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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 June 30, 2003
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
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 July 31, 2003, Belden & Blake Corporation had outstanding
10,349,994 shares of common stock, without par value, which is its only class of
stock.
BELDEN & BLAKE CORPORATION
INDEX
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PAGE
----
PART I Financial Information:
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2003 and
December 31, 2002................................................................ 1
Consolidated Statements of Operations for the three and six
months ended June 30, 2003 and 2002 ............................................. 2
Consolidated Statements of Shareholders' Equity (Deficit)
for the six months ended June 30, 2003 and the years
ended December 31, 2002 and 2001................................................. 3
Consolidated Statements of Cash Flows for the six
months ended June 30, 2003 and 2002 ............................................. 4
Notes to Consolidated Financial Statements.......................................... 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations.............................................. 10
Item 3. Quantitative and Qualitative Disclosures About Market Risk.......................... 22
Item 4. Controls and Procedures............................................................. 23
PART II Other Information
Item 6. Exhibits and Reports on Form 8-K.................................................... 24
BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
JUNE 30, DECEMBER 31,
2003 2002
--------- ---------
(UNAUDITED)
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 1,783 $ 1,722
Accounts receivable, net 18,698 14,652
Inventories 953 848
Deferred income taxes 7,954 4,200
Other current assets 1,566 1,341
Fair value of derivatives 24 --
Assets of discontinued operations 255 1,066
--------- ---------
TOTAL CURRENT ASSETS 31,233 23,829
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties (successful efforts method) 461,738 438,240
Gas gathering systems 14,743 14,482
Land, buildings, machinery and equipment 23,173 22,748
--------- ---------
499,654 475,470
Less accumulated depreciation, depletion and amortization 246,284 243,596
--------- ---------
PROPERTY AND EQUIPMENT, NET 253,370 231,874
FAIR VALUE OF DERIVATIVES 931 3
OTHER ASSETS 7,722 8,139
--------- ---------
$ 293,256 $ 263,845
========= =========
LIABILITIES AND SHAREHOLDERS' DEFICIT
CURRENT LIABILITIES
Accounts payable $ 5,580 $ 5,661
Accrued expenses 15,573 17,767
Current portion of long-term liabilities 759 315
Fair value of derivatives 14,216 5,486
Liabilities of discontinued operations 210 335
--------- ---------
TOTAL CURRENT LIABILITIES 36,338 29,564
LONG-TERM LIABILITIES
Bank and other long-term debt 44,149 26,868
Senior subordinated notes 225,000 225,000
Other 4,256 91
--------- ---------
273,405 251,959
FAIR VALUE OF DERIVATIVES 14,261 4,371
DEFERRED INCOME TAXES 21,818 22,596
SHAREHOLDERS' DEFICIT
Common stock without par value; $.10 stated value per share; authorized
58,000,000 shares; issued 10,557,457 and 10,490,440 shares
(which includes 206,534 and 194,890 treasury shares, respectively) 1,035 1,030
Paid in capital 107,174 107,118
Deficit (143,952) (148,332)
Accumulated other comprehensive loss (16,823) (4,461)
--------- ---------
TOTAL SHAREHOLDERS' DEFICIT (52,566) (44,645)
--------- ---------
$ 293,256 $ 263,845
========= =========
See accompanying notes
1
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, in thousands)
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
--------------------------- -------------------------
2003 2002 2003 2002
-------- -------- -------- --------
Revenues
Oil and gas sales $ 21,448 $ 23,714 $ 40,875 $ 45,572
Gas gathering, marketing, and oilfield service 5,814 6,503 13,918 13,133
Other 294 509 477 1,008
-------- -------- -------- --------
27,556 30,726 55,270 59,713
EXPENSES
Production expense 4,752 5,092 9,255 9,959
Production taxes 657 488 1,330 931
Gas gathering, marketing, and oilfield service 5,281 5,578 12,795 10,608
Exploration expense 2,501 3,262 4,743 5,851
General and administrative expense 1,087 1,174 2,261 2,376
Franchise, property and other taxes 87 74 158 145
Depreciation, depletion and amortization 4,436 5,852 8,767 11,852
Accretion expense 86 -- 172 --
Derivative fair value loss (gain) (451) (229) (174) 198
Severance and other nonrecurring expense -- 165 -- 165
-------- -------- -------- --------
18,436 21,456 39,307 42,085
-------- -------- -------- --------
OPERATING INCOME 9,120 9,270 15,963 17,628
OTHER EXPENSE
Interest expense 6,422 5,839 12,638 11,733
-------- -------- -------- --------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 2,698 3,431 3,325 5,895
Provision for income taxes 999 1,313 1,231 2,268
-------- -------- -------- --------
INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 1,699 2,118 2,094 3,627
(Loss) income from discontinued operations, net of tax (87) 462 (111) 397
-------- -------- -------- --------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 1,612 2,580 1,983 4,024
Cumulative effect of change in accounting principle, net of tax -- -- 2,397 --
-------- -------- -------- --------
NET INCOME $ 1,612 $ 2,580 $ 4,380 $ 4,024
======== ======== ======== ========
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, 2001 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 derivatve (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 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 income (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 income:
Net income 4,380 4,380
Other comprehensive income, net of tax:
Change in derivative fair value (17,788) (17,788)
Reclassification adjustment for derivative (gain)
loss reclassified into oil and gas sales 5,426 5,426
------------
Total comprehensive income (7,982)
------------
Stock options exercised 66 6 55 61
Stock-based compensation 36 36
Repurchase of stock options (48) (48)
Tax benefit of repurchase of stock options
and stock options exercised 37 37
Treasury stock (12) (1) (24) (25)
- ------------------------------------------ ---------- ---------- ----------- ------------ ------------- ------------
June 30, 2003 (unaudited) 10,350 $ 1,035 $ 107,174 $ (143,952) $ (16,823) $ (52,566)
========================================== ========== ========== =========== ============ ============= ============
See accompanying notes.
