Attached files
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EX-31.2 - EXHIBIT 31.2 - BELDEN & BLAKE CORP /OH/ | c92486exv31w2.htm |
EX-31.1 - EXHIBIT 31.1 - BELDEN & BLAKE CORP /OH/ | c92486exv31w1.htm |
EX-32.1 - EXHIBIT 32.1 - BELDEN & BLAKE CORP /OH/ | c92486exv32w1.htm |
EX-32.2 - EXHIBIT 32.2 - BELDEN & BLAKE CORP /OH/ | c92486exv32w2.htm |
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
þ | Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the quarterly period ended September 30, 2009
or
o | Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the transition period from ________________________ to _______________________
Commission File Number: 0-20100
BELDEN & BLAKE CORPORATION
(Exact name of registrant as specified in its charter)
Ohio | 34-1686642 | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
|
1001 Fannin Street, Suite 800 Houston, Texas |
77002 | |
(Address of principal executive offices) | (Zip Code) |
(713) 659-3500
(Registrants telephone number, including area code)
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. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate website, if any, every Interactive Data File required to be submitted and posted pursuant
to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for
such shorter period that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer or a smaller reporting company. See definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer o | Accelerated filer o | Non-accelerated filer þ | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
As of October 31, 2009, Belden & Blake Corporation had outstanding 1,534 shares of common
stock, without par value, which is its only class of stock.
BELDEN & BLAKE CORPORATION
INDEX
Page | ||||||||
1 | ||||||||
2 | ||||||||
3 | ||||||||
4 | ||||||||
11 | ||||||||
19 | ||||||||
21 | ||||||||
21 | ||||||||
21 | ||||||||
21 | ||||||||
21 | ||||||||
21 | ||||||||
21 | ||||||||
22 | ||||||||
23 | ||||||||
Exhibit 31.1 | ||||||||
Exhibit 31.2 | ||||||||
Exhibit 32.1 | ||||||||
Exhibit 32.2 |
Table of Contents
PART I. FINANCIAL INFORMATION
Item 1. | Financial Statements |
BELDEN & BLAKE CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited, in thousands, except share data)
September 30, | December 31, | |||||||
2009 | 2008 | |||||||
ASSETS |
||||||||
Current assets |
||||||||
Cash and cash equivalents |
$ | 7,983 | $ | 22,816 | ||||
Accounts receivable (less accumulated provision for doubtful accounts: September 30, 2009 $353; December 31, 2008 $312) |
11,188 | 19,244 | ||||||
Inventories |
845 | 1,004 | ||||||
Deferred income taxes |
7,404 | 7,946 | ||||||
Other current assets |
52 | 332 | ||||||
Derivative asset |
988 | 430 | ||||||
Total current assets |
28,460 | 51,772 | ||||||
Property and equipment, at cost |
||||||||
Oil and gas properties (successful efforts method) |
691,334 | 735,398 | ||||||
Gas gathering systems |
1,317 | 1,413 | ||||||
Land, buildings, machinery and equipment |
2,562 | 2,836 | ||||||
695,213 | 739,647 | |||||||
Less accumulated depreciation, depletion and amortization |
142,569 | 124,175 | ||||||
Property and equipment, net |
552,644 | 615,472 | ||||||
Long-term derivative asset |
480 | 868 | ||||||
Other assets |
2,173 | 1,352 | ||||||
$ | 583,757 | $ | 669,464 | |||||
LIABILITIES AND SHAREHOLDERS EQUITY |
||||||||
Current liabilities |
||||||||
Accounts payable |
$ | 4,649 | $ | 3,570 | ||||
Accrued expenses |
12,963 | 19,251 | ||||||
Current portion of long-term liabilities |
211 | 25,237 | ||||||
Derivative liability |
19,708 | 20,520 | ||||||
Total current liabilities |
37,531 | 68,578 | ||||||
Long-term liabilities |
||||||||
Bank and other long-term debt |
56,431 | 74,938 | ||||||
Senior secured notes |
162,548 | 163,302 | ||||||
Subordinated promissory note related party |
29,741 | 27,623 | ||||||
Asset retirement obligations and other long-term liabilities |
22,743 | 23,863 | ||||||
Long-term derivative liability |
80,244 | 101,570 | ||||||
Deferred income taxes |
123,778 | 133,039 | ||||||
Total long-term liabilities |
475,485 | 524,335 | ||||||
Shareholders equity |
||||||||
Common stock: without par value; 3,000 shares authorized and 1,534 shares issued |
| | ||||||
Paid in capital |
130,000 | 122,500 | ||||||
Retained deficits |
(49,494 | ) | (32,754 | ) | ||||
Accumulated other comprehensive loss |
(9,765 | ) | (13,195 | ) | ||||
Total shareholders equity |
70,741 | 76,551 | ||||||
$ | 583,757 | $ | 669,464 | |||||
See accompanying notes.
1
Table of Contents
BELDEN & BLAKE CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, in thousands)
Three months ended | Three months ended | Nine months ended | Nine months ended | |||||||||||||
September 30, 2009 | September 30, 2008 | September 30, 2009 | September 30, 2008 | |||||||||||||
Revenues |
||||||||||||||||
Oil and gas sales |
$ | 15,336 | $ | 41,765 | $ | 46,198 | $ | 119,691 | ||||||||
Gas gathering and marketing |
1,312 | 3,571 | 4,558 | 9,949 | ||||||||||||
Other |
374 | 127 | 743 | 432 | ||||||||||||
17,022 | 45,463 | 51,499 | 130,072 | |||||||||||||
Expenses |
||||||||||||||||
Production expense |
5,123 | 6,565 | 16,342 | 19,543 | ||||||||||||
Production taxes |
246 | 895 | 799 | 2,491 | ||||||||||||
Gas gathering and marketing |
1,247 | 2,819 | 4,196 | 8,221 | ||||||||||||
Exploration expense |
849 | 1,614 | 3,164 | 2,173 | ||||||||||||
Impairment of oil and gas properties |
(1,297 | ) | | 23,933 | 2,011 | |||||||||||
General and administrative expense |
1,631 | 2,225 | 5,925 | 6,240 | ||||||||||||
Depreciation, depletion and
amortization |
9,066 | 8,517 | 28,414 | 25,876 | ||||||||||||
Accretion expense |
319 | 359 | 989 | 1,047 | ||||||||||||
Derivative fair value loss (gain) |
539 | (134,829 | ) | (19,884 | ) | 10,397 | ||||||||||
17,723 | (111,835 | ) | 63,878 | 77,999 | ||||||||||||
Operating (loss) income |
(701 | ) | 157,298 | (12,379 | ) | 52,073 | ||||||||||
Other (income) expense |
||||||||||||||||
Interest expense |
5,411 | 5,753 | 15,543 | 17,411 | ||||||||||||
Other income, net |
(155 | ) | (119 | ) | (255 | ) | (349 | ) | ||||||||
(Loss) income before income taxes |
(5,957 | ) | 151,664 | (27,667 | ) | 35,011 | ||||||||||
(Benefit) provision for income taxes |
(2,341 | ) | 59,959 | (10,927 | ) | 13,847 | ||||||||||
Net (loss) income |
$ | (3,616 | ) | $ | 91,705 | $ | (16,740 | ) | $ | 21,164 | ||||||
See accompanying notes.
