applied
the fair value provisions of SFAS 123 for the quarters ended March 31, 2004, and
2003 were not material.
The changes in share value and the vesting of shares are reported as
adjustments to compensation expense. The vesting of shares in the quarters ended
March 31, 2004, and 2003, resulted in an increase in compensation expense of
$19,000 and $18,000, respectively.
(5) INDUSTRY SEGMENT FINANCIAL INFORMATION
The Company operates in one reportable segment, as an independent energy
company engaged in producing oil and natural gas; exploring for and developing
oil and gas reserves; acquiring and enhancing the economic performance of
producing oil and gas properties; and 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.
6
(6) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
THREE MONTHS ENDED MARCH 31,
-----------------------------
(IN THOUSANDS) 2004 2003
----- -------
CASH PAID DURING THE PERIOD FOR:
Interest $ 981 $ 612
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF TAX -- 2,397
(7) SUBSEQUENT EVENT
In April 2004, the Company decided to dispose of its Arrow Oilfield
Service Company ("Arrow") assets. The Company is currently negotiating purchase
and sale agreements and expects the sale to be completed by the end of the
second quarter.
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," and 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
Securities and Exchange Commission ("SEC") guidance. See the "Notes to
Consolidated Financial Statements" included in "Item 8. Financial Statements and
Supplementary Data" in the Company's 2003 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
7
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 included in the Company's 2003
Form 10-K is based on estimates prepared by independent petroleum engineers.
Estimates prepared by others may be higher or lower than these estimates.
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.
8
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 determined 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. Impairment of unproved properties is based on the estimated fair value
of the property.
DERIVATIVES AND HEDGING
The Company recognizes all derivative financial instruments as either
assets or liabilities at fair value. Derivative instruments that are not hedges
must be adjusted to fair value through net income (loss). 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). Ineffective portions of a derivative instrument's change in fair value
are immediately recognized in net income (loss). Deferred gains and losses on
terminated commodity hedges will be recognized as increases or decreases to oil
and gas revenues during the same periods in which the underlying forecasted
transactions are recognized in net income (loss).
The relationship between the hedging instruments and the hedged items must
be highly effective in achieving the offset of changes in fair values or cash
flows attributable to the hedged risk both at the inception of the contract and
on an ongoing basis. The Company measures effectiveness on changes in the
hedge's intrinsic value. The Company considers these hedges to be highly
effective and expects there will be no ineffectiveness to be recognized in net
income (loss) since the critical terms of the hedging instruments and the hedged
forecasted transactions are the same. Ongoing assessments of hedge effectiveness
will include verifying and documenting that the critical terms of the hedge and
forecasted transaction do not change. The Company measures effectiveness on at
least a quarterly basis.
The Company's financial results and cash flows can be significantly
impacted as commodity prices fluctuate widely in response to changing market
conditions. To manage its exposure to natural gas or oil price volatility, the
Company has entered into NYMEX based commodity derivative contracts, currently
natural gas swaps and collars, and has designated the contracts for the special
hedge accounting treatment permitted under SFAS 133.
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 the goods or services have been
provided.
NEW ACCOUNTING PRONOUNCEMENTS
In 2003, the Company was made aware of an issue regarding the application
of provisions of SFAS 141, "Business Combinations" and SFAS 142, "Goodwill and
Other Intangible Assets," to oil and
9
gas companies. The issue was whether SFAS 142 required registrants to reclassify
costs associated with mineral rights, including both proved and unproved
leasehold acquisition costs, as intangible assets in the balance sheet, apart
from other capitalized oil and gas property costs. Historically, the Company and
other oil and gas companies have included the cost of oil and gas leasehold
interests as part of oil and gas properties and provided the disclosures
required by SFAS 69, "Disclosures about Oil and Gas Producing Activities."
This matter was referred to the EITF in late 2003. Although the EITF has
not issued formal guidance for oil and gas companies, at the March 2004 meeting,
the Task Force reached a consensus that mineral rights for mining companies
should be accounted for as tangible assets. In order to resolve this
inconsistency, the Board directed the FASB staff to prepare a FSP that amended
SFAS 141 and SFAS 142. FSP FAS 141-1 and 142-1 is effective for the first
reporting period beginning after April 29, 2004. As the Company already includes
these assets as part of its capitalized oil and gas properties the application
of this FSP will not have an impact on the Company.