3
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED, IN THOUSANDS)
SIX MONTHS ENDED JUNE 30,
-------------------------
2003 2002
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Income from continuing operations $ 2,094 $ 3,627
Adjustments to reconcile income from continuing operations
to net cash provided by operating activities:
Depreciation, depletion and amortization 8,767 11,852
Accretion of discount on asset retirement obligations 172 --
Loss on disposal of property and equipment 610 158
Net monetization of derivatives -- 22,091
Amortization of derivatives and other noncash hedging activities 416 (9,223)
Exploration expense 4,743 5,852
Deferred income taxes (1,036) 2,266
Stock-based compensation 36 42
Change in operating assets and liabilities, net of
effects of acquisition and disposition of businesses:
Accounts receivable and other operating assets (4,416) (1,351)
Inventories (105) 90
Accounts payable and accrued expenses (2,275) 5,011
--------- ---------
NET CASH PROVIDED BY CONTINUING OPERATIONS 9,006 40,415
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of businesses, net of cash acquired (4,628) (1,630)
Disposition of businesses, net of cash 100 250
Proceeds from property and equipment disposals 118 85
Exploration expense (4,743) (5,852)
Additions to property and equipment (17,335) (17,471)
Increase in other assets (83) (378)
--------- ---------
NET CASH USED IN INVESTING ACTIVITIES (26,571) (24,996)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving line of credit 105,198 73,536
Repayment of long-term debt and other obligations (88,158) (90,974)
Proceeds from stock options exercised 61 5
Repurchase of stock options (48) (7)
Tax benefit of repurchase of stock options and stock options exercised 37 --
Purchase of treasury stock (25) (14)
--------- ---------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES 17,065 (17,454)
--------- ---------
NET DECREASE IN CASH AND CASH EQUIVALENTS
FROM CONTINUING OPERATIONS (500) (2,035)
NET INCREASE IN CASH AND CASH EQUIVALENTS
FROM DISCONTINUED OPERATIONS 561 1,329
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 1,722 1,935
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 1,783 $ 1,229
========= =========
See accompanying notes.
4
BELDEN & BLAKE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
JUNE 30, 2003
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(1) BASIS OF PRESENTATION
The accompanying unaudited consolidated financial statements of Belden
& Blake Corporation (the "Company") have been prepared in accordance with
generally accepted accounting principles for interim financial information and
with the instructions to Form 10-Q and Article 10 of Regulation S-X.
Accordingly, they do not include all of the information and footnotes required
by generally accepted accounting principles for complete financial statements.
In the opinion of management, all adjustments (consisting of normal recurring
accruals) considered necessary for a fair presentation have been included.
Operating results for the three and six month periods ended June 30, 2003 are
not necessarily indicative of the results that may be expected for the year
ended December 31, 2003. 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, 2002. Certain reclassifications have
been made to conform to the current presentation.
(2) NEW ACCOUNTING PRONOUNCEMENTS
On January 1, 2003, the Company adopted Financial Accounting Standards
Board (FASB) Statement of Financial Accounting Standards No. (SFAS) 143,
"Accounting for Asset Retirement Obligations." SFAS 143 amends SFAS 19,
"Financial Accounting and Reporting by Oil and Gas Producing Companies" to
require the Company to recognize a liability for the fair value of its asset
retirement obligations associated with its tangible, long-lived assets. The
majority of the asset retirement obligations recorded by the Company relate to
the plugging and abandonment (excluding salvage value) of its oil and gas
properties. At January 1, 2003, there were no assets legally restricted for
purposes of settling asset retirement obligations. The adoption of SFAS 143
resulted in a January 1, 2003 cumulative effect adjustment to record a $4.0
million increase in long-term asset retirement obligation liabilities, a
$621,000 increase in current asset retirement obligation liabilities, a $3.2
million increase in the carrying value of oil and gas assets, a $5.2 million
decrease in accumulated depreciation, depletion and amortization and a $1.4
million increase in deferred income tax liabilities. The net effect of adoption
was to record a gain of $2.4 million, net of tax, as a cumulative effect of a
change in accounting principle in the Company's consolidated statement of
operations in the first quarter of 2003.
Subsequent to the adoption of SFAS 143, there has been no significant
current period activity with respect to additional retirement obligations,
settled obligations, accretion expense and revisions of estimated cash flows.
The unaudited pro forma net income for the six months and quarter ended June 30,
2002 was $4.5 million and $2.8 million, respectively, and has been prepared to
give effect to the adoption of SFAS 143 as if it had been adopted on January 1,
2002. Assuming retroactive application of the change in accounting principle as
of January 1, 2002, liabilities would have increased $6 million.
5
A reconciliation of the Company's liability for plugging and
abandonment costs for the six months ended June 30, 2003 is as follows (in
thousands):
Asset retirement obligation, December 31, 2002 $ -
Cumulative effect adjustment 4,614
Liabilities incurred 66
Liabilities settled -
Accretion expense 172
------
Asset retirement obligation, June 30, 2003 $4,852
======
On January 1, 2003, the Company adopted SFAS 145, "Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from
Extinguishment of Debt," SFAS 44, "Accounting for Intangible Assets of Motor
Carriers" and SFAS 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund
Requirements" and amends SFAS No. 13, "Accounting for Leases." Statement 145
also makes technical corrections to other existing pronouncements. SFAS 4
required gains and losses from extinguishment of debt to be classified as an
extraordinary item, net of the related income tax effect. As a result of the
rescission of SFAS 4, the criteria for extraordinary items in Accounting
Principles Board Opinion No. (APB) 30, "Reporting the Results of Operations -
Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary,
Unusual and Infrequently Occurring Events and Transactions," now will be used to
classify those gains and losses. The adoption of SFAS 145 did not have any
effect on the Company's financial position, results of operations or cash flows.
In June 2002, the FASB issued SFAS 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS 146 is effective for the
Company for disposal activities initiated after December 31, 2002. The adoption
of this standard did not have any effect on the Company's financial position,
results of operations or cash flows.
In November 2002, the FASB issued FASB Interpretation No. (FIN) 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others." FIN 45's disclosure requirements
are effective for the Company's interim and annual financial statements for
periods ending after December 15, 2002. The initial recognition and measurement
provisions are applicable on a prospective basis to guarantees issued or
modified after December 31, 2002. FIN 45 requires certain guarantees to be
recorded at fair value, which is different from current practice, which is
generally to record a liability only when a loss is probable and reasonably
estimable. FIN 45 also requires a guarantor to make significant new disclosures,
even when the likelihood of making any payments under the guarantee is remote.
The adoption of FIN 45 did not have any effect on the Company's financial
statement disclosures, financial position, results of operations or cash flows.
In December 2002, the FASB issued SFAS 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure." SFAS 148 amends FASB 123, "Accounting
for Stock-Based Compensation," to provide alternative methods of transition for
a voluntary change to the fair value based method of accounting for stock-based
employee compensation. In addition, SFAS 148 amends the disclosure requirements
of SFAS 123 to require prominent disclosures in both annual and interim
financial statements about the method of accounting for stock-based employee
compensation and the effect of the method used on the reported results. The
Company measures expense associated with stock-based compensation using the
intrinsic value method prescribed by APB 25, "Accounting for Stock Issued to
Employees" and its related interpretations. Under APB 25, no compensation
expense is required to be
6
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. The provisions of SFAS 148 were effective for
financial statements for fiscal years ending after December 15, 2002. The
adoption of SFAS 148 did not have a material effect on the Company's financial
position, results of operations or cash flows.
