UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ
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Quarterly report under Section 13 or 15(d) of the Securities Exchange Act of 1934
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For the quarterly period ended September 30, 2007.
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o
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Transition report under Section 13 or 15(d) of the Securities Exchange Act of 1934
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For the transition period from
to
.
Commission file number: 0-17371
QUEST RESOURCE CORPORATION
(Exact name of registrant as specified in its charter)
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Nevada
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90-0196936
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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9520 N. May Avenue, Suite 300, Oklahoma City, OK
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73120
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(Address of principal executive offices)
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(Zip Code)
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405-488-1304
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 past 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 is a large accelerated filer, an accelerated filer or
a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule
12b-2 of the Exchange Act. (Check one):
Large accelerated filer
o
Accelerated filer
þ
Non-accelerated filer
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 November 7, 2007, the issuer had 22,483,276 shares of common stock outstanding.
QUEST RESOURCE CORPORATION
FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2007
TABLE OF CONTENTS
-2-
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
Except as otherwise required by the context, references in this quarterly report to we,
our, us, Quest or the Company refer to Quest Resource Corporation and its subsidiaries:
Quest Cherokee, LLC; Quest Cherokee Oilfield Service, LLC; Bluestem Pipeline, LLC; Quest Midstream
Partners, L.P.; Quest Midstream GP, LLC; Quest Energy Partners, L.P., Quest Energy GP, LLC, Quest
Oil & Gas, LLC; Ponderosa Gas Pipeline Company, LLC; Quest Energy Service, LLC; STP Cherokee, LLC;
Producers Service, LLC; and J-W Gas Gathering, L.L.C. Our operations are primarily conducted
through Quest Cherokee, LLC, Quest Cherokee Oilfield Service, LLC, Bluestem Pipeline, LLC and Quest
Energy Service, LLC.
Our unaudited interim financial statements, including condensed consolidated balance sheets as
of December 31, 2006 and September 30, 2007, a condensed consolidated statement of operations and
comprehensive income for the three month and nine month periods ended September 30, 2006 and 2007,
and a condensed consolidated statement of cash flows for the nine month periods ended September 30,
2006 and 2007, and the notes thereto are attached hereto as Pages F-1 through F-17 and are
incorporated herein by this reference.
The financial statements included herein have been prepared internally, without audit,
pursuant to the rules and regulations of the Securities and Exchange Commission and the Public
Company Accounting Oversight Board. Certain information and footnote disclosures normally included
in financial statements prepared in accordance with generally accepted accounting principles have
been omitted. However, in our opinion, all adjustments (which include only normal recurring
accruals) necessary to fairly present the financial position and results of operations have been
made for the periods presented. The results of operations of any interim period are not
necessarily indicative of the results of operations for the full year.
The financial statements included herein should be read in conjunction with the financial
statements and notes thereto included in our annual report on Form 10-K/A for the year ended
December 31, 2006.
-3-
QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
($ in thousands, except per share amounts)
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December 31,
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September 30,
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2006
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2007
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(unaudited)
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ASSETS
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Current assets:
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Cash
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$
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41,820
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$
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21,002
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Restricted cash
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1,150
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1,236
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Accounts receivable, trade
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9,840
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10,425
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Other receivables
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371
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1,466
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Other current assets
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1,068
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2,128
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Inventory
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5,632
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5,792
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Short-term derivative asset
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10,795
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7,286
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Total current assets
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70,676
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49,335
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Property and
equipment, net of accumulated depreciation of $5,107 and $6,352
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16,212
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20,206
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Pipeline
assets, net of accumulated depreciation of $6,104 and $9,674
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127,690
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150,138
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Pipeline assets under construction
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880
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3,763
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Oil and gas properties:
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Properties being amortized
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316,780
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389,315
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Properties not being amortized
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9,545
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14,619
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326,325
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403,934
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Less: Accumulated depreciation, depletion, amortization and valuation allowance
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(92,732
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)
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(114,541
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)
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Net oil and gas properties
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233,593
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289,393
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Other assets, net
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9,467
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10,430
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Long-term derivative asset
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4,782
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8,697
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Total assets
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$
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463,300
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$
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531,962
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LIABILITIES AND STOCKHOLDERS EQUITY
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Current liabilities:
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Accounts payable
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$
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14,778
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$
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35,247
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Revenue payable
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4,540
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5,676
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Accrued expenses
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2,525
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3,287
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Current portion of notes payable
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324
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122
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Short-term derivative liability
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5,244
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6,098
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Total current liabilities
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27,411
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50,430
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Non-current liabilities:
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Long-term derivative liability
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7,449
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2,067
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Asset retirement obligation
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1,410
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1,619
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Notes payable
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225,569
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280,176
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Less current maturities
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(324
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)
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(122
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)
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Non-current liabilities
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234,104
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283,740
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Total liabilities
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261,515
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334,170
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Minority interest
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84,431
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82,629
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Commitments and contingencies
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Stockholders equity:
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10% convertible preferred stock, $.001 par value, 50,000,000 shares authorized,
0 shares issued and outstanding at December 31, 2006 and
September 30, 2007
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Common
stock, $.001 par value, 200,000,000 shares authorized, 22,206,014
shares issued and outstanding at December 31, 2006 and 22,483,276
shares issued and outstanding at September 30, 2007
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22
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22
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Additional paid-in capital
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205,994
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209,805
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Accumulated other comprehensive income (loss)
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428
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|
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|
7
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Accumulated deficit
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(89,090
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)
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|
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(94,671
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)
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|
|
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Total stockholders equity
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117,354
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|
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115,163
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|
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Total liabilities and stockholders equity
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$
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463,300
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$
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531,962
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The accompanying notes are an integral part of these financial statements.
F-1
QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(UNAUDITED)
($ in thousands, except per share amounts)
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For the Three Months Ended
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For the Nine Months Ended
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September 30,
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September 30,
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2006
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2007
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2006
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2007
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Revenue:
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Oil and gas sales
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$
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15,329
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$
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28,494
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$
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49,114
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$
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81,910
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Gas pipeline revenue
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1,372
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|
|
|
1,788
|
|
|
|
3,722
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|
|
|
5,122
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Other revenue (expense)
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|
4
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|
|
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(5
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)
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(63
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)
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(37
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)
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|
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|
|
|
|
|
|
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Total revenues
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|
16,705
|
|
|
|
30,277
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|
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|
52,773
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86,995
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|
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Costs and expenses:
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|
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Oil and gas production
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5,492
|
|
|
|
7,280
|
|
|
|
14,064
|
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|
22,247
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|
Pipeline operating
|
|
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3,400
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|
|
|
5,004
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|
|
|
9,330
|
|
|
|
14,271
|
|
General and administrative
|
|
|
2,723
|
|
|
|
3,653
|
|
|
|
6,596
|
|
|
|
11,698
|
|
Depreciation, depletion and amortization
|
|
|
7,875
|
|
|
|
9,276
|
|
|
|
20,643
|
|
|
|
25,610
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
19,490
|
|
|
|
25,213
|
|
|
|
50,633
|
|
|
|
73,826
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(2,785
|
)
|
|
|
5,064
|
|
|
|
2,140
|
|
|
|
13,169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in derivative fair value
|
|
|
(332
|
)
|
|
|
5,539
|
|
|
|
6,300
|
|
|
|
5,354
|
|
(Loss)/gain on sale of assets
|
|
|
(57
|
)
|
|
|
50
|
|
|
|
(14
|
)
|
|
|
(141
|
)
|
Interest income
|
|
|
74
|
|
|
|
102
|
|
|
|
323
|
|
|
|
382
|
|
Interest expense
|
|
|
(6,973
|
)
|
|
|
(8,206
|
)
|
|
|
(15,885
|
)
|
|
|
(22,928
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(7,288
|
)
|
|
|
(2,515
|
)
|
|
|
(9,276
|
)
|
|
|
(17,333
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before minority interest and income taxes
|
|
|
(10,073
|
)
|
|
|
2,549
|
|
|
|
(7,136
|
)
|
|
|
(4,164
|
)
|
Minority interest in consolidated subsidiary
|
|
|
|
|
|
|
(576
|
)
|
|
|
|
|
|
|
(1,660
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) before income taxes
|
|
|
(10,073
|
)
|
|
|
1,973
|
|
|
|
(7,136
|
)
|
|
|
(5,824
|
)
|
Income tax expense deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
(10,073
|
)
|
|
|
1,973
|
|
|
|
(7,136
|
)
|
|
|
(5,824
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss), net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fixed-price contract and other
derivative fair value, net of tax of $0 and $0
|
|
|
18,027
|
|
|
|
5,147
|
|
|
|
38,197
|
|
|
|
(421
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss)
|
|
|
18,027
|
|
|
|
5,147
|
|
|
|
38,197
|
|
|
|
(421
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
7,954
|
|
|
$
|
7,120
|
|
|
$
|
31,061
|
|
|
$
|
(6,245
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share basic
|
|
$
|
(0.46
|
)
|
|
$
|
0.09
|
|
|
$
|
(0.32
|
)
|
|
$
|
(0.26
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share diluted
|
|
$
|
(0.46
|
)
|
|
$
|
0.09
|
|
|
$
|
(0.32
|
)
|
|
$
|
(0.26
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common and common equivalent shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
22,123,514
|
|
|
|
22,296,179
|
|
|
|
22,090,363
|
|
|
|
22,240,077
|
|
Diluted
|
|
|
22,123,514
|
|
|
|
22,308,139
|
|
|
|
22,090,363
|
|
|
|
22,240,077
|
|
The accompanying notes are an integral part of these financial statements.
F-2
QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
($ in thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended September 30,
|
|
|
|
2006
|
|
|
2007
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(7,136
|
)
|
|
$
|
(5,824
|
)
|
Adjustments to reconcile net income (loss) to cash provided
by operations:
|
|
|
|
|
|
|
|
|
Depreciation and depletion
|
|
|
23,022
|
|
|
|
27,617
|
|
Change in derivative fair value
|
|
|
(16,532
|
)
|
|
|
(5,354
|
)
|
Stock issued for retirement plan
|
|
|
428
|
|
|
|
|
|
Stock options granted for directors fees
|
|
|
358
|
|
|
|
264
|
|
Stock awards granted to employees
|
|
|
466
|
|
|
|
3,850
|
|
Amortization of loan origination fees
|
|
|
874
|
|
|
|
1,757
|
|
Amortization of gas swap fees
|
|
|
146
|
|
|
|
187
|
|
Amortization of deferred hedging gains
|
|
|
(179
|
)
|
|
|
|
|
Bad debt expense
|
|
|
42
|
|
|
|
|
|
(Gain) loss on sale of assets
|
|
|
14
|
|
|
|
142
|
|
Minority interest
|
|
|
|
|
|
|
1,660
|
|
Change in assets and liabilities:
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
3,169
|
|
|
|
(86
|
)
|
Accounts receivable
|
|
|
1,456
|
|
|
|
(585
|
)
|
Other receivables
|
|
|
(23
|
)
|
|
|
(1,095
|
)
|
Other current assets
|
|
|
715
|
|
|
|
(1,060
|
)
|
Inventory
|
|
|
(4,381
|
)
|
|
|
(160
|
)
|
Accounts payable
|
|
|
21,858
|
|
|
|
20,468
|
|
Revenue payable
|
|
|
(1,168
|
)
|
|
|
1,137
|
|
Accrued expenses
|
|
|
1,531
|
|
|
|
788
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
24,660
|
|
|
|
43,706
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Additions to equipment, development and leasehold costs
|
|
|
(142,944
|
)
|
|
|
(106,131
|
)
|
Net additions to other property and equipment
|
|
|
(5,576
|
)
|
|
|
(6,289
|
)
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(148,520
|
)
|
|
|
(112,420
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Proceeds from bank borrowings
|
|
|
139,068
|
|
|
|
55,000
|
|
Change in other long-term liabilities
|
|
|
|
|
|
|
123
|
|
Repayments of note borrowings
|
|
|
(331
|
)
|
|
|
(393
|
)
|
Syndication costs paid
|
|
|
(393
|
)
|
|
|
(48
|
)
|
Cash distributions to QMP minority unit holders
|
|
|
|
|
|
|
(3,879
|
)
|
Refinancing costs
|
|
|
(1,342
|
)
|
|
|
(2,907
|
)
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
137,002
|
|
|
|
47,896
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash
|
|
|
13,142
|
|
|
|
(20,818
|
)
|
Cash, beginning of period
|
|
|
2,559
|
|
|
|
41,820
|
|
|
|
|
|
|
|
|
Cash, end of period
|
|
$
|
15,701
|
|
|
$
|
21,002
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flow information
|
|
|
|
|
|
|
|
|
Cash paid during the period for:
|
|
|
|
|
|
|
|
|
Interest expense
|
|
$
|
14,039
|
|
|
$
|
21,558
|
|
Income taxes
|
|
$
|
|
|
|
$
|
|
|
The accompanying notes are an integral part of these financial statements.
F-3
QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Concentration of Credit Risk
A significant portion of the Companys liquidity is concentrated in cash and derivative
contracts that enable the Company to hedge a portion of its exposure to price volatility from
producing natural gas and oil. These arrangements expose the Company to credit risk from its
counterparties. The Companys accounts receivable are primarily from purchasers of natural gas and
oil products. Natural gas sales to one purchaser (ONEOK) accounted for approximately 95% of our
natural gas and oil revenues for the nine months ended September 30, 2006. Two purchasers, ONEOK
and Tenaska, accounted for approximately 74% and 26%, respectively, of our natural gas and oil
revenues for the nine months ended September 30, 2007. This industry and customer concentration
has the potential to impact the Companys overall exposure to credit risk, either positively or
negatively, by changes in economic, industry or other conditions that affect the natural gas and
oil industry in general and ONEOK and Tenaska in particular.
Other Property and Equipment
During the three months ended September 30, 2006 and 2007, depreciation totaling $500,000 and
$253,000, respectively, was capitalized in the full cost pool. During the nine months ended
September 30, 2006 and 2007, depreciation totaling $2.4 million and $722,000, respectively, was
capitalized in the full cost pool.
Full Cost Pool Test of Ceiling Limitation
Based on the low natural gas prices on September 30, 2007, the Company would have incurred a
non-cash impairment loss of approximately $90 million for the third quarter of 2007. However,
under the SECs accounting guidance in Staff Accounting Bulletin Topic 12(D)(e), if natural gas
prices increase sufficiently between the end of a period and the completion of the financial
statements for that period to eliminate the need for an impairment charge, an issuer is not
required to recognize the non-cash impairment loss in its financial statements for that period. As
of November 1, 2007, natural gas prices had improved sufficiently to eliminate the need for an
impairment loss at September 30, 2007 and as a result, no impairment loss is reflected in the
Companys financial statements for the quarter ended September 30, 2007.
Debt Issue Costs
Included in other assets are costs associated with bank credit facilities. The remaining
unamortized debt issue costs at December 31, 2006 and September 30, 2007 totaled $9.1 million and
$10.3 million, respectively, and are being amortized over the life of the credit facilities. The
increase as of September 30, 2007 is due to a fee paid in connection with the amendment to the
Companys credit facilities entered into in April 2007.
Income Taxes
The Company accounts for income taxes pursuant to the provisions of the SFAS 109,
Accounting
for Income Taxes
, which requires an asset and liability approach to calculating deferred income
taxes. The asset and liability approach requires the recognition of deferred tax liabilities and
assets for the expected future tax consequences of temporary differences between the carrying
amounts and the tax basis of assets and liabilities. No income tax expense was recognized for the
nine months ended September 30, 2006 and 2007.
The effective tax rate for the nine months ended September 30, 2006 and 2007 is less than the
federal statutory rate primarily due to our deferred tax assets (primarily intangible drilling
costs and the net operating loss carry forward) being fully reserved with a 100% valuation
allowance.
