UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-Q
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(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
March 31, 2008.
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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 .
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Commission file
number: 0-17371
QUEST
RESOURCE CORPORATION
(Exact
name of registrant 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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210 Park Avenue, Suite 2750, Oklahoma City, OK 73102
(Address of principal executive
offices) (Zip Code)
405-600-7704
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, a non-accelerated filer
or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
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Large
accelerated
filer
o
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Accelerated
filer
þ
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Non-accelerated
filer
o
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Smaller
reporting
company
o
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(Do not check if a smaller
reporting company)
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 May 8, 2008, the issuer had 23,522,859 shares of
common stock outstanding.
QUEST
RESOURCE CORPORATION
FORM 10-Q
FOR THE QUARTER ENDED MARCH 31, 2008
TABLE OF CONTENTS
-2-
PART I
FINANCIAL INFORMATION
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Item 1.
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Financial
Statements
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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
Energy Partners, L.P.; Quest Energy GP, LLC; Quest Cherokee,
LLC; Quest Cherokee Oilfield Service, LLC; Quest Midstream
Partners, L.P.; Quest Midstream GP, LLC; Bluestem Pipeline, LLC;
Quest Transmission Company, LLC; Quest Kansas Pipeline, L.L.C;
Quest Kansas General Partner, L.L.C.; Quest Pipelines (KPC);
Quest Oil & Gas, LLC; and Quest Energy Service, LLC.
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 a
consolidated balance sheet as of March 31, 2008, a
consolidated statement of operations and comprehensive income, a
consolidated statement of cash flows for the three month period
ended March 31, 2008 and the comparable period of 2007, and
a consolidated statement of stockholders equity for the
three month period ended March 31, 2008, are attached
hereto as
Pages F-1
through
F-25
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 financial statements included herein should be read in
conjunction with the financial statements and notes thereto
included in the Companys annual report on
Form 10-K
for the year ended December 31, 2007, as amended (the
2007
Form 10-K).
-3-
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
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March 31,
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December 31,
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2008
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2007
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(Unaudited)
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($ in thousands)
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ASSETS
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Current assets:
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Cash
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$
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20,634
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$
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16,680
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Restricted cash
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1,236
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1,236
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Accounts receivable, trade
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17,131
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15,768
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Other receivables
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3,351
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1,632
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Other current assets
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4,599
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3,717
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Inventory
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10,609
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6,622
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Short-term derivative asset
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223
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6,729
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Total current assets
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57,783
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52,384
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Property and equipment, net of accumulated depreciation of
$7,768 and $6,917
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21,799
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21,394
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Pipeline assets, net of accumulated depreciation of $37,893 and
$34,736
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303,491
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296,039
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Pipeline assets under construction
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255
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1,240
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Oil and gas properties:
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Properties being amortized
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435,303
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406,665
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Properties not being amortized
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23,692
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22,020
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458,995
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428,685
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Less: Accumulated depreciation, depletion and amortization
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(137,444
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)
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(127,968
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)
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Net property, plant and equipment
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321,551
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300,717
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Other assets, net
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8,222
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8,268
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Long-term derivative asset
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599
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1,568
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Total assets
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$
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713,700
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$
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681,610
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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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27,534
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$
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27,911
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Revenue payable
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5,184
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6,806
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Accrued expenses
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9,952
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9,058
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Current portion of notes payable
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448
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666
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Short-term derivative liability
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28,745
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8,241
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Total current liabilities
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71,863
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52,682
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Non-current liabilities:
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Long-term derivative liability
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17,203
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5,586
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Asset retirement obligation
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3,998
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3,813
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Notes payable
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273,613
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233,712
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Less current maturities
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(448
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(666
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)
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Non-current liabilities
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294,366
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242,445
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Total liabilities
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366,229
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295,127
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Minority interests
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281,581
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294,630
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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 March 31, 2008 and December 31, 2007
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Common stock, $.001 par value, 200,000,000 shares
authorized, 23,766,743 shares issued and outstanding at
March 31, 2008 and 22,701,029 shares issued and
outstanding at December 31, 2007
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24
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23
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Additional paid-in capital
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214,262
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212,819
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Accumulated other comprehensive income
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(17,249
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)
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(1,485
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)
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Accumulated deficit
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(131,147
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)
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(119,504
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)
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Total stockholders equity
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65,890
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91,853
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Total liabilities and stockholders equity
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$
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713,700
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$
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681,610
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The accompanying notes are an integral part of these
consolidated statements.