The fair value of the Company's stock options was estimated at the date
of grant using a Black-Scholes option pricing model with the following
weighted-average assumptions for the first six months of 2003 and 2002,
respectively: risk-free interest rates of 3.6% and 4.5%, volatility factor of
the expected market price of the Company's common stock of near zero, dividend
yield of zero, and a weighted-average expected life of the option of seven
years.
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because the Company's stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
management's opinion, the existing models do not necessarily provide a reliable
single measure of the fair value of its stock options.
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 June 30, 2003 and
2002 were not material.
In January 2003, the FASB issued FIN 46, "Consolidation of Variable
Interest Entities - An Interpretation of Accounting Research Bulletin (ARB) 51."
FIN 46 is an interpretation of ARB 51, "Consolidated Financial Statements," and
addresses consolidation by business enterprises of variable interest entities
(VIEs). The primary objective of FIN 46 is to provide guidance on the
identification of, and financial reporting for, entities over which control is
achieved through means other than voting rights; such entities are known as
VIEs. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has
a variable interest that will absorb a majority of the entity's expected losses
if they occur, receive a majority of the entity's expected residual returns if
they occur or both. An enterprise shall consider the rights and obligations
conveyed by its variable interests in making this determination. This guidance
applies immediately to VIEs created after January 31, 2003, and to VIEs in which
an enterprise obtains an interest after that date. It applies in the first
fiscal year or interim period beginning after June 15, 2003, to VIEs in which an
enterprise holds a variable interest that it acquired before February 1, 2003.
The adoption of FIN 46 is not expected to have any effect on the Company's
financial statement disclosures, financial position, results of operations or
cash flows.
In April 2003, the FASB issued SFAS 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." This Statement is intended to
result in more consistent reporting of contracts as either freestanding
derivative instruments subject to Statement 133 in its entirety, or as hybrid
instruments with debt host contracts and embedded derivative features. SFAS 149
is effective for the Company's financial statements for the interim period
beginning July 1, 2003. The adoption of SFAS 149 is not expected to have a
material effect on the Company's financial position, results of operations or
cash flows.
In May 2003, the FASB issued SFAS 150, "Accounting for Financial
Instruments with Characteristics of both Liabilities and Equity." This Statement
establishes standards for classifying and measuring as liabilities certain
financial instruments that embody obligations of the issuer and have
7
characteristics of both liabilities and equity. Instruments that are indexed to
and potentially settled in an issuer's own shares that are not within the scope
of Statement 150 remain subject to existing guidance. SFAS 150 is effective for
the Company's financial statements for the interim period beginning July 1,
2003. The adoption of SFAS 150 is not expected to have a material effect on the
Company's financial position, results of operations or cash flows.
(3) ACQUISITION
In February 2003, the Company purchased reserves in certain wells the
Company operates in Michigan for $3.75 million in cash. These properties were
subject to a prior monetization transaction of the Section 29 tax credits which
the Company entered into in 1996. The Company had the option to purchase these
properties beginning in 2003. The Company previously held a production payment
on these properties including a 75% reversionary interest in certain future
production. The Company purchased those reserve volumes beyond its previously
held production payment along with the 25% reversionary interest not owned. The
estimated volumes acquired were 4.4 Bcf (billion cubic feet) of proved developed
producing gas reserves. The pro forma effect of the acquisition was not
material.
(4) 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
June 30, 2003, 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 six months of 2003 and 2002, a net loss of $8.5
million ($5.4 million after tax) and a net gain of $12.0 million ($7.6 million
after tax), respectively, were reclassified from accumulated other comprehensive
income to earnings. The fair value of open hedges decreased $28.0 million ($17.8
million after tax) in the first six months of 2003 and increased $1.4 million
($866,000 after tax) in the first six months of 2002. At June 30, 2003, the
estimated net loss in accumulated other comprehensive income that is expected to
be reclassified into earnings within the next 12 months is approximately $10.4
million.
8
The Company has partially hedged its exposure to the variability in future cash
flows through December 2005.
In March 2003, the Company entered into a collar for 4,320 Bbtu
(billion British thermal units) of its natural gas production in 2004 with a
ceiling price of $5.80 per Mmbtu (million British thermal units) and a floor
price of $4.00 per Mmbtu. The Company also sold a floor at $3.00 per Mmbtu on
this volume of gas. This aggregate structure has the effect of: 1) setting a
maximum price of $5.80 per Mmbtu; 2) floating at prices from $4.00 to $5.80 per
Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are between $3.00 and
$4.00 per Mmbtu; and 4) receiving a price of $1.00 per Mmbtu above the price if
the price is $3.00 or less. All prices are based on monthly NYMEX settle.
In April 2003, the Company entered into a collar for 6,000 Bbtu of its
natural gas production in 2005 with a ceiling price of $5.37 per Mmbtu and a
floor price of $4.00 per Mmbtu. The Company also sold a floor at $3.10 per Mmbtu
on this volume of gas. This aggregate structure has the effect of: 1) setting a
maximum price of $5.37 per Mmbtu; 2) floating at prices from $4.00 to $5.37 per
Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are between $3.10 and
$4.00 per Mmbtu; and 4) receiving a price of $0.90 per Mmbtu above the price if
the price is $3.10 or less. All prices are based on monthly NYMEX settle.
(5) LONG-TERM DEBT
The Company has a $100 million revolving credit facility (the
"Revolver") from Ableco Finance LLC and Foothill Capital Corporation which
matures on June 30, 2006. The Revolver bears interest at the prime rate plus two
percentage points, payable monthly. At June 30, 2003, the interest rate was
6.00%. At June 30, 2003, the Company had $46.5 million of outstanding letters of
credit. At June 30, 2003, the outstanding balance under the credit agreement was
$44.0 million with $34.5 million of borrowing capacity available for general
corporate purposes.
The Revolver was amended on March 31, 2003 to increase the letter of
credit sublimit to $55 million. On May 30, 2003, the Company amended its $100
million revolving credit facility. The amendment increased the total commitment
amount from $100 million to $125 million solely to provide for 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 amendment also extended the Revolver's final maturity
date to June 30, 2006, from December 31, 2005.
The Revolver, as amended, is subject to certain financial covenants.
These include a quarterly senior debt interest coverage ratio of 3.2 to 1
extended through March 31, 2006; and a senior debt leverage ratio of 2.7 to 1
extended through March 31, 2006. The amendment extended the early termination
fee, equal to .125% of the Revolver, to June 30, 2005, from December 31, 2004.