Accounting for Uncertainty in Income Taxes
. In June 2006, the Financial Accounting
Standards Board (FASB) issued Interpretation No. 48,
Accounting for Uncertainty in Income Taxes an Interpretation of FASB Statement No. 109
(FIN 48). FIN 48 is intended to clarify the accounting
for uncertainty in income taxes recognized in a companys financial statements and prescribes the
recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN
48 also provides guidance on de-recognition, classification, interest and penalties, accounting in
interim periods, disclosure and transition.
Under FIN 48, evaluation of a tax position is a two-step process. The first step is to
determine whether it is more-likely-than-not that a tax position will be sustained upon
examination, including the resolution of any related appeals or litigation based
F-4
QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
on the technical
merits of that position. The second step is to measure a tax position that meets the
more-likely-than-not threshold to determine the amount of benefit to be recognized in the financial
statements. A tax position is measured at the largest amount of benefit that is greater than 50%
likely of being realized upon ultimate settlement.
Tax positions that previously failed to meet the more-likely-than-not recognition threshold
should be recognized in the first subsequent period in which the threshold is met. Previously
recognized tax positions that no longer meet the more-likely-than-not criteria should be
de-recognized in the first subsequent financial reporting period in which the threshold is no
longer met.
The adoption of FIN 48 at January 1, 2007 did not have a material effect on the Companys
financial position.
Stock-Based Compensation
Stock Awards
.
The Company granted shares of common stock to certain employees in
October 2005, October, November and December, 2006, February, March, April, May, and September
2007. The shares are subject to pro rata vesting which ranges from 0 to 4 years. During this
vesting period, the fair value of the stock awards granted is recognized pro rata as compensation
expense. To the extent the compensation expense relates to employees directly involved in
acquisition, exploration and development activities, such amounts are capitalized to oil and gas
properties. Amounts not capitalized to oil and gas properties are recognized in general and
administrative expenses. The value of common stock grants capitalized in the full cost pool for
the three and nine month periods ended September 30, 2007 were $342,000, $756,000, respectively,
and for the three and nine month periods ended September 30, 2006 were $61,000 and $182,000,
respectively. The value of common stock grants included in general and administrative
expenses for the three and nine month periods ended
September 30, 2007 were $672,000 and $3.0 million,
respectively, and for the three and nine month periods ended September 30, 2006 were $212,000,and
$466,000, respectively.
Partnership Unit Awards
. Quest Midstream GP, LLC granted bonus units to certain
employees during the nine months ended September 30, 2007. The units are subject to pro rata
vesting which ranges from 0 to 3 years. During this vesting period, the fair value of the unit
awards granted is recognized pro rata as compensation expense. To the extent the compensation
expense relates to employees directly involved in acquisition and development of pipeline
activities, such amounts are capitalized to the pipeline. Amounts not capitalized to the pipeline
are recognized in general and administrative expenses. For the three and nine month periods ended
September 30, 2007, the Partnership did not capitalize any of the value associated with the bonus
unit grants. The value of the bonus unit grants included in general and administrative expenses
for the three and nine months ended September 30, 2007 were $394,000 and $1.1 million,
respectively.
Stock Options
.
Effective January 1, 2006, the Company adopted SFAS No. 123 (Revised
2004),
Share-Based Payment
, which requires that compensation related to all stock-based awards,
including stock options, be recognized in the financial statements based on their estimated
grant-date fair value. The Company has previously recorded stock compensation pursuant to the
intrinsic value method under APB Opinion No. 25, whereby compensation was recorded related to
performance share and unrestricted share awards and no compensation was recognized for most stock
option awards. The Company is using the modified prospective application method of adopting SFAS
No. 123R, whereby the estimated fair value of unvested stock awards granted prior to January 1,
2006 will be recognized as compensation expense in periods subsequent to December 31, 2005, based
on the same valuation method used in the Companys prior pro forma disclosures. The Company has
estimated expected forfeitures, as required by SFAS No. 123R, and the Company is recognizing
compensation expense only for those awards expected to vest. Compensation expense is amortized over
the estimated service period, which is the shorter of the awards time vesting period or the
derived service period as implied by any accelerated vesting provisions when the common stock price
reaches specified levels. All compensation must be recognized by the time the award vests. The
cumulative effect of initially adopting SFAS No. 123R was immaterial.
Reclassification
Certain reclassifications have been made to the prior years financial statements in order to
conform to the current presentation.
Recently Issued Accounting Standards
The Financial Accounting Standards Board recently issued the following standards which the
Company reviewed to determine the potential impact on our financial statements upon adoption.
F-5
QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
In June 2006, the FASB issued FASB Interpretation No. 48,
Accounting for Uncertainty in Income
Taxesan Interpretation of FASB Statement No. 109
(FIN 48). FIN 48 provides guidance for
recognizing and measuring uncertain tax positions, as defined in SFAS 109,
Accounting for Income
Taxes
. FIN 48 prescribes a threshold condition that a tax position must meet for any of the benefit
of the uncertain tax position to be recognized in the financial statements. Guidance is also
provided regarding de-recognition, classification and disclosure of these uncertain tax positions.
FIN 48 is effective for fiscal years beginning after December 15, 2006. The adoption of FIN 48 did
not have a material impact on our financial position, results of operations or cash flows.
In September 2006, the FASB issued Statement No. 157,
Fair Value Measurements
(SFAS No.
157). SFAS No. 157 addresses how companies should measure fair value when they are required to use
a fair value measure for recognition or disclosure purposes under generally accepted accounting
principles. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and
expands the required disclosures about fair value measurements. SFAS No. 157 is effective for
fiscal years beginning after November 15, 2007, with earlier adoption permitted. Management is
assessing the impact of the adoption of SFAS No. 157.
In September 2006, the FASB issued Statement No. 158,
Employers Accounting for Defined
Benefit Pension and Other Postretirement Plans
(SFAS No. 158), an amendment of FASB Statements
No. 87, 88, 106 and 132(R). SFAS No. 158 requires (a) recognition of the funded status (measured as
the difference between the fair value of the plan assets and the benefit obligation) of a benefit
plan as an asset or liability in the employers statement of financial position, (b) measurement of
the funded status as of the employers fiscal year-end with limited exceptions, and (c) recognition
of changes in the funded status in the year in which the changes occur through comprehensive
income. The requirement to recognize the funded status of a benefit plan and the disclosure
requirements are effective as of the end of the fiscal year ending after December 15, 2006. The
requirement to measure the plan assets and benefit obligations as of the date of the employers
fiscal year-end statement of financial position is effective for fiscal years ending after December
15, 2008. SFAS No. 158 has no current applicability to the Companys financial statements.
In September 2006, the Securities Exchange Commission issued Staff Accounting Bulletin No. 108
(SAB No. 108). SAB No. 108 addresses how the effects of prior year uncorrected misstatements
should be considered when quantifying misstatements in current year financial statements. SAB No.
108 requires companies to quantify misstatements using a balance sheet and income statement
approach and to evaluate whether either approach results in quantifying an error that is material
in light of relevant quantitative and qualitative factors. When the effect of initial adoption is
material, companies will record the effect as a cumulative effect adjustment to beginning of year
retained earnings and disclose the nature and amount of each individual error being corrected in
the cumulative adjustment. Complying with the requirements of SAB No. 108 had no impact on the
Companys financial statements.
In February 2007, the FASB issued Statement No. 159,
The Fair Value Option for Financial
Assets and Financial Liabilities
(SFAS No. 159), an amendment of FASB Statement No. 115. SFAS
No. 159 addresses how companies should measure many financial instruments and certain other items
at fair value. The objective is to mitigate volatility in reported earnings caused by measuring
related assets and liabilities differently without having to apply complex hedge accounting
provisions. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007, with
earlier adoption permitted. Management is assessing the impact of the adoption of SFAS No. 159.
2. LONGTERM DEBT
Long-term debt consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
September 30, 2007
|
|
|
|
(dollars in thousands)
|
|
Senior credit facilities Quest
|
|
$
|
225,000
|
|
|
$
|
250,000
|
|
Senior credit Quest Midstream
|
|
|
|
|
|
|
30,000
|
|
Other notes payable
|
|
|
569
|
|
|
|
176
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
225,569
|
|
|
|
280,176
|
|
|
|
|
|
|
|
|
|
|
Less current maturities
|
|
|
324
|
|
|
|
122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt, net of current maturities
|
|
$
|
225,245
|
|
|
$
|
280,054
|
|
|
|
|
|
|
|
|
F-6
QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The aggregate scheduled maturities of notes payable and long-term debt for the five years
ending December 31, 2012 and thereafter were as follows as of September 30, 2007:
|
|
|
|
|
2008
|
|
$
|
122
|
|
2009
|
|
|
26
|
|
2010
|
|
|
8
|
|
2011
|
|
|
50,006
|
|
2012
|
|
|
230,006
|
|
Thereafter
|
|
|
8
|
|
|
|
|
|
|
|
$
|
280,176
|
|
|
|
|
|
Credit Facilities
Quest Resource Corporation and Quest Cherokee
As of September 30, 2007, the Companys credit facilities consisted of a $100 million Senior
Credit Agreement between the Company and Quest Cherokee, Guggenheim Corporate Funding, LLC
(Guggenheim), as administrative agent and syndication agent, and the lenders party thereto, a
$100 million Second Lien Term Loan Agreement between the Company, Quest Cherokee, Guggenheim, as
Administrative Agent, and the lenders party thereto and a $75 million Third Lien Term Loan
Agreement between the Company, Quest Cherokee, Guggenheim, as Administrative Agent, and the lenders
party thereto. The Senior Credit Agreement consists of a five-year $50 million revolving credit
facility and a five-year $50 million first lien term loan.
Availability under the revolving credit facility is tied to a borrowing base that will be
re-determined by the lenders every six months taking into account the value of the Companys
reserves and such other information (including, without limitation, the status of title information
with respect to the Companys natural gas and oil properties and the existence of any other
indebtedness) as the administrative agent deems appropriate and consistent with its normal oil and
gas lending criteria as it exists at the particular time. The unanimous consent of the lenders is
required to increase the borrowing base and the consent of 66 2/3% of the lenders is required to
decrease or maintain the borrowing base. In addition, the Company or the lenders may each request a
special re-determination of the borrowing base once every 12 months. The outstanding principal
balance of the first lien term loan and any outstanding letters of credit will be reserved against
the borrowing base in determining availability under the revolving credit facility. As of September
30, 2007, the borrowing base under the revolving credit facility was $100 million.
The Company pays a commitment fee equal to 0.75% on the difference between $50 million and the
outstanding balance of borrowings and letters of credit under the revolving credit facility.
Interest accrues on the revolving credit facility at LIBOR plus 1.75% or the base rate plus
0.75%, at our option. Interest accrues on the first lien term loan at LIBOR plus 3.25% or the base
rate plus 2.50%, at our option. The base rate is the greater of the prime rate or the federal funds
effective rate plus 0.5%. Interest accrues on the second lien term loan at LIBOR plus 5.50%.
Interest accrues on the third lien term loan at LIBOR plus 8.00%. For the three months ended
September 30, 2007, the Companys weighted average interest rates under the credit facilities were
as follows.
|
|
Revolving credit facility under the Senior Credit Agreement 8.92%;
|
|
|
First lien term loan under the Senior Credit Agreement 8.67%;
|
|
|
Second Lien Term Loan 10.88%; and
|
|
|
Third Lien Term Loan 13.38%.
|
The Company failed to comply with the maximum total debt to EBITDA ratio contained in all
three credit agreements for the fiscal quarter ended March 31, 2007. On April 25, 2007, the
lenders waived the default under the credit agreements due to the Companys failure to comply with
this financial covenant for the fiscal quarter ended March 31, 2007 and the credit facilities were
amended to reset the maximum ratio for the remaining quarters of 2007. In connection with the
waiver and amendments, the lenders were paid a fee in the aggregate amount equal to $1,687,500.
The financial covenants applicable to the credit agreements require that:
F-7
QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
|
|
|
for the Senior Credit Agreement, the Company is required to maintain a ratio of
PV-10 value for all of its proved reserves to indebtedness under the Senior Credit
Agreement (excluding obligations under hedging agreements secured by the Senior Credit
Agreement) of not less than 2.0 to 1.0.
|
|
|
|
for the Second and Third Lien Term Loan Agreements, the Companys ratio of PV-10
value for all of its proved reserves to total net debt must not be less than 1.5 to 1.
|
|
|
|
for all three credit agreements, after giving effect to the amendments described
above, the Companys ratio of total net debt to EBITDA for each quarter ending on the
dates set forth below must not be more than:
|
|
|
|
5.50 to 1.0 for the quarter ended June 30, 2007;
|
|
|
|
|
4.75 to 1.0 for the quarter ended September 30, 2007;
|
|
|
|
|
4.25 to 1.0 for the quarter ended December 31, 2007;
|
|
|
|
|
3.50 to 1.0 for the quarter ended March 31, 2008;
|
|
|
|
|
3.25 to 1.0 for the quarter ended June 30, 2008; and
|
|
|
|
|
3.0 to 1.0 for the quarter ended on or after September 30, 2008.
|
Under all three credit agreements PV-10 value is generally defined as the future cash flows
from the Companys proved reserves (based on the NYMEX three-year pricing strip and taking into
account the effects of its hedge agreements) discounted at 10%.
EBITDA is generally defined in all three of the credit agreements as consolidated net income
plus interest, income taxes, depreciation, depletion, amortization and other non-cash charges
(including unrealized losses on hedging agreements), plus costs and expenses directly incurred in
connection with the credit agreements, the private equity transaction and the buy-out of ArcLights
investment in Quest Cherokee and any write-off of prior debt issue costs, minus all non-cash income
(including unrealized gains on hedging agreements). The EBITDA for each quarter will be multiplied
by four in calculating the above ratios.
Total net debt is generally defined as funded debt, less cash and cash equivalents,
reimbursement obligations under letters of credit and certain surety bonds.
For additional information regarding the Companys credit facilities, see Note 3 to the
consolidated financial statements included in the Companys Form 10-K/A for the year ended December
31, 2006.
Quest Midstream Partners, L.P. and Bluestem Pipeline
Bluestem has a separate $75 million syndicated revolving credit facility. The credit facility
is guaranteed by Quest Midstream Partners. Royal Bank of Canada is the administrative agent and
collateral agent. As of September 30, 2007, $30 million was outstanding under the credit facility.
Bluestem pays a quarterly commitment fee equal to 0.30% to 0.50% (depending on the leverage
ratio) on the difference between $75 million and the outstanding balance of borrowings and letters
of credit under the revolving credit facility.
In general, interest accrues on the revolving credit facility at either LIBOR plus a margin
ranging from 1.25% to 2.00% (depending on the leverage ratio) or the base rate plus a margin
ranging from 0.25% to 1.00% (depending on the leverage ratio), at our option. For the three months
ended September 30, 2007, the weighted average interest rate under the credit facility was 7.33%.
The credit agreements financial covenants prohibit Bluestem, Quest Midstream Partners and any
of their subsidiaries from:
|
|
|
permitting the interest coverage ratio (ratio of consolidated EBITDA to consolidated
interest charges) at any fiscal quarter-end, commencing with the quarter ended March
31, 2007, to be less than the ratio of 3.01 to 1.0; and
|
|
|
|
permitting the leverage ratio (ratio of cash adjusted consolidated funded debt to
consolidated EBITDA) at any fiscal quarter-end, commencing with the quarter ended March
31, 2007, to be greater than 4.0 to 1.0.
|
F-8
QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Consolidated EBITDA is defined in the credit agreement to mean for Quest Midstream Partners
and its subsidiaries on a consolidated basis, an amount equal to the sum of (i) consolidated net
income, (ii) consolidated interest charges, (iii) the amount of taxes, based on or measured by
income, used or included in the determination of such consolidated net income, (iv) the amount of
depreciation, depletion and amortization expense deducted in determining such consolidated net
income, and (v) other non-cash charges and expenses, including, without limitation, non-cash
charges and expenses related to swap contracts or resulting from accounting convention changes, of
Quest Midstream Partners and its subsidiaries on a consolidated basis, all determined in accordance
with generally accepted accounting principles.
