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UNITED STATES
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, 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
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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, 2004, Belden & Blake Corporation had outstanding 1,500
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 June 30, 2004 and December 31, 2003................ 1
Consolidated Statements of Operations for the three and six months ended June 30,
2004 and 2003 ..................................................................... 2
Consolidated Statements of Shareholders' Equity (Deficit) for the six months ended
June 30, 2004 and the years ended December 31, 2003 and 2002...................... 3
Consolidated Statements of Cash Flows for the six months ended June 30, 2004
and 2003 .......................................................................... 4
Notes to Consolidated Financial Statements........................................... 5
Item 2. Management's Discussion and Analysis of Financial Condition and Results of
Operations......................................................................... 9
Item 3. Quantitative and Qualitative Disclosures About Market Risk........................... 18
Item 4. Controls and Procedures.............................................................. 20
PART II Other Information
Item 6. Exhibits and Reports on Form 8-K..................................................... 20
BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
JUNE 30, DECEMBER 31,
2004 2003
--------- ---------
(UNAUDITED)
ASSETS
- ------
CURRENT ASSETS
Cash and cash equivalents $ 45,616 $ 1,428
Accounts receivable, net 17,731 14,270
Inventories 701 780
Deferred income taxes 9,859 6,853
Other current assets 1,912 2,353
Fair value of derivatives 733 319
Assets of discontinued operations 3,721 22,230
--------- ---------
TOTAL CURRENT ASSETS 80,273 48,233
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties (successful efforts method) 463,403 452,167
Gas gathering systems 15,255 15,264
Land, buildings, machinery and equipment 13,076 13,173
--------- ---------
491,734 480,604
Less accumulated depreciation, depletion and amortization 258,539 250,162
--------- ---------
PROPERTY AND EQUIPMENT, NET 233,195 230,442
FAIR VALUE OF DERIVATIVES 528 755
OTHER ASSETS 5,371 5,881
--------- ---------
$ 319,367 $ 285,311
========= =========
LIABILITIES AND SHAREHOLDERS' DEFICIT
- -------------------------------------
CURRENT LIABILITIES
Accounts payable $ 3,931 $ 4,873
Accrued expenses 17,839 12,726
Current portion of long-term liabilities 665 729
Fair value of derivatives 23,182 14,765
Liabilities of discontinued operations 4,378 3,811
--------- ---------
TOTAL CURRENT LIABILITIES 49,995 36,904
LONG-TERM LIABILITIES
Bank and other long-term debt 23,954 47,503
Senior subordinated notes 225,000 225,000
Other 4,264 4,108
--------- ---------
253,218 276,611
FAIR VALUE OF DERIVATIVES 9,853 9,723
DEFERRED INCOME TAXES 34,726 19,413
SHAREHOLDERS' DEFICIT
Common stock without par value; $.10 stated value per share;
authorized 58,000,000 shares; issued 10,675,428 and 10,610,450
shares (which includes 221,888 and 214,593 treasury shares,
respectively) 1,045 1,040
Paid in capital 108,640 107,633
Deficit (117,085) (150,656)
Accumulated other comprehensive loss (21,025) (15,357)
--------- ---------
TOTAL SHAREHOLDERS' DEFICIT (28,425) (57,340)
--------- ---------
$ 319,367 $ 285,311
========= =========
See accompanying notes.
1
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED, IN THOUSANDS)
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
--------------------------- -------------------------
2004 2003 2004 2003
------- -------- -------- --------
REVENUES
Oil and gas sales $22,945 $ 21,250 $ 45,307 $ 40,677
Gas gathering and marketing 2,474 2,244 5,057 5,495
Other 329 240 458 400
------- -------- -------- --------
25,748 23,734 50,822 46,572
EXPENSES
Production expense 5,545 4,766 10,951 9,322
Production taxes 648 656 1,300 1,329
Gas gathering and marketing 2,300 1,929 4,533 5,236
Exploration expense 1,369 1,589 2,717 3,241
General and administrative expense 1,265 1,096 2,500 2,270
Franchise, property and other taxes 45 49 115 105
Depreciation, depletion and amortization 4,535 4,121 9,089 8,151
Accretion expense 100 80 195 162
Derivative fair value (gain) loss 11 (451) (321) (174)
------- -------- -------- --------
15,818 13,835 31,079 29,642
------- -------- -------- --------
OPERATING INCOME 9,930 9,899 19,743 16,930
OTHER EXPENSE
Interest expense 6,112 6,036 12,184 11,941
------- -------- -------- --------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 3,818 3,863 7,559 4,989
Provision for income taxes 1,240 1,406 2,615 1,813.