RESULTS OF OPERATIONS - FIRST QUARTERS OF 2004 AND 2003 COMPARED
The following Management's Discussion and Analysis is based on the results
of operations from continuing operations, unless otherwise noted. Accordingly,
discontinued operations have been excluded.
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,
---------------------
2004 2003
--------- ---------
PRODUCTION
Gas (Mmcf) 4,036 3,443
Oil (Mbbls) 97 101
Total production (Mmcfe) 4,616 4,047
AVERAGE PRICE
Gas (per Mcf) $ 4.99 $ 4.76
Oil (per Bbl) 32.05 30.09
Mcfe 5.04 4.80
AVERAGE COSTS (PER MCFE)
Production expense 1.17 1.11
Production taxes 0.14 0.17
Depletion 0.82 0.78
OPERATING MARGIN (PER MCFE) 3.73 3.52
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
REVENUES
Net operating revenues increased from $27.5 million in the first quarter
of 2003 to $29.0 million in the first quarter of 2004. The increase was due to
higher gas sales revenues of $3.8 million partially offset by lower revenues
from gas gathering, marketing and oilfield service of $2.3 million.
Gas volumes sold increased 593 Mmcf (17%) from 3.4 Bcf (billion cubic
feet) in the first quarter of 2003 to 4.0 Bcf in the first quarter of 2004
resulting in an increase in gas sales revenues of approximately $2.8 million.
Oil volumes sold decreased approximately 4,000 Bbls (4%) from 101,000 Bbls in
the first quarter of 2003 to 97,000 Bbls in the first quarter of 2004 resulting
in a decrease in oil sales revenues of approximately $125,000. The gas volume
increase was primarily due to the production
10
from wells drilled in 2003 and 2004 including approximately 142 Mmcf from two
Trenton Black River ("TBR") wells that began production in December 2003 and
March 2004, respectively.
The average price realized for the Company's natural gas increased $0.23
per Mcf to $4.99 per Mcf in the first quarter of 2004 compared to the first
quarter of 2003 which increased gas sales revenues in the first quarter of 2004
by approximately $930,000. As a result of the Company's hedging activities, gas
sales revenues were decreased by $3.5 million ($0.88 per Mcf) in the first
quarter of 2004 and decreased by $6.1 million ($1.77 per Mcf) in the first
quarter of 2003. The average price paid for the Company's oil increased from
$30.09 per Bbl in the first quarter of 2003 to $32.05 per Bbl in the first
quarter of 2004 which increased oil sales revenues by approximately $190,000.
The operating margin from oil and gas sales (oil and gas sales revenues
less production expense and production taxes) on a per unit basis increased from
$3.52 per Mcfe in the first quarter of 2003 to $3.73 per Mcfe in the first
quarter of 2004.
The decrease in gas gathering, marketing and oilfield service revenues was
primarily due to a $1.8 million decrease in oilfield service revenues and a $1.2
million decrease in gas marketing revenues partially offset by a $540,000
increase in gas gathering revenues. The decrease in oilfield service revenues
was primarily due to a decrease in third-party drilling activities in Michigan
in the first quarter of 2004. The lower marketing revenues were the result of
decreased gas marketing activity partially offset by higher prices. The increase
in gas gathering revenues was primarily due to higher margins on a gathering
system in Pennsylvania.
COSTS AND EXPENSES
Production expense increased $916,000 (20%) from $4.5 million in the first
quarter of 2003 to $5.4 million in the first quarter of 2004 primarily due to
increased costs to stimulate production on declining wells in the higher oil and
natural gas price environment. These efforts increased production volumes during
the first quarter of 2004 but also had the effect of increasing the per unit
cost. The average production cost increased from $1.11 per Mcfe in the first
quarter of 2003 to $1.17 per Mcfe in the first quarter of 2004. The per unit
increase was primarily due to the higher costs incurred during the first quarter
of 2004 as discussed above partially offset by certain fixed costs spread over
greater volumes in the first quarter of 2004. Production taxes decreased $9,000
from $673,000 in the first quarter of 2003 to $664,000 in the first quarter of
2004.
Exploration expense decreased $165,000 from $2.2 million in the first
quarter of 2003 to $2.1 million in the first quarter of 2004.
General and administrative expense increased $61,000 from the first
quarter of 2003 to the first quarter of 2004. The Company incurred $176,000
related to strategic advisory services in the first quarter of 2004.