There is no termination fee after June 30, 2005.
(6) 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.
9
(7) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
SIX MONTHS ENDED JUNE 30,
-----------------------------
(IN THOUSANDS) 2003 2002
------------- -------------
CASH PAID DURING THE PERIOD FOR:
Interest $ 12,526 $ 12,610
Income taxes, net of refunds -- 5
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Acquisition of assets in exchange for long-term liabilities -- 263
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF TAX 2,397 --
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 SEC guidance. See the "Notes to Consolidated Financial Statements"
included in "Item 8. Financial Statements and Supplementary Data" in the
Company's 2002 Form 10-K annual report filed with the SEC for a comprehensive
discussion of the Company's significant accounting policies. GAAP requires
information in financial statements about the accounting principles and methods
used and the risks and uncertainties inherent in significant estimates including
choices between acceptable methods. Following is a discussion of the Company's
most critical accounting policies:
SUCCESSFUL EFFORTS METHOD OF ACCOUNTING
The accounting for and disclosure of oil and gas producing activities
requires the Company's management to choose between GAAP alternatives and to
make judgments about estimates of future uncertainties.
The Company utilizes the "successful efforts" method of accounting for
oil and gas producing activities as opposed to the alternate acceptable "full
cost" method. Under the successful efforts method,
10
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.
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
11
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 was
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. 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, options and collars, and has designated the contracts for the
special hedge accounting treatment. Had the Company not designated the
derivative contracts as hedges, the change in fair value of the contracts would
have been reflected directly in the statement of operations.
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
- -----------------------------
On January 1, 2003, the Company adopted SFAS 143, "Accounting for Asset
Retirement Obligations." SFAS 143 amends SFAS 19, "Financial Accounting and
Reporting by Oil and Gas Producing Companies" to require the Company to
recognize a liability for the fair value of its asset retirement obligations
associated with its tangible, long-lived assets. The majority of the asset
retirement obligations recorded by the Company relate to the plugging and
abandonment (excluding salvage value)
12
of its oil and gas properties. At January 1, 2003, there were no assets legally
restricted for purposes of settling asset retirement obligations. The adoption
of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record
a $4.0 million increase in long-term asset retirement obligation liabilities, a
$621,000 increase in current asset retirement obligation liabilities, a $3.2
million increase in the carrying value of oil and gas assets, a $5.2 million
decrease in accumulated depreciation, depletion and amortization and a $1.4
million increase in deferred income tax liabilities. The net effect of adoption
was to record a gain of $2.4 million, net of tax, as a cumulative effect of a
change in accounting principle in the Company's consolidated statement of
operations in the first quarter of 2003.
Subsequent to the adoption of SFAS 143, there has been no significant
current period activity with respect to additional retirement obligations,
settled obligations, accretion expense and revisions of estimated cash flows.
The unaudited pro forma net income for the six months and quarter ended June 30,
2002 was $4.5 million and $2.8 million, respectively, and has been prepared to
give effect to the adoption of SFAS 143 as if it had been adopted on January 1,
2002. Assuming retroactive application of the change in accounting principle as
of January 1, 2002, liabilities would have increased $6 million.
A reconciliation of the Company's liability for plugging and
abandonment costs for the six months ended June 30, 2003 is as follows (in
thousands):
Asset retirement obligation, December 31, 2002 $ -
Cumulative effect adjustment 4,614
Liabilities incurred 66
Liabilities settled -
Accretion expense 172
------
Asset retirement obligation, June 30, 2003 $4,852
======
On January 1, 2003, the Company adopted SFAS 145, "Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from
Extinguishment of Debt," SFAS 44, "Accounting for Intangible Assets of Motor
Carriers" and SFAS 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund
Requirements" and amends SFAS No. 13, "Accounting for Leases." Statement 145
also makes technical corrections to other existing pronouncements. SFAS 4
required gains and losses from extinguishment of debt to be classified as an
extraordinary item, net of the related income tax effect. As a result of the
rescission of SFAS 4, the criteria for extraordinary items in APB 30, "Reporting
the Results of Operations - Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions," now will be used to classify those gains and losses. The adoption
of SFAS 145 did not have any effect on the Company's financial position, results
of operations or cash flows.
In June 2002, the FASB issued SFAS 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS 146 is effective for the
Company for disposal activities initiated after December 31, 2002. The adoption
of this standard did not have any effect on the Company's financial position,
results of operations or cash flows.
In November 2002, the FASB issued FIN 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others." FIN 45's disclosure requirements are effective for the
Company's interim and annual financial statements for periods ending after
December 15, 2002. The initial recognition and measurement provisions are
13
applicable on a prospective basis to guarantees issued or modified after
December 31, 2002. FIN 45 requires certain guarantees to be recorded at fair
value, which is different from current practice, which is generally to record a
liability only when a loss is probable and reasonably estimable. FIN 45 also
requires a guarantor to make significant new disclosures, even when the
likelihood of making any payments under the guarantee is remote. The adoption of
FIN 45 did not have any effect on the Company's financial statement disclosures,
financial position, results of operations or cash flows.
In December 2002, the FASB issued SFAS 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure." SFAS 148 amends FASB 123, "Accounting
for Stock-Based Compensation," to provide alternative methods of transition for
a voluntary change to the fair value based method of accounting for stock-based
employee compensation. In addition, SFAS 148 amends the disclosure requirements
of SFAS 123 to require prominent disclosures in both annual and interim
financial statements about the method of accounting for stock-based employee
compensation and the effect of the method used on the reported results. The
Company measures expense associated with stock-based compensation using the
intrinsic value method prescribed by 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. The provisions
of SFAS 148 were effective for financial statements for fiscal years ending
after December 15, 2002. The adoption of SFAS 148 did not have a material effect
on the Company's financial position, results of operations or cash flows.
The fair value of the Company's stock options was estimated at the date
of grant using a Black-Scholes option pricing model with the following
weighted-average assumptions for the first six months of 2003 and 2002,
respectively: risk-free interest rates of 3.6% and 4.5%, volatility factor of
the expected market price of the Company's common stock of near zero, dividend
yield of zero, and a weighted-average expected life of the option of seven
years.
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because the Company's stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
management's opinion, the existing models do not necessarily provide a reliable
single measure of the fair value of its stock options.
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 June 30, 2003 and
2002 were not material.
In January 2003, the FASB issued FIN 46, "Consolidation of Variable
Interest Entities - An Interpretation of Accounting Research Bulletin (ARB) 51."