------- -------- -------- --------
INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 2,578 2,457 4,944 3,176
Income (loss) from discontinued operations, net of tax 28,941 (845) 28,627 (1,193)
------- -------- -------- --------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 31,519 1,612 33,571 1,983
Cumulative effect of change in accounting principle, net of tax -- -- -- 2,397
------- -------- -------- --------
NET INCOME $31,519 $ 1,612 $ 33,571 $ 4,380
======= ======== ======== ========
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 33,571 33,571
Other comprehensive income, net of tax:
Change in derivative fair value (11,180) (11,180)
Reclassification adjustment for derivative (gain) loss
reclassified into oil and gas sales 5,512 5,512
--------
Total comprehensive income 27,903
--------
Stock options exercised 65 6 105 111
Stock-based compensation 1,097 1,097
Repurchase of stock options (283) (283)
Tax benefit of repurchase of stock options and stock
options exercised 116 116
Treasury stock (6) (1) (28) (29)
------ ------- --------- --------- -------- --------
JUNE 30, 2004 (UNAUDITED) 10,455 $ 1,045 $ 108,640 $(117,085) $(21,025) $(28,425)
====== ======= ========= ========= ======== ========
See accompanying notes.
3
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED, IN THOUSANDS)
SIX MONTHS ENDED JUNE 30,
-------------------------
2004 2003
---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Income from continuing operations $ 4,944 $ 3,176
Adjustments to reconcile income from continuing operations
to net cash provided by operating activities:
Depreciation, depletion and amortization 9,089 8,151
Accretion 195 162
Loss on disposal of property and equipment 375 610
Amortization of derivatives and other noncash hedging activities (549) 416
Exploration expense 2,717 3,241
Deferred income taxes 2,896 1,813
Stock-based compensation 1,097 36
Change in operating assets and liabilities, net of
effects of acquisition and disposition of businesses:
Accounts receivable and other operating assets (4,486) (5,506)
Inventories 79 (102)
Accounts payable and accrued expenses 2,237 (2,371)
--------- ---------
NET CASH PROVIDED BY CONTINUING OPERATIONS 18,594 9,626
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of businesses, net of cash acquired -- (4,628)
Disposition of businesses, net of cash -- 100
Proceeds from property and equipment disposals 247 118
Exploration expense (2,717) (3,241)
Additions to property and equipment (11,228) (6,556)
Decrease (increase) in other assets 1,218 (83)
--------- ---------
NET CASH USED IN INVESTING ACTIVITIES (12,480) (14,290)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving line of credit 140,679 105,198
Repayment of long-term debt and other obligations (164,335) (88,158)
Debt issue costs 131 --
Proceeds from stock options exercised 111 61
Repurchase of stock options (283) (48)
Purchase of treasury stock (29) (25)
--------- ---------
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES (23,726) 17,028
--------- ---------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS
FROM CONTINUING OPERATIONS (17,612) 12,364
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
FROM DISCONTINUED OPERATIONS 61,800 (12,304)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 1,428 1,715
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 45,616 $ 1,775
========= =========
See accompanying notes.
4
BELDEN & BLAKE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
JUNE 30, 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 six-month period ended June 30, 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 FASB 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 did not have an
impact on the Company.
(3) DISPOSITIONS AND DISCONTINUED OPERATIONS
On June 25, 2004, the Company completed a sale of substantially all of its
Trenton Black River ("TBR") assets to Fortuna Energy Inc., a wholly owned
subsidiary of Talisman Energy Inc. The assets sold include working interests in
16 wells, approximately 11 miles of natural gas gathering lines and oil and gas
leases on approximately 475,000 gross acres. The assets are located primarily in
New York, Pennsylvania, Ohio and West Virginia. The TBR assets accounted for
approximately 5 Bcfe of the Company's estimated proved reserves as of December
31, 2003.
The sale resulted in proceeds of approximately $68.4 million. The proceeds
were used to pay down the Company's existing revolving credit facility. As a
result of the disposition of the TBR geographical/geological pools, the Company
recorded a gain of approximately $46.3 million ($29.5
5
million net of tax) in June 2004. According to SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," the disposition of this group of
wells is classified as discontinued operations.
In April 2004, the Company decided to dispose of its Arrow Oilfield
Service Company ("Arrow") assets. The Company sold the Michigan assets of Arrow
in May 2004 and sold the Ohio and Pennsylvania assets of Arrow in June 2004. The
two Arrow asset sales resulted in proceeds of approximately $4.2 million. As a
result of the disposition of all of its Arrow assets, the Company recorded a
loss of approximately $1.3 million ($839,000 net of tax) in the second quarter
of 2004. According to SFAS 144, the disposition of the Arrow assets is
classified as discontinued operations.
(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, 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 six months of 2004 and 2003, a net loss of $8.7 million
($5.5 million after tax) and a net loss of $8.5 million ($5.4 million after
tax), respectively, were reclassified from accumulated other comprehensive
income to earnings. The fair value of open hedges decreased $17.6 million ($11.2
million after tax) in the first six months of 2004 and decreased $28.0 million
($17.8 million after tax) in the first six months of 2003. At June 30, 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 $22.8
million. At June 30, 2004, the Company has partially hedged its exposure to the
variability in future cash flows through December 2005. See Note 8.