Depreciation, depletion and amortization increased by $616,000 from $4.3
million in the first quarter of 2003 to $4.9 million in the first quarter of
2004. This increase was primarily due to an increase in depletion. Depletion
expense increased $628,000 (20%) from $3.1 million in the first quarter of 2003
to $3.8 million in the first quarter of 2004 due to higher gas volumes and a
higher depletion rate per Mcfe. Depletion per Mcfe increased from $0.78 per Mcfe
in the first quarter of 2003 to $0.82 per Mcfe in the first quarter of 2004,
primarily due to higher production from higher cost wells.
Derivative fair value (gain) loss was a loss of $277,000 in the first
quarter of 2003 compared to a gain of $332,000 in the first quarter of 2004. The
derivative fair value (gain) loss reflects the changes in fair value of certain
derivative instruments that are not designated as cash flow hedges.
11
Interest expense increased $327,000 (5%) from $6.2 million in the first
quarter of 2003 to $6.5 million in the first quarter of 2004. This increase was
due to an increase in average outstanding borrowings partially offset by lower
blended interest rates.
Income tax expense increased $974,000 from $232,000 in the first quarter
of 2003 to $1.2 million in the first quarter of 2004. The increase was due to an
increase in income from continuing operations before income taxes and cumulative
effect of change in accounting principle in the first quarter of 2004.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS
The primary sources of cash in the three-month period ended March 31, 2004
have been from funds generated from operations and from borrowings under the
Company's $100 million revolving credit facility (the "Revolver"). Funds used
during this period were primarily used for operations, exploration and
development expenditures, interest expense and repayment of debt. 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 operating activities provided cash flows of $12.5 million
during the first quarter of 2004 compared to $7.8 million in the first quarter
of 2003. The increase was primarily due to higher cash received for oil and gas
revenues (net of hedging) of $3.8 million and changes in working capital items
of $1.7 million.
Cash flows used in investing activities decreased in the first quarter of
2004 primarily due to a $3.8 million acquisition in the first quarter of 2003
partially offset by $771,000 of increased capital expenditures in the first
quarter of 2004.
Cash flows used in financing activities in the first quarter of 2004 were
primarily due to payments on the credit facility. Cash flows used in financing
activities during the first quarter of 2003 were primarily due to borrowings on
the credit facility to fund acquisition, exploration and development
expenditures in the first quarter of 2003.
The Company's current ratio at March 31, 2004 was .71 to 1. During the
first three months of 2004, the working capital decreased $6.1 million from a
deficit of $7.0 million at December 31, 2003 to a deficit of $13.1 million at
March 31, 2004. The decrease was primarily due to a $5.8 million increase in the
net current liability for the fair value of derivatives in the first three
months of 2004 and a $4.1 million increase in accrued expenses partially offset
by a $2.2 million increase in the deferred income taxes asset and a $1.3 million
decrease in accounts payable. The $4.1 million increase in accrued expenses was
primarily due to an increase in accrued interest expense.
CAPITAL EXPENDITURES
During the first three months of 2004, the Company invested approximately
$5.3 million to drill 21 gross (19.8 net) development wells. All 21 of the wells
were successfully completed as producers in the target formation. This cost
excludes approximately $1.5 million related to 2 gross (1.0 net) TBR wells in
progress as of March 31, 2004. If these wells are determined to be dry holes,
their cost will be charged to exploratory dry hole expense in subsequent
periods.
The Company currently expects to spend approximately $36 million during
2004 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
and the sale of non-strategic assets. At March 31, 2004, the Company had
approximately $40.5 million available under the Revolver. The level of the
Company's future cash flow will depend on a number of
12
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.
FINANCING AND CREDIT FACILITIES
The Company has a $100 million revolving credit facility from Ableco
Finance LLC and Wells Fargo Foothill, Inc. which matures on June 30, 2006. The
Revolver bears interest at the prime rate plus two percentage points, payable
monthly. At March 31, 2004, the interest rate was 6.00%. At March 31, 2004, the
Company had $39.2 million of outstanding letters of credit. At March 31, 2004,
the outstanding balance under the credit agreement was $45.3 million with $40.5
million of borrowing capacity available for general corporate purposes.
The Revolver has a total commitment amount of $125 million including a
letter of credit sub-limit of $55 million and a special letter of credit
facility in the amount of $25 million which combined with the existing letter of
credit sub-limit of $55 million would allow a total of $80 million in letters of
credit. The Revolver's final maturity date is June 30, 2006.