F-1
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
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Three Months Ended March 31,
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2008
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2007
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(Unaudited)
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($ in thousands, except per share amounts)
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Revenue:
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Oil and gas sales
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$
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37,353
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$
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25,549
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Gas pipeline revenue
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6,901
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1,542
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Other revenue (expense)
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50
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(13
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)
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Total revenues
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44,304
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27,078
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Costs and expenses:
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Oil and gas production
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8,211
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7,227
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Pipeline operating
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7,249
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4,934
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General and administrative
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4,829
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2,638
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Depreciation, depletion and amortization
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12,800
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7,863
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Total costs and expenses
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33,089
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22,662
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Operating income (loss)
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11,215
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4,416
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Other income (expense):
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Change in derivative fair value
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(23,831
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)
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(464
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)
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Sale of assets
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30
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107
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Interest income
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17
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177
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Interest expense
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(5,124
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)
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(7,113
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)
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|
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Total other income (expense)
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(28,908
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)
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(7,293
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)
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Income (loss) before income taxes
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(17,693
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)
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(2,877
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)
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Income tax expense deferred
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|
|
|
|
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|
|
|
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Net income (loss) before minority interest
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(17,693
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)
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(2,877
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)
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Minority interests
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6,050
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(434
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)
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Net (loss)
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(11,643
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)
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|
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(3,311
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)
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Other comprehensive income (loss), net of tax:
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|
|
|
|
|
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Change in fixed-price contract and other derivative fair value,
net of tax of $0 and $0
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(15,764
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)
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(13,481
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)
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|
|
|
|
|
|
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Other comprehensive income (loss)
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(15,764
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)
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|
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(13,481
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)
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|
|
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|
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|
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Comprehensive income (loss)
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$
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(27,407
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)
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$
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(16,792
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)
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|
|
|
|
|
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Net income (loss)
|
|
$
|
(11,643
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)
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|
$
|
(3,311
|
)
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common shareholders
|
|
$
|
(11,643
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)
|
|
$
|
(3,311
|
)
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share basic
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|
$
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(0.50
|
)
|
|
$
|
(0.15
|
)
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share diluted
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|
$
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(0.50
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)
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$
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(0.15
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)
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|
|
|
|
|
|
|
|
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Weighted average common and common equivalent shares:
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|
|
|
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Basic
|
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23,295,476
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22,206,014
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Diluted
|
|
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23,295,476
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22,206,014
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The accompanying notes are an integral part of these
consolidated statements.