2
Table of Contents
BELDEN & BLAKE CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, in thousands)
Nine months ended | Nine months ended | |||||||
September 30, 2009 | September 30, 2008 | |||||||
Cash flows from operating activities: |
||||||||
Net (loss) income |
$ | (16,740 | ) | $ | 21,164 | |||
Adjustments to reconcile net (loss) income
to net cash provided by operating activities: |
||||||||
Depreciation, depletion and amortization |
28,414 | 25,876 | ||||||
Accretion expense |
989 | 1,047 | ||||||
Amortization of derivatives and other non-cash hedging activities |
(16,640 | ) | 16,685 | |||||
Exploration expense |
2,181 | 1,788 | ||||||
Deferred income taxes |
(10,927 | ) | 13,847 | |||||
Impairment of oil and gas properties |
23,933 | 2,011 | ||||||
Other non-cash items |
2,704 | 21 | ||||||
Change in operating assets and liabilities |
||||||||
Accounts receivable and other current assets |
8,336 | (2,321 | ) | |||||
Inventories |
81 | 127 | ||||||
Accounts payable and accrued expenses |
(4,048 | ) | (569 | ) | ||||
Net cash provided by operating activities |
18,283 | 79,676 | ||||||
Cash flows from investing activities: |
||||||||
Additions to property and equipment |
(10,707 | ) | (18,722 | ) | ||||
Proceeds from property and equipment disposals |
17,403 | 3,049 | ||||||
Exploration expense |
(2,181 | ) | (1,788 | ) | ||||
(Increase) decrease in other assets |
(54 | ) | 77 | |||||
Net cash provided by (used in) investing activities |
4,461 | (17,384 | ) | |||||
Cash flows from financing activities: |
||||||||
Repayment of long-term debt and other obligations |
(43,577 | ) | (7 | ) | ||||
Debt redetermination costs |
(1,470 | ) | | |||||
Settlement of derivative liabilities recorded in purchase accounting |
(30 | ) | (51,360 | ) | ||||
Capital contributions |
7,500 | | ||||||
Dividends paid |
| (2,500 | ) | |||||
Net cash used in financing activities |
(37,577 | ) | (53,867 | ) | ||||
Net (decrease) increase in cash and cash equivalents |
(14,833 | ) | 8,425 | |||||
Cash and cash equivalents at beginning of period |
22,816 | 16,014 | ||||||
Cash and cash equivalents at end of period |
$ | 7,983 | $ | 24,439 | ||||
See accompanying notes.
3
Table of Contents
BELDEN & BLAKE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
September 30, 2009
(1) Basis of Presentation
Unless the context requires otherwise or unless otherwise noted, when we use the terms Belden
& Blake, we, us, our or the Company, we are referring to Belden & Blake Corporation and
its predecessors. On August 16, 2005, the former partners of the direct parent of Belden & Blake
Corporation, Capital C Energy Operations, L.P., a Delaware limited partnership (Capital C),
completed the sale of all of the partnership interests in Capital C to certain institutional funds
managed by EnerVest, Ltd. (EnerVest), a Houston-based privately held oil and gas operator and
institutional funds manager.
The accompanying unaudited financial statements 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 period ended September 30, 2009 are not necessarily indicative of the results that
may be expected for the year ended December 31, 2009. For further information, refer to the
financial statements and footnotes included in our Annual Report on Form 10-K for the year ended
December 31, 2008.
Correction of an Error to Previously Issued Condensed Consolidated Financial Statements
Subsequent to the issuance of the quarterly report on Form 10-Q for the period ended June 30,
2009, the Company determined that the impairment recorded on our coalbed methane properties in
Pennsylvania, which were sold on July 10, 2009, had not been properly adjusted to include the
impact of certain assets and liabilities, including the asset retirement obligations that were
conveyed in the transaction as disclosed in Note 13 on the Form 10-Q for the period ended June 30,
2009. As a result, prior period amounts have been corrected in the current period, which resulted
in a reduction in the impairment of oil and gas properties of $1.3 million on a pre tax basis, and
$784,000 on a post tax basis. The Company does not believe that the correction of this error is
material to the Companys condensed consolidated financial statements for the quarterly period
ended September 30, 2009, or to the condensed consolidated financial statements for the prior
quarterly period ended June 30, 2009.
(2) Derivatives and Hedging
Effective
January 1, 2009, we adopted new FASB accounting guidance
regarding disclosures about derivative instruments
and hedging activities that requires enhanced
disclosures about an entitys derivative and hedging activities and how they affect an entitys
financial position, financial performance and cash flows.
From time to time, we may enter into a combination of futures contracts, commodity derivatives
and fixed-price physical commodity contracts to manage our exposure to natural gas price, crude oil
price or interest rate volatility and support our capital expenditure plans. Our derivative
financial instruments take the form of swaps or collars. At September 30, 2009, our derivative
contracts were comprised of natural gas swaps, natural gas basis differential swaps, crude oil
swaps and interest rate swaps which were placed with major financial institutions that we believe
are a minimal credit risk. All of our derivative instruments are currently accounted for as
non-qualifying derivative contracts. The changes in fair value of non-qualifying derivative
contracts are reported in expense in the consolidated statements of operations as derivative fair
value (gain) loss.
4
Table of Contents
We
have certain derivative contracts that qualified for hedge accounting
treatment in prior periods, as well as derivative contracts that were
de designated in prior periods. During the three month period ended
September 30, 2009 and 2008, accumulated other comprehensive
income decreased $921,000 ($557,000 after tax) and $1.2 million
($703,000 after tax), respectively. During the nine month period
ended September 30, 2009 and 2008, accumulated other
comprehensive income decreased $5.6 million ($3.4
million after tax) and $7.4 million ($4.5 million
after tax), respectively. All such amounts were reclassified into
earnings during the respective periods. At September 30, 2009,
the estimated net loss in accumulated other comprehensive income that
is expected to be reclassified into earnings within the next
12 months is approximately $4.0 million after tax. At
September 30, 2009, we have partially hedged our exposure to the
variability in future cash flows through December 2013.
The following table reflects the natural gas and crude oil volumes and the weighted average
prices under financial derivative contracts (including settled derivative contracts) at September
30, 2009:
Natural Gas Swaps | Crude Oil Swaps | Natural Gas Basis Swaps | ||||||||||||||||||||||
NYMEX | NYMEX | Basis | ||||||||||||||||||||||
Bbtu | Price per Mmbtu | Mbbls | Price per Bbl | Bbtu | Differential | |||||||||||||||||||
Quarter Ending |
||||||||||||||||||||||||
December 31, 2009 |
2,382 | $ | 4.47 | 48 | $ | 29.09 | 2,116 | $ | 0.34 | |||||||||||||||
Year Ending |
||||||||||||||||||||||||
December 31, 2010 |
8,938 | $ | 4.28 | 175 | $ | 28.86 | 7,665 | $ | 0.243 | |||||||||||||||
December 31, 2011 |
8,231 | 4.19 | 157 | 28.77 | 5,110 | 0.252 | ||||||||||||||||||
December 31, 2012 |
7,005 | 4.09 | 138 | 28.70 | 3,660 | 0.110 | ||||||||||||||||||
December 31, 2013 |
6,528 | 4.04 | 127 | 28.70 | | |
At
September 30, 2009, we had interest rate swaps in place through
September 30, 2013 covering $43.5 million of our
outstanding debt under the revolving credit facility, which currently
matures on August 16, 2011. The swaps provide 1-month LIBOR
fixed rates of 4.10%, plus the applicable margin.