6
The following table reflects the natural gas volumes and the weighted
average prices under financial hedges (including settled hedges) at June 30,
2004:
NATURAL GAS SWAPS NATURAL GAS COLLARS
------------------------ --------------------------
NYMEX PRICE
NYMEX PRICE PER MMBTU
QUARTER ENDING BBTU PER MMBTU BBTU FLOOR/CAP (1)
- -------------- ---- ----------- ---- -------------
September 30, 2004 2,040 $ 3.84 1,080 $ 4.00 - 5.80
December 31, 2004 2,040 3.84 1,080 4.00 - 5.80
----- ------------ ----- -------------
4,080 $ 3.84 2,160 $ 4.00 - 5.80
===== ============ ===== =============
March 31, 2005 1,500 $ 3.84 1,500 $ 4.00 - 5.37
June 30, 2005 1,500 3.73 1,500 4.00 - 5.37
September 30, 2005 1,500 3.73 1,500 4.00 - 5.37
December 31, 2005 1,500 3.73 1,500 4.00 - 5.37
----- ------------ ----- -------------
6,000 $ 3.76 6,000 $ 4.00 - 5.37
===== ============ ===== =============
MMBTU - MILLION BRITISH THERMAL UNITS
BBTU - BILLION BRITISH THERMAL UNITS
(1) The NYMEX price per Mmbtu floor/cap 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. The NYMEX price per Mmbtu floor/cap 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.
(5) 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 June 30, 2004, and
2003 were not material.
The changes in share value and the vesting of shares are reported as
adjustments to compensation expense. The change in share value in the quarter
ended June 30, 2004, resulted in anon-cash increase in compensation expense of
$1.1 million. The vesting of shares in the quarter ended June 30, 2003, resulted
in a non-cash increase in compensation expense of $18,000.
(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.
7
(7) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
SIX MONTHS ENDED JUNE 30,
----------------------------
(IN THOUSANDS) 2004 2003
---------- -----------
CASH PAID DURING THE PERIOD FOR:
Interest $ 12,158 $ 11,829
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF TAX -- 2,397
(8) SUBSEQUENT EVENT
On July 7, 2004, the Company, Capital C Energy Operations, LP, a Delaware
limited partnership ("Capital C"), and Capital C Ohio, Inc., an Ohio corporation
and a wholly owned subsidiary of Capital C ("Merger Sub"), completed a merger
pursuant to which Merger Sub was merged with and into the Company (the
"Merger"), with the Company surviving the Merger as a wholly owned subsidiary of
Capital C. The Merger resulted in a change in control of the Company. The
general partner of Capital C's general partner is Capital C Energy, LLC, an
entity formed in April 2004 by David M. Carmichael, Frost W. Cochran and Peter
R. Coneway in partnership with Carlyle/Riverstone Global Energy & Power Fund II,
L.P. and Capital C Energy Partners, L.P. Capital C Energy, LLC is headquartered
in Houston, Texas. The Merger was completed on July 7, 2004 and for financial
reporting purposes will be accounted for as a purchase effective July 1, 2004.
The acquisition will result in a new basis of accounting reflecting estimated
fair values for assets and liabilities at that date.
In the Merger, each issued and outstanding share of the Company common
stock was converted into the right to receive cash. All outstanding amounts of
indebtedness under the Company's prior credit facility were repaid. In
connection with the Consent Solicitation and Tender Offer previously announced
by the Company, over 98% of the Company's $225 million aggregate principal
amount of 9-7/8% Senior Subordinated Notes were also tendered and repaid at the
closing of the Merger, and the terms of a supplemental indenture eliminating
several covenants in the indenture governing the 9-7/8% Senior Subordinated
Notes have become effective.
Capital C obtained the funds necessary to consummate the Merger through
(1) equity capital contributions of $77.5 million by its partners, (2) the
Company's entry into a secured credit facility with various lenders arranged
through Goldman Sachs Credit Partners, L.P. with a $100 million term facility
maturing on July 7, 2011, a $30 million revolving facility maturing on July 7,
2010 and a $40 million letter of credit facility, which amounts are secured by
substantially all of the assets of the Company and are guaranteed by two of the
Company's subsidiaries, Ward Lake Drilling, Inc. and The Canton Oil & Gas
Company (the "Senior Facilities"), and (3) a private placement of $192.5 million
aggregate principal amount of 8-3/4% Senior Secured Notes due 2012 (the
"Notes"), which are secured by a second-priority lien on the same assets and
guaranteed by the same subsidiaries that guarantee the Senior Facilities.
Pre-existing commodity hedges and ten-year commodity hedges effected in
connection with the Merger will also be secured by a second-priority lien on the
same assets and guaranteed by the same subsidiaries that guarantee the Senior
Facilities and the Notes.