F-2
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
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Three Months Ended March 31,
|
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2008
|
|
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2007
|
|
|
|
|
|
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(Unaudited)
|
|
|
|
|
|
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($ in thousands)
|
|
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|
|
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Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
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|
Net income (loss)
|
|
$
|
(11,643
|
)
|
|
$
|
(3,311
|
)
|
|
|
|
|
Adjustments to reconcile net income (loss) to cash provided by
operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and depletion
|
|
|
13,575
|
|
|
|
8,528
|
|
|
|
|
|
Change in derivative fair value
|
|
|
23,831
|
|
|
|
464
|
|
|
|
|
|
Stock options granted for directors fees
|
|
|
344
|
|
|
|
162
|
|
|
|
|
|
Stock awards granted to employees
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|
|
1,217
|
|
|
|
326
|
|
|
|
|
|
Amortization of loan origination fees
|
|
|
424
|
|
|
|
479
|
|
|
|
|
|
Amortization of gas swap fees
|
|
|
|
|
|
|
62
|
|
|
|
|
|
(Gain) loss on sale of assets
|
|
|
(57
|
)
|
|
|
(65
|
)
|
|
|
|
|
Minority interest
|
|
|
(6,050
|
)
|
|
|
434
|
|
|
|
|
|
Change in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(3,082
|
)
|
|
|
(3,103
|
)
|
|
|
|
|
Other current assets
|
|
|
(882
|
)
|
|
|
(951
|
)
|
|
|
|
|
Inventory
|
|
|
(3,987
|
)
|
|
|
624
|
|
|
|
|
|
Accounts payable
|
|
|
(31
|
)
|
|
|
5,163
|
|
|
|
|
|
Revenue payable
|
|
|
(1,563
|
)
|
|
|
1,900
|
|
|
|
|
|
Accrued expenses
|
|
|
(2,786
|
)
|
|
|
(329
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
9,310
|
|
|
|
10,383
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Equipment, development and leasehold costs
|
|
|
(29,046
|
)
|
|
|
(28,472
|
)
|
|
|
|
|
Oil and gas property acquisition
|
|
|
(9,500
|
)
|
|
|
|
|
|
|
|
|
Net additions to other property and equipment
|
|
|
(1,190
|
)
|
|
|
(3,941
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(39,736
|
)
|
|
|
(32,413
|
)
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from bank borrowings
|
|
|
40,000
|
|
|
|
10,000
|
|
|
|
|
|
Repayments of note borrowings
|
|
|
(224
|
)
|
|
|
(222
|
)
|
|
|
|
|
Syndication costs paid
|
|
|
(236
|
)
|
|
|
(11
|
)
|
|
|
|
|
Refinancing costs RBC
|
|
|
(377
|
)
|
|
|
|
|
|
|
|
|
Distributions to unitholders
|
|
|
(4,993
|
)
|
|
|
|
|
|
|
|
|
Change in other long-term liabilities
|
|
|
210
|
|
|
|
40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
34,380
|
|
|
|
9,807
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash
|
|
|
3,954
|
|
|
|
(12,223
|
)
|
|
|
|
|
Cash, beginning of period
|
|
|
16,680
|
|
|
|
41,789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of period
|
|
$
|
20,634
|
|
|
$
|
29,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flow information
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the period for:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
$
|
4,756
|
|
|
$
|
5,845
|
|
|
|
|
|
Income taxes
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated statements.
F-3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
|
|
|
Stock
|
|
|
Additional
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Preferred
|
|
|
Common
|
|
|
Stock
|
|
|
Par
|
|
|
Paid-in
|
|
|
Comprehensive
|
|
|
Accumulated
|
|
|
|
|
|
|
Shares
|
|
|
Shares
|
|
|
Par Value
|
|
|
Value
|
|
|
Capital
|
|
|
Income (Loss)
|
|
|
Deficit
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
($ in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007
|
|
|
|
|
|
|
22,701,029
|
|
|
$
|
|
|
|
$
|
23
|
|
|
$
|
212,819
|
|
|
$
|
(1,485
|
)
|
|
$
|
(119,504
|
)
|
|
$
|
91,853
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11,643
|
)
|
|
|
(11,643
|
)
|
Net loss Other comprehensive loss, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fixed-price contract and other derivative fair value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(15,764
|
)
|
|
|
|
|
|
|
(15,764
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(27,407
|
)
|
Stock awards granted to employees
|
|
|
|
|
|
|
1,065,714
|
|
|
|
|
|
|
|
1
|
|
|
|
1,347
|
|
|
|
|
|
|
|
|
|
|
|
1,348
|
|
Stock options granted to directors
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
96
|
|
|
|
|
|
|
|
|
|
|
|
96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, March 31, 2008
|
|
|
|
|
|
|
23,766,743
|
|
|
$
|
|
|
|
$
|
24
|
|
|
$
|
214,262
|
|
|
$
|
(17,249
|
)
|
|
$
|
(131,147
|
)
|
|
$
|
65,890
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated statements.