5
Table of Contents
At September 30, 2009, the fair value of these derivatives was as follows:
Asset Derivatives | Liability Derivatives | |||||||||||||||
September 30, 2009 | December 31, 2008 | September 30, 2009 | December 31, 2008 | |||||||||||||
Oil and natural gas commodity contracts |
$ | 1,468 | $ | 1,298 | $ | (97,151 | ) | $ | (118,547 | ) | ||||||
Interest rate swaps |
| | (2,801 | ) | (3,543 | ) | ||||||||||
Total fair value |
$ | 1,468 | $ | 1,298 | $ | (99,952 | ) | $ | (122,090 | ) | ||||||
Location of derivatives in our consolidated balance
sheets: |
||||||||||||||||
Derivative asset |
$ | 988 | $ | 430 | $ | | $ | | ||||||||
Long-term derivative asset |
480 | 868 | | | ||||||||||||
Derivative liability |
| | (19,708 | ) | (20,520 | ) | ||||||||||
Long-term derivative liability |
| | (80,244 | ) | (101,570 | ) | ||||||||||
$ | 1,468 | $ | 1,298 | $ | (99,952 | ) | $ | (122,090 | ) | |||||||
The net amount due under these derivative contracts may become due and payable if our
Amended Credit Agreement or our senior secured notes become due and payable due to an event of
default.
The following table presents the impact of derivatives and their location within the statement
of operations:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
The following amounts are recorded in Oil and gas sales: |
||||||||||||||||
Unrealized losses: |
||||||||||||||||
Oil and natural gas commodity contracts |
$ | (921 | ) | $ | (1,163 | ) | $ | (5,603 | ) | $ | (6,340 | ) | ||||
The following amounts are recorded in Interest expense: |
||||||||||||||||
Realized losses: |
||||||||||||||||
Interest rate swaps |
$ | | $ | 391 | $ | | $ | 1,009 | ||||||||
The following are recorded in Derivative fair value loss (gain): |
||||||||||||||||
Unrealized (gains) losses: |
||||||||||||||||
Oil and natural gas commodity contracts |
$ | 647 | $ | (154,479 | ) | $ | (21,569 | ) | $ | (41,405 | ) | |||||
Interest rate swaps |
(171 | ) | 403 | (740 | ) | 323 | ||||||||||
Total |
476 | (154,076 | ) | (22,309 | ) | (41,082 | ) | |||||||||
Realized (gains) losses: |
||||||||||||||||
Oil and natural gas commodity contracts |
(600 | ) | 19,247 | 293 | 51,479 | |||||||||||
Interest rate swaps |
663 | | 2,132 | | ||||||||||||
Total |
63 | 19,247 | 2,425 | 51,479 | ||||||||||||
Derivative fair value loss (gain) |
$ | 539 | $ | (134,829 | ) | $ | (19,884 | ) | $ | 10,397 | ||||||
(3) Industry Segment Financial Information
We operate 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. Our operations are conducted
entirely in the United States.
6
Table of Contents
(4) Fair Value of Financial Instruments
Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts
payable and accrued liabilities, long-term debt and derivatives. Our derivatives are recorded at
fair value (see Notes 2 and 11). The carrying amount of our other financial instruments other than
debt approximates fair value because of the short-term nature of the items. The carrying value of
our debt, including our senior secured notes and subordinated promissory note, approximates fair
value because the interest rates approximates current market rates.
(5) Supplemental Disclosure of Cash Flow Information
Nine months ended | Nine months ended | |||||||
(in thousands) | September 30, 2009 | September 30, 2008 | ||||||
Cash paid during the period for: |
||||||||
Interest |
$ | 18,182 | $ | 21,372 | ||||
Income taxes |
| | ||||||
Non-cash investing and financing activities: |
||||||||
Accrued additions to property and equipment |
566 | 2,392 | ||||||
Non-cash additions to debt |
(2,118 | ) | (15 | ) |
(6) Contingencies
We are involved in several lawsuits arising in the ordinary course of business. We believe
that the results of such proceedings, individually or in the aggregate, will not have a material
adverse effect on our financial position or the results of operations.
(7) Comprehensive Income
Comprehensive income includes net income and certain items recorded directly to shareholders
equity and classified as other comprehensive income. The table below summarizes comprehensive
income and provides the components of the change in accumulated other comprehensive income (loss)
for the three and nine month periods ended September 30, 2009 and 2008.
Three months ended | Three months ended | Nine months ended | Nine months ended | |||||||||||||
September 30, 2009 | September 30, 2008 | September 30, 2009 | September 30, 2008 | |||||||||||||
Comprehensive (loss) income: |
||||||||||||||||
Net (loss) income |
$ | (3,616 | ) | $ | 91,705 | $ | (16,740 | ) | $ | 21,164 | ||||||
Other comprehensive income (loss), net of tax: |
||||||||||||||||
Unrealized gain in derivative fair value |
| 18 | | 409 | ||||||||||||
Reclassification adjustment for derivative loss
reclassified into earnings |
(556 | ) | (939 | ) | (3,429 | ) | (4,482 | ) | ||||||||
Change in accumulated other comprehensive loss |
(556 | ) | (921 | ) | (3,429 | ) | (4,073 | ) | ||||||||
$ | (4,172 | ) | $ | 90,784 | $ | (20,169 | ) | $ | 17,091 | |||||||
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(8) Related Party Transactions
We have a joint operating agreement with EnerVest Operating LLC (EnerVest Operating). In the
third quarter of 2009, we recorded costs of approximately $1.4 million (as general and
administrative expense) for operating overhead fees, $1.4 million (as production expense) for field
labor, vehicles and district office expense, $54,000 (capitalized) for drilling overhead fees and
$203,000 (capitalized) for drilling labor costs related to this agreement. We recorded costs of
approximately $1.7 million for operating overhead fees, $1.7 million for field labor, vehicles and
district office expense, $71,000 for drilling overhead fees and $283,000 for drilling labor costs
in the third quarter of 2008 related to this agreement. In the first nine months of 2009, we
recorded costs of approximately $4.7 million (as general and administrative expense) for operating
overhead fees, $4.4 million (as production expense) for field labor, vehicles and district office
expense, $81,000 (capitalized) for drilling overhead fees and $948,000 (capitalized) for drilling
labor costs related to this agreement. We recorded costs of approximately $4.9 million for
operating overhead fees, $5.1 million for field labor, vehicles and district office expense,
$194,000 for drilling overhead fees and $624,000 for drilling labor costs in the first nine months
of 2008 related to this agreement.
We have a note in favor of our parent, Capital C in the maximum amount of $94 million. The
amount due under the note at September 30, 2009 was $29.7 million. In lieu of cash payments, we
have the option to make interest payments on the note by borrowing additional amounts against the
note. We borrowed $2.1 million against the note for interest payments in the first nine months of
2009 and made cash payments of $2.0 million in the first nine months of 2008 to Capital C.
As of September 30, 2009, we owed EnerVest $690,000 and EnerVest Operating owed us
$401,000. These amounts are included in accounts payable on the condensed consolidated balance
sheet.
(9) Impairment of Oil and Gas Properties
For the periods ended September 30, 2009 and 2008, we reviewed our oil and gas properties for
impairment as prescribed by FASB accounting guidance related to the accounting for the impairment
or disposal of long-lived assets. As a result of this evaluation, we recorded an impairment of
$2.0 million during the second quarter of 2008 to proved properties in the Utica Shale formation in
Ohio. In the second quarter of 2009, we recorded an impairment of $25.2 million to our coalbed
methane properties in Pennsylvania. In the third quarter of 2009, we corrected the amount recorded
in the second quarter of 2009 by reducing it by $1.3 million (see Note 1).
(10) New Accounting Standards
In December 2007, the FASB issued new accounting guidance regarding the accounting for
business combinations. This new guidance retains the acquisition method of accounting used in
business combinations and establishes principles and requirements for the recognition and
measurement of assets, liabilities and goodwill, including the requirement that most transaction
and restructuring costs related to the acquisition be expensed. In addition, this guidance requires
disclosures to enable users to evaluate the nature and financial effects of the business
combination. We adopted this new guidance on January 1, 2009.