In connection with the Merger the Company entered into commodity hedges on
a substantial portion of its future oil and gas production through the year
2013. See Note 8.
The Company's management team remained with the Company after the Merger
with the exception of the retirement of the former Chief Executive Officer, John
L. Schwager. Frost W. Cochran is the Company's new President and Chief Executive
Officer. In addition, Gregory A. Beard joined the Company as Executive Vice
President, Assistant Secretary and Director; and B. Dee Davis and W. Mac Jensen
joined the Company as Senior Vice Presidents. Upon consummation of the Merger
all former
8
directors of the Company resigned and the new Board of Directors consists of six
members, each of whom is elected annually to serve one-year terms. The initial
six members of the Board of Directors are Frost W. Cochran, David M. Carmichael,
Michael B. Hoffman, Pierre F. Lapeyre, Jr., David M. Leuschen, and Gregory A.
Beard.
In April 2002, the Company was notified of a claim by an overriding
royalty owner in Michigan alleging the underpayment of royalty resulting from
disputes as to the interpretation of the terms of several farmout agreements. On
July 6, 2004, a suit was filed in Otsego County, Michigan by the successor in
interest to these royalty interests, alleging substantially the same
underpayments. The Company believes there will be no material amount payable
above and beyond the amount accrued as of June 30, 2004 and therefore, the
result will have no material adverse effect on its financial position, results
of operation or cash flows.
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 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 activities as opposed to the alternate acceptable "full cost"
method. Under the successful efforts method,
9
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.
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
10
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 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
11
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 did not have an impact on the Company.
RESULTS OF OPERATIONS
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 periods
indicated:
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
--------------------------- -------------------------
2004 2003 2004 2003
---- ---- ---- ----
PRODUCTION
Gas (Mmcf) 3,818 3,582 7,697 7,025
Oil (Mbbls) 92 102 189 203
Total production (M mcfe) 4,370 4,194 8,828 8,241
AVERAGE PRICE
Gas (per Mcf) $ 5.17 $ 5.18 $ 5.07 $ 4.97
Oil (per Bbl) 34.94 26.59 33.46 28.33
Mcfe 5.25 5.07 5.13 4.94
AVERAGE COSTS (PER MCFE)
Production expense 1.27 1.14 1.24 1.13
Production taxes 0.15 0.16 0.15 0.16
Depletion 0.84 0.78 0.83 0.78
OPERATING MARGIN (PER MCFE) 3.83 3.77 3.74 3.65
MMCF - MILLION CUBIC FEET MBBLS - THOUSAND BARRELS MMCFE - MILLION CUBIC FEET OF NATURAL GAS EQUIVALENT
MCF - THOUSAND CUBIC FEET BBL - BARREL MCFE - THOUSAND CUBIC FEET OF NATURAL GAS EQUIVALENT
OPERATING MARGIN (PER MCFE) - AVERAGE PRICE LESS PRODUCTION EXPENSE AND PRODUCTION TAXES
RESULTS OF OPERATIONS - SECOND QUARTERS OF 2004 AND 2003 COMPARED
REVENUES
Net operating revenues increased from $23.5 million in the second quarter
of 2003 to $25.4 million in the second quarter of 2004. The increase was due to
higher gas sales revenues of $1.2 million, higher oil sales revenues of $506,000
and higher gas gathering and marketing revenues of $230,000.
Gas volumes sold increased 236 Mmcf (7%) from 3.6 Bcf (billion cubic feet)
in the second quarter of 2003 to 3.8 Bcf in the second quarter of 2004 resulting
in an increase in gas sales revenues of approximately $1.2 million. Oil volumes
sold decreased approximately 10,000 Bbls (10%) from 102,000 Bbls in the second
quarter of 2003 to 92,000 Bbls in the second quarter of 2004 resulting in a
decrease in oil sales revenues of approximately $265,000. The gas sales volume
increase was due to the production from wells drilled in 2003 and 2004 and
increased production as a result of additional expenditures to stimulate
production on declining wells partially offset by normal production declines.
The lower oil
12
sales volumes are due to normal production declines. The Company's drilling
program primarily targets natural gas reserves.
The average price realized for the Company's natural gas decreased $0.01
per Mcf to $5.17 per Mcf in the second quarter of 2004 compared to the second
quarter of 2003 which decreased gas sales revenues in the second quarter of 2004
by approximately $40,000. As a result of the Company's hedging activities, gas
sales revenues were decreased by $4.9 million ($1.28 per Mcf) in the second
quarter of 2004 and decreased by $2.4 million ($0.68 per Mcf) in the second
quarter of 2003. The average price paid for the Company's oil increased from
$26.59 per Bbl in the second quarter of 2003 to $34.94 per Bbl in the second
quarter of 2004 which increased oil sales revenues by approximately $770,000.
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
$3.77 per Mcfe in the second quarter of 2003 to $3.83 per Mcfe in the second
quarter of 2004.