The Revolver is subject to certain financial covenants. These include a
quarterly senior debt interest coverage ratio of 3.2 to 1 through March 31,
2006; and a senior debt leverage ratio of 2.7 to 1 through March 31, 2006. There
is an early termination fee, equal to .125% of the Revolver, through June 30,
2005. There is no termination fee after June 30, 2005.
The Company's agreement with its hedging counterparty requires letters of
credit based on an initial collateral requirement plus any negative market value
thereafter. The initial collateral requirement currently is approximately $10
million. At April 30, 2004, the Company's hedge position had a negative market
value of approximately $28.3 million and the aggregate minimum letter of credit
requirement was approximately $38.5 million. At April 30, 2004, the Company had
a total of $42.2 million of outstanding letters of credit.
The Company is required to hedge, through financial instruments or fixed
price contracts, at least 20% but not more than 80% of its estimated hydrocarbon
production, on a 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 September 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 provided
that the NYMEX strip price for natural gas shall not exceed $5.00 per Mmbtu
(million British thermal units). Prices are adjusted for basis differential,
fixed price contracts and financial hedges in place. The weighted average price
at March 31, 2004, was $5.00 per Mcfe. The present value (using a 10% discount
rate) of the Company's future net income at March 31, 2004, using the borrowing
base price forecast, was $463 million. The present value under the borrowing
base formula above was approximately $275 million for all proved reserves of the
Company and $182 million for properties secured by a mortgage.
The Revolver is subject to certain financial covenants. These include a
senior debt interest coverage ratio of 3.2 to 1 and a senior debt leverage ratio
of 2.7 to 1. EBITDA, as defined in the
13
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 March 31, 2004,
the Company's current ratio including the above adjustments was 4.26 to 1. The
Company had satisfied all financial covenants as of March 31, 2004.
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
2004 or 2003.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Among other risks, the Company is exposed to interest rate and commodity
price risks.
The interest rate risk relates to existing debt under the Company's
revolving credit facility as well as any new debt financing needed to fund
capital requirements. The Company may manage its interest rate risk through the
use of interest rate swaps to hedge the interest rate exposure associated with
the credit agreement, whereby a portion of the Company's floating rate exposure
is exchanged for a fixed interest rate. A portion of the Company's long-term
debt consists of senior subordinated notes where the interest component is
fixed. The Company had no derivative financial instruments for managing interest
rate risks in place as of March 31, 2004 or 2003. If market interest rates for
short-term borrowings increased 1%, the increase in the Company's interest
expense in the first quarter would be approximately $113,000. This sensitivity
analysis is based on the Company's financial structure at March 31, 2004.
The commodity price risk relates to natural gas and crude oil produced,
held in storage and marketed by the Company. The Company's financial results can
be significantly impacted as commodity prices fluctuate widely in response to
changing market forces. 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 commodity price volatility. The fixed-price
physical contracts generally have terms of a year or more. 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 or options. If NYMEX gas prices
decreased $0.50 per Mcf, the Company's gas sales revenues for the quarter would
decrease by $863,000, after considering the effects of the hedging contracts in
place. The Company had no hedges or fixed price contracts on its oil production
during 2004 or 2003. If the price of crude oil decreased $3.00 per Bbl, the
Company's oil sales revenues for the quarter would decrease by $290,000.
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 net pretax losses on its hedging
activities of $3.5 million in the first three months of 2004 and $6.1 million in
the first three months of 2003.