In March 2008, the FASB issued new accounting guidance requiring enhanced disclosures about an
entitys derivative and hedging activities and their effect on an entitys financial position,
financial performance and cash flows. This new guidance is effective for fiscal years and interim
periods beginning after November 15, 2008. We adopted the new accounting guidance on January 1,
2009 (see Note 2).
In December 2008, the SEC published Modernization of Oil and Gas Reporting, a revision to its
oil and natural gas reporting disclosures. The new disclosure requirements include provisions that
permit the use of new technologies to determine proved reserves if those technologies have been
demonstrated empirically to lead to reliable conclusions about reserves volumes. The new
requirements also will allow companies to disclose their probable and possible reserves to
investors. In addition, the new disclosure requirements require companies to: (i) report the
independence and qualifications of its reserves preparer or auditor; (ii) file reports when a third
party is relied upon to prepare reserves estimates or conducts a reserves audit; and (iii) report
oil and natural gas reserves using an average price based upon the prior 12 month period rather
than year end prices. The new disclosure requirements are effective for registration statements
filed on or after January 1, 2010, and for annual reports on Forms 10-K and 20-F for fiscal years
ending on or after December 31, 2009. We will adopt the new disclosure requirements for our Form
10-K for the year ending December 31, 2009.
8
Table of Contents
In April 2009, the FASB issued new accounting guidance to require disclosures about the
fair value of financial instruments for interim reporting periods of publicly traded companies as
well as in annual financial statements. This new guidance is effective for interim or financial
periods ending after June 15, 2009. We adopted this new guidance in our interim period ended June
30, 2009 (see Notes 2 and 11).
In May 2009, the FASB issued new accounting guidance to establish standards of accounting for
and disclosure of events that occur after the balance sheet date but before financial statements
are issued or are available to be issued. This new guidance is effective for interim or financial
periods ending after June 15, 2009. We adopted this new guidance in our interim period ended June
30, 2009 (see Note 13).
In June 2009, the FASB issued The FASB Accounting Standards Codification and the Hierarchy of
Generally Accepted Accounting Principle (the Codification). On September 15, 2009, the
Codification became the source of authoritative U.S. generally accepted accounting principles
(GAAP) recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive
releases of the SEC under authority of federal securities laws are also sources of authoritative
GAAP for SEC registrants. The Codification has superseded all then existing non-SEC accounting and
reporting standards. All other non grandfathered non-SEC accounting literature not included in the
Codification has become non authoritative.
No other new accounting pronouncements issued or effective during the nine months ended
September 30, 2009 have had or are expected to have a material impact on our condensed consolidated
financial statements.
(11) Fair Value Measurements
FASB
accounting guidance establishes a valuation hierarchy for disclosure of the inputs to valuation used to
measure fair value. This hierarchy prioritizes the inputs into the following three levels:
Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or
liabilities.
Level 2 inputs are quoted prices for similar assets and liabilities in active markets or
inputs that are observable for the asset or liability, either directly or indirectly through market
corroboration.
Level 3 inputs are unobservable inputs based on our own assumptions used to measure assets
and liabilities at fair value.
A financial asset or liabilitys classification within the hierarchy is determined based on
the lowest level input that is significant to the fair value measurement.
The following table presents the fair value hierarchy table for our assets and liabilities that are
required to be measured at fair value on a recurring basis:
Fair Value Measurements at September 30, 2009 Using: | ||||||||||||||||
Quoted Prices in | Significant | |||||||||||||||
Active Markets | Other | Significant | ||||||||||||||
for Identical | Observable | Unobservable | ||||||||||||||
Assets | Inputs | Inputs | ||||||||||||||
Total Carrying Value | (Level 1) | (Level 2) | (Level 3) | |||||||||||||
Derivative instruments |
$ | (98,484 | ) | $ | | $ | (98,484 | ) | $ | |
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Our derivative instruments consist of over-the-counter (OTC) contracts which are not
traded on a public exchange. These derivative instruments are indexed to active trading hubs for
the underlying commodity, and are OTC contracts commonly used in the energy industry and offered by
a number of financial institutions and large energy companies.
As the fair value of these derivative instruments is based on inputs using market prices
obtained from independent brokers or determined using quantitative models that use as their basis
readily observable market parameters that are actively quoted and can be validated through external
sources, including third-party pricing services, brokers and market transactions, we have
categorized these derivative instruments as Level 2.
Our estimates of fair value have been determined at discrete points in time based on relevant
market data. These estimates involve uncertainty and cannot be determined with precision. There
were no changes in valuation techniques or related inputs in the three or nine months ended
September 30, 2009.
(12) Asset Retirement Obligations
If a reasonable estimate of the fair value of an obligation to perform site reclamation,
dismantle facilities or plug and abandon wells can be made, we record an asset retirement
obligation (ARO) and capitalize the asset retirement cost in oil and natural gas properties in
the period in which the retirement obligation is incurred. After recording these amounts, the ARO
is accreted to its future estimated value using an assumed cost of funds and the additional
capitalized costs are depreciated on a unit-of-production basis. The changes in the aggregate ARO
are as follows:
Balance as of December 31, 2008 |
$ | 23,885 | ||
Accretion expense |
989 | |||
Liabilities incurred |
13 | |||
Liabilities settled |
(2,077 | ) | ||
Revisions in estimated cash flows |
| |||
Balance as of September 30, 2009 |
$ | 22,810 | ||
As of September 30, 2009 and December 31, 2008, $202,000 and $229,000, respectively, of
our ARO is classified as current.
(13) Subsequent Event
On October 23, 2009, we received an equity contribution from our parent in the amount $12.5
million which was used to repay $12.5 million under our Amended Credit Agreement on October 26,
2009.
On November, 6 2009, we completed the sale of undeveloped acreage in Bradford County,
Pennsylvania for approximately $35.8 million.
We evaluated subsequent events through November 12, 2009, the date of our condensed
consolidated financial statements were issued.
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Item 2. Managements 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
the 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, continue, estimate, plan, outlook, may, future, projection,
likely, possible, could and variations of these statements and similar expressions are
forward-looking statements as are any other statements relating to developments, events,
occurrences, results, efforts or impacts. These forward-looking statements are based on current
expectations and projections about future events. Forward-looking statements and the business
prospects of Belden & Blake are subject to a number of risks and uncertainties which may cause our
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, our access to capital, the
market demand for and prices of oil and natural gas, our oil and gas production and costs of
operation, results of our future drilling activities, the uncertainties of reserve estimates,
general economic conditions, including current economic and financial market crisis, new
legislation or regulatory changes, changes in accounting principles, policies or guidelines and
environmental risks. These and other risks are described in our Annual Report on Form 10-K for the
year ended December 31, 2008, under the Heading Risk Factors and in our other filings with the
Securities and Exchange Commission (SEC). We undertake no obligation to publicly update or
revise any forward-looking statement, whether as a result of new information, future events,
changes in assumptions, or otherwise.
Impact of the Current Financial and Credit Markets
The U.S. and other world economies have been in a recession which has lasted well into 2009
and economic conditions remain uncertain. Additionally, the financial and credit markets are
undergoing unprecedented disruptions. Many financial institutions have liquidity concerns prompting
intervention from governments. Our exposure to the disruptions in the financial markets includes
our credit facility and investments exposure.
Our credit facility extends through August 16, 2011. If the disruption in the financial
markets continues for an extended period of time, replacement or amendment of the credit facility
may be more expensive.