Consolidated interest charges is defined to mean for Quest Midstream Partners and its
subsidiaries on a consolidated basis, the sum of (i) all interest, premium payments, fees, charges
and related expenses of Quest Midstream Partners and its subsidiaries in connection with
indebtedness (net of interest rate swap contract settlements) (including capitalized interest), in
each case to the extent treated as interest in accordance with generally accepted accounting
principles, and (ii) the portion of rent expense of Quest Midstream Partners and its subsidiaries
with respect to any period under capital leases that is treated as interest in accordance with
generally accepted accounting principles.
Consolidated net income is defined to mean for Quest Midstream Partners and its subsidiaries
on a consolidated basis, the net income or net loss of Quest Midstream Partners and its
subsidiaries from continuing operations, excluding: (i) the income (or loss) of any entity other
than a subsidiary, except to the extent that any such income has been actually received by Quest
Midstream Partners or such subsidiary in the form of cash dividends or similar cash distributions;
(ii) extraordinary gains and losses; (iii) any gains or losses attributable to non-cash write-ups
or write-downs of assets; (iv) proceeds of any insurance on property, plant or equipment other than
business interruption insurance; (v) any gain or loss, net of taxes, on the sale, retirement or
other disposition of assets; and (vi) the cumulative effect of a change in accounting principles.
The credit agreement contains some phase-in provisions with respect to the calculation of
the financial covenants during 2007.
For additional information regarding Bluestems credit facility, see Note 2 to the
consolidated financial statements included in the Companys Form 10-Q for the three months ended
March 31, 2007.
Other Long-Term Indebtedness
As of September 30, 2007, $176,000 of notes payable to banks and finance companies were
outstanding. These notes are secured by equipment and vehicles, with payments due in monthly
installments through October 2013 with interest rates ranging from 1.9% to 8.0% per annum.
3. COMMITMENTS AND CONTINGENCIES
The Company, Quest Cherokee, STP, Bluestem, Quest Energy Service, Inc. (QES), Quest
Midstream Partners and Quest Midstream GP, among others, have been named Defendants in a lawsuit
(Case #CJ-2003-30) filed by Plaintiffs, Eddie R. Hill, et al, on September 27, 2003 in the District
Court for Craig County, Oklahoma. Plaintiffs are royalty owners who are alleging underpayment of
royalties owed to them. Plaintiffs also allege, among other things, that Defendants have engaged in
self-dealing, have breached their fiduciary duties to Plaintiffs and have acted fraudulently
towards Plaintiffs. Plaintiffs also allege that the gathering fees and related charges imposed by
Bluestem should not be deducted in paying royalties. Plaintiffs are seeking unspecified actual and
punitive damages as a result of the alleged conduct by the Defendants. Defendants intend to defend
vigorously against these claims.
STP, Quest Cherokee, QES and Bluestem, among others, have been named Defendants in a lawsuit
(Case No. CJ-2005-143) by Plaintiffs John C. Kirkpatrick, et ux., in the District Court for Craig
County, Oklahoma. Plaintiffs allege that Defendants sold natural gas from wells owned by the
Plaintiffs without providing the requisite notice to Plaintiffs. Plaintiffs have also requested an
accounting to determine if royalties have been properly paid and state, that if Plaintiffs have
suffered any damages for failure to properly pay royalties, Plaintiffs have a right to recover
those damages. Plaintiffs have further asserted claims of fraud, alleging generally that Defendants
have failed to disclose all deductions taken from Defendants royalty, that Defendants took
improper deductions, and that Defendants paid Plaintiffs based on an allocated rather than actual
volume of production without disclosing the same to Plaintiffs. Plaintiffs have not quantified
their alleged damages. Discovery is ongoing and Defendants intend to defend vigorously against
these claims.
Quest Cherokee and Bluestem were named as defendants in a lawsuit (Case No. 04-C-100-PA) filed
by plaintiff Central Natural Resources, Inc. on September 1, 2004 in the District Court of Labette
County, Kansas. Central Natural Resources owns
F-9
QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
the coal underlying numerous tracts of land in
Labette County, Kansas. Quest Cherokee has obtained oil and gas leases from the owners of the oil,
gas, and minerals other than coal underlying approximately 1,100 acres of that land and has drilled
wells that produce coal bed methane gas on that land. Plaintiff alleges that it is entitled to the
coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a
trespasser. Plaintiff is seeking quiet title and an equitable accounting for the revenues from the
coal bed methane gas produced. Plaintiff has alleged conversion of the gas and seeks an accounting
for all gas produced from the wells in issue. Quest Cherokee contends it has valid leases with the
owners of the coal bed methane gas rights. The issue is whether the coal bed methane gas is owned
by the owner of the coal rights or by the owners of the gas rights. Quest Cherokee has asserted
third party claims against the persons who entered into the gas leases with Quest Cherokee for
breach of the warranty of title contained in their leases in the event that the court finds that
Plaintiff owns the coal bed methane gas. The District Court granted Quest Cherokees motion for
summary judgment, ruling that coal bed methane gas is owned by the owners of the gas rights. That
ruling was appealed and the appeal is pending before the Kansas Supreme Court. The appeal has been
fully briefed and oral argument is scheduled for December 4, 2007.
Quest Cherokee was named as a defendant in a lawsuit (Case No. CJ-06-07) filed by plaintiff
Central Natural Resources, Inc. on January 17, 2006, in the District Court of Craig County,
Oklahoma. Bluestem is not a party to this lawsuit. Central Natural Resources owns the coal
underlying approximately 2,500 acres of land in Craig County, Oklahoma. Quest Cherokee has obtained
oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying those
lands, and has drilled and completed 20
wells that produce coal bed methane gas on those lands. Plaintiff alleges that it is entitled
to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a
trespasser. Plaintiff seeks to quiet its alleged title to the coal bed methane and an accounting of
the revenues from the coal bed methane gas produced by Quest Cherokee. Quest Cherokee contends it
has valid leases from the owners of the coal bed methane gas rights. The issue is whether the coal
bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. Quest
Cherokee has answered the petition and discovery is ongoing. Quest Cherokee intends to defend
vigorously against these claims.
Quest Cherokee was named as a defendant in a lawsuit (Case No.05 CV 41) filed by Labette
Energy, LLC in the district court of Labette County, Kansas. Plaintiff claims to own a 3.2 mile gas
gathering pipeline in Labette County, Kansas, and that Quest Cherokee used that pipeline without
plaintiffs consent. Plaintiff also contends that the defendants slandered its alleged title to
that pipeline and suffered damages from the cancellation of their proposed sale of that pipeline.
Plaintiff claims that it was damaged in the amount of $202,375. Discovery in that case is ongoing
and Quest Cherokee intends to defend vigorously against the plaintiffs claims.
QES was named as a defendant in a lawsuit (Case No. 2006 CV 103) filed by Western Uniform and
Towel Service, Inc. in the district court of Neosho County, Kansas. Plaintiff contends that QES has
failed to pay for goods and services provided by the Plaintiff, and that QES wrongfully terminated
certain contracts with the plaintiff to provide uniforms and merchandise to QES. In July 2007, QES
and Plaintiff agreed to settle the dispute and the Plaintiff dismissed the case with prejudice.
Bluestem and Quest Cherokee were named as Defendants in a lawsuit (Case No. CJ-2007-325) filed
by Devonian Enterprises, Inc. d/b/a Permian Land Company (Permian) in the district court of
Oklahoma County, Oklahoma. Permian asserted claims against Quest Cherokee and Bluestem in the
amount of $521,252.88 for land services allegedly rendered to Quest Cherokee and Bluestem by
Permian and for which no payment has purportedly been received by Permian. Quest Cherokee and
Bluestem have asserted counterclaims against Permian for breach of contract and negligence, among
other theories, due to Permians failure to file acquired instruments of record and deliver such
records to Quest Cherokee and Bluestem, which has caused Quest Cherokee and Bluestem to incur
unnecessary costs to re-acquire such instruments. In addition, Permian failed to ascertain whether
or not minerals were leased or otherwise burdened and acquired oil and gas leases for Quest
Cherokee and Bluestem, which were, in fact, burdened, causing Quest Cherokee and Bluestem to incur
thousands of dollars in curative costs to acquire title to such minerals. Further, without
approval, Permian inserted non-standard construction completion penalty provisions into said
rights-of-way and easements, forcing Quest Cherokee and Bluestem to incur thousands of dollars in
damages resulting from the unauthorized construction penalty provisions. Finally, Plaintiff has
failed to return confidential information to Quest Cherokee and Bluestem pursuant to the parties
written confidentiality and non-disclosure agreement. This matter was recently settled on July 30,
2007.
Quest Cherokee is a defendant in several lawsuits in which the plaintiffs allege that certain
of the oil and gas leases owned by Quest Cherokee are either invalid, have expired by their terms
and/or have been forfeited by Quest Cherokee. The plaintiffs in those cases are generally seeking
statutory damages of $100 per lease, attorneys fees, and a judicial declaration that Quest
Cherokees leases have terminated. As of October 31, 2007, the total amount of acreage covered by
the leases at issue in these lawsuits was approximately 7,500 acres. Quest Cherokee contends that
it has complied with the terms of these oil and gas leases and that they remain in full force and
effect. Quest Cherokee intends to vigorously defend against the claims.
Quest Cherokee was named in an Order to Show Cause issued by the Kansas Corporation Commission
(the KCC)
F-10
QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(KCC Docket No. 07-CONS-155-CSHO) filed on February 23, 2007. The KCC has ordered Quest
Cherokee to demonstrate why it should not be held responsible for plugging 22 abandoned and
unplugged oil wells on a gas lease owned and operated by Quest Cherokee in Wilson County, Kansas.
Quest Cherokee denies that it is legally responsible for plugging the wells in issue and intends to
vigorously defend against the KCCs claims.
On August 3, 2007, certain alleged mineral and/or overriding royalty interests owners in land
located in the Kansas portion of the Cherokee Basin filed a putative class action lawsuit against
Quest Cherokee. Hugo Spieker, et al. v. Quest Cherokee, LLC, United States District Court for the
District of Kansas, Case No. 07-1225-MLB. The named plaintiffs allege that Quest Cherokee has
failed to properly make royalty payments to them and the putative class by, among other things,
paying royalties based on reduced volumes instead of volumes of gas measured at the wellheads, by
allocating certain expenses to plaintiffs interests, and by allocating more than the actual cost
of the expenses. Plaintiffs allege that the amount in controversy exceed five million dollars.
Quest Cherokee is in the process of investigating and evaluating the claims. Quest Cherokee denies
any wrongdoing and intends to vigorously defend against the claims.
The Company, from time to time, may be subject to legal proceedings and claims that arise in
the ordinary course of its business. Although no assurance can be given, management believes,
based on its experiences to date, that the ultimate resolution of such items will not have a
material adverse impact on the Companys business, financial position or results of operations.
Like other natural gas and oil producers and marketers, the Companys operations are subject to
extensive and rapidly changing federal and state environmental regulations governing air emissions,
wastewater discharges, and solid and hazardous waste management activities.
Therefore it is extremely difficult to reasonably quantify future environmental related
expenditures.
On December 22, 2006, Quest Midstream Partners entered into a registration rights agreement with a
group of its investors. The registration rights agreement was amended on November 1, 2007, to add
additional investors to the agreement. The agreement currently covers 8,614,866 common units of
Quest Midstream Partners.
Under the registration rights agreement, Quest Midstream Partners granted the investors certain
piggyback registration rights and certain rights to require Quest Midstream to file and maintain a
shelf registration statement for the resale of the common units by the investors. Under the
registration rights agreement, at any time on or after the date that is 270 days after December 22,
2006, the investors (by action of the investors holding a majority of the common units subject to
registration or action of certain of the investors) may require Quest Midstream Partners to (a)
file the shelf registration statement as soon as reasonably practicable, but in any event within 90
days, after notice to Quest Midstream Partners, subject to certain changes in timing if Quest
Midstream Partners is then working toward the filing of a registration statement for an initial
public offering, (b) use its commercially reasonable efforts to cause the shelf registration
statement to be declared effective within 210 days after the initial filing of the shelf
registration statement and (c) maintain effectiveness of the shelf registration statement with
respect to each common unit included in the shelf registration statement, subject to certain
suspension and blackout periods, until (i) the common unit is sold pursuant to a registration
statement, (ii) the common unit is distributed to the public pursuant to Rule 144 or is eligible
for sale without registration pursuant to Rule 144(k), in the opinion of counsel to Quest Midstream
Partners, or (iii) the common unit is sold to Quest Midstream Partners or to the registrant or any
subsidiary of the registrant.
Under the registration rights agreement, Quest Midstream Partners is required to pay liquidated
damages if the shelf registration statement is not filed or declared effective within the time
periods established in the agreement, if the shelf registration statement is not maintained in
accordance with the agreement and with respect to any common units required to be included in the
shelf registration statement that are not included. The liquidated damages amount payable is $0.175
per common unit entitled to liquidated damages for each 90-day period for which liquidated damages
are payable, subject to proration for periods of less than 90 days.
4. FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
Natural Gas Hedging Activities
The Company seeks to reduce its exposure to unfavorable changes in natural gas prices, which
are subject to significant and often volatile fluctuation, through the use of fixed-price
contracts. The fixed-price contracts are comprised of energy swaps, collars and basis swaps. These
contracts allow the Company to predict with greater certainty the effective natural gas prices to
be received for hedged production and benefit operating cash flows and earnings when market prices
are less than the fixed prices provided in the contracts. However, the Company will not benefit
from market prices that are higher than the fixed prices in the contracts for hedged production.
Collar structures provide for participation in price increases and decreases to the extent of the
ceiling and floor prices provided in those contracts. For the nine months ended September 30, 2006
and 2007, fixed-price contracts hedged 64.0% and 66.17%, respectively, of the Companys natural gas
production. As of September 30, 2007, fixed-price contracts were in place to hedge 28.1 Bcf of
estimated future natural gas production. Of this total volume, 2.7 Bcf are hedged for the fourth
quarter of 2007 and 25.4 Bcf thereafter. See Note 15 to the Companys consolidated financial
statements included in the Companys Annual Report on Form 10-K/A for the year ended December 31,
2006 for additional information with respect to the Companys fixed-price contracts.
For energy swap contracts, the Company receives a fixed price for the respective commodity and
pays a floating market price, as defined in each contract (generally a regional spot market index
or in some cases, NYMEX future prices), to the counterparty. The fixed-price payment and the
floating-price payment are netted, resulting in a net amount due to or from the counterparty.
Natural gas collars contain a fixed floor price (put) and ceiling price (call) (generally a
regional spot market index or in some cases, NYMEX future prices). If the market price of natural
gas exceeds the call strike price or falls below the put strike price, then the Company receives
the fixed price and pays the market price. If the market price of natural gas is between the call
and the put strike price, then no payments are due from either party.