The increase in gas gathering and marketing revenues was primarily due to
a $140,000 increase in gas marketing revenues and a $90,000 increase in gas
gathering revenues. The higher marketing revenues were the result of 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 $779,000 (16%) from $4.8 million in the
second quarter of 2003 to $5.5 million in the second quarter of 2004 primarily
due to $462,000 of additional non-cash stock-based compensation expense recorded
in the second quarter of 2004 to reflect the increased value of the Company's
stock and increased costs to stimulate production on declining wells in the
higher oil and natural gas price environment. These efforts increased production
volumes during the second quarter of 2004 but also had the effect of increasing
the per unit cost. The average production cost increased from $1.14 per Mcfe in
the second quarter of 2003 to $1.27 per Mcfe in the second quarter of 2004. The
per unit increase was primarily due to the higher costs incurred during the
second quarter of 2004 as discussed above partially offset by certain fixed
costs spread over greater volumes in the second quarter of 2004. Production
taxes decreased $8,000 from $656,000 in the second quarter of 2003 to $648,000
in the second quarter of 2004.
Exploration expense decreased $220,000 (14%) from $1.6 million in the
second quarter of 2003 to $1.4 million in the second quarter of 2004. This
decrease is primarily due to decreases in expired lease expense and exploratory
dry hole cost partially offset by additional non-cash stock-based compensation
expense in the second quarter of 2004.
General and administrative expense increased $169,000 (15%) from the
second quarter of 2003 to the second quarter of 2004 due to $292,000 of
additional non-cash stock-based compensation expense recorded in the second
quarter of 2004 to reflect the increased value of the Company's stock partially
offset by decreases in other employment and compensation related expenses.
Depreciation, depletion and amortization increased by $414,000 from $4.1
million in the second quarter of 2003 to $4.5 million in the second quarter of
2004. This increase was primarily due to an increase in depletion expense.
Depletion expense increased $398,000 (12%) from $3.3 million in the second
quarter of 2003 to $3.7 million in the second 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 second quarter of 2003 to $0.84 per Mcfe in the second
quarter of 2004, primarily due to higher production from higher cost wells.
13
Derivative fair value (gain) loss was a gain of $451,000 in the second
quarter of 2003 compared to a loss of $11,000 in the second 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.
Interest expense increased $76,000 from $6.0 million in the second quarter
of 2003 to $6.1 million in the second quarter of 2004. This increase was due to
an increase in average outstanding borrowings partially offset by lower blended
interest rates.
Income tax expense decreased $166,000 from $1.4 million in the second
quarter of 2003 to $1.2 million in the second quarter of 2004. The decrease was
due to a decrease in income from continuing operations before income taxes and a
lower effective tax rate in the second quarter of 2004.
Discontinued operations relating to the TBR and Arrow asset sales resulted
in a net income of $28.9 million in the second quarter of 2004 compared to a net
loss of $845,000 in the second quarter of 2003. This was primarily attributable
to the $45.0 million ($28.6 million net of tax) gain recorded in the second
quarter of 2004.
RESULTS OF OPERATIONS - SIX MONTHS OF 2004 AND 2003 COMPARED
REVENUES
Net operating revenues increased from $46.2 million in the first six
months of 2003 to $50.4 million in the first six months of 2004. The increase
was due to higher gas sales revenues of $4.1 million and higher oil sales
revenues of $568,000 partially offset by lower gas gathering and marketing
revenues of $438,000.
Gas volumes sold increased 672 Mmcf (10%) from 7.0 Bcf in the first six
months of 2003 to 7.7 Bcf in the first six months of 2004 resulting in an
increase in gas sales revenues of approximately $3.3 million. Oil volumes sold
decreased approximately 14,000 Bbls (7%) from 203,000 Bbls in the first six
months of 2003 to 189,000 Bbls in the first six months of 2004 resulting in a
decrease in oil sales revenues of approximately $400,000. The gas sales volume
increase was primarily due to the production from wells drilled in 2003 and 2004
and increased production as a result of additional expenditures to stimulate
production on declining wells partially offset by normal production declines.
The lower oil sales volumes are due to normal production declines. The Company's
drilling program primarily targets natural gas reserves.
The average price realized for the Company's natural gas increased $0.10
per Mcf to $5.07 per Mcf in the first six months of 2004 compared to the first
six months of 2003 which increased gas sales revenues in the first six months of
2004 by approximately $770,000. As a result of the Company's hedging activities,
gas sales revenues were decreased by $8.4 million ($1.10 per Mcf) in the first
six months of 2004 and decreased by $8.5 million ($1.21 per Mcf) in the first
six months of 2003. The average price paid for the Company's oil increased from
$28.33 per Bbl in the first six months of 2003 to $33.46 per Bbl in the first
six months of 2004 which increased oil sales revenues by approximately $1.0
million.
The operating margin from oil and gas sales on a per unit basis increased
from $3.65 per Mcfe in the first six months of 2003 to $3.74 per Mcfe in the
first six months of 2004.