We have reviewed the creditworthiness and believe our hedge counterparties to be strong and
creditworthy. However, current disruptions occurring in the financial markets could lead to sudden
changes in a counterpartys liquidity, which could impair their ability to perform under the terms
of the hedging contract. We are unable to predict sudden changes in a counterpartys
creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our
ability to negate the risk may be limited depending upon market conditions.
While oil and gas prices have strengthened in recent months, they remain unstable and are
expected to be volatile in the future. Continued lower commodity prices will reduce the Companys
cash flows from operations.
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Results of Operations
The following table sets forth certain information regarding our net oil and natural gas
production, revenues and expenses for the periods indicated. The average prices shown in the table
include the effects of our qualified effective hedging activities.
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Production |
||||||||||||||||
Gas (Mmcf) |
2,941 | 3,308 | 9,288 | 9,902 | ||||||||||||
Oil (Mbbls) |
83 | 80 | 246 | 246 | ||||||||||||
Total production (Mmcfe) |
3,440 | 3,789 | 10,762 | 11,377 | ||||||||||||
Average price (1) |
||||||||||||||||
Gas (per Mcf) |
$ | 3.39 | $ | 9.83 | $ | 3.58 | $ | 9.40 | ||||||||
Oil (per Bbl) |
64.51 | 115.10 | 52.61 | 108.19 | ||||||||||||
Mcfe |
4.46 | 11.02 | 4.29 | 10.52 | ||||||||||||
Average costs (per Mcfe) |
||||||||||||||||
Production expense |
$ | 1.49 | $ | 1.73 | $ | 1.52 | $ | 1.72 | ||||||||
Production taxes |
0.07 | 0.24 | 0.07 | 0.22 | ||||||||||||
Depletion |
2.61 | 2.22 | 2.61 | 2.25 |
(1) | The average prices presented above include non-cash amounts related to derivative contracts. Excluding these non-cash amounts from oil and gas sales revenues would result in the following average prices: |
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Gas (per Mcf) |
$ | 3.70 | $ | 10.18 | $ | 4.19 | $ | 10.04 | ||||||||
Oil (per Bbl) |
64.51 | 115.10 | 52.61 | 108.19 | ||||||||||||
Mcfe |
4.73 | 11.33 | 4.81 | 11.08 |
Results of Operations Third Quarters of 2009 and 2008 Compared
Revenues
Operating revenues decreased from $45.5 million in the third quarter of 2008 to $17.0 million
in the third quarter of 2009. The decrease in operating revenues was primarily due to lower oil
and gas sales revenues of $26.4 million and lower gas gathering and marketing revenues of $2.3
million. The decreased oil and gas sales revenues were primarily due to a decrease of $23.2
million related to lower prices for oil and natural gas and a $3.6 million decrease due to lower
gas sales volumes.
Gas volumes sold were 2.9 Bcf in the third quarter of 2009, which was a decrease of 367 Mmcf
(11%) compared to the third quarter of 2008. This decrease in gas volumes sold resulted in a
decrease in gas sales revenues of approximately $3.6 million. Oil volumes sold increased
approximately 3,000 Bbls (4%) from 80,000 Bbls in the third quarter of 2008 to 83,000 Bbls in the
third quarter of 2009 resulting in an increase in oil sales revenues of approximately $330,000.
The lower gas sales volumes are primarily due to normal production declines and the sale of the
coalbed methane assets in Pennsylvania which are partially offset by production from new wells
drilled and wells reworked during 2008 and 2009.
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The average price realized for our natural gas decreased $6.44 per Mcf from $9.83 in the third
quarter of 2008 to $3.39 per Mcf in the third quarter of 2009, which reduced gas sales revenues by
approximately $19.0 million. As a result of our qualified hedging and derivative financial
instrument activities, gas sales revenues were lower by $921,000 ($0.31 per Mcf) in the third
quarter of 2009 and lower by $1.2 million ($0.35 per Mcf) in the third quarter of 2008 than if our
gas price was not affected by
derivative financial instruments. The average price realized for our oil decreased from
$115.10 per Bbl in the third quarter of 2008 to $64.51 per Bbl in the third quarter of 2009, which
reduced oil sales revenues by approximately $4.2 million.
Gas gathering and marketing revenues decreased from $3.6 million in the third quarter of 2008
to $1.3 million in the third quarter of 2009. The decrease was due to a $1.7 million decrease in
gas marketing revenues and a $600,000 decrease in gas gathering revenues as a result of lower
average gas prices in the third quarter of 2009 compared to the third quarter of 2008.
Costs and Expenses
Production expense decreased $1.5 million from $6.6 million in the third quarter of 2008 to
$5.1 million in the third quarter of 2009. The average production cost decreased from $1.73 per
Mcfe in the third quarter of 2008 to $1.49 per Mcfe in the third quarter of 2009. The decrease in
production expense was due to decreases in labor costs, gas processing costs, well work activity,
the sale of the coalbed methane assets in Pennsylvania and general decreases in third party service
costs.
Production taxes decreased $649,000 from $895,000 in the third quarter of 2008 to $246,000 in
the third quarter of 2009. Average per unit production taxes decreased from $0.24 per Mcfe in the
third quarter of 2008 to $0.07 per Mcfe in the third quarter of 2009. The decreased production
taxes were primarily due to lower oil and gas prices in Michigan in the third quarter of 2009
compared to the third quarter of 2008. In Michigan, production taxes are based on a percentage of
revenues, excluding the effects of hedging.
Gas gathering and marketing expenses decreased from $2.8 million in the third quarter of 2008
to $1.2 million in the third quarter of 2009. The decrease was primarily due to a $1.7 million
decrease in gas marketing expenses as a result of lower average gas prices in the third quarter of
2009 compared to the third quarter of 2008.
Exploration expense decreased $765,000 from $1.6 million in the third quarter of 2008 to
$849,000 in the third quarter of 2009. The decrease in exploration expense was primarily due to a
decrease in dry hole expense.
Impairment of oil and gas properties was a credit of $1.3 million in the third quarter of 2009
due to an adjustment to the impairment of coalbed methane properties in Pennsylvania properties
which was recorded in the second quarter of 2009. These properties were sold in the third quarter
of 2009.
General and administrative expense decreased $594,000 from $2.2 million in the third quarter
of 2008 to $1.6 million in the third quarter of 2009. The decrease was primarily due to lower
overhead fees incurred to EverVest and lower franchise tax expense.
Depreciation, depletion and amortization increased by $549,000 from $8.5 million in the third
quarter of 2008 to $9.1 million in the third quarter of 2009. This increase was primarily due to a
$560,000 increase in depletion expense. Depletion per Mcfe increased from $2.22 per Mcfe in the
third quarter of 2008 to $2.61 per Mcfe in the third quarter of 2009, primarily due to decreased
reserves volumes at June 30, 2009 due to lower oil and gas prices.
Derivative fair value loss (gain) was a loss of $539,000 in the third quarter of 2009 compared
to a gain of $134.8 million in the third quarter of 2008. The derivative fair value loss (gain)
reflects the changes in fair value of certain derivative instruments that are not designated or do
not qualify as cash flow hedges. The change was due to the fluctuation of oil and gas prices during
those periods.
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Interest expense decreased $342,000 from $5.8 million in the third quarter of 2008 to $5.4
million
in the third quarter of 2009. This decrease in interest expense was primarily due to lower debt
levels partially offset by higher blended interest rates.
Income tax expense was a benefit of $2.3 million in the third quarter of 2009 compared to
expense of $60.0 million in the third quarter of 2008. The change in income tax expense was
primarily due to a decrease in income before income taxes. The decrease in income before income
taxes was primarily due to the change in the derivative fair value loss (gain) and the decrease in
oil and gas sales revenues.