F-4
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
MARCH 31, 2008
(UNAUDITED)
Nature
of Business
Quest Resource Corporation (the Company) is a Nevada
corporation formed in July 1982. Unless the context requires
otherwise, references to we, us,
our or the Company are intended to mean
Quest Resource Corporation and its consolidated subsidiaries.
We are an independent energy company with an emphasis on the
acquisition, production, transportation, exploration, and
development of natural gas (coal bed methane) in the Cherokee
Basin of southeastern Kansas and northeastern Oklahoma. Our
operations are currently focused on developing coal bed methane
gas production through Quest Energy Partners, L.P. (Quest
Energy) in a fifteen county region that is served by a
pipeline network owned through Quest Midstream Partners, L.P.
(Quest Midstream). Quest Midstream also owns a
1,120-mile interstate natural gas transmission pipeline that
runs from Oklahoma to Missouri (the KPC Pipeline).
In addition, through Quest Oil & Gas, LLC, we have
begun developing acreage located in Pennsylvania that is
prospective for the Marcellus Shale.
We conduct our business through two reportable business
segments. These segments and the activities performed to provide
services to our customers and create value for our stockholders
are as follows:
|
|
|
|
|
Quest Energy gas and oil production focused on coal
bed methane in the Cherokee Basin; and
|
|
|
|
Quest Midstream transporting, selling, gathering,
treating and processing natural gas.
|
Consolidation Policy
. Investee
companies in which the Company directly or indirectly owns more
than 50% of the outstanding voting securities or those in which
the Company has effective control over are generally accounted
for under the consolidation method of accounting. Under this
method, an Investee companys balance sheet and results of
operations are reflected within the Companys consolidated
financial statements. All significant intercompany accounts and
transactions have been eliminated. Minority interests in the net
assets and earnings or losses of a consolidated investee are
reflected in the caption Minority interest in the
Companys consolidated balance sheet and statement of
operations. Minority interest adjusts the Companys
consolidated results of operations to reflect only the
Companys share of the earnings or losses of the
consolidated investee company. Upon dilution of control below
50% and the loss of effective control, the accounting method is
adjusted to the equity or cost method of accounting, as
appropriate, for subsequent periods.
Financial reporting by the Companys subsidiaries is
consolidated into one set of financial statements with the
Company.
|
|
2.
|
Summary
of Significant Accounting Policies
|
Reference is hereby made to the Companys Annual Report on
Form 10-K,
as amended, for the year ended December 31, 2007 (the
2007
Form 10-K),
which contains a summary of significant accounting policies
followed by the Company in the preparation of its consolidated
financial statements. These policies were also followed in
preparing the consolidated financial statements as of
March 31, 2008 and for the three months ended
March 31, 2008 and 2007.
Use of
Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires us to make
estimates and assumptions that affect the amounts reported in
the consolidated financial statements and accompanying notes.
Actual results could differ from those estimates.
F-5
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Estimates made in preparing the consolidated financial
statements include, among other things, estimates of the proved
gas and oil reserve volumes used in calculating depletion,
depreciation and amortization expense; the estimated future cash
flows and fair value of properties used in determining the need
for any impairment write-down; and the timing and amount of
future abandonment costs used in calculating asset retirement
obligations. Future changes in the assumptions used could have a
significant impact on reported results in future periods.
Basis
of Accounting
The Companys financial statements are prepared using the
accrual method of accounting. Revenues are recognized when
earned and expenses when incurred.
Revenue
Recognition
Revenue from the sale of oil and natural gas is recognized when
title passes, net of royalties.
Cash
Equivalents
For purposes of the consolidated financial statements, the
Company considers investments in all highly liquid instruments
with original maturities of three months or less at date of
purchase to be cash equivalents.
Uninsured
Cash Balances
The Company maintains its cash balances at several financial
institutions. Accounts at the institutions are insured by the
Federal Deposit Insurance Corporation up to $100,000. The
Companys cash balances typically are in excess of this
amount.
Restricted
Cash
Restricted Cash represents cash pledged to support reimbursement
obligations under outstanding letters of credit.