F-11
QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair
value attributable to the fixed-price contracts as of September 30, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
|
|
|
|
Ending
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
Years Ending December 31,
|
|
|
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
Total
|
|
|
|
|
|
|
(dollars in thousands, except per MMBtu data)
|
|
|
|
|
Natural Gas Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (MMBtu)
|
|
|
593,000
|
|
|
|
2,332,000
|
|
|
|
9,999,000
|
|
|
|
6,000,000
|
|
|
|
18,924,000
|
|
Weighted average fixed
price per MMBtu (1)
|
|
$
|
7.20
|
|
|
$
|
7.35
|
|
|
$
|
7.85
|
|
|
$
|
7.55
|
|
|
$
|
8
|
|
Fixed-price sales
|
|
$
|
4,272
|
|
|
$
|
17,141
|
|
|
$
|
78,451
|
|
|
$
|
45,239
|
|
|
$
|
145,103
|
|
Fair value, net
|
|
$
|
282
|
|
|
$
|
1,495
|
|
|
$
|
5,265
|
|
|
$
|
1,922
|
|
|
$
|
8,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Collars:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (MMBtu)
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
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|
2,125,000
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|
|
|
7,028,000
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|
|
|
|
|
|
|
|
|
|
|
9,153,000
|
|
Ceiling
|
|
|
2,125,000
|
|
|
|
7,028,000
|
|
|
|
|
|
|
|
|
|
|
|
9,153,000
|
|
Weighted average fixed
price per MMBtu (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
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|
$
|
6.63
|
|
|
$
|
6.54
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
7
|
|
Ceiling
|
|
$
|
7.54
|
|
|
$
|
7.54
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
8
|
|
Fixed-price sales (2)
|
|
$
|
14,087
|
|
|
$
|
45,973
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
60,060
|
|
Fair value, net
|
|
$
|
463
|
|
|
|
($1,608
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(1,145
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas Contracts(3):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (MMBtu)
|
|
|
2,718,000
|
|
|
|
9,360,000
|
|
|
|
9,999,000
|
|
|
|
6,000,000
|
|
|
|
28,077,000
|
|
Weighted average fixed
price per MMBtu (1)
|
|
$
|
6.75
|
|
|
$
|
6.74
|
|
|
$
|
7.85
|
|
|
$
|
7.54
|
|
|
$
|
7.31
|
|
Fixed-price sales (2)
|
|
$
|
18,359
|
|
|
$
|
63,114
|
|
|
$
|
78,451
|
|
|
$
|
45,239
|
|
|
$
|
205,163
|
|
Fair value, net
|
|
$
|
745
|
|
|
|
($113
|
)
|
|
$
|
5,265
|
|
|
$
|
1,922
|
|
|
$
|
7,819
|
|
|
|
|
(1)
|
|
The prices to be realized for hedged production are expected to vary from the prices shown
due to basis.
|
|
(2)
|
|
Assumes ceiling prices for natural gas collar volumes.
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|
(3)
|
|
Does not include basis swaps with notional volumes by year, as follows: 2007:
305,000 MMBtu; 2008: 1,464,000 MMBtu.
|
The estimates of fair value of the fixed-price contracts are computed based on the difference
between the prices provided by the fixed-price contracts and forward market prices as of the
specified date, as adjusted for basis. Forward market prices for natural gas are dependent upon
supply and demand factors in such forward market and are subject to significant volatility. The
fair value estimates shown above are subject to change as forward market prices and basis change.
All fixed-price contracts have been approved by the Companys board of directors. The
differential between the fixed price and the floating price for each contract settlement period
multiplied by the associated contract volume is the contract profit or loss. For fixed-price
contracts qualifying as cash flow hedges pursuant to SFAS 133, the realized contract profit or loss
is included in oil and gas sales in the period for which the underlying production was hedged. For
the three months ended September 30, 2006 and 2007, oil and gas sales included a loss of $3.7
million and a gain of $3.7 million, respectively, associated with realized gains and losses under
fixed-price contracts. For the nine months ended September 30, 2006 and 2007, oil and gas sales
included a loss of $4.4 million and a gain of $5.2 million, respectively, associated with realized
gains and losses under fixed-price contracts.
For fixed-price contracts qualifying as cash flow hedges, changes in fair value for volumes
not yet settled are shown as adjustments to other comprehensive income. For those contracts not
qualifying as cash flow hedges, changes in fair value for volumes not yet settled are recognized in
change in derivative fair value in the statement of operations. The fair value of all fixed-price
contracts are recorded as assets or liabilities in the balance sheet.
Based upon market prices at September 30, 2007, the estimated amount of unrealized losses for
fixed-price contracts shown as adjustments to other comprehensive income that are expected to be
reclassified into earnings as actual contract cash settlements are realized within the next 12
months is $1.2 million.
F-12
QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Interest Rate Hedging Activities
At September 30, 2007, the Company had no outstanding interest rate cap or swap agreements.
Change in Derivative Fair Value
Change in derivative fair value in the statements of operations for the three and nine months
ended September 30, 2006 and 2007 is comprised of the following:
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|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
September 30,
|
|
September 30,
|
|
|
|
|
|
2006
|
|
2007
|
|
2006
|
|
2007
|
|
|
|
|
|
(dollars in thousands)
|
|
|
|
Change in fair value of derivatives not
qualifying as
cash flow hedges
|
|
$
|
(1,330
|
)
|
|
$
|
4,748
|
|
|
$
|
13,300
|
|
|
$
|
3,329
|
|
Settlements due to ineffective cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
(10,232
|
)
|
|
|
|
|
Ineffective portion of derivatives qualifying
as cash
flow hedges
|
|
|
998
|
|
|
|
791
|
|
|
|
3,232
|
|
|
|
2,025
|
|
|
|
|
|
|
$
|
(332
|
)
|
|
$
|
5,539
|
|
|
$
|
6,300
|
|
|
$
|
5,354
|
|
|
|
|
The amounts recorded in change in derivative fair value do not represent cash gains or losses.
Rather, they are temporary valuation swings in the fair value of the contracts. All amounts
initially recorded in this caption are ultimately reversed within this same caption over the
respective contract terms.
The change in carrying value of interest rate swaps and caps in the balance sheet since
December 31, 2006 resulted from the expiration of the Companys interest rate cap agreement. The
change in the carrying value of fixed price contracts in the balance sheet since December 31, 2006
resulted from an increase in gas prices.
Credit Risk
Energy swaps, collars and basis swaps provide for a net settlement due to or from the
respective party as discussed previously. The counterparty to the derivative contracts is a major
energy corporation. Should a counterparty default on a contract, there can be no assurance that the
Company would be able to enter into a new contract with a third party on terms comparable to the
original contract. The Company has not experienced non-performance by its counterparties.
Cancellation or termination of a fixed-price contract would subject a greater portion of the
Companys natural gas production to market prices, which, in a low price environment, could have an
adverse effect on its future operating results. In addition, the associated carrying value of the
derivative contract would be removed from the balance sheet.
Market Risk
The differential between the floating price paid under each energy swap or collar contract and
the price received at the wellhead for the Companys production is termed basis and is the result
of differences in location, quality, contract terms, timing and other variables. For instance, some
of the Companys fixed price contracts are tied to commodity prices on the New York Mercantile
Exchange (NYMEX), that is, the Company receives the fixed price amount stated in the contract and
pays to its counterparty the current market price for gas as listed on the NYMEX. However, due to
the geographic location of the Companys natural gas assets and the cost of transporting the
natural gas to another market, the amount that the Company receives when it actually sells its
natural gas is generally based on the Southern Star Central TX/KS/OK (Southern Star) first of
month index, with the remainder being sold based on the daily price on the Southern Star index. The
difference between natural gas prices on the NYMEX and the price actually received by the Company
is referred to as a basis differential. Typically, the price for natural gas on the Southern Star
first of the month index is less than the price on the NYMEX due to the more limited demand for
natural gas on the Southern Star first of the month index.
The effective price realizations that result from the fixed-price contracts are affected by
movements in this basis differential. Basis movements can result from a number of variables,
including regional supply and demand factors, changes in the
F-13
QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
portfolio of the Companys fixed-price contracts and the composition of its producing property
base. Basis movements are generally considerably less than the price movements affecting the
underlying commodity, but their effect can be significant. Recently, the basis differential has
been increasingly volatile and has on occasion resulted in the Company receiving a net price for
its natural gas that is significantly below the price stated in the fixed price contract.
Changes in future gains and losses to be realized in natural gas and oil sales upon cash
settlements of fixed-price contracts as a result of changes in market prices for natural gas are
expected to be offset by changes in the price received for hedged natural gas production.
Fair Value of Financial Instruments
The following information is provided regarding the estimated fair value of the financial
instruments, including derivative assets and liabilities as defined by SFAS 133 that the Company
held as of December 31, 2006 and September 30, 2007 and the methods and assumptions used to
estimate their fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
September 30, 2007
|
|
|
|
|
|
Carrying
|
|
|
|
|
|
Carrying
|
|
|
|
|
Amount
|
|
Fair Value
|
|
Amount
|
|
Fair Value
|
|
|
|
|
|
(dollars in thousands)
|
|
|
|
Derivative assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swaps and caps
|
|
$
|
197
|
|
|
$
|
197
|
|
|
$
|
|
|
|
$
|
|
|
Basis swaps
|
|
$
|
62
|
|
|
$
|
62
|
|
|
$
|
205
|
|
|
$
|
205
|
|
Fixed-price natural gas swaps
|
|
$
|
2,207
|
|
|
$
|
2,207
|
|
|
$
|
8,815
|
|
|
$
|
8,815
|
|
Fixed-price natural gas collars
|
|
$
|
13,111
|
|
|
$
|
13,111
|
|
|
$
|
6,963
|
|
|
$
|
6,963
|
|
Derivative liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis swaps
|
|
$
|
(377
|
)
|
|
$
|
(377
|
)
|
|
$
|
(57
|
)
|
|
$
|
(57
|
)
|
Fixed-price natural gas collars
|
|
$
|
(12,316
|
)
|
|
$
|
(12,316
|
)
|
|
$
|
(8,108
|
)
|
|
$
|
(8,108
|
)
|
Credit facilities
|
|
$
|
(225,000
|
)
|
|
$
|
(225,000
|
)
|
|
$
|
(280,000
|
)
|
|
$
|
(280,000
|
)
|
Other financing agreements
|
|
$
|
(569
|
)
|
|
$
|
(569
|
)
|
|
$
|
(176
|
)
|
|
$
|
(176
|
)
|
The carrying amount of cash, receivables, deposits, accounts payable and accrued expenses
approximates fair value due to the short maturity of those instruments. The carrying amounts for
notes payable approximate fair value due to the variable nature of the interest rates of the notes
payable.
The
fair value of all derivative contracts as of December 31, 2006 and September 30,
2007 was based upon estimates determined by the Companys counter-parties and subsequently
evaluated internally using established index prices and other sources. These values are based upon,
among other things, futures prices, volatility, and time to maturity and credit risk. The values
reported in the financial statements change as these estimates are revised to reflect actual
results, changes in market conditions or other factors.
Derivative assets and liabilities reflected as current in the September 30, 2007 balance sheet
represent the estimated fair value of fixed-price contract and interest rate cap settlements
scheduled to occur over the subsequent twelve-month period based on market prices for natural gas
and fluctuations in interest rates as of the balance sheet date. The offsetting increase in value
of the hedged future production has not been accrued in the accompanying balance sheet. The
contract settlement amounts are not due and payable until the monthly period that the related
underlying hedged transaction occurs. In some cases the recorded liability for certain contracts
significantly exceeds the total settlement amounts that would be paid to a counterparty based on
prices in effect at the balance sheet date due to option time value. Since the Company expects to
hold these contracts to maturity, this time value component has no direct relationship to actual
future contract settlements and consequently does not represent a liability that will be settled in
cash or realized in any way.
5. EARNINGS PER SHARE
SFAS 128 requires a reconciliation of the numerator and denominator of the basic and diluted
earnings per share (EPS) computations. The following securities were not included in the
calculation of diluted earnings per share because their effect was antidilutive.
|
|
|
For the three and nine months ended September 30, 2006, dilutive shares do
not include the assumed exercise of stock options and stock awards because the
effects were antidilutive.
|
F-14
QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
|
|
|
For the nine months ended September 30, 2007, dilutive shares do not include
the assumed exercise of stock options and stock awards because the effects were
antidilutive.
|
The following reconciles the components of the EPS computation (dollars in thousands,
except per share):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
Shares
|
|
|
Per Share
|
|
|
|
(Numerator)
|
|
|
(Denominator)
|
|
|
Amount
|
|
For the three months ended September 30, 2006
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(10,073
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic EPS loss available to common shareholders
|
|
$
|
(10,073
|
)
|
|
|
22,123,514
|
|
|
$
|
(0.46
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
None
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS loss available to common shareholders
|
|
$
|
(10,073
|
)
|
|
|
22,123,514
|
|
|
$
|
(0.46
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended September 30, 2007
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,973
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic EPS available to common shareholders
|
|
$
|
1,973
|
|
|
|
22,296,179
|
|
|
$
|
0.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options
|
|
|
|
|
|
|
626
|
|
|
|
|
|
Stock awards
|
|
|
|
|
|
|
11,334
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS available to common shareholders
|
|
$
|
1,973
|
|
|
|
22,308,139
|
|
|
$
|
0.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the nine months ended September 30, 2006
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
(7,136
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic EPS loss available to common shareholders
|
|
$
|
(7,136
|
)
|
|
|
22,090,363
|
|
|
$
|
(0.32
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
None
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS loss available to common shareholders
|
|
$
|
(7,136
|
)
|
|
|
22,090,363
|
|
|
$
|
(0.32
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the nine months ended September 30, 2007
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(5,824
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic EPS available to common shareholders
|
|
$
|
(5,824
|
)
|
|
|
22,240,077
|
|
|
$
|
(0.26
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
None
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS available to common shareholders
|
|
$
|
(5,824
|
)
|
|
|
22,240,077
|
|
|
$
|
(0.26
|
)
|
|
|
|
|
|
|
|
|
|
|
6. ASSET RETIREMENT OBLIGATIONS
The Company has adopted SFAS 143,
Accounting for Asset Retirement Obligations
. The following
table provides a roll forward of the asset retirement obligations for the three and nine months
ended September 30, 2006 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
September 30,
|
|
September 30,
|
|
|
|
|
|
2006
|
|
2007
|
|
2006
|
|
2007
|
|
|
|
|
|
(dollars in thousands)
|
|
|
|
Asset
retirement obligation beginning balance
|
|
$
|
1,275
|
|
|
$
|
1,546
|
|
|
$
|
1,150
|
|
|
$
|
1,410
|
|
Liabilities incurred
|
|
|
45
|
|
|
|
44
|
|
|
|
130
|
|
|
|
128
|
|
Liabilities settled
|
|
|
(2
|
)
|
|
|
(2
|
)
|
|
|
(5
|
)
|
|
|
(5
|
)
|
Accretion expense
|
|
|
24
|
|
|
|
31
|
|
|
|
67
|
|
|
|
86
|
|
Revisions in estimated cash flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation ending balance
|
|
$
|
1,342
|
|
|
$
|
1,619
|
|
|
$
|
1,342
|
|
|
$
|
1,619
|
|
|
|
|
F-15
QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
7. PARTNERS CAPITAL AND CASH DISTRIBUTIONS
The common unit holders in Quest Midstream Partners have the right to receive quarterly
distributions of available cash from operating surplus (each as defined in the Quest Midstream
Partners partnership agreement) in an amount equal to the minimum quarterly distribution of $0.425
per common unit plus any arrearages in the payment of the minimum quarterly distribution on the
common units from prior quarters, before any distributions of available cash from operating surplus
may be made on the subordinated units. No arrearages will be paid on the subordinated units during
the subordination period.
If the tests for ending the subordination period are satisfied for any three consecutive
four-quarter periods ending on or after the last day of the quarter containing the third
anniversary of the initial public offering of Quest Midstream Partners, 25% of the subordinated
units will convert into an equal number of common units. Similarly, if those tests are also
satisfied for any three consecutive four-quarter periods ending on or after the last day of the
quarter containing the fourth anniversary of the initial public offering of Quest Midstream
Partners, an additional 25% of the subordinated units will convert into an equal number of common
units. The second early conversion of subordinated units may not occur, however, until at least one
year following the end of the period for the first early conversion of subordinated units.