Results of Operations Nine Months of 2009 and 2008 Compared
Revenues
Operating revenues decreased from $130.1 million in the first nine months of 2008 to $51.5
million in the first nine months of 2009. The decrease in operating revenues was primarily due to
lower oil and gas sales revenues of $73.5 million and lower gas gathering and marketing revenues of
$5.4 million. The decreased oil and gas sales revenues were due to a decrease of $67.7 million
related to lower prices for oil and natural gas and a $5.8 million decrease in revenues due to
lower gas sales volumes.
Gas volumes sold were 9.3 Bcf in the first nine months of 2009, which was a decrease of 613
Mmcf (6%) compared to the 9.9 Bcf sold in the first nine months of 2008. This decrease in gas
volumes sold resulted in a decrease in gas sales revenues of approximately $5.8 million. Oil
volumes sold were 246,000 Bbls in the first nine months of 2008 and 2009. The decrease in gas
sales volumes was primarily due to normal production declines and the sale of the coalbed methane
assets in Pennsylvania, which were partially offset by production from new wells drilled and wells
reworked in 2008 and 2009.
The average price realized for our natural gas decreased $5.82 per Mcf from $9.40 in the first
nine months of 2008 to $3.58 per Mcf in the first nine months of 2009, which reduced gas sales
revenues by approximately $54.1 million. As a result of our qualified hedging and derivative
financial instrument activities, gas sales revenues were lower by $5.6 million ($0.61 per Mcf) in
the first nine months of 2009 and lower by $6.3 million ($0.64 per Mcf) in the first nine months of
2008 than if our gas price was not affected by derivative financial instruments. The average price
realized for our oil decreased from $108.19 per Bbl in the first nine months of 2008 to $52.61 per
Bbl in the first nine months of 2009, which reduced oil sales revenues by approximately $13.6
million.
Gas gathering and marketing revenues decreased from $9.9 million in the first nine months of
2008 to $4.6 million in the first nine months of 2009 due to a $4.2 million decrease in gas
marketing revenues and a $1.2 million decrease in gas gathering revenues as a result of lower
average gas prices in the first nine months of 2009 compared to the first nine months of 2008.
Costs and Expenses
Production expense decreased from $19.5 million in the first nine months of 2008 to $16.3
million in the first nine months of 2009. The average production cost decreased from $1.72 per
Mcfe in the first nine months of 2008 to $1.52 per Mcfe in the first nine months of 2009. The
decrease in production expense was primarily due to decreases in labor costs, gas processing costs,
well work activity, the sale of the coalbed methane assets in Pennsylvania and general decreases in
third party service costs.
Production taxes decreased from $2.5 million in the first nine months of 2008 to $799,000 in
the first nine months of 2009. Average per unit production taxes decreased from $0.22 per Mcfe in
the first nine months of 2008 to $0.07 per Mcfe in the first nine months of 2009. The decreased
production taxes are primarily due to lower oil and gas prices in the first nine months of 2009 in
Michigan, where production taxes are based on a percentage of revenues, excluding the effects of
hedging.
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Gas gathering and marketing expenses decreased $4.0 million from $8.2 million in the first
nine months of 2008 to $4.2 million in the first nine months of 2009, primarily due to a $4.2
million decrease in gas marketing expenses as a result of lower average gas prices in the first
nine months of 2009 compared to the first nine months of 2008.
Exploration expense increased $1.0 million from $2.2 million in the first nine months of 2008
to $3.2 million in the first nine months of 2009. The increase in exploration expense was
primarily due to the noncash write-off of costs related to expired undeveloped leases in the first
quarter of 2009, higher lease rental expense and seismic costs related to the evaluation of Knox
formation drilling potential on recently acquired acreage in Ohio.
Impairment of oil and gas properties was $2.0 million in the first nine months of 2008 due to
the impairment of properties in the Utica Shale formation in Ohio. Impairment of oil and gas
properties was $23.9 million in the first nine months of 2009 due to the impairment of coalbed
methane properties in Pennsylvania which were sold in the third quarter of 2009.
General and administrative expense decreased from $6.2 million in the first nine months of
2008 to $5.9 million in the first nine months of 2009. This decrease was primarily due to lower
third party service fees, lower overhead fees paid to EnerVest and lower franchise tax expense,
which was partially offset by higher bad debt expense.
Depreciation, depletion and amortization increased by $2.5 million from $25.9 million in the
first nine months of 2008 to $28.4 million in the first nine months of 2009. This increase was
primarily due to a $2.6 million increase in depletion expense, which was primarily due to a
decrease in reserves volumes at June 30, 2009 due to lower oil and gas prices. Depletion per Mcfe
increased from $2.25 per Mcfe in the first nine months of 2008 to $2.61 in the first nine months of
2009.
Derivative fair value loss (gain) was a gain of $19.9 million in the first nine months of 2009
compared to a loss of $10.4 million in the first nine months of 2008. The derivative fair value
loss (gain) reflects the changes in fair value of certain derivative instruments that are not
designated or do not qualify as cash flow hedges. The change was due to the fluctuation of oil and
gas prices during those periods.
Interest expense decreased $1.9 million from $17.4 million in the first nine months of 2008 to
$15.5 million in the first nine months of 2009. This decrease in interest expense was primarily
due to lower blended interest rates and lower debt levels.
Income tax expense was a benefit of $10.9 million in the first nine months of 2009 compared to
expense of $13.8 million in the first nine months of 2008. The change in income tax expense was
primarily due to a decrease in income before income taxes. The decrease in income before income
taxes was primarily due to the change in the derivative fair value loss (gain), lower oil and gas
sales revenues and an increase in the impairment of oil and gas properties.
Liquidity and Capital Resources
Cash Flows
The primary sources of cash in the nine month period ended September 30, 2009 have been funds
generated from operations and proceeds from asset sales. Funds used during this period were
primarily used for operations, development expenditures, debt repayment and interest expense. Our
liquidity and capital resources are closely related to and dependent upon the current prices paid
for our oil and gas.
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Our operating activities provided cash flows of $18.3 million during the first nine months of
2009 compared to $79.7 million in the first nine months of 2008. The decrease was primarily due to
a decrease
in oil and gas revenues (net of hedging) which was partially offset by an increase in the change in
working capital items of $7.1 million.
Our investing activities provided cash flows of $4.5 million during the first nine months of
2009 compared to $17.4 million used in the first nine months of 2008. The increase was due to a
decrease in capital expenditures of $8.0 million and an increase in cash received for property and
equipment disposals of $14.4 million.
Cash flows used in financing activities decreased $16.3 million in the first nine months of
2009 from $53.9 million in the first nine months of 2008 to $37.6 million in the first nine months
of 2009. The decrease was primarily due to a decrease of $51.3 million in derivative settlements
and an increase in capital contributions of $7.5 million which was partially offset by an increase
in the repayment of long term debt of $43.6 million and an increase in debt financing costs of $1.5
million.
Our current ratio at September 30, 2009 was 0.76 to 1. During the first nine months of 2009,
working capital increased $7.7 million from a deficit of $16.8 million at December 31, 2008 to a
deficit of $9.1 million at September 30, 2009. The increase in working capital was primarily due
to a decrease in the current portion of long term liabilities of $25.0 million, a decrease in
accrued expenses of $6.3 million, which was partially offset by a $14.8 million decrease in cash, a
$8.0 million decrease in accounts receivable and an increase in accounts payable of $1.1 million.