FIN 46 is an interpretation of ARB 51, "Consolidated Financial Statements," and
addresses consolidation by business enterprises of VIEs. The primary objective
of FIN 46 is to provide guidance on the identification of, and financial
reporting for, entities over which control is achieved through means other than
voting rights; such entities are known as VIEs. FIN 46 requires an enterprise to
consolidate a VIE if that enterprise has a variable interest that will absorb a
majority of the entity's expected losses if they occur, receive a majority of
the entity's expected residual returns if they occur or both. An enterprise
shall consider the rights and obligations conveyed by its variable interests in
making this determination. This guidance applies immediately to VIEs created
after January 31, 2003, and to VIEs in which an enterprise obtains an interest
after that date. It applies in
14
the first fiscal year or interim period beginning after June 15, 2003, to VIEs
in which an enterprise holds a variable interest that it acquired before
February 1, 2003. The adoption of FIN 46 is not expected to have any effect on
the Company's financial statement disclosures, financial position, results of
operations or cash flows.
In April 2003, the FASB issued SFAS 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." This Statement is intended to
result in more consistent reporting of contracts as either freestanding
derivative instruments subject to Statement 133 in its entirety, or as hybrid
instruments with debt host contracts and embedded derivative features. SFAS 149
is effective for the Company's financial statements for the interim period
beginning July 1, 2003. The adoption of SFAS 149 is not expected to have a
material effect on the Company's financial position, results of operations or
cash flows.
In May 2003, the FASB issued SFAS 150, "Accounting for Financial
Instruments with Characteristics of both Liabilities and Equity." This Statement
establishes standards for classifying and measuring as liabilities certain
financial instruments that embody obligations of the issuer and have
characteristics of both liabilities and equity. Instruments that are indexed to
and potentially settled in an issuer's own shares that are not within the scope
of Statement 150 remain subject to existing guidance. SFAS 150 is effective for
the Company's financial statements for the interim period beginning July 1,
2003. The adoption of SFAS 150 is not expected to have a material effect on the
Company's financial position, results of operations or cash flows.
RESULTS OF OPERATIONS - THREE AND SIX MONTHS ENDED JUNE 30, 2003 AND 2002
COMPARED
The following Management's Discussion and Analysis is based on the
results of operations from continuing operations, unless otherwise noted.
Accordingly, the 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 JUNE 30 SIX MONTHS ENDED JUNE 30,
-------------------------- -------------------------
2003 2002 2003 2002
-------- ------- ------- -------
PRODUCTION
Gas (Mmcf) 3,617 4,069 7,060 8,282
Oil (Mbbls) 102 143 203 291
Total production (Mmcfe) 4,229 4,927 8,276 10,025
AVERAGE PRICE
Gas (per Mcf) $ 5.18 $ 5.01 $ 4.98 $ 4.77
Oil (per Bbl) 26.59 23.41 28.33 20.91
Mcfe 5.07 4.81 4.94 4.55
AVERAGE COSTS (PER MCFE)
Production expense 1.12 1.03 1.12 0.99
Production taxes 0.16 0.10 0.16 0.09
Depletion 0.77 0.88 0.77 0.88
OPERATING MARGIN (PER MCFE) 3.79 3.68 3.66 3.47
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
15
RESULTS OF OPERATIONS - SECOND QUARTERS OF 2003 AND 2002 COMPARED
Operating income decreased $150,000 (2%) from $9.3 million in the
second quarter of 2002 to $9.1 million in the second quarter of 2003. This
decrease was primarily a result of a $2.5 million (13%) decrease in operating
margins partially offset by a $1.5 million decrease in depreciation, depletion
and amortization and a $761,000 (23%) decrease in exploration expense.
The $2.5 million decrease in operating margins was primarily due to a
$2.1 million decrease in the operating margin from oil and gas sales resulting
primarily from a decrease in oil and gas volumes sold partially offset by an
increase in the average prices realized for the Company's oil and natural gas in
the second quarter of 2003. A $392,000 decrease in the operating margin from gas
gathering, marketing and oilfield service also contributed to the decrease in
operating margins.
Income from continuing operations before income taxes and cumulative
effect of change in accounting principle decreased $733,000 from $3.4 million in
the second quarter of 2002 to $2.7 million in the second quarter of 2003. This
decrease is due primarily to the decrease in operating income discussed above
and a $583,000 increase in interest expense.
Net income decreased $1.0 million from $2.6 million in the second
quarter of 2002 to $1.6 million in the second quarter of 2003. This decrease was
a result of the decrease in income from continuing operations before income
taxes and cumulative effect of change in accounting principle discussed above
and a $549,000 decrease in income from discontinued operations, net of tax. This
decrease was partially offset by a $314,000 decrease in the provision for income
taxes.
Total revenues decreased $3.2 million (10%) in the second quarter of
2003 compared to the second quarter of 2002 due to a $2.3 million decrease in
oil and gas sales revenues, a $689,000 decrease in gas gathering, marketing and
oilfield service revenues and a $215,000 decrease in other revenues. The
decrease in other revenues is due to the loss of revenue from Section 29 tax
credit monetization transactions which ended upon expiration of the
non-conventional fuel source tax credit as of December 31, 2002. The decrease in
gas gathering, marketing and oilfield service revenues was due to a $2.0 million
decrease in gas marketing revenues resulting from a decrease in gas marketing
activity and the termination of a gas marketing contract and a $273,000 decrease
in gas gathering revenues partially offset by a $1.6 million increase in
oilfield service revenues as a result of the acquisition of a drilling
consulting business in the second quarter of 2002.
Gas volumes sold in the second quarter of 2003 were 3.6 Bcf, a decrease
of 452 Mmcf (11%) compared to the second quarter of 2002 due primarily to the
sale of wells in Ohio and Pennsylvania during 2002 and the natural decline of
the wells partially offset by production from wells drilled in 2003 and 2002.
The decrease in gas volumes sold resulted in a decrease in gas sales revenues of
approximately $2.3 million. Oil volumes sold decreased 41,000 Bbls (29%) from
143,000 Bbls in the second quarter of 2002 to 102,000 Bbls in the second quarter
of 2003 primarily due to the sale of wells in Ohio during 2002 and the natural
decline of the wells. This resulted in a decrease in oil sales revenues of
approximately $960,000.
The average price realized for the Company's natural gas increased
$0.17 per Mcf to $5.18 per Mcf in the second quarter of 2003 compared to the
second quarter of 2002, which increased gas sales revenues in the second quarter
of 2003 by approximately $610,000. As a result of the Company's hedging
activities, gas sales revenues for the second quarter of 2003 decreased by
approximately $2.4 million or $0.67 per Mcf compared to an increase of
approximately $5.4 million or $1.34 per Mcf for the second quarter of 2002. The
average price realized for the Company's oil increased from $23.41 per Bbl
16
in the second quarter of 2002 to $26.59 per Bbl in the second quarter of 2003
which increased oil sales revenues by approximately $320,000.