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
14
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 April 30, 2004:
NATURAL GAS SWAPS NATURAL GAS COLLARS FIXED PRICE CONTRACTS
---------------------------------- ------------------------------------ -------------------------
ESTIMATED NYMEX PRICE ESTIMATED ESTIMATED
NYMEX PRICE WELLHEAD PRICE PER MMBTU WELLHEAD PRICE ESTIMATED WELLHEAD PRICE
QUARTER ENDING BBTU PER MMBTU PER MCF BBTU FLOOR/CAP (1) PER MCF (1) MMCF PER MCF
- ------------------ ----- ----------- -------------- ----- ------------- -------------- --------- --------------
June 30, 2004 2,040 $ 3.84 $ 3.99 1,080 $ 4.00 - 5.80 $ 4.15 - 5.95 37 $ 4.06
September 30, 2004 2,040 3.84 3.99 1,080 4.00 - 5.80 4.15 - 5.95 -- --
December 31, 2004 2,040 3.84 4.06 1,080 4.00 - 5.80 4.22 - 6.02 -- --
----- ----------- -------------- ----- ------------- -------------- ---- --------------
6,120 $ 3.84 $ 4.01 3,240 $ 4.00 - 5.80 $ 4.17 - 5.97 37 $ 4.06
===== =========== ============== ===== ============= ============== ==== ==============
March 31, 2005 1,500 $ 3.84 $ 4.09 1,500 $ 4.00 - 5.37 $ 4.25 - 5.62
June 30, 2005 1,500 3.73 3.88 1,500 4.00 - 5.37 4.15 - 5.52
September 30, 2005 1,500 3.73 3.88 1,500 4.00 - 5.37 4.15 - 5.52
December 31, 2005 1,500 3.73 3.95 1,500 4.00 - 5.37 4.22 - 5.59
----- ----------- -------------- ----- ------------- --------------
6,000 $ 3.76 $ 3.95 6,000 $ 4.00 - 5.37 $ 4.19 - 5.56
===== =========== ============== ===== ============= ==============
MCF - THOUSAND CUBIC FEET MMBTU - MILLION BRITISH THERMAL UNITS
MMCF - MILLION CUBIC FEET BBTU - BILLION BRITISH THERMAL UNITS
(1) The NYMEX price per Mmbtu floor/cap and the estimated wellhead price per Mcf
for the natural gas collars in 2004 assume the monthly NYMEX settles at $3.00
per Mmbtu or higher. If the monthly NYMEX settles at less than $3.00 per Mmbtu
then the NYMEX price per Mmbtu will be the NYMEX settle plus $1.00 and the
estimated wellhead price per Mcf will be the NYMEX settle plus $1.15 to $1.25.
The NYMEX price per Mmbtu floor/cap and the estimated wellhead price per Mcf for
the natural gas collars in 2005 assume the monthly NYMEX settles at $3.10 per
Mmbtu or higher. If the monthly NYMEX settles at less than $3.10 per Mmbtu then
the NYMEX price per Mmbtu will be the NYMEX settle plus $0.90 and the estimated
wellhead price per Mcf will be the NYMEX settle plus $1.05 to $1.15.
ITEM 4. CONTROLS AND PROCEDURES
As of the end of the period covered by this quarterly report, the Company
carried out an evaluation, under the supervision and with the participation of
the Company's management, including the Company's Chief Executive Officer and
Chief Financial Officer, of the effectiveness of the design and operation of the
Company's disclosure controls and procedures pursuant to Exchange Act Rule
13a-15. Based upon the evaluation, the Chief Executive Officer and Chief
Financial Officer concluded that the Company's disclosure controls and
procedures were effective as of the end of the period covered by this quarterly
report. During the quarter ended March 31, 2004, there have been no changes in
the Company's internal controls over financial reporting, identified in
connection with our evaluation thereof that have materially affected, or are
reasonably likely to materially affect our internal control over financial
reporting.
15
PART II OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
10.1* Retention Plan.
31.1* Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2* Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1* Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2* Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1* Audit Committee Charter.
* Filed herewith
(b) Reports on Form 8-K
On February 9, 2004, the Company filed a Current Report on Form 8-K
dated February 9, 2004, reporting under Item 5 related to the Company's
significant wildcat discoveries in the Appalachian Trenton Black River trend and
planned 2004 drilling in the area.
On March 10, 2004, the Company filed a Current Report on Form 8-K
dated March 9, 2004, reporting under Item 5 related to the Company's engagement
of Randall & Dewey Partners, L.P., an oil and gas strategic advisory and
consulting firm based in Houston, Texas, to assist the Company in evaluating its
strategic alternatives.
On March 24, 2004, the Company filed a Current Report on Form 8-K
dated March 17, 2004, reporting under Item 9 related to the Company's
operational outlook for 2004 and capital expenditure plan for 2004.
16
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 7, 2004 By: /s/ John L. Schwager
-----------------------------------------
John L. Schwager, Director, President
and Chief Executive Officer
Date: May 7, 2004 By: /s/ Robert W. Peshek
-----------------------------------------
Robert W. Peshek, Senior Vice President
and Chief Financial Officer
17