Capital Expenditures
During the first nine months of 2009, we spent approximately $10.7 million on our drilling
activities and other capital expenditures. In the first nine months of 2009, we drilled 3 gross
(1.7 net) wells, which were all completed as producing wells in the target formation. We also
performed major workovers on 15 wells during the first nine months of 2009.
We currently expect to spend approximately $12.7 million during 2009 on our drilling
activities and other capital expenditures. We intend to finance our planned capital expenditures
through our cash on hand and available operating cash flow. At September 30, 2009, we had cash of
$8.0 million and approximately $7.5 million available under our revolving facility. The level of
our future cash flow will depend on a number of factors including the demand for and price levels
of oil and gas and the scope and success of our drilling and workover activities. There can be no
assurance that the future drilling of our proved undeveloped locations will provide adequate
liquidity in the future.
Financing and Credit Facilities
On September 25, 2009, Belden & Blake Corporation entered into the Fifth Amendment to Credit
Agreement. The Credit Agreement was amended to (1) reduce the borrowing base to $65 million, (2)
extend the termination date by one year to August 16, 2011, (3) decrease the aggregate amount of
the revolving commitments to $100 million, and (4) make certain other amendments to the Credit
Agreement.
At September 30, 2009, we had an Amended Credit Agreement comprised of a five-year $100
million revolving facility with a borrowing base of $65 million, of which $56.4 million was
outstanding at September 30, 2009. On October 23, 2009, we
received an equity contribution from our parent in the amount of
$12.5 million which was used to repay $12.5 million under
our Amended Credit Agreement on October 26, 2009. This facility is for working capital requirements and general
corporate purposes, including the issuance of letters of credit; and a five year $40 million letter
of credit facility that may be used only to provide credit support for our obligations under the
hedge agreement and other hedge transactions. Borrowings under the Amended Credit Agreement bear
interest (i) at the greater of the prime rate, an adjusted federal funds rate or an adjusted
Eurodollar rate, plus an applicable margin ranging from 1.0% to 2.0% based on the aggregate
principal amount outstanding under the Amended Credit Agreement, or, (ii) at our option, the
Eurodollar base rate plus an applicable margin ranging from 2.5% to 3.5% based on the aggregate
principal amount outstanding under the Amended Credit Agreement. The full amount
borrowed under the Amended Credit Agreement will mature on August 16, 2011.
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The obligations under the Amended Credit Agreement are secured by a first lien security
interest in substantially all of our assets. The obligations under the Amended Credit Agreement are
further secured by a pledge of 100% of our capital stock held by Capital C, our parent.
The Amended Credit Agreement contains covenants that will limit or prohibit our ability to,
among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or
repurchase stock; pay principal and interest on certain subordinated debt; make certain types of
investments; sell assets or merge with another entity; pledge or otherwise encumber our capital
stock; or enter into transactions with affiliates. The Amended Credit Agreement also requires
compliance with customary financial covenants, including a minimum interest coverage ratio, a
maximum leverage ratio and a minimum current ratio.
Changes in oil and gas prices significantly affect our revenues, financial condition, cash
flows and borrowing capacity. Markets for oil and gas have historically been volatile and we expect
this trend to continue. Prices for oil and gas may fluctuate in response to changes in supply and
demand, market uncertainty, seasonal, political and other factors beyond our control. We are unable
to accurately predict the prices we will receive for our oil and gas. Accordingly, any significant
or sustained declines in oil and gas prices will materially adversely affect our financial
condition, operating results, liquidity and ability to obtain additional financing or to refinance
our Amended Credit Agreement upon maturity. Continued or prolonged low oil and gas prices may also
result in non-compliance with our financial covenants in our Amended Credit Agreement. If we were
not in compliance with the covenants in a future period, an event of default may occur which could
cause all outstanding debt under the Amended Credit Agreement, the senior secured notes and our
derivative contracts to be due and payable. We expect to maintain compliance with the covenants
through 2009 and 2010.
At September 30, 2009, we were in compliance with our covenants under the Amended Credit
Agreement.
At September 30, 2009, we had $41.1 million of outstanding letters of credit. At September 30,
2009, there was $56.4 million outstanding under the revolving
credit agreement. We had $7.5 million
of borrowing capacity under our revolving facility available for general corporate purposes.
In connection with our entry into the Amended Credit Agreement, we executed a Subordinated
Promissory Note (Subordinated Note) in favor of Capital C in the maximum principal amount of $94
million. Under the Subordinated Note, Capital C loaned $25 million to us on August 16, 2005. As of
September 30, 2009, the current amount due under the Subordinated Note was $29.7 million. The
Subordinated Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. In
lieu of cash payments, we have the option to make interest payments on the Subordinated Note by
borrowing additional amounts against the Subordinated Note. The Subordinated Note has no
prepayment penalty or premium and may be prepaid in whole or in part at any time. Pursuant to our
Amended Credit Agreement cash payments for principal or interest on the Subordinated Note are
prohibited. The Subordinated Note is subordinate to our senior debt, which includes obligations
under the Amended Credit Agreement, a long-term hedging program with J. Aron under a master
agreement and related confirmations and documentation and senior secured notes issued under our
Indenture dated July 7, 2004 with BNY Midwest Trust Company, as indenture trustee.
New Accounting Standards
In December 2007, the FASB issued new accounting guidance regarding the accounting for
business combinations. This new guidance retains the acquisition method of accounting used in
business combinations and establishes principles and requirements for the recognition and
measurement of assets, liabilities and goodwill, including the requirement that most transaction
and restructuring costs related to
the acquisition be expensed. In addition, this guidance requires disclosures to enable users to
evaluate the nature and financial effects of the business combination. We adopted this new
guidance on January 1, 2009.
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In March 2008, the FASB issued new accounting guidance requiring enhanced disclosures about an
entitys derivative and hedging activities and their effect on an entitys financial position,
financial performance and cash flows. This new guidance is effective for fiscal years and interim
periods beginning after November 15, 2008. We adopted the new accounting guidance on January 1,
2009 (see Note 2).
In December 2008, the SEC published Modernization of Oil and Gas Reporting, a revision to its
oil and natural gas reporting disclosures. The new disclosure requirements include provisions that
permit the use of new technologies to determine proved reserves if those technologies have been
demonstrated empirically to lead to reliable conclusions about reserves volumes. The new
requirements also will allow companies to disclose their probable and possible reserves to
investors. In addition, the new disclosure requirements require companies to: (i) report the
independence and qualifications of its reserves preparer or auditor; (ii) file reports when a third
party is relied upon to prepare reserves estimates or conducts a reserves audit; and (iii) report
oil and natural gas reserves using an average price based upon the prior 12 month period rather
than year end prices. The new disclosure requirements are effective for registration statements
filed on or after January 1, 2010, and for annual reports on Forms 10-K and 20-F for fiscal years
ending on or after December 31, 2009. We will adopt the new disclosure requirements for our Form
10-K for the year ending December 31, 2009.
In April 2009, the FASB issued new accounting guidance to require disclosures about the fair
value of financial instruments for interim reporting periods of publicly traded companies as well
as in annual financial statements. This new guidance is effective for interim or financial periods
ending after June 15, 2009. We adopted this new guidance in our interim period ended June 30, 2009
(see Notes 2 and 11).
In May 2009, the FASB issued new accounting guidance to establish standards of accounting for
and disclosure of events that occur after the balance sheet date but before financial statements
are issued or are available to be issued. This new guidance is effective for interim or financial
periods ending after June 15, 2009. We adopted this new guidance in our interim period ended June
30, 2009 (see Note 13).