Accounts
Receivable
The Company conducts the majority of its operations in the
States of Kansas and Oklahoma and operates exclusively in the
natural gas and oil industry. The Companys receivables are
generally unsecured; however, the Company has not experienced
any significant losses to date. Receivables are recorded at the
estimate of amounts due based upon the terms of the related
agreements.
Management periodically assesses the Companys accounts
receivable and establishes an allowance for estimated
uncollectible amounts. Accounts determined to be uncollectible
are charged to operations when that determination is made.
Inventory
Inventory, which is included in current assets, includes tubular
goods and other lease and well equipment which we plan to
utilize in our ongoing exploration and development activities
and is carried at the lower of cost or market using the specific
identification method.
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 Energy
F-6
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Marketing and Trading Company) accounted for more than 99% of
total natural gas and oil revenues for the three months ended
March 31, 2008. Natural gas sales to two purchasers (ONEOK
and Tenaska Marketing Ventures) accounted for 73% and 27% of
total natural gas revenues for the three months ended
March 31, 2007.
KPC Pipelines two primary customers are Kansas Gas Service
(KGS) and Missouri Gas Energy (MGE), both of which are served
under long-term natural gas transportation contracts
representing 59% and 36% of the gas transported, respectively
for the three months ended March 31, 2008.
The industry concentration has the potential to impact the
Companys overall exposure to credit risk, either
positively or negatively, in that the Companys customers
may be similarly affected by changes in economic, industry or
other conditions.
Natural
Gas and Oil Properties
The Company follows the full cost method of accounting for
natural gas and oil properties, prescribed by the Securities and
Exchange Commission (SEC). Under the full cost
method, all acquisition, exploration, and development costs are
capitalized. The Company capitalizes internal costs including:
salaries and related fringe benefits of employees directly
engaged in the acquisition, exploration and development of
natural gas and oil properties, as well as other directly
identifiable general and administrative costs associated with
such activities.
All capitalized costs of natural gas and oil properties,
including the estimated future costs to develop proved reserves,
are amortized on the
units-of-production
method using estimates of proved reserves. The costs of unproved
properties are excluded from amortization until the properties
are evaluated. The Company reviews all of its unevaluated
properties quarterly to determine whether or not and to what
extent proved reserves have been assigned to the properties and
otherwise if impairment has occurred. Unevaluated properties are
assessed individually when individual costs are significant.
The Company reviews the carrying value of its oil and natural
gas properties under the full-cost accounting rules of the
Securities and Exchange Commission on a quarterly basis. This
quarterly review is referred to as a ceiling test. Under the
ceiling test, capitalized costs, less accumulated amortization
and related deferred income taxes, may not exceed an amount
equal to the sum of the present value of estimated future net
revenues (adjusted for cash flow hedges) less estimated future
expenditures to be incurred in developing and producing the
proved reserves, plus the cost of properties not being
amortized, less any related income tax effects. In calculating
future net revenues, current prices and costs used are those as
of the end of the appropriate quarterly period. Such prices are
utilized except where different prices are fixed and
determinable from applicable contracts for the remaining term of
those contracts, including the effects of derivatives qualifying
as cash flow hedges. Two primary factors impacting this test are
reserve levels and current prices, and their associated impact
on the present value of estimated future net revenues. Revisions
to estimates of natural gas and oil reserves
and/or
an
increase or decrease in prices can have a material impact on the
present value of estimated future net revenues. Any excess of
the net book value, less deferred income taxes, is generally
written off as an expense. Under SEC regulations, the excess
above the ceiling is not expensed (or is reduced) if, subsequent
to the end of the period, but prior to the release of the
financial statements, oil and natural gas prices increase
sufficiently such that an excess above the ceiling would have
been eliminated (or reduced) if the increased prices were used
in the calculations.
Based on the low natural gas prices on December 31, 2007,
the Company would have incurred a non-cash impairment loss of
approximately $14.9 million for the quarter ended
December 31, 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 March 1, 2008,
natural gas prices had improved sufficiently to eliminate the
need for an impairment loss at December 31, 2007 and as a
result, no impairment loss is reflected in the Companys
financial statements for the year ended December 31, 2007.