The decrease in gas gathering and marketing revenues was primarily due to
a $1.0 million decrease in gas marketing revenues partially offset by a $577,000
increase in gas gathering revenues. The lower marketing revenues were the result
of decreased gas marketing activity and lower prices. The increase in gas
gathering revenues was primarily due to higher margins on a gathering system in
Pennsylvania.
14
COSTS AND EXPENSES
Production expense increased $1.7 million (17%) from $9.3 million in the
first six months of 2003 to $11.0 million in the first six months of 2004
primarily due to increased costs to stimulate production on declining wells in
the higher oil and natural gas price environment and $462,000 of additional
non-cash stock-based compensation expense recorded in the second quarter of 2004
to reflect the increased value of the Company's stock. The additional
expenditures increased production volumes during the first six months of 2004
but also had the effect of increasing the per unit cost. The average production
cost increased from $1.13 per Mcfe in the first six months of 2003 to $1.24 per
Mcfe in the first six months of 2004. The per unit increase was primarily due to
the higher costs incurred during the first six months of 2004 as discussed above
partially offset by certain fixed costs spread over greater volumes in the first
six months of 2004. Production taxes decreased $29,000 in the first six months
of 2004.
Exploration expense decreased $524,000 (16%) from $3.2 million in the
first six months of 2003 to $2.7 million in the first six months of 2004
primarily due to decreases in expiring lease expense and exploratory dry hole
expense partially offset by additional non-cash stock-based compensation expense
recorded in the second quarter of 2004.
General and administrative expense increased $230,000 (10%) from the first
six months of 2003 to the first six months of 2004 due to $292,000 of additional
non-cash stock-based compensation expense recorded in the second quarter of 2004
to reflect the increased value of the Company's stock partially offset by
decreases in other employment and compensation related expenses.
Depreciation, depletion and amortization increased by $938,000 from $8.2
million in the first six months of 2003 to $9.1 million in the first six months
of 2004. This increase was primarily due to an increase in depletion expense.
Depletion expense increased $944,000 (15%) from $6.4 million in the first six
months of 2003 to $7.4 million in the first six months 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 six months of 2003 to $0.83 per Mcfe in the first
six months of 2004, primarily due to higher production from higher cost wells.
Derivative fair value (gain) loss was a gain of $174,000 in the first six
months of 2003 compared to a gain of $321,000 in the first six months 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.
Interest expense increased $243,000 (2%) from $11.9 million in the first
six months of 2003 to $12.2 million in the first six months of 2004. This
increase was due to an increase in average outstanding borrowings partially
offset by lower blended interest rates.
Income tax expense increased $802,000 from $1.8 million in the first six
months of 2003 to $2.6 million in the first six months of 2004. The increase was
due to an increase in income from continuing operations before income taxes
partially offset by a lower effective tax rate in the first six months of 2004.
Discontinued operations relating to the TBR and Arrow asset sales resulted
in a net income of $28.6 million in the first six months of 2004 compared to a
net loss of $1.2 million in the first six months of 2003. This was primarily
attributable to the $45.0 million ($28.6 million net of tax) gain recorded in
the second quarter of 2004.
15
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS
The primary sources of cash in the six-month period ended June 30, 2004
have been net proceeds from the sale of the Company's TBR and Arrow assets,
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 $18.6 million
during the first six months of 2004 compared to $9.6 million in the first six
months of 2003. The increase was primarily due to higher cash received for oil
and gas revenues (net of hedging) of $4.6 million and changes in working capital
items of $8.0 million.
Cash flows used in investing activities decreased in the first six months
of 2004 primarily due to $4.6 million in acquisitions in the first six months of
2003, a $1.3 million decrease in other assets and a $524,000 decrease in
exploration expense partially offset by $4.7 million of increased capital
expenditures in the first six months of 2004.
Cash flows used in financing activities in the first six months of 2004
were primarily due to payments on the credit facility. Cash flows provided by
financing activities during the first six months of 2003 were borrowings on the
credit facility to fund acquisition, exploration and development expenditures in
the first six months of 2003.
The Company's current ratio from continuing operations at June 30, 2004
was 1.68 to 1. During the first six months of 2004, the working capital from
continuing operations increased $38.0 million from a deficit of $7.1 million at
December 31, 2003 to working capital of $30.9 million at June 30, 2004. The
increase was primarily due to a $44.2 million increase in cash from the proceeds
of the second quarter 2004 asset sales, a $3.5 million increase in accounts
receivable and a $3.0 increase in the deferred income taxes asset partially
offset by an $8.0 million increase in the net current liability for the fair
value of derivatives and a $5.1 million increase in accrued expenses. The
increase in accrued expenses is primarily due to increases in accrued income
taxes and accrued drilling costs.