In June 2009, the FASB issued The FASB Accounting Standards Codification and the Hierarchy of
Generally Accepted Accounting Principle (the Codification). On September 15, 2009, the
Codification became the source of authoritative U.S. generally accepted accounting principles
(GAAP) recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive
releases of the SEC under authority of federal securities laws are also sources of authoritative
GAAP for SEC registrants. The Codification has superseded all then existing non-SEC accounting and
reporting standards. All other non grandfathered non-SEC accounting literature not included in the
Codification has become non authoritative.
No other new accounting pronouncements issued or effective during the nine months ended
September 30, 2009 have had or are expected to have a material impact on our condensed consolidated
financial statements.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
Among other risks, we are exposed to interest rate and commodity price risks.
The interest rate risk relates to existing debt under our revolving facility as well as any
new debt financing needed to fund capital requirements. We may manage our 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 our floating rate exposure is exchanged for a fixed interest rate. A portion
of our long-term debt consists of senior secured notes where the interest component is fixed. At
September 30, 2009, we had interest rate swaps in place covering $43.5 million of our outstanding
balance on the revolving credit agreement. The fair value of these interest rate swaps was an
unrealized loss of $2.8 million at September 30, 2009. If market interest rates for short-term
borrowings increased 1%, the increase in interest expense in the first nine months of 2009 would be
approximately $603,000. The impact of the interest rate increase on our cash flows would be
significantly less than this amount due to the interest rate swaps in place. The impact of the
interest rate increase would reduce our cash flows by approximately $94,000. This sensitivity
analysis is based on our financial structure at September 30, 2009.
The commodity price risk relates to natural gas and crude oil produced, held in storage and
marketed. Our financial results can be significantly impacted as commodity prices fluctuate widely
in response to changing market forces. From time to time, we may enter into a combination of
futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure
to commodity price volatility. We employ a policy of partially hedging oil and gas production
selling NYMEX-based commodity derivative contracts which are placed with major financial
institutions that we believe are minimal credit risks. The contracts may take the form of futures
contracts, swaps or options. At September 30, 2009, we had derivatives covering a portion of our
oil and gas production from 2009 through 2013. Our oil and gas sales revenues included a net
pre-tax loss of $1.2 million in the third quarter of 2008 and a net pre-tax loss of $921,000 in the
third quarter of 2009 relating to hedges which previously qualified
for hedge accounting and were subsequently de-designated. Our oil and gas sales revenues included
a net pre-tax loss of $6.3 million in the first nine months of 2008 and a net pre-tax loss of $5.6
million in the first nine months of 2009 on our qualified hedging activities.
If gas prices decreased $1.00 per Mcf, our gas sales revenues for the first nine months of
2009 would decrease by approximately $9.3 million. If the price of crude oil decreased $10.00 per
Bbl, our oil sales revenues for the first nine months of 2009 would
decrease by approximately $2.5 million. The impact of these price decreases on our cash flows would be significantly less than
these amounts due to our oil and gas derivatives. Price decreases of $1.00 per Mcf and $10.00 per
Bbl would decrease cash flows from the sale of oil and gas for the first nine months of 2009 by
approximately $3.2 million after considering the effects of the derivative contracts in place as of
September 30, 2009. This sensitivity analysis is based on our first nine months 2009 oil and gas
sales volumes.
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The following table reflects the natural gas and crude oil volumes and the weighted average
prices under financial hedges (including settled hedges) at October 31, 2009, which has not changed
since September 30, 2009:
Natural Gas Swaps | Crude Oil Swaps | Natural Gas Basis Swaps | ||||||||||||||||||||||
NYMEX | NYMEX | Basis | ||||||||||||||||||||||
Bbtu | Price per Mmbtu | Mbbls | Price per Bbl | Bbtu | Differential | |||||||||||||||||||
Quarter Ending |
||||||||||||||||||||||||
December 31, 2009 |
2,382 | $ | 4.47 | 48 | $ | 29.09 | 2,116 | $ | 0.34 | |||||||||||||||
Year Ending |
||||||||||||||||||||||||
December 31, 2010 |
8,938 | $ | 4.28 | 175 | $ | 28.86 | 7,665 | $ | 0.243 | |||||||||||||||
December 31, 2011 |
8,231 | 4.19 | 157 | 28.77 | 5,110 | 0.252 | ||||||||||||||||||
December 31, 2012 |
7,005 | 4.09 | 138 | 28.70 | 3,660 | 0.110 | ||||||||||||||||||
December 31, 2013 |
6,528 | 4.04 | 127 | 28.70 | | |
The fair value of our oil and gas swaps was a net liability of approximately $95.7 million as
of September 30, 2009.
At September 30, 2009, we had interest rate swaps in place covering $43.5 million of our
outstanding debt under the revolving credit facility. On September 29, 2009, we amended the
existing swaps to cover $43.5 million of our outstanding debt through September 30, 2013. The
amended swaps provide 1-month LIBOR fixed rates of 4.10%, plus the applicable margin. The fair
value of these interest rate swaps was an unrealized loss of $2.8 million at September 30, 2009.
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Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We have established and maintain a system of disclosure controls and procedures to provide
reasonable assurances that information required to be disclosed by us in the reports that we file
or submit under the Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the SECs rules and forms. Based on the evaluation of our disclosure controls
and procedures as of the end of the period covered by this report, the principal executive officer
and principal financial officer of Belden & Blake Corporation have concluded that our disclosure
controls and procedures as of September 30, 2009 were effective, at a reasonable assurance level,
in ensuring that the information required to be disclosed by us in reports filed under the Exchange
Act is recorded, processed, summarized and reported within the time periods specified in the rules
and forms of the SEC.
Change in Internal Controls Over Financial Reporting
There have not been any changes in our internal controls over financial reporting that
occurred during the quarterly period ended September 30, 2009 that materially affected, or are
reasonably likely to materially affect, our internal controls over financial reporting.
PART II OTHER INFORMATION
Item 1. Legal Proceedings
We are involved in several lawsuits arising in the ordinary course of business. We believe
that the result of such proceedings, individually or in the aggregate, will not have a material
adverse effect on our financial position or the results of operations.
Item 1A. Risk Factors
As of the date of this filing, there have been no changes from the risk factors previously
disclosed in our Risk Factors in our Annual Report on Form 10-K for the year ended December 31,
2008.
These risks and uncertainties are not the only ones facing us and there may be additional
matters that we are unaware of or that we currently consider immaterial. All of these could
adversely affect our business, financial condition, results of operations and cash flows.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults upon Senior Securities
None.
Item 4. Submission of Matters to a Vote of Security Holders
None.
Item 5. Other Information
None.
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Item 6. Exhibits.
(a) Exhibits
31.1 | * | Certification of Principal Executive Officer of Belden & Blake Corporation as required by
Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934 |
|
31.2 | * | Certification of Principal Financial Officer of Belden & Blake Corporation as required by
Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934 |
|
32.1 | * | Certification of Chief Executive Officer of Belden & Blake Corporation pursuant to 18 U.S.C.
Section 1350. |
|
32.2 | * | Certification of Chief Financial Officer of Belden & Blake Corporation pursuant to 18 U.S.C.
Section 1350. |
* | Filed herewith. |
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the
Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
BELDEN & BLAKE CORPORATION |
||||
Date: November 12, 2009 | By: | /s/ Mark A. Houser | ||
Mark A. Houser, Chief Executive Officer, | ||||
Chairman of the Board of Directors and Director (Principal Executive Officer) |
||||
Date: November 12, 2009 | By: | /s/ James M. Vanderhider | ||
James M. Vanderhider, President, | ||||
Chief Financial Officer and Director (Principal Financial Officer) |
23