Production expense decreased $340,000 (7%) from $5.1 million in the
second quarter of 2002 to $4.8 million in the second quarter of 2003 primarily
due to the sale of wells in Ohio and Pennsylvania during 2002 partially offset
by increased costs to stimulate production on declining wells in the higher oil
and natural gas price environment of 2003. The average production cost increased
from $1.03 per Mcfe in the second quarter of 2002 to $1.12 per Mcfe in the
second quarter of 2003 due to the cost increases and lower volumes discussed
above. Production taxes increased $169,000 from $488,000 in the second quarter
of 2002 to $657,000 in the second quarter of 2003. Average per unit production
taxes increased from $0.10 per Mcfe in the second quarter of 2002 to $0.16 per
Mcfe in the second quarter of 2003 primarily due to higher oil and gas prices in
Michigan, where production taxes are based on a percentage of revenues,
excluding the effect of hedging.
Exploration expense decreased $761,000 (23%) from $3.3 million in the
second quarter of 2002 to $2.5 million in the second quarter of 2003 primarily
due to a $425,000 decrease in dry hole expense and decreased geophysical
expenditures partially offset by higher leasing costs.
General and administrative expense decreased $87,000 (7%) from $1.2
million in the second quarter of 2002 to $1.1 million in the second quarter of
2003.
Depreciation, depletion and amortization decreased by $1.5 million
(24%) from $5.9 million in the second quarter of 2002 to $4.4 million in the
second quarter of 2003. Depletion expense decreased $1.0 million (24%) from $4.3
million in the second quarter of 2002 to $3.3 million in the second quarter of
2003 due to lower oil and gas volumes sold and a lower depletion rate per Mcfe.
Depletion per Mcfe decreased from $0.88 per Mcfe in the second quarter of 2002
to $0.77 per Mcfe in the second quarter of 2003. This decrease in the depletion
rate per Mcfe was primarily due to higher reserves resulting from higher oil and
gas prices at year-end 2002, excluding the effect of hedging, and the effect of
the adoption of SFAS 143. The depreciable basis of oil and gas properties was
increased by the fair value of the estimated future plugging liability and
decreased by the gross amount of the estimated salvage value of the well
equipment.
Interest expense increased $583,000 (10%) from $5.8 million in the
second quarter of 2002 to $6.4 million in the second quarter of 2003 due to the
allocation of interest to discontinued operations in the second quarter of 2002
and higher blended interest rates in the second quarter of 2003.
Income tax expense decreased $314,000 from $1.3 million in the second
quarter of 2002 to $1.0 million in the second quarter of 2003 due primarily to
the decrease in income from continuing operations.
In accordance with SFAS 144, the Company was required to reclassify the
assets, liabilities and results of discontinued operations for all accounting
periods presented. Although both revenues and expenses for prior periods were
reclassified, there was no impact upon previously reported net earnings.
RESULTS OF OPERATIONS - SIX MONTHS OF 2003 AND 2002 COMPARED
Operating income decreased $1.6 million (9%) from $17.6 million in the
first six months of 2002 to $16.0 million in the first six months of 2003. This
decrease was primarily a result of a $5.8 million (16%) decrease in operating
margins partially offset by a $3.1 million decrease in depreciation, depletion
and amortization and a $1.2 million decrease in exploration expense.
The $5.8 million decrease in operating margins was primarily due to a
$4.4 million decrease in the operating margin from oil and gas sales resulting
primarily from a decrease in oil and gas volumes
17
sold partially offset by an increase in the average prices realized for the
Company's oil and natural gas in the first six months of 2003. A $1.4 million
decrease in the operating margin from gas gathering, marketing and oilfield
service, resulting primarily from a lower margin on a gathering system in
Pennsylvania, also contributed to the decrease in operating margins.
Income from continuing operations before income taxes and cumulative
effect of change in accounting principle decreased $2.6 million from $5.9
million in the first six months of 2002 to $3.3 million in the first six months
of 2003. This decrease is due primarily to the decrease in operating income
discussed above and a $905,000 increase in interest expense.
Net income increased $356,000 from $4.0 million in the first six months
of 2002 to $4.4 million in the first six months of 2003. This increase was a
result of a $2.4 million gain on the cumulative effect of change in accounting
principle, net of tax, recorded in the first six months of 2003 related to asset
retirement obligations and a decrease in the provision for income taxes of $1.0
million. This increase in net income was partially offset by the decrease in
income from continuing operations before income taxes and cumulative effect of
change in accounting principle discussed above and a $508,000 decrease in income
from discontinued operations.
Total revenues decreased $4.4 million (7%) in the first six months of
2003 compared to the first six months of 2002 due to a $4.7 million decrease in
oil and gas sales revenues and a $531,000 decrease in other revenues partially
offset by a $785,000 increase in gas gathering, marketing and oilfield service
revenues. The decrease in other revenues is due to the loss of revenue from
Section 29 tax credit monetization transactions which ended upon expiration of
the non-conventional fuel source tax credit as of December 31, 2002. The
increase in gas gathering, marketing and oilfield service revenues was due
primarily to a $4.9 million increase in oilfield service revenues primarily from
drilling operations as a result of the acquisition of a drilling consulting
business in the second quarter of 2002. This increase was partially offset by a
$4.1 million decrease in gas gathering and marketing revenues resulting from a
decrease in gas marketing activity and the termination of a gas marketing
contract and lower revenues from a gas gathering system in Pennsylvania.
Gas volumes sold in the first six months of 2003 were 7.1 Bcf, a
decrease of 1.2 Bcf (15%) compared to the first six months of 2002 due primarily
to the sale of wells in Ohio and Pennsylvania during 2002, extreme weather
conditions experienced in the first quarter of 2003 and the natural decline of
the wells partially offset by production from wells drilled in 2003 and 2002.
The decrease in gas volumes sold resulted in a decrease in gas sales revenues of
approximately $5.8 million. Oil volumes sold decreased 88,000 Bbls (30%) from
291,000 Bbls in the first six months of 2002 to 203,000 Bbls in the first six
months of 2003 primarily due the sale of wells in Ohio during 2002, extreme
weather conditions experienced in the first quarter of 2003 and the natural
decline of the wells. This resulted in a decrease in oil sales revenues of
approximately $1.8 million. The extreme weather conditions, including colder
temperatures and greater snowfall, negatively impacted production during the
first quarter of 2003 due to mechanical breakdowns and freezing of pipelines and
wellheads which reduced production along with difficulty accessing wells for
production and well maintenance.