The Quest Midstream Partners partnership agreement sets forth the levels of distributions to
be made to each of the common unit holders and Quest Midstream GP of available cash from operating
surplus for any quarter during and after the subordination period. The partnership agreement
provides that Quest Midstream GP initially will be entitled to 2% of all distributions that Quest
Midstream Partners makes prior to its liquidation. Quest Midstream GP has the right, but not the
obligation, to contribute a proportionate amount of capital to Quest Midstream Partners to maintain
its 2% general partner interest if Quest Midstream Partners issues additional units. Quest
Midstream GPs 2% interest, and the percentage of Quest Midstream Partners cash distributions to
which it is entitled, will be proportionately reduced if Quest Midstream Partners issues additional
units in the future and Quest Midstream GP does not contribute a proportionate amount of capital to
Quest Midstream Partners in order to maintain its 2% general partner interest.
During the nine months ended September 30, 2007, the partnership made $3.9 million in
distributions to the common unit holders.
8. SUBSEQUENT EVENTS
On October 15, 2007, the Company entered into an Agreement and Plan of Merger (the Merger
Agreement) with its newly-formed subsidiary, Quest Mergersub, Inc., and Pinnacle Gas Resources,
Inc. (Pinnacle), which provides for the acquisition of Pinnacle by the Company in a
stock-for-stock transaction. Consummation of the merger is subject to various conditions,
including approval by the stockholders of both the Company and Pinnacle, the closing of the initial
public offering of common units of Quest Energy Partners, L.P. and certain other customary
conditions. In addition, the Merger Agreement contains termination rights for both the Company and
Pinnacle, and further provides that, upon termination of the Merger Agreement under specified
circumstances (including an adverse change by either partys board of directors of its
recommendation to stockholders to vote for the merger), a party may be required to pay the other
party a termination fee of $3.0 million. It is anticipated that the closing of the merger will
occur in the first or second quarter of 2008.
On November 1, 2007, Quest Midstream Partners closed on the acquisition of (i) a 1,120-mile
interstate gas pipeline running from Oklahoma to Missouri (the KPC Pipeline) and (ii) all of the
membership interests in the two general partners of Enbridge Pipelines (KPC), the owner of the KPC
Pipeline (the Enbridge Acquisition). Quest Midstream Partners completed the purchase of the KPC
Pipeline for $133 million in cash, subject to a working capital adjustment, pursuant to a Purchase
and Sale Agreement dated October 9, 2007, by and among Enbridge Midcoast Energy, L.P., Midcoast
Holdings No. One, L.L.C., and Quest Midstream Partners.
On November 1, 2007, Quest Midstream Partners sold 3,750,000 Common Units, representing an
approximate 27.12% interest in Quest Midstream Partners, for $20.00 per Common Unit, or $75 million
in the aggregate, in a private placement pursuant to a Purchase Agreement dated October 16, 2007,
among Quest Midstream Partners, Quest Midstream GP, the Company and a group of institutional
investors. Quest Midstream GP purchased an additional 76,531 general partner units in Quest
Midstream Partners and the Company made a capital contribution of approximately $1.3 million in
order for Quest Midstream GP to maintain its 2% general partner interest in Quest Midstream
Partners. As a result, Quest Midstream GP now holds 276,531 general partner units and continues to
hold all of the incentive distribution rights, and the Company continues to hold 35,134 Class A
Subordinated Units and 4,900,000 Class B Subordinated Units in Quest Midstream Partners. The
proceeds of the offering were used to fund a portion of the purchase price of the Enbridge
Acquisition.
F-16
QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
On November 1, 2007, Quest Midstream Partners and its wholly-owned subsidiary, Bluestem,
entered into an Amended and Restated Credit Agreement (the Credit Agreement) to increase the
aggregate commitment under Bluestems existing five-year revolving credit facility from $75 million
to $135 million, to add Quest Midstream Partners as a co-borrower instead of a guarantor, and to
change the maturity date from January 31, 2012 to November 1, 2012. The Credit Agreement is among
Bluestem, Quest Midstream Partners, Royal Bank of Canada, as administrative agent and collateral
agent, and the lenders party thereto. As of November 1, 2007, the amount borrowed under the Credit
Agreement was $95 million. Further information regarding this transaction is disclosed in the
Companys Current Report on Form 8-K filed with the Securities and Exchange Commission on November
2, 2007.
On November 1, 2007, J-W Gas Gathering, L.L.C. merged with and into Producers Service, LLC,
which then merged with and into Ponderosa Gas Pipeline Company, LLC (Ponderosa). On November 2,
2007, Ponderosa and STP Cherokee, LLC merged with and into the Company with the Company being the
survivor. These changes were made to simplify the Companys organizational structure and to
eliminate certain inactive subsidiaries.
On
November 8, 2007, Quest Energy Partners priced the public
offering of 9,100,000 common
units, representing a 42.1% limited partner interest in it (or
10,645,000 common units,
representing a 48.5% limited partner interest, if the underwriters exercise their overallotment
option in full) at a price of $18.00 per unit. Net proceeds of the offering, before expenses, are
expected to be approximately
$152.7 million (or
$176.1 million if the over-allotment option is
exercised in full), after deducting the underwriting discount and commissions and a structuring
fee. Quest Energy Partners intends to use the net proceeds of the offering to pay down existing
indebtedness. If the underwriters exercise their over-allotment option, Quest Energy Partners will
use the net proceeds to redeem a number of common units from the Company equal to the number of
common units issued upon the exercise of the underwriters option. The Company will use the net
proceeds from the redemption to reduce its indebtedness.
In October 2007, the Company entered into additional derivative contracts for 2008, 2009 and
2010. The Companys current schedule of derivative contracts for these years is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedge Summary
|
|
|
Hedged Price
|
|
|
|
|
Floor
|
|
Ceiling
|
|
Vol.(Mmcf)
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Southern Star Swap
|
|
$
|
7.35
|
|
|
$
|
7.35
|
|
|
|
2,332
|
|
Southern Star Collar
|
|
$
|
8.00
|
|
|
$
|
8.93
|
|
|
|
2,137
|
|
NYMEX Collar (1)
|
|
$
|
4.50
|
|
|
$
|
5.52
|
|
|
|
2,928
|
|
Southern Star Collar
|
|
$
|
8.00
|
|
|
$
|
9.02
|
|
|
|
1,963
|
|
NYMEX Swap
|
|
$
|
7.88
|
|
|
$
|
7.88
|
|
|
|
4,800
|
|
2008 Total
|
|
|
|
|
|
|
|
|
|
|
14,160
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Southern Star Swap
|
|
$
|
7.82
|
|
|
$
|
7.82
|
|
|
|
4,500
|
|
Southern Star Swap
|
|
$
|
7.87
|
|
|
$
|
7.87
|
|
|
|
4,500
|
|
Southern Star Swap
|
|
$
|
7.85
|
|
|
$
|
7.85
|
|
|
|
1,000
|
|
Southern Star Swap
|
|
$
|
7.13
|
|
|
$
|
7.13
|
|
|
|
2,630
|
|
2009 Total
|
|
|
|
|
|
|
|
|
|
|
12,630
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
Southern Star Swap
|
|
$
|
7.50
|
|
|
$
|
7.50
|
|
|
|
4,000
|
|
Southern Star Swap
|
|
$
|
7.615
|
|
|
$
|
7.615
|
|
|
|
2,000
|
|
Southern Star Swap
|
|
$
|
7.010
|
|
|
$
|
7.010
|
|
|
|
4,000
|
|
Southern Star Swap
|
|
$
|
7.010
|
|
|
$
|
7.010
|
|
|
|
500
|
|
2010 Total
|
|
|
|
|
|
|
|
|
|
|
10,499
|
|
|
|
|
(1)
|
|
1,464 Bcf with basis lock @ $1.03 per mcf
|
F-17
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
Business of Issuer
We are an independent energy company with an emphasis on the acquisition, exploration,
development, production, and transportation of natural gas (coal bed methane) in the Cherokee Basin
of southeastern Kansas and northeastern Oklahoma. We also own and operate a gas gathering pipeline
network of approximately 1,800 miles in length within this basin. Our main focus is upon the
development of our coal bed methane gas reserves in our pipeline network region and upon the
continued enhancement of the pipeline system and supporting infrastructure. Unless otherwise
indicated, references to us, we, the Company or Quest include our operating subsidiaries.
Significant Developments During the Nine Months Ended September 30, 2007
During the first nine months of 2007, we continued to be focused on drilling and completing
new wells. We drilled 452 gross wells and completed the connection of 450 gross wells during this
period. As of September 30, 2007, we had approximately 155 additional gas wells (gross) that we
were in the process of completing and connecting to our gas gathering pipeline system.
We also continued our program of re-completing our existing single seam wells into multi-seam
wells (that is, opening up production of additional gas from different depths), which management
anticipates will in the long term increase overall natural gas production. However, the
re-completion program may in the short term negatively affect natural gas production as natural gas
wells are taken off line for the re-completions and then undergo a period of dewatering after
they are re-connected. During the first nine months of 2007, we completed 47 re-completions.
We completed 247 miles of pipeline infrastructure expansion and had a net increase in the
total number of acres that we lease under natural gas leases of 24,943 acres (net).
We are also evaluating the operation of our natural gas gathering system to determine whether
changes in compression or other alterations in the operation of the pipeline system might improve
production.
On September 30, 2007, our average gross daily production was 62.4 MMcfe/d.
Public Offering of Quest Energy Partners, L.P.
On
November 8, 2007, Quest Energy Partners priced the public
offering of 9,100,000 common
units, representing a 42.1% limited partner interest in it (or
10,645,000 common units,
representing a 48.5% limited partner interest, if the underwriters exercise their overallotment
option in full) at a price of
$18.00 per unit. Net proceeds of the offering, before expenses, are
expected to be approximately
$152.7 million (or
$176.1 million if the over-allotment option is
exercised in full), after deducting the underwriting discount and commissions and a structuring
fee. Quest Energy Partners intends to use the net proceeds of the offering to pay down existing
indebtedness. If the underwriters exercise their over-allotment option, Quest Energy Partners will
use the net proceeds to redeem a number of common units from us equal to the number of common units
issued upon the exercise of the underwriters option. We will use the net proceeds from the
redemption to reduce our indebtedness.
Upon completion of the offering, Quest Energy Partners will own substantially all of our
natural gas and oil exploration and production assets. Quest Energy GP is the general partner of
Quest Energy Partners and will conduct the business and manage the operations of Quest Energy
Partners. Pursuant to a management services agreement, QES will provide legal, accounting,
finance, tax, property management, engineering, risk management and acquisition services to Quest
Energy Partners.
KPC Acquisition
On November 1, 2007, Quest Midstream Partners closed on the acquisition of (i) a 1,120-mile
interstate gas pipeline running from Oklahoma to Missouri (the KPC Pipeline) and (ii) all of the
membership interests in the two general partners of Enbridge Pipelines (KPC), the owner of the KPC
Pipeline (the Enbridge Acquisition). Quest Midstream Partners completed the purchase of the KPC
Pipeline for $133 million in cash, subject to a working capital adjustment, pursuant to a Purchase
and Sale Agreement dated October 9, 2007, by and among Enbridge Midcoast Energy, L.P., Midcoast
Holdings No. One, L.L.C., and Quest Midstream Partners.
Results of Operations
The following discussion is based on the consolidated operations of all our subsidiaries and
should be read in conjunction with the financial statements included in this report; and should
further be read in conjunction with the audited financial statements and notes thereto included in
our annual report on Form 10-K/A for the year ended December 31, 2006. Comparisons made
-4-
between reporting periods herein are for the three and nine month periods ended September 30,
2006 as compared to the same period in 2007.
Three Months Ended September 30, 2006 and September 30, 2007
Overview.
The following table summarizes our results of operations for the three months ended
September 30, 2006 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
|
|
Ended
|
|
|
|
|
September 30,
|
|
Increase/
|
|
|
2006
|
|
2007
|
|
(Decrease)
|
|
|
($ in thousands)
|
|
|
Oil and gas sales
|
|
$
|
15,329
|
|
|
$
|
28,494
|
|
|
$
|
13,165
|
|
|
|
85.9
|
%
|
Gas pipeline revenue
|
|
|
1,372
|
|
|
|
1,788
|
|
|
|
416
|
|
|
|
30.3
|
%
|
Other revenue/(expense)
|
|
|
4
|
|
|
|
(5
|
)
|
|
|
(9
|
)
|
|
|
-225.0
|
%
|
Oil and gas production costs, including GPT/Ad valorem tax
|
|
|
5,492
|
|
|
|
7,280
|
|
|
|
1,788
|
|
|
|
32.6
|
%
|
Pipeline operating expenses, including Ad valorem tax
|
|
|
3,400
|
|
|
|
5,004
|
|
|
|
1,604
|
|
|
|
47.2
|
%
|
Depreciation, depletion and amortization
|
|
|
7,875
|
|
|
|
9,276
|
|
|
|
1,401
|
|
|
|
17.8
|
%
|
General and administrative expenses
|
|
|
2,723
|
|
|
|
3,653
|
|
|
|
930
|
|
|
|
34.2
|
%
|
Interest expense
|
|
|
6,937
|
|
|
|
8,206
|
|
|
|
1,269
|
|
|
|
18.3
|
%
|
Change in derivative fair value
|
|
|
(332
|
)
|
|
|
5,539
|
|
|
|
5,871
|
|
|
|
1,768.4
|
%
|
Production.
The following table presents the primary components of our revenues, as well as
the average costs per Mcfe, for the three months ended September 30, 2006 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
|
|
Ended
|
|
|
|
|
September 30,
|
|
Increase/
|
|
|
2006
|
|
2007
|
|
(Decrease)
|
Production Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production (MMcfe)
|
|
|
3,331
|
|
|
|
4,554
|
|
|
|
1,223
|
|
|
|
36.7
|
%
|
Average daily production (MMcfe/d)
|
|
|
36.21
|
|
|
|
49.50
|
|
|
$
|
13.29
|
|
|
|
36.7
|
%
|
Average Sales Price per Unit (Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excluding hedges
|
|
$
|
5.67
|
|
|
$
|
6.24
|
|
|
$
|
0.57
|
|
|
|
10.1
|
%
|
Including hedges
|
|
|
4.56
|
|
|
|
5.43
|
|
|
|
0.87
|
|
|
|
19.1
|
%
|
Average Unit Costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production costs, including
GPT/Ad valorem tax
|
|
$
|
1.65
|
|
|
$
|
1.60
|
|
|
$
|
(0.05)
|
|
|
|
-3.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline operating, including Ad valorem tax
|
|
|
1.02
|
|
|
|
1.10
|
|
|
|
0.08
|
|
|
|
7.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
2.36
|
|
|
|
2.04
|
|
|
|
(0.32
|
)
|
|
|
-13.8
|
%
|
General and administrative expenses
|
|
|
0.82
|
|
|
|
0.80
|
|
|
|
(0.02
|
)
|
|
|
-1.9
|
%
|
Revenues.
Oil and gas sales were $28.5 million for the three months ended September 30, 2007
compared to $15.3 million for the three months ended September 30, 2006, an increase of $13.2
million, or 85.9%. The increase in oil and gas
sales for the three months ended September 30, 2007 was the result of a
-5-
36.7% increase in sales volumes that was achieved by the addition of more producing wells and an increase in natural gas
prices between periods, which was partially offset by the natural decline in production from some
of our older gas wells.