CAPITAL EXPENDITURES
During the first six months of 2004, the Company spent approximately
$11 million on its drilling activities and other capital expenditures related to
continuing operations. In the first six months of 2004, the Company drilled 41
gross (37.4 net) development wells, all of which were successfully completed as
producers in the target formation. The cost excludes approximately $300,000
related to 2 gross (1.2 net) shallow exploratory wells in progress as of June
30, 2004.
The Company currently expects to spend approximately $24 million during
2004 on its drilling activities and other capital expenditures related to
continuing operations. 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, 2004, the Company had
approximately $52.9 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.
CAPITAL C MERGER
As disclosed in Note 8 "Subsequent Event" to the consolidated financial
statements, on July 7, 2004, the Company, Capital C Energy Operations, LP, a
Delaware limited partnership ("Capital C"), and Capital C Ohio, Inc., an Ohio
corporation and a wholly owned subsidiary of Capital C ("Merger Sub"),
16
completed a merger pursuant to which Merger Sub was merged with and into the
Company (the "Merger"), with the Company surviving the Merger as a wholly owned
subsidiary of Capital C. The Merger resulted in a change in control of the
Company. The general partner of Capital C's general partner is Capital C Energy,
LLC, an entity formed in April 2004 by David M. Carmichael, Frost W. Cochran and
Peter R. Coneway in partnership with Carlyle/Riverstone Global Energy & Power
Fund II, L.P. and Capital C Energy Partners, L.P. Capital C Energy, LLC is
headquartered in Houston, Texas. The Merger was completed on July 7, 2004 and
for financial reporting purposes will be accounted for as a purchase effective
July 1, 2004. The acquisition will result in a new basis of accounting
reflecting estimated fair values for assets and liabilities at that date.
In the Merger, each issued and outstanding share of the Company common
stock was converted into the right to receive cash. All outstanding amounts of
indebtedness under the Company's prior credit facility were repaid. In
connection with the Consent Solicitation and Tender Offer previously announced
by the Company, over 98% of the Company's $225 million aggregate principal
amount of 9-7/8% Senior Subordinated Notes were also tendered and repaid at the
closing of the Merger, and the terms of a supplemental indenture eliminating
several covenants in the indenture governing the 9-7/8% Senior Subordinated
Notes have become effective.
Capital C obtained the funds necessary to consummate the Merger through
(1) equity capital contributions of $77.5 million by its partners, (2) the
Company's entry into a secured credit facility with various lenders arranged
through Goldman Sachs Credit Partners, L.P. with a $100 million term facility
maturing on July 7, 2011, a $30 million revolving facility maturing on July 7,
2010 and a $40 million letter of credit facility, which amounts are secured by
substantially all of the assets of the Company and are guaranteed by two of the
Company's subsidiaries, Ward Lake Drilling, Inc. and The Canton Oil & Gas
Company (the "Senior Facilities"), and (3) a private placement of $192.5 million
aggregate principal amount of 8-3/4% Senior Secured Notes due 2012 of the
Company (the "Notes"), which are secured by a second-priority lien on the same
assets and guaranteed by the same subsidiaries that guarantee the Senior
Facilities. Pre-existing commodity hedges and ten-year commodity hedges effected
in connection with the Merger will also be secured by a second-priority lien on
the same assets and guaranteed by the same subsidiaries that guarantee the
Senior Facilities and the Notes.
In connection with the Merger the Company entered into commodity hedges on
a substantial portion of its future oil and gas production through the year
2013. See Note 8.
The Company's management team remained with the Company after the Merger
with the exception of the retirement of the former Chief Executive Officer, John
L. Schwager. Frost W. Cochran is the Company's new President and Chief Executive
Officer. In addition, Gregory A. Beard joined the Company as Executive Vice
President, Assistant Secretary and Director; and B. Dee Davis and W. Mac Jensen
joined the Company as Senior Vice Presidents. Upon consummation of the Merger
all former directors of the Company resigned and the new Board of Directors
consists of six members, each of whom is elected annually to serve one-year
terms. The initial six members of the Board of Directors are Frost W. Cochran,
David M. Carmichael, Michael B. Hoffman, Pierre F. Lapeyre, Jr., David M.
Leuschen, and Gregory A. Beard.
FINANCING AND CREDIT FACILITIES
At June 30, 2004, the Company had a $100 million revolving credit facility
and a special letter of credit facility in the amount of $25 million from Ableco
Finance LLC and Wells Fargo Foothill, Inc. At June 30, 2004, the interest rate
was 6.00%. At June 30, 2004, the Company had $48.2 million of outstanding
letters of credit. At June 30, 2004, the outstanding balance under the credit
agreement was $23.9 million with $52.9 million of borrowing capacity available
for general corporate purposes. As of
17
June 30, 2004, the Company had satisfied all financial covenants and
requirements under the existing revolving credit facility.
At July 31, 2004, the Company had $55.0 million of outstanding letters of
credit under the Company's post Merger Senior Facilities.