The average price realized for the Company's natural gas increased
$0.21 per Mcf to $4.98 per Mcf in the first six months of 2003 compared to the
first six months of 2002 which increased gas sales revenues in the first six
months of 2003 by approximately $1.5 million. As a result of the Company's
hedging activities, gas sales revenues for the first six months of 2003
decreased by approximately $8.5 million or $1.21 per Mcf compared to an increase
of approximately $11.9 million or $1.44 per Mcf for the first six months of
2002. The average price realized for the Company's oil increased from $20.91 per
Bbl in the first six months of 2002 to $28.33 per Bbl in the first six months of
2003 which increased oil sales revenues by approximately $1.5 million.
18
Production expense decreased $704,000 (7%) from $10.0 million in the
first six months of 2002 to $9.3 million in the first six months of 2003
primarily due to the sale of wells in Ohio and Pennsylvania during 2002
partially offset by additional costs incurred as a result of colder temperatures
and greater amounts of snow during the first quarter of 2003 and increased costs
to stimulate production on declining wells in the higher oil and natural gas
price environment of 2003. The average production cost increased from $0.99 per
Mcfe in the first six months of 2002 to $1.12 per Mcfe in the first six months
of 2003 due to the cost increases and lower volumes discussed above. Production
taxes increased $399,000 from $931,000 in the first six months of 2002 to $1.3
million in the first six months of 2003. Average per unit production taxes
increased from $0.09 per Mcfe in the first six months of 2002 to $0.16 per Mcfe
in the first six months of 2003 primarily due to higher oil and gas prices in
Michigan, where production taxes are based on a percentage of revenues,
excluding the effect of hedging.
Exploration expense decreased $1.2 million (19%) from $5.9 million in
the first six months of 2002 to $4.7 million in the first six months of 2003
primarily due to a $887,000 decrease in dry hole expense and decreased
geophysical expenditures partially offset by higher leasing costs.
General and administrative expense decreased $115,000 (5%) from $2.4
million in the first six months of 2002 to $2.3 million in the first six months
of 2003.
Depreciation, depletion and amortization decreased by $3.1 million
(26%) from $11.9 million in the first six months of 2002 to $8.8 million in the
first six months of 2003. Depletion expense decreased $2.5 million (28%) from
$8.9 million in the first six months of 2002 to $6.4 million in the first six
months of 2003 due to lower oil and gas volumes sold and a lower depletion rate
per Mcfe. Depletion per Mcfe decreased from $0.88 per Mcfe in the first six
months of 2002 to $0.77 per Mcfe in the first six months of 2003. This decrease
in the depletion rate per Mcfe was primarily due to higher reserves resulting
from higher oil and gas prices at year-end 2002, excluding the effect of
hedging, and the effect of the adoption of SFAS 143. The depreciable basis of
oil and gas properties was increased by the fair value of the estimated future
plugging liability and decreased by the gross amount of the estimated salvage
value of the well equipment.
Interest expense increased $905,000 (8%) from $11.7 million in the
first six months of 2002 to approximately $12.6 million in the first six months
of 2003 due to the allocation of interest to discontinued operations in the
first six months of 2002 and higher blended interest rates in the first six
months of 2003. This increase was partially offset by a decrease in average
outstanding borrowings in the first six months of 2003.
Income tax expense decreased $1.1 million from $2.3 million in the
first six months of 2002 to $1.2 million in the first six months of 2003 due
primarily to the decrease in income from continuing operations.
In accordance with SFAS 144, the Company was required to reclassify the
assets, liabilities and results of discontinued operations for all accounting
periods presented. Although both revenues and expenses for prior periods were
reclassified, there was no impact upon previously reported net earnings
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 June 30, 2003 was .86 to 1. During the
first six months of 2003, the working capital from continuing operations
increased $1.3 million from a deficit of $6.5 million at
19
December 31, 2002 to a deficit of $5.2 million at June 30, 2003. The increase
was primarily due to a $4.0 million increase in accounts receivable, a $3.8
million increase in the deferred income taxes asset and a $2.2 million decrease
in accrued expenses partially offset by $8.7 million decrease in the fair value
of derivatives in the first six months of 2003. The $4.0 million increase in
accounts receivable was primarily due to higher natural gas prices. The
Company's operating activities provided cash flows of $9.0 million during the
first six months of 2003.
The Company has a $100 million revolving credit facility from Ableco
Finance LLC and Foothill Capital Corporation which matures on June 30, 2006. The
Revolver bears interest at the prime rate plus two percentage points, payable
monthly. At June 30, 2003, the interest rate was 6.00%. At June 30, 2003, the
Company had $46.5 million of outstanding letters of credit. At June 30, 2003,
the outstanding balance under the credit agreement was $44.0 million with $34.5
million of borrowing capacity available for general corporate purposes.
The Revolver was amended on March 31, 2003 to increase the letter of
credit sublimit to $55 million. On May 30, 2003, the Company amended its $100
million revolving credit facility. The amendment increased the total commitment
amount from $100 million to $125 million solely to provide for 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 amendment also extended the Revolver's final maturity
date to June 30, 2006, from December 31, 2005.
The Revolver, as amended, is subject to certain financial covenants.
These include a quarterly senior debt interest coverage ratio of 3.2 to 1
extended through March 31, 2006; and a senior debt leverage ratio of 2.7 to 1
extended through March 31, 2006. The amendment extended the early termination
fee, equal to .125% of the Revolver, to June 30, 2005, from December 31, 2004.
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 July 31, 2003, the Company's hedge position had a negative
market value of approximately $17.7 million and the aggregate minimum letter of
credit requirement was approximately $27.9 million. At July 31, 2003, the
Company had a total of $31.9 million of outstanding letters of credit.
The Revolver has an early termination fee equal to .125% of the
facility if terminated by June 30, 2005. There is no termination fee after June
30, 2005. 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 August 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.
Prices are adjusted for basis differential, fixed price contracts and financial
hedges in place. The weighted average price at June 30, 2003, was $5.07 per
20
Mcfe. The present value (using a 10% discount rate) of the Company's future net
income at June 30, 2003, using the borrowing base price forecast, was $466
million. The present value under the borrowing base formula above was
approximately $272 million for all proved reserves of the Company and $184
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 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 June 30, 2003, the Company's current ratio including
the above adjustments was 3.26 to 1. The Company had satisfied all financial
covenants as of June 30, 2003.
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 six months of 2003
or 2002.
During the first six months of 2003, the Company invested $12.2
million, including exploratory dry hole expense, to drill 41 development wells
and four exploratory wells. All 41 of the development wells and two of the
exploratory wells were successfully completed as producers in the target
formation. This cost excludes approximately $3.5 million related to 4 gross (2.8
net) TBR wells in progress as of June 30, 2003. If these wells are determined to
be dry holes, their cost will be charged to exploratory dry hole expense in
subsequent periods.