Gas pipeline revenue was $1.8 million for the three months ended September 30, 2007 compared
to $1.4 million for the three months ended September 30, 2006, an increase of $0.4 million, or
30.3%. The increase was due to the increased volumes flowing through our pipelines and an increase
in natural gas prices, which resulted in increased revenues for gas transported on a percentage of
proceeds basis.
The additional wells contributed to the production of 4,544,000 net Mcf of gas for the three
months ended September 30, 2007, as compared to 3,331,000 net Mcf produced in the same quarter last
year. Our product prices on an equivalent basis (Mcfe) increased from $5.67 per Mcfe on average for
the three months ended September 30, 2006 to $6.24 per Mcfe on average for the three months ended
September 30, 2007.
Operating Expenses.
Oil and gas production costs, including gross production tax and ad
valorem tax were $7.3 million for the three months ended September 30, 2007, as compared to $5.5
million for the three months ended September 30, 2006, an increase of $1.8 million, or 32.6%.
Lease operating costs, excluding gross production tax and ad valorem tax, per Mcfe for the three
months ended September 30, 2007, decreased to $1.20 per Mcfe as compared to $1.31 per Mcfe for the
three months ended September 30, 2006. The lease operating cost per Mcfe decreased due to
reductions in several cost categories, including chemical treatment and third party service units.
Pipeline operating costs increased by approximately 47.2% from $3.4 million for the three
months ended September 30, 2006 to $5.0 million for the three months ended September 30, 2007.
Pipeline operating costs per Mcf for the three months ended September 30, 2007 and 2006 were $1.10
per Mcf and $1.02 per Mcf, respectively. The cost increases incurred for pipeline operations are
due to a number of factors, including: excessively wet summer weather conditions (including
flooding) that resulted in significant overtime hours for our field labor force working to restore
production, the number of wells acquired, completed and operated during the quarter, the increased
miles of pipeline and compression in service and increased property taxes due to both the increased
miles of pipeline and an increase in property tax rates.
Depreciation,
Depletion and Amortization.
For the three months ended September 30, 2007, depreciation, depletion and amortization
increased to $9.3 million as compared to $7.9 million for the three months ended September 30,
2006. The increase in depreciation, depletion and amortization is a result of the increased number
of producing wells and miles of pipelines developed and the higher volumes of gas and oil produced.
General and Administrative Expenses
. General and administrative expenses increased from $2.7
million for the three months ended September 30, 2006 to $3.7 million for the three months ended
September 30, 2007, an increase of $1.0 million, or 34.2%. This increase resulted primarily from a
non-cash charge of approximately $976,000 for amortization of equity incentive awards. The
remainder of the increase is due to an increase in staff personnel, legal, accounting and
professional fees related to the increased size and complexity of our operations.
Interest Expense.
Interest expense was $8.2 million for the three months ended September 30,
2007 as compared to $7.0 million for the three months ended September 30, 2006, an increase of $1.2
million, or 17.7%. This increase was due to an increase in our outstanding borrowings related to
equipment, development and leasehold expenditures and higher average interest rates.
Other Expense.
Other expense for the three months ended September 30, 2007 was $5,000 as
compared to other income of $4,000 for the three-month period ended September 30, 2006.
Change in Derivative Fair Value
. Change in derivative fair value was a non-cash gain of $5.5
million for the three months ended September 30, 2007, which included a $4.7 million gain
attributable to the change in fair value for certain derivatives that did not qualify as cash flow
hedges pursuant to SFAS 133 and a gain of $791,000 relating to hedge ineffectiveness. Change in
derivative fair value was a non-cash loss of $332,000 for the three months ended September 30,
2006, which included a $1.3 million loss attributable to the change in fair value for certain
derivatives that did not qualify as cash flow hedges pursuant to SFAS 133 and a gain of $998,000
relating to hedge ineffectiveness. Amounts recorded in this caption represent non-cash gains and
losses created by valuation changes in derivatives that are not entitled to receive hedge
accounting. All amounts recorded in this caption are ultimately reversed in this caption over the
respective contract term.
-6-
The following table reflects the results of operations we achieved through the exploration and
development activities and the results achieved from Quest Midstream Partners through the pipeline
activity. The required inter-company elimination entries are listed that result in the consolidated
results of operations as listed in this quarterly filing ($ in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quest Resource
|
|
|
Quest Midstream
|
|
|
Inter-company
|
|
|
|
|
|
|
Corporation
|
|
|
Partners
|
|
|
eliminations
|
|
|
Consolidated
|
|
Gas/oil sales
|
|
$
|
28,494
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
28,494
|
|
Pipeline revenue
|
|
|
|
|
|
|
9,256
|
|
|
|
(7,468
|
)
|
|
|
1,788
|
|
Other expense
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
28,489
|
|
|
|
9,256
|
|
|
|
(7,468
|
)
|
|
|
30,277
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating cost, including
GPT/Ad valorem tax
|
|
|
7,280
|
|
|
|
|
|
|
|
|
|
|
|
7,280
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transport fee/POE, including
Ad valorem tax
|
|
|
7,468
|
|
|
|
5,004
|
|
|
|
(7,468
|
)
|
|
|
5,004
|
|
General and administrative cost
|
|
|
2,415
|
|
|
|
1,238
|
|
|
|
|
|
|
|
3,653
|
|
Depreciation, depletion and
amortization
|
|
|
7,978
|
|
|
|
1,298
|
|
|
|
|
|
|
|
9,276
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs
|
|
|
25,141
|
|
|
|
7,540
|
|
|
|
(7,468
|
)
|
|
|
25,213
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
3,348
|
|
|
|
1,716
|
|
|
|
|
|
|
|
5,064
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss)/gain on sale of assets
|
|
|
49
|
|
|
|
1
|
|
|
|
|
|
|
|
50
|
|
Interest expense
|
|
|
(7,665
|
)
|
|
|
(541
|
)
|
|
|
|
|
|
|
(8,206
|
)
|
Interest income
|
|
|
102
|
|
|
|
|
|
|
|
|
|
|
|
102
|
|
Change in derivate fair value
|
|
|
5,539
|
|
|
|
|
|
|
|
|
|
|
|
5,539
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before minority
interest and income taxes
|
|
$
|
1,373
|
|
|
$
|
1,176
|
|
|
$
|
|
|
|
$
|
2,549
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2007
Overview.
The following table summarizes our results of operations for the nine months ended
September 30, 2006 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
|
|
Ended
|
|
|
|
|
September 30,
|
|
Increase/
|
|
|
2006
|
|
2007
|
|
(Decrease)
|
|
|
($ in thousands)
|
Oil and gas sales
|
|
$
|
49,114
|
|
|
$
|
81,910
|
|
|
$
|
32,796
|
|
|
|
66.8
|
%
|
Gas pipeline revenue
|
|
|
3,722
|
|
|
|
5,122
|
|
|
|
1,400
|
|
|
|
37.6
|
%
|
Other revenue/(expense)
|
|
|
(63
|
)
|
|
|
(37
|
)
|
|
|
26
|
|
|
|
-41.3
|
%
|
Oil and gas production costs, including GPT/Ad valorem tax
|
|
|
14,064
|
|
|
|
22,247
|
|
|
|
8,183
|
|
|
|
58.2
|
%
|
Pipeline operating expenses, including Ad valorem tax
|
|
|
9,330
|
|
|
|
14,271
|
|
|
|
4,941
|
|
|
|
53.0
|
%
|
Depreciation, depletion and amortization
|
|
|
20,643
|
|
|
|
25,610
|
|
|
|
4,967
|
|
|
|
24.1
|
%
|
General and administrative expenses
|
|
|
6,596
|
|
|
|
11,698
|
|
|
|
5,102
|
|
|
|
77.3
|
%
|
Interest expense
|
|
|
15,885
|
|
|
|
22,928
|
|
|
|
7,043
|
|
|
|
44.3
|
%
|
Change in derivative fair value
|
|
|
6,300
|
|
|
|
5,354
|
|
|
|
(946
|
)
|
|
|
-15.0
|
%
|
-7-
Production.
The following table presents the primary components of our revenues, as well as
the average costs per Mcfe, for the nine months ended September 30, 2006 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
|
|
Ended
|
|
|
|
|
September 30,
|
|
Increase/
|
|
|
2006
|
|
2007
|
|
(Decrease)
|
Production Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production (MMcfe)
|
|
|
8,718
|
|
|
|
12,338
|
|
|
|
3,620
|
|
|
|
40.6
|
%
|
Average daily production (MMcfe/d)
|
|
|
31.93
|
|
|
|
45.19
|
|
|
$
|
13.26
|
|
|
|
41.5
|
%
|
Average Sales Price per Unit (Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excluding hedges
|
|
$
|
6.08
|
|
|
$
|
6.21
|
|
|
$
|
0.13
|
|
|
|
2.0
|
%
|
Including hedges
|
|
|
4.40
|
|
|
|
6.61
|
|
|
|
2.21
|
|
|
|
50.6
|
%
|
Average Unit Costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production costs, including
GPT/Ad valorem tax
|
|
$
|
1.31
|
|
|
$
|
1.80
|
|
|
$
|
0.49
|
|
|
|
37.6
|
%
|
Pipeline operating, including Ad Valorem tax
|
|
|
1.07
|
|
|
|
1.16
|
|
|
|
0.09
|
|
|
|
8.1
|
%
|
Depreciation, depletion and amortization
|
|
|
2.37
|
|
|
|
2.08
|
|
|
|
(0.29
|
)
|
|
|
-12.3
|
%
|
General and administrative expenses
|
|
|
0.76
|
|
|
|
0.95
|
|
|
|
0.19
|
|
|
|
25.3
|
%
|
Revenues.
Oil and gas sales were $81.9 million for the nine months ended September 30, 2007
compared to $49.1 million for the nine months ended September 30, 2006, an increase of $32.8
million, or 66.8%. The
increase in oil and gas sales for the nine months ended
September 30, 2007 resulted from a 40.6%
increase in sales volumes that was achieved by the addition of more
producing wells, which was
partially offset by the natural decline in production from some of our older gas wells.
Gas
pipeline revenue was $5.1 million for the nine months ended September 30, 2007 compared to
$3.7 million for the nine months ended September 30, 2006, an increase of $1.4 million, or 37.6%.
The increase was due to the increased volumes flowing through our pipelines and an increase in
natural gas prices, which resulted in increased revenues for gas transported on a percentage of
proceeds basis.
The additional wells contributed to the production of 12,338,000 net Mcf of gas for the nine
months ended September 30, 2007, as compared to 8,718,000 net Mcf produced in the same nine month
period last year. Our product prices on an equivalent basis (Mcfe) increased from $6.08 per Mcfe on
average for the nine months ended September 30, 2006 to $6.21 per Mcfe on average for the nine
months ended September 30, 2007.
Operating Expenses
. Oil and gas production costs including gross production tax and ad
valorem tax were $22.2 million for the nine months ended
September 30, 2007, as compared to $14.1
million for the nine months ended September 30, 2006, an increase of $8.1 million, or 58%. Lease
operating costs excluding gross production tax and ad valorem tax, per Mcfe for the nine months
ended September 30, 2007 increased to $1.31 per Mcfe as compared to $1.23 per Mcfe for the nine
months ended September 30, 2006. The lease operating cost per Mcfe increased due to a number of
factors, including: winter weather and excessively wet spring and summer weather conditions
(including flooding) that resulted in a larger percentage of the field labor force being charged to
operating expense as compared to capital expenditures, our increased development program, an
increase in wage rates due to a tight labor market for skilled workers in the Cherokee Basin, an
increase in well repairs, utilities and fuel costs due to the increase in the number of wells being
operated, an increase in energy and raw material costs.
Pipeline operating costs increased by approximately 53% from $9.3 million for the nine months
ended September 30, 2006 to $14.3 million for the nine months ended September 30, 2007. Pipeline
operating costs per Mcf for the nine months ended
-8-
September 30, 2007 increased to $1.16 per Mcf as
compared to $1.07 per Mcf for the nine months ended September 30, 2006. The cost increases incurred
for pipeline operations are due to a number of factors, including: winter weather and excessively
wet spring and summer weather conditions (including flooding) that resulted in significant overtime
hours for our field labor force working to restore production, the number of wells acquired,
completed and operated during the quarter, the increased miles of pipeline and compression in
service and increased property taxes due to both the increased miles of pipeline and an increase in
property tax rates.
Depreciation, Depletion and Amortization
. For the nine months ended September 30, 2007, depreciation, depletion and amortization
increased to $25.6 million as compared to $20.6 million for the nine months ended September 30,
2006. The increase in depreciation, depletion and amortization is a result of the increased number
of producing wells and miles of pipelines developed and the higher volumes of gas and oil produced.
General and Administrative Expenses
. General and administrative expenses increased from $6.6
million for the nine months ended September 30, 2006 to $11.7 million for the nine months ended
September 30, 2007, an increase of $5.1 million, or 77.3%. This increase resulted primarily from a
non-cash charge of approximately $3.9 million for amortization of equity incentive awards. The
remainder of the increase is due to an increase in staff personnel, legal, accounting and
professional fees related to the increased size and complexity of our operations.
Interest Expense
. Interest expense was $22.9 million for the nine months ended September 30,
2007 as compared to $15.9 million for the nine months ended September 30, 2006, an increase of $7.0
million, or 44.3%. This increase was due to an increase in our outstanding borrowings related to
equipment, development and leasehold expenditures and higher average interest rates.
Other Expense.
Other expense for the nine months ended September 30, 2007 was $37,000 as
compared to other expense of $63,000 for the nine-month period ended September 30, 2006. The
decrease is due to a reduction in overhead and pumper charges.
Change in Derivative Fair Value.
Change in derivative fair value was a non-cash gain of $5.4
million for the nine months ended September 30, 2007, which
included a $3.3 million gain
attributable to the change in fair value for certain derivatives that did not qualify as cash flow
hedges pursuant to SFAS 133 and a gain of $2.0 million relating to hedge ineffectiveness. Change in
derivative fair value was a non-cash gain of $6.3 million for the nine months ended September 30,
2006, which included a $13.3 million gain attributable to the change in fair value for certain
derivatives that did not qualify as cash flow hedges pursuant to SFAS 133, a $10.2 million loss due
to the contracts not qualifying for hedge accounting treatment, and a gain of $3.2 million relating
to hedge ineffectiveness. Amounts recorded in this caption represent non-cash gains and losses
created by valuation changes in derivatives that are not entitled to receive hedge accounting. All
amounts recorded in this caption are ultimately reversed in this caption over the respective
contract term.