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 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 June 30, 2004 or 2003. 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 $60,000. This sensitivity
analysis is based on the Company's financial structure at June 30, 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 $833,000, after considering the effects of the hedging contracts in
place. At June 30, 2004, 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 $276,000.
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 $8.4 million in the first six months of 2004 and $8.5 million in
the first six 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 modify its fixed price contract and
financial hedging positions by entering into new transactions.
18
The following table reflects the natural gas and crude oil volumes and the
weighted average prices under financial hedges (including settled hedges) at
July 31, 2004:
NATURAL GAS SWAPS NATURAL GAS COLLARS CRUDE OIL SWAPS
----------------- ------------------- ---------------
NYMEX PRICE
NYMEX PER MMBTU NYMEX
PRICE PER FLOOR/CAP ESTIMATED PRICE PER
QUARTER ENDING BBTU MMBTU BBTU (1) MBBLS BBL
------ --------- ----- ----------- --------- -----------
September 30, 2004 2,040 $ 3.82 1,080 $4.00-5.77 74 $ 36.06
December 31, 2004 2,040 3.81 1,080 4.00-5.76 74 35.68
------ --------- ----- ---------- --- -----------
4,080 $ 3.82 2,160 $4.00-5.76 148 $ 35.87
====== ========= ===== ========== === ===========
March 31, 2005 1,500 $ 3.81 1,500 $4.00-5.32 68 $ 34.76
June 30, 2005 1,500 3.70 1,500 4.00-5.32 68 34.18
September 30, 2005 1,500 3.70 1,500 4.00-5.32 67 33.72
December 31, 2005 1,500 3.70 1,500 4.00-5.32 67 33.31
------ --------- ----- ---------- --- -----------
6,000 $ 3.73 6,000 $4.00-5.32 270 $ 34.00
====== ========= ===== ========== === ===========
March 31, 2006 2,829 $ 6.14 63 $ 32.71
June 30, 2006 2,829 5.24 62 32.35
September 30, 2006 2,829 5.22 62 32.02
December 31, 2006 2,829 5.39 62 31.71
------ --------- --- -----------
11,316 $ 5.50 249 $ 32.20
====== ========= === ===========
YEAR ENDING
December 31, 2007 10,745 $ 4.97 227 $ 30.91
December 31, 2008 10,126 4.64 208 29.96
December 31, 2009 9,529 4.43 191 29.34
December 31, 2010 8,938 4.28 175 28.86
December 31, 2011 8,231 4.19 157 28.77
December 31, 2012 7,005 4.09 138 28.70
December 31, 2013 6,528 4.04 127 28.70
BBL - BARREL MMBTU - MILLION BRITISH THERMAL UNITS
MBBLS - THOUSAND BARRELS BBTU - BILLION BRITISH THERMAL UNITS
(1) The NYMEX price per Mmbtu floor/cap 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. The NYMEX price per Mmbtu floor/cap 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.
The proximity of the Company's properties in the Appalachian and Michigan
basins to large commercial and industrial natural gas markets has generally
resulted in premium wellhead gas prices compared with the prices of NYMEX
futures contracts for gas delivered at the Henry Hub in Louisiana. Monthly spot
natural gas prices in our market areas are typically 15 to 60 cents higher per
Mcf than comparable NYMEX prices. The Company's average price received for crude
oil is typically $2.50 to $3.25 per barrel below the NYMEX price per barrel.
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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, 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.
PART II OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
10.1* Amendment No. 3 of the Belden & Blake Corporation 1999 Change in Control
Protection Plan for Key Employees dated as of April 20, 2004.
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.
*Filed herewith
(b) Reports on Form 8-K
On June 22, 2004, the Company filed a Current Report on Form 8-K dated
June 15, 2004, reporting under Item 5 that the Company had issued two press
releases announcing that (1) it had signed an Agreement and Plan of Merger with
an affiliate of Capital C Energy, LLC, a private investment limited partnership
controlled by Carlyle/Riverstone Global Energy and Power Fund II, L.P.; and (2)
it had commenced a cash tender offer and consent solicitation to purchase for
cash any and all of its outstanding $225,000,000 aggregate principal amount of 9
7/8% Senior Subordinated Notes due 2007.
On June 24, 2004, the Company filed a Current Report on Form 8-K dated
June 23, 2004, reporting under Item 5 that the Company had issued two press
releases announcing that (1) it planed to offer $192.5 million principal amount
of Senior Secured Notes due 2012 pursuant to a private placement; and (2) it had
executed a Letter Agreement with a third-party buyer, pursuant to which the
Company will sell substantially all of its Trenton Black River assets. The
assets are located primarily in New York, Pennsylvania, Ohio and West Virginia.
20
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 10, 2004 By: /s/ Frost W. Cochran
------------------------------------
Frost W. Cochran, Director, President
and Chief Executive Officer
Date: August 10, 2004 By: /s/ Robert W. Peshek
------------------------------------
Robert W. Peshek, Senior Vice President
and Chief Financial Officer
21