The Company had four exploratory wells in progress at December 31,
2002. One Trenton Black River ("TBR") well was completed and began production in
April. Gas production rates from this well declined rapidly and it is currently
shut-in for further evaluation. Another TBR well is being completed and is
expected to begin production in the third quarter. A Michigan well was
determined to be dry and approximately $300,000 was recorded as exploratory dry
hole expense in the second quarter of 2003. The fourth well is still being
evaluated. Two additional TBR wells drilled in 2003 and one TBR currently being
drilled are included in the wells in progress cost.
The Company currently expects to spend approximately $26 million during
2003 on its drilling activities, including exploratory dry hole expense, and
other capital expenditures. The Company is also evaluating additional drilling
opportunities that could increase its 2003 drilling expenditures by up to $10
million, dependent on the results of its current exploratory drilling program.
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 June 30, 2003, the Company had approximately $34.5
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.
As a result of the Company's decision to shift focus away from
exploration and development activities in the Knox formation in Ohio, the
Company has entered into an agreement to sell substantially all of its
undeveloped Knox acreage in Ohio. The Company has classified the net book value
of this
21
acreage as assets held-for-sale in oil and gas properties. The Company expects
to record a small gain on the sale that is expected to close by the end of the
third quarter.
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 June 30, 2003 or 2002. If market
interest rates for short-term borrowings increased 1%, the increase in the
Company's interest expense in the second quarter would be approximately
$110,000. This sensitivity analysis is based on the Company's financial
structure at June 30, 2003.
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 $480,000, after considering the effects of the hedging contracts in
place. The Company had no hedges or fixed price contracts on its oil production
during 2003 or 2002. If the price of crude oil decreased $3.00 per Bbl, the
Company's oil sales revenues for the quarter would decrease by $306,000.
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 a net pretax loss on its
hedging activities of $8.5 million in the first six months of 2003 and a net
pretax gain of $11.9 million in the first six months of 2002.
In March 2003, the Company entered into a collar for 4,320 Bbtu of its
natural gas production in 2004 with a ceiling price of $5.80 per Mmbtu and a
floor price of $4.00 per Mmbtu. The Company also sold a floor at $3.00 per Mmbtu
on this volume of gas. This aggregate structure has the effect of: 1) setting a
maximum price of $5.80 per Mmbtu; 2) floating at prices from $4.00 to $5.80 per
Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are between $3.00 and
$4.00 per Mmbtu; and 4) receiving a price of $1.00 per Mmbtu above the price if
the price is $3.00 or less. All prices are based on monthly NYMEX settle.
In April 2003, the Company entered into a collar for 6,000 Bbtu of its
natural gas production in 2005 with a ceiling price of $5.37 per Mmbtu and a
floor price of $4.00 per Mmbtu. The Company also sold a floor at $3.10 per Mmbtu
on this volume of gas. This aggregate structure has the effect of: 1) setting a
maximum price of $5.37 per Mmbtu; 2) floating at prices from $4.00 to $5.37 per
Mmbtu; 3)
22
locking in a price of $4.00 per Mmbtu if prices are between $3.10 and $4.00 per
Mmbtu; and 4) receiving a price of $0.90 per Mmbtu above the price if the price
is $3.10 or less. All prices are based on monthly NYMEX settle.
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 July 31, 2003:
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
- -------------------- --------- --------------- -------------- ------- --------------- ---------------- ----------- -------------
September 30, 2003 1,800 $ 3.92 $ 4.07 1,290 $ 3.40 - 5.23 $ 3.55 - 5.38 69 $ 4.02
December 31, 2003 1,800 3.92 4.14 1,290 3.40 - 5.23 3.62 - 5.45 55 4.00
--------- --------------- -------------- ------- --------------- ---------------- ----------- -------------
3,600 $ 3.92 $ 4.11 2,580 $ 3.40 - 5.23 $ 3.58 - 5.41 124 $ 4.01
========= =============== ============== ======= =============== ================ =========== =============
March 31, 2004 2,040 $ 3.84 $ 4.09 1,080 $ 4.00 - 5.80 $ 4.25 - 6.05 54 $ 4.10
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 5 3.20
December 31, 2004 2,040 3.84 4.06 1,080 4.00 - 5.80 4.22 - 6.02 5 3.20
--------- --------------- -------------- ------- --------------- ---------------- ----------- -------------
8,160 $ 3.84 $ 4.03 4,320 $ 4.00 - 5.80 $ 4.19 - 5.99 101 $ 4.00
========= =============== ============== ======= =============== ================ =========== =============
March 31, 2005 1,500 $ 3.84 $ 4.09 1,500 $ 4.00 - 5.37 $ 4.25 - 5.62 5 $ 4.00
June 30, 2005 1,500 3.73 3.88 1,500 4.00 - 5.37 4.15 - 5.52 5 4.00
September 30, 2005 1,500 3.73 3.88 1,500 4.00 - 5.37 4.15 - 5.52 5 4.00
December 31, 2005 1,500 3.73 3.95 1,500 4.00 - 5.37 4.22 - 5.59 5 4.00
--------- --------------- -------------- ------- --------------- ---------------- ----------- -------------
6,000 $ 3.76 $ 3.95 6,000 $ 4.00 - 5.37 $ 4.19 - 5.56 20 $ 4.00
========= =============== ============== ======= =============== ================ =========== =============
Bbtu - BILLION BRITISH THERMAL UNITS Mmcf - MILLION CUBIC FEET
Mmbtu - MILLION BRITISH THERMAL UNITS Mcf - THOUSAND CUBIC FEET
(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 June 30, 2003, 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.
23
PART II OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
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.
(b) Reports on Form 8-K
On April 10, 2003, the Company filed a Current Report on Form 8-K dated
March 31, 2003, reporting under Item 5 related to the Company's discontinued
operations and the Company's natural gas hedging position. The Company also
reported under Item 9 related to its operational outlook for 2003.
On June 10, 2003, the Company filed a Current Report on Form 8-K dated
May 30, 2003, reporting under Items 5 and 7 related to the Company's revolving
credit facility and under Item 9 related the operational outlook for 2003.
24
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: August 12, 2003 By: /s/ John L. Schwager
--------------------- ---------------------------------------
John L. Schwager, Director, President
and Chief Executive Officer
Date: August 12, 2003 By: /s/ Robert W. Peshek
--------------------- ---------------------------------------
Robert W. Peshek, Vice President
and Chief Financial Officer
25