The following table reflects the results of operations we achieved through the exploration and
development activities and the results achieved from Quest Midstream Partners through the pipeline
activity. The required inter-company elimination entries are listed that result in the consolidated
results of operations as listed in this quarterly filing ($ in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quest Resource
|
|
|
Quest Midstream
|
|
|
Inter-company
|
|
|
|
|
|
|
Corporation
|
|
|
Partners
|
|
|
eliminations
|
|
|
Consolidated
|
|
Gas/oil sales
|
|
$
|
81,910
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
81,910
|
|
Pipeline revenue
|
|
|
|
|
|
|
25,761
|
|
|
|
(20,639
|
)
|
|
|
5,122
|
|
Other expense
|
|
|
(37
|
)
|
|
|
|
|
|
|
|
|
|
|
(37
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
81,873
|
|
|
|
25,761
|
|
|
|
(20,639
|
)
|
|
|
86,995
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating cost, including
GPT/ Ad valorem tax
|
|
|
22,247
|
|
|
|
|
|
|
|
|
|
|
|
22,247
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transport fee/POE, including
Ad valorem tax
|
|
|
20,639
|
|
|
|
14,271
|
|
|
|
(20,639
|
)
|
|
|
14,271
|
|
General and administrative cost
|
|
|
8,262
|
|
|
|
3,436
|
|
|
|
|
|
|
|
11,698
|
|
Depreciation, depletion and
amortization
|
|
|
22,041
|
|
|
|
3,569
|
|
|
|
|
|
|
|
25,610
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs
|
|
|
73,189
|
|
|
|
21,276
|
|
|
|
(20,639
|
)
|
|
|
73,826
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
8,684
|
|
|
|
4,485
|
|
|
|
|
|
|
|
13,169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss)/gain on sale of assets
|
|
|
(147
|
)
|
|
|
6
|
|
|
|
|
|
|
|
(141
|
)
|
Interest expense
|
|
|
(21,824
|
)
|
|
|
(1,104
|
)
|
|
|
|
|
|
|
(22,928
|
)
|
Interest income
|
|
|
382
|
|
|
|
|
|
|
|
|
|
|
|
382
|
|
Change in derivate fair value
|
|
|
5,354
|
|
|
|
|
|
|
|
|
|
|
|
5,354
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) before
minority interest and income
taxes
|
|
$
|
(7,551
|
)
|
|
$
|
3,387
|
|
|
$
|
|
|
|
$
|
(4,164
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-9-
Liquidity and Capital Resources
Liquidity
Our primary sources of liquidity are cash generated from our operations, amounts available
under our revolving credit facility and Bluestems revolving credit facility and funds from future
private and public equity and debt offerings. Please read Note 2 to our consolidated financial
statements included in this report for additional information regarding our and Bluestems credit
facilities, including a description of the financial covenants contained in each of the credit
facilities.
At September 30, 2007, we had $23.5 million of availability under our revolving credit
facility, which was available to fund the drilling and completion of additional gas wells, the
recompletion of single seam wells into multi-seam wells, the acquisition of additional acreage,
equipment and vehicle replacement and purchases and the construction of salt water disposal
facilities.
At September 30, 2007, Bluestem had $45 million of availability under its revolving credit
facility, which was available to fund additional pipeline construction, the connection of
additional wells to our pipeline system, pipeline acquisitions and working capital for our pipeline
operations. On November 1, 2007, in connection with the acquisition of the KPC pipeline, Quest
Midstream Partners and Bluestem entered into an Amended and Restated Credit Agreement, which
increased the aggregate commitment under Bluestems existing revolving credit facility from $75
million to $135 million. For further information regarding this credit facility, see Note 8.
Subsequent Events to the financial statements included in this report and our Current Report on
Form 8-K filed with the Securities and Exchange Commission on November 2, 2007. Immediately after
the acquisition of the KPC Pipeline, Quest Midstream Partners had $40 million of availability under
this credit facility.
At September 30, 2007, we had current assets of $49.3 million. Our working capital (current
assets minus current liabilities, excluding the short-term derivative asset and liability of $7.3
million and $6.1 million, respectively) was a deficit of $2.3 million at September 30, 2007,
compared to working capital (excluding the short-term derivative asset and liability of $10.8
million and $5.2 million, respectively) of $37.7 million at December 31, 2006. Working capital
(including the short-term derivative assets and liabilities) was a deficit of $1.1 million as of
September 30, 2007. The changes in working capital were primarily due to the use of cash of $112.0
million, substantially all of which was used for capital expenditures, and an increase in accounts
payable of $20.5 million due to the expansion of our wells and pipeline development program, which
was partially offset by an increase in revenue payable of $1.1 million resulting from higher
production volumes and an increase of $1.7 million in receivables. A substantial portion of our
production is hedged. We are generally required to settle our commodity hedges on either the 5th or
25th day of each month. As is typical in the gas and oil business, we generally do not receive the
proceeds from the sale of the hedged production until around the 25th day of the following month.
As a result, when gas and oil prices increase and are above the prices fixed in our derivative
contracts, we will be required to pay the hedge counterparty the difference between the fixed price
in the hedge and the market price before we receive the proceeds from the sale of the hedged
production.
Future Capital Expenditures
During 2007, we intend to focus on drilling and completing up to 558 new wells. We also
currently intend to drill approximately 325 wells during 2008. Management currently estimates that
it will require for 2007 and 2008 capital investments of:
|
|
|
$76.0 million and $49.5 million, respectively, to drill and complete these wells and
recomplete an estimated 80 gross wells in the Cherokee Basin;
|
|
|
|
|
$37.0 million and $29.0 million, respectively, for acreage, equipment and vehicle
replacement and purchases and salt water disposal facilities in the Cherokee Basin;
|
-10-
|
|
|
$38.0 million and 25.0 million, respectively, for the pipeline expansion to connect the
new wells to our existing gas gathering pipeline network in the Cherokee Basin; and
|
|
|
|
|
$3.0 million in 2007 and $4.4 million in 2008 for areas outside of the Cherokee Basin.
|
In connection with the closing of the Quest Energy Partners initial public offering, Quest
Energy Partners principal operating subsidiary (Quest Cherokee) will enter into a new 5-year $250
million revolving credit agreement, with an initial borrowing base of $160.0 million, with a
syndicate of financial institutions. We anticipated that $75 million will be outstanding under
this credit agreement upon the closing of the offering. In addition, we intend to enter into a new
3-year, $50 million revolving credit agreement at the closing of Quest Energy Partners initial
public offering. We anticipated that approximately $41.5 million will be outstanding under this credit agreement
upon the closing of the offering.
Our capital expenditures will consist of, the following:
|
|
|
maintenance capital expenditures, which are those capital expenditures required to
maintain our production levels and asset base and pipeline volumes over the long term; and
|
|
|
|
|
expansion capital expenditures, which are those capital expenditures that we expect will
increase our production of our gas and oil properties, our asset base or our pipeline
volumes over the long term.
|
Quest
Energy Partners and Quest Midstream Partners will be responsible for the Cherokee Basin
capital expenditures described above. In general, Quest Energy Partners and Quest Midstream
Partners intend to finance future maintenance capital expenditures generally from cash flow from
operations and expansion capital expenditures generally with borrowings under their credit
facilities and/or the issuance of debt or equity.
Quest Resource Corporation will be responsible for the capital expenditures outside the
Cherokee Basin described above. Quest Resource intends to finance these capital expenditures
through either borrowings under its revolving credit facility, the issuance of debt or equity
securities and/or distributions from Quest Energy Partners and/or Quest Midstream Partners.
In the event we make one or more acquisitions and the amount of capital required is greater
than the amount we have available for acquisitions at that time, we would reduce the expected level
of capital expenditures and/or seek additional capital. If we seek additional capital for that or
other reasons, we may do so through traditional reserve base borrowings, joint venture
partnerships, production payment financings, asset sales, offerings of debt or equity securities or
other means.
We cannot assure you that needed capital will be available on acceptable terms or at all. Our
ability to raise funds through the incurrence of additional indebtedness will be limited by
covenants in our credit facility and the credit facilities of Quest Midstream Partners and Quest
Energy Partners. If we are unable to obtain funds when needed or on acceptable terms, we may not be
able to complete acquisitions that may be favorable to us or finance the capital expenditures
necessary to replace our reserves and maintain our pipeline volumes. Please read Note 2 to our
consolidated financial statements included in this report for a description of the financial
covenants contained in each of the credit facilities. If we are unable to obtain funds when needed
or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or
finance the capital expenditures necessary to replace our reserves.
Cash Flows
Cash Flows from Operating Activities.
Net cash provided by operating activities totaled $43.7
million for the nine months ended September 30, 2007 as compared to net cash provided by operations
of $24.7 million for the nine months ended September 30, 2006. This increase resulted from a change
in derivative fair value, an increase in accounts receivable and accounts payable and an increase
in revenue payable and other receivables.
Cash Flows Used in Investing Activities.
Net cash used in investing activities totaled $112.4
million for the nine months ended September 30, 2007 as compared to $148.5 million for the nine
months ended September 30, 2006. During the nine months ended September 30, 2007, a total of
approximately $112.4 million of capital expenditures was invested as follows: $75.4 million was
invested in new natural gas wells and properties, $25.6 million in new pipeline facilities, $5.1
million in acquiring leasehold and $6.3 million in other additional capital items.
Cash Flows from Financing Activities.
Net cash provided by financing activities totaled $47.9
million for the nine months ended September 30, 2007 as compared to $139.1 million for the nine
months ended September 30, 2006, and related to the financing of capital expenditures. The
decrease in cash provided from financing activities was due primarily to a $55 million
-11-
increase in borrowings under the Quest Cherokee credit facilities for the nine months ended
September 30, 2007 compared to a $125 million increase under the Quest Cherokee credit facilities
during the nine months ended September 30, 2006.
Contractual Obligations
Future payments due on our contractual obligations as of September 30, 2007 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2007
|
|
|
2008-2009
|
|
|
2010-2011
|
|
|
thereafter
|
|
|
|
($ in thousands)
|
|
|
|
|
First Lien Term Note
|
|
$
|
50,000
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
50,000
|
|
|
$
|
|
|
Second Lien Term Note
|
|
|
100,000
|
|
|
|
|
|
|
|
|
|
|
|
100,000
|
|
|
|
|
|
Third Lien Term Note
|
|
|
75,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
75,000
|
|
Revolver Quest (1)
|
|
|
25,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25,000
|
|
Credit Facility Quest
Midstream (2)
|
|
|
30,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30,000
|
|
Interest payment
Obligation (3)
|
|
|
122,899
|
|
|
|
7,278
|
|
|
|
58,177
|
|
|
|
51,934
|
|
|
|
5,510
|
|
Asset
retirement obligation
|
|
|
1,619
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,619
|
|
Drilling contractor
|
|
|
5,952
|
|
|
|
1,711
|
|
|
|
4,241
|
|
|
|
|
|
|
|
|
|
Notes payable
|
|
|
176
|
|
|
|
122
|
|
|
|
34
|
|
|
|
12
|
|
|
|
8
|
|
Lease obligations
|
|
|
6,950
|
|
|
|
219
|
|
|
|
1,665
|
|
|
|
1,465
|
|
|
|
3,601
|
|
Derivatives
|
|
|
8,165
|
|
|
|
6,098
|
|
|
|
2,067
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
425,761
|
|
|
$
|
15,428
|
|
|
$
|
66,184
|
|
|
$
|
203,411
|
|
|
$
|
140,738
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
We have a $50 million revolving credit facility that matures on November 14, 2010. As of
September 30, 2007, $25 million was borrowed under this facility.
|
|
(2)
|
|
Quest Midstream Partners has a revolving credit facility that matures on January 31, 2012. As
of September 30, 2007, $30 million was borrowed under this facility.
|
|
(3)
|
|
The interest payment obligation was computed using the LIBOR interest rate as of September 30,
2007. If the interst rate were to change 1%, then the interest payment obligation would change by
$11.7 million.
|
Critical Accounting Policies
Certain amounts included in or affecting our consolidated financial statements and related
disclosures must be estimated, requiring us to make certain assumptions with respect to values or
conditions that cannot be known with certainty at the time the financial statements are prepared.
These estimates and assumptions affect the amounts we report for assets and liabilities and our
disclosure of contingent assets and liabilities at the date of our financial statements. We
routinely evaluate these estimates, utilizing historical experience, consultation with experts and
other methods we consider reasonable in the particular circumstances. Nevertheless, actual results
may differ significantly from our estimates. Any effects on our business, financial position or
results of operations resulting from revisions to these estimates are recorded in the period in
which the facts that give rise to the revision become known. Our critical accounting policies are
available in Item 7 of our Annual Report on Form 10-K/A for the year ended December 31, 2006. There
have been no significant changes with respect to these policies during the first nine months of
2007.
Off-Balance Sheet Arrangements
At September 30, 2007 and December 31, 2006, we did not have any relationships with
unconsolidated entities or financial partnerships, such as entities often referred to as structured
finance or special purpose entities, which would have been established for the purpose of
facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. In
addition, we do not engage in trading activities involving non-exchange traded contracts. As such,
we are not exposed to any financing, liquidity, market, or credit risk that could arise if we had
engaged in such activities.
Forward-looking Information
This quarterly report contains forward-looking statements that are subject to a number of
risks and uncertainties, many of which are beyond our control, which may include statements about:
-12-
|
|
|
our ability to implement our business strategy;
|
|
|
|
|
the extent of our success in discovering, developing and producing reserves, including
the risks inherent in exploration and development drilling, well completion and other
development activities, including pipeline infrastructure;
|
|
|
|
|
fluctuations in the commodity prices for natural gas and crude oil;
|
|
|
|
|
engineering and mechanical or technological difficulties with operational equipment, in
well completions and workovers, and in drilling new wells;
|
|
|
|
|
land issues;
|
|
|
|
|
the effects of government regulation and permitting and other legal requirements;
|
|
|
|
|
labor problems;
|
|
|
|
|
environmental related problems;
|
|
|
|
|
the uncertainty inherent in estimating future natural gas and oil production or
reserves;
|
|
|
|
|
production variances from expectations;
|
|
|
|
|
the substantial capital expenditures required for construction of pipelines and the
drilling of wells and the related need to fund such capital requirements through commercial
banks and/or public securities markets;
|
|
|
|
|
disruptions, capacity constraints in or other limitations on our pipeline systems;
|
|
|
|
|
costs associated with perfecting title for natural gas rights and pipeline easements and
rights of way in some of our properties;
|
|
|
|
|
the need to develop and replace reserves;
|
|
|
|
|
competition;
|
|
|
|
|
dependence upon key personnel;
|
|
|
|
|
the lack of liquidity of our equity securities;
|
|
|
|
|
operating hazards attendant to the natural gas and oil business;
|
|
|
|
|
down-hole drilling and completion risks that are generally not recoverable from third
parties or insurance;
|
|
|
|
|
potential mechanical failure or under-performance of significant wells;
|
|
|
|
|
climatic conditions;
|
|
|
|
|
natural disasters;
|
|
|
|
|
acts of terrorism;
|
|
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availability and cost of material and equipment;
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delays in anticipated start-up dates;
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our ability to find and retain skilled personnel;
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availability of capital;
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the strength and financial resources of our competitors; and
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general economic conditions.
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All of these types of statements, other than statements of historical fact included in this
report, are forward-looking statements. These statements relate to future events or to our future
financial performance. In some cases, you can identify forward-looking statements by terminology
such as may, will, should, could, expect, plan, anticipates, believes, estimates,
predicts, potential, project, intend, pursue, target or continue or the negative of
such terms or other comparable terminology. The forward-looking statements contained in this
report are largely based on our expectations, which reflect estimates and assumptions made by our
management. These estimates and assumptions reflect our best judgment based on currently known
market conditions and other factors. Although we believe such estimates and assumptions to be
reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are
beyond our control. In addition, managements assumptions about future events may prove to be
inaccurate. Management cautions all readers that the forward-looking statements contained in this
report are not guarantees of future performance, and we cannot assure any reader that such
statements will be realized or the forward-looking events and circumstances will occur. Actual
results may differ materially from those anticipated or implied in the forward-looking statements
due to factors listed in Item 1ARisk Factors in our annual report on Form 10-K/A for the year
ended December 31, 2006 and in Part II, Item 1A in this report. All forward-looking statements
speak only as of the date of this report. We do not intend to publicly update or revise any
forward-looking statements as a result of new information, future events or otherwise. These
cautionary statements qualify all forward-looking statements attributable to us or persons acting
on our behalf.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
See Note 4 to our consolidated financial statements which are included elsewhere in this
report and incorporated by reference.
-13-
Item 4. Controls and Procedures
As of September 30, 2007, our management, including the Chief Executive Officer and the Chief
Financial Officer, evaluated the effectiveness of the design and operation of our disclosure
controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934.
There are inherent limitations to the effectiveness of any system of disclosure controls and
procedures, including the possibility of human error and the circumvention or overriding of the
controls and procedures. Accordingly, even effective disclosure controls and procedures can only
provide reasonable assurance of achieving their control objectives. Based upon this evaluation,
the Chief Executive Officer and the Chief Financial Officer concluded that the design and operation
of our disclosure controls and procedures were effective as of such date to provide reasonable
assurance that information required to be disclosed in the reports that we file or submit under the
Exchange Act is recorded, processed, summarized and reported within the time periods specified in
Securities and Exchange Commission rules and forms and is accumulated and communicated to our
management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to
allow timely decisions regarding required disclosure.
Changes in Internal Controls
There has been no change in our internal control over financial reporting during the quarter
ended September 30, 2007 that has materially affected, or is reasonably likely to materially
affect, our internal control over financial reporting.
PART II OTHER INFORMATION
Item 1. Legal Proceedings
See Part I, Item 1, Note 3 to our condensed consolidated financial statements entitled
Commitments and Contingencies, which is incorporated herein by reference.
In addition, from time to time, we may be subject to legal proceedings and claims that arise
in the ordinary course of our business. Although no assurance can be given, management believes,
based on its experiences to date, that the ultimate resolution of such items will not have a
material adverse impact on our business, financial position or results of operations.
Item 1A. Risk Factors
Except as set forth below with respect to the pending merger of Pinnacle Gas Resources, Inc.
(Pinnacle) into one of our subsidiaries, there have not been any material changes from the risk
factors previously disclosed in our Form 10-Q for the quarter ended June 30, 2007 in response to
Item 1A. to Part II of Form 10-Q.
The value of the consideration received by Pinnacle stockholders will vary with the value of our
common stock.
The exchange ratio in the merger is fixed and will not be adjusted in the event of any change
in the stock prices of Pinnacle or us prior to the merger. Accordingly, the value of the
consideration that Pinnacle stockholders will be entitled to receive pursuant to the merger will
depend on the trading price of our common stock. This means that there is no price protection
mechanism contained in the merger agreement that would adjust the number of shares that Pinnacle
stockholders will receive based on any increases or decreases in the trading price of our common
stock. If our stock price increases, the market value of the consideration will also increase.
Stock price changes may result from a variety of factors, including general market and economic
conditions, changes in oil and natural gas prices, changes in our respective businesses, operations
and prospects, and regulatory considerations. Many of these factors are beyond our control.
The integration of Pinnacle following the merger will present significant challenges that may
reduce the anticipated potential benefits of the merger.
We will face significant challenges in consolidating functions and integrating Pinnacles and
our organizations, procedures and operations within a timely and efficient manner, as well as
retaining key personnel. The integration of Pinnacle with us will be complex and time-consuming
due to the size and complexity of each organization. The principal challenges will include the
following:
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integrating Pinnacles and our existing businesses;
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preserving customer, supplier and other important relationships and resolving
potential conflicts that may arise as a result of the merger;
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consolidating and integrating duplicative facilities and operations; and
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addressing differences in business cultures, preserving employee morale and
retaining key employees, while maintaining focus on meeting the operational and
financial goals of the combined company.
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-14-
Our management will have to dedicate substantial effort to integrating the businesses. These
efforts could divert managements focus and resources from other day-to-day tasks, corporate
initiatives or strategic opportunities during the integration process.
We and Pinnacle will incur significant transaction and merger-related integration costs in
connection with the merger.
We and Pinnacle expect to pay significant transaction costs. These transaction fees include
investment banking, legal and accounting fees and expenses, SEC filing fees, printing expenses,
mailing expenses and other related charges, as well as payments to some of Pinnacles employees
pursuant to change of control agreements. A portion of the transaction costs will be incurred
regardless of whether the merger is consummated.
We anticipate that we will incur substantial costs to integrate Pinnacles operations with our
existing business. We are in the early stages of assessing the magnitude of these costs, and,
therefore, are unable at this time to estimate the costs that may be incurred in the integration of
Pinnacles business with our business.
While the merger is pending, we will be subject to business uncertainties and contractual
restrictions that could adversely affect their businesses.
Uncertainty about the effect of the merger on employees, customers and suppliers may have an
adverse effect on both us and Pinnacle and, consequently, on the combined company. These
uncertainties may impair our and Pinnacles ability to attract, retain and motivate key personnel
until the merger is consummated and for a period of time thereafter, and could cause customers,
suppliers and others who deal with us and Pinnacle to seek to change existing business
relationships with us and Pinnacle. Employee retention may be particularly challenging during the
pendency of the merger because employees may experience uncertainty about their future roles with
the combined company. If, despite our and Pinnacles retention efforts, key employees depart
because of issues relating to the uncertainty and difficulty of integration or a desire not to
remain with the combined company, the combined companys business could be seriously harmed. In
addition, the merger agreement restricts us and Pinnacle, without the other partys consent and
subject to certain exceptions, from making certain acquisitions and taking other specified actions
until the merger occurs or the merger agreement terminates. These restrictions may prevent us and
Pinnacle from pursuing otherwise attractive business opportunities and making other changes to our
businesses that may arise prior to completion of the merger or termination of the merger agreement.
Failure to complete the merger could negatively impact our stock price and future business and
financial results because of, among other things, the disruption that would occur as a result of
uncertainties relating to a failure to complete the merger.
Both our stockholders and those of Pinnacle may not approve the merger. If the merger is not
completed for any reason, we could be subject to several risks, including the following:
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being required to pay Pinnacle a termination fee of up to $3.0 million in certain
circumstances;
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having had the focus of our management directed toward the merger and integration
planning instead of on our core business and other opportunities that could have been
beneficial to us; and
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incurring substantial transaction costs related to the merger.
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In addition, we would not realize any of the expected benefits of having completed the merger.
If the merger is not completed, the price of our common stock may decline to the extent that
the current market price of our common stock reflects a market assumption that the merger will be
completed and that the related benefits and synergies will be realized, or as a result of the
markets perceptions that the merger were not consummated due to an adverse change in our business.
In addition, our business may be harmed, and the price of our stock may decline as a result, to
the extent that suppliers and others believe that we cannot compete in the marketplace as
effectively without the merger or otherwise remain uncertain about our future prospects in the
absence of the merger. Similarly, our current and prospective employees may experience uncertainty
about their future roles with the resulting company and choose to pursue other opportunities, which
could adversely affect us if the merger is not completed. The realization of any of these risks
may materially adversely affect our business, financial results, financial condition and stock
price.
The merger agreement limits our ability to pursue an alternative acquisition proposal and require
us to pay a termination fee of up to $3.0 million if we do.
-15-
The merger agreement prohibits us from soliciting, initiating or encouraging alternative
merger or acquisition proposals with any third party. The merger agreement also provides for the
payment by us of a termination fee of up to $3.0 million if the merger agreement is terminated in
certain circumstances in connection with a competing acquisition proposal or the withdrawal by our
board of directors of its recommendation that our stockholders vote for the adoption of the merger
agreement.
These provisions limit our ability to pursue offers from third parties that could result in
greater value to our stockholders. The obligation to make the termination fee payment also may
discourage a third party from pursuing an alternative acquisition proposal.
The price of Quests common stock may experience volatility.
Following the consummation of the merger, the price of our common stock may be volatile. Some
of the factors that could affect the price of our common stock are quarterly increases or decreases
in revenue or earnings, changes in revenue or earnings estimates by the investment community, our
ability to implement our integration strategy and to realize the expected synergies and other
benefits from the merger and speculation in the press or investment community about our financial
condition or results of operations. General market conditions and U.S. or international economic
factors and political events unrelated to our performance may also affect our stock price. For
these reasons, investors should not rely on recent trends in the price of our common stock to
predict the future price of our common stock or our financial results.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None
Item 3. Default Upon Senior Securities
None
Item 4. Submission of Matters to Vote of Security Holders
None.
Item 5. Other Information
None.
Item 6. Exhibits
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2.1*
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Agreement and Plan of Merger, dated as of October 15, 2007, by and
among Quest Resource Corporation, Pinnacle Gas Resources, Inc., and
Quest Mergersub, Inc. (incorporated herein by reference to Exhibit
2.1 to the Companys Current Report on Form 8-K filed on October 16,
2007).
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2.2*
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Purchase and Sale Agreement, dated as of October 9, 2007, by and
among Enbridge Midcoast Energy, L.P., Midcoast Holdings No. One,
L.L.C., and Quest Midstream Partners, L.P. (incorporated herein by
reference to Exhibit 2.1 to the Companys Current Report on Form 8-K
filed on November 2, 2007).
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3.1*
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Second Amended and Restated Bylaws of Quest Resource Corporation
(incorporated herein by reference to Exhibit 3.1 to the Companys
Current Report on Form 8-K filed on October 18, 2005).
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3.2*
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First Amendment to the Second Amended and Restated Bylaws of Quest
Resource Corporation (incorporated herein by reference to Exhibit
3.1(b) to the Companys Current Report on Form 8-K filed on October
17, 2007).
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10.1*
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Amendment No. 1 to the Midstream Services and Gas Dedication
Agreement, dated as of August 9, 2007, by and between Quest Resource
Corporation and Bluestem Pipeline, LLC (incorporated herein by
reference to Exhibit 10.1 to the Companys Current Report on Form
8-K filed on August 13, 2007).
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-16-
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10.2*
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Employment Agreement dated September 19, 2007 between Quest
Midstream GP, LLC and Richard E. Muncrief (incorporated herein by
reference to Exhibit 10.1 to the Companys Current Report on Form
8-K filed on September 25, 2007).
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10.3*
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Support Agreement, dated as of October 15, 2007, by and between
Quest Resource Corporation and certain stockholders of Pinnacle Gas
Resources, Inc. (incorporated herein by reference to Exhibit 10.1 to
the Companys Current Report on Form 8-K filed on October 16, 2007).
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10.4*
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Purchase Agreement, dated as of October 16, 2007, by and among Quest
Midstream Partners, L.P., Quest Midstream GP, LLC, Quest Resource
Corporation, Alerian Opportunity Partners IX, L.P., Bel Air MLP
Energy Infrastructure Fund, LP, Tortoise Capital Resources
Corporation, Tortoise Gas and Oil Corporation, Dalea Partners, LP,
Hartz Capital MLP, LLC, ZLP Fund, L.P., KED MME Investment Partners,
LP, Eagle Income Appreciation Partners, L.P., Eagle Income
Appreciation II, L.P., Citigroup Financial Products, Inc., and The
Northwestern Mutual Life Insurance Company (incorporated herein by
reference to Exhibit 10.1 to the Companys Current Report on Form
8-K filed on November 2, 2007).
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10.5*
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Amended and Restated Investors Rights Agreement, dated as of
November 1, 2007, by and among Quest Midstream Partners, L.P., Quest
Midstream GP, LLC, Quest Resource Corporation, Alerian Opportunity
Partners IV, L.P., Swank MLP Convergence Fund, LP, Swank Investment
Partners, LP, The Cushing MLP Opportunity Fund I, LP, The Cushing GP
Strategies Fund, LP, Tortoise Capital Resources Corporation, Alerian
Opportunity Partners IX, L.P., Bel Air MLP Energy Infrastructure
Fund, LP, Tortoise Gas and Oil Corporation, Dalea Partners, LP,
Hartz Capital MLP, LLC, ZLP Fund, L.P., KED MME Investment Partners,
LP, Eagle Income Appreciation Partners, L.P., Eagle Income
Appreciation II, L.P., Citigroup Financial Products, Inc., and The
Northwestern Mutual Life Insurance Company (incorporated herein by
reference to Exhibit 10.2 to the Companys Current Report on Form
8-K filed on November 2, 2007).
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10.6*
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Second Amended and Restated Agreement of Limited Partnership of
Quest Midstream Partners, L.P., dated as of November 1, 2007, by and
among Quest Midstream GP, LLC, Quest Resource Corporation, Alerian
Opportunity Partners IV, L.P., Swank MLP Convergence Fund, LP, Swank
Investment Partners, LP, The Cushing MLP Opportunity Fund I, LP, The
Cushing GP Strategies Fund, LP, Tortoise Capital Resources
Corporation, Alerian Opportunity Partners IX, L.P., Bel Air MLP
Energy Infrastructure Fund, LP, Tortoise Gas and Oil Corporation,
Dalea Partners, LP, Hartz Capital MLP, LLC, ZLP Fund, L.P., KED MME
Investment Partners, LP, Eagle Income Appreciation Partners, L.P.,
Eagle Income Appreciation II, L.P., Citigroup Financial Products,
Inc., and The Northwestern Mutual Life Insurance Company
(incorporated herein by reference to Exhibit 10.3 to the Companys
Current Report on Form 8-K filed on November 2, 2007).
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10.7*
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First Amendment to Registration Rights Agreement, dated as of
November 1, 2007, by and among Quest Midstream Partners, L.P., Quest
Resource Corporation, Alerian Opportunity Partners IV, L.P., Swank
MLP Convergence Fund, LP, Swank Investment Partners, LP, The Cushing
MLP Opportunity Fund I, LP, The Cushing GP Strategies Fund, LP,
Tortoise Capital Resources Corporation, Alerian Opportunity Partners
IX, L.P., Bel Air MLP Energy Infrastructure Fund, LP, Tortoise Gas
and Oil Corporation, Dalea Partners, LP, Hartz Capital MLP, LLC, ZLP
Fund, L.P., KED MME Investment Partners, LP, Eagle Income
Appreciation Partners, L.P., Eagle Income Appreciation II, L.P.,
Citigroup Financial Products, Inc., and The Northwestern Mutual Life
Insurance Company (incorporated herein by reference to Exhibit 10.4
to the Companys Current Report on Form 8-K filed on November 2,
2007).
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10.8*
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Amended and Restated Credit Agreement, dated as of November 1, 2007,
by and among Quest Midstream Partners, L.P., Bluestem Pipeline, LLC,
Royal Bank of Canada, RBC Capital Markets and the Lenders party
thereto (incorporated herein by reference to Exhibit 10.5 to the
Companys Current Report on Form 8-K filed on November 2, 2007).
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10.9
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Guaranty by Quest Kansas General Partner, L.L.C., Quest Kansas
Pipeline, L.L.C., and Quest Pipeline (KPC) in favor of Royal Bank of
Canada, dated as of November 1, 2007.
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-17-
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10.10
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Pledge and Security Agreement by Quest Kansas General Partner,
L.L.C. in favor of Royal Bank of Canada, dated as of November 1,
2007.
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10.11
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Pledge and Security Agreement by Quest Kansas Pipeline, L.L.C. in
favor of Royal Bank of Canada, dated as of November 1, 2007.
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10.12
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Pledge and Security Agreement by Quest Pipelines (KPC) in favor of
Royal Bank of Canada, dated as of November 1, 2007.
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10.13
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Amended and Restated Pledge and Security Agreement by Bluestem
Pipeline, LLC in favor of Royal Bank of Canada, dated as of November
1, 2007.
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10.14
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Amended and Restated Pledge and Security Agreement by Quest
Midstream Partners, L.P. in favor of Royal Bank of Canada, dated as
of November 1, 2007.
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12.1
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Statement Re: Computation of Ratios of Earnings to Combined Fixed
Charges and Preferred Dividends.
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31.1
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Certification by Chief Executive Officer pursuant to Rule 13a-14(a)
or 15d-14(a) of the Securities Exchange Act of 1934, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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31.2
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Certification by Chief Financial Officer pursuant to Rule 13a-14(a)
or 15d-14(a) of the Securities Exchange Act of 1934, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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32.1
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Certification by Chief Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
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32.2
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Certification by Chief Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
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*
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Incorporated by reference
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-18-
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant caused
this report to be signed on its behalf by the undersigned, thereunto duly authorized this 8th day
of November, 2007.
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QUEST RESOURCE CORPORATION
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By:
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/s/ Jerry D. Cash
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Jerry D. Cash
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Chief Executive Officer
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By:
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/s/ David E. Grose
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David E. Grose
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Chief Financial Officer
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-19-
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