F-7
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Sales of proved and unproved properties are accounted for as
adjustments of capitalized costs with no gain or loss
recognized, unless such adjustments would significantly alter
the relationship between the capitalized costs and proved
reserves of natural gas and oil, in which case the gain or loss
is recognized in income.
Other
Property and Equipment
Other property and equipment is reviewed on an annual basis for
impairment and as of December 31, 2007, the Company had not
identified any such impairment. Repairs and maintenance are
charged to operations when incurred and improvements and
renewals are capitalized.
Other property and equipment are stated at cost. Depreciation is
calculated using the straight-line method for financial
reporting purposes and accelerated methods for income tax
purposes.
The estimated useful lives are as follows:
|
|
|
Pipeline
|
|
15 to 40 years
|
Buildings
|
|
25 years
|
Equipment
|
|
10 years
|
Vehicles
|
|
7 years
|
Debt
Issue Costs
Included in other assets are costs associated with bank credit
facilities. The remaining unamortized debt issue costs at
March 31, 2008 and 2007 totaled $8.0 million and
$9.7 million, respectively, and are being amortized over
the life of the credit facilities.
Other
Dispositions
Upon disposition or retirement of property and equipment other
than natural gas and oil properties, the cost and related
accumulated depreciation are removed from the accounts and the
gain or loss thereon, if any, is credited or charged to income.
Marketable
Securities
In accordance with Statement of Financial Accounting Standards
(SFAS) 115,
Accounting for Certain
Investments in Debt and Equity Securities
, the Company
classifies its investment portfolio according to the provisions
of SFAS 115 as either held to maturity, trading, or
available for sale. At March 31, 2008 and 2007, the Company
did not have any investments in its investment portfolio
classified as available for sale and held to maturity.
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. The provision for income taxes differ from the
amounts currently payable because of temporary differences
(primarily intangible drilling costs and the net operating loss
carry forward) in the recognition of certain income and expense
items for financial reporting and tax reporting purposes.
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
F-8
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 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.
Earnings
Per Common Share
SFAS 128,
Earnings Per Share
, requires presentation
of basic and diluted earnings per share
on the face of the statements of operations for all entities
with complex capital structures. Basic earnings per share is
computed by dividing net income by the weighted average number
of common shares outstanding for the period. Diluted earnings
per share reflects the potential dilution that could occur if
securities or other contracts to issue common stock were
exercised or converted during the period. Dilutive securities
having an anti-dilutive effect on diluted earnings per share are
excluded from the calculation. See Note 7
Earnings Per Share, for a reconciliation of the numerator and
denominator of the basic and diluted earnings per share
computations.
Fair
Value of Financial Instruments
The Companys financial instruments consist of cash,
receivables, deposits, hedging contracts, accounts payable,
accrued expenses and notes payable. The carrying amount of cash,
receivables, deposits, accounts payable and accrued expenses
approximates fair value because of the short-term nature of
those instruments. The hedging contracts are recorded in
accordance with the provisions of SFAS 133,
Accounting
for Derivative Instruments and Hedging Activities.
The
carrying amounts for notes payable approximate fair value due to
the variable nature of the interest rates of the notes payable.
Stock-Based
Compensation
Stock Options
. Effective
January 1, 2006, the Company adopted SFAS 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 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 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
F-9
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 123R was
immaterial.
On March 5, 2008, the Companys board of directors
approved the cancellation of each of the independent
directors unvested stock options. Replacement bonus shares
were awarded such that for every two shares subject to the
original options, the director would be entitled to receive one
bonus share. The bonus shares will become vested on the dates
respective to the dates the original stock options would have
become exercisable.
Partnership Unit Awards
.
Quest
Energy GP, LLC, the general partner of Quest Energy, granted
bonus units to certain members of its Board of Directors during
the three months ended March 31, 2008. The units are
subject to vesting with 25% of the units immediately vested and
one-third of the remaining units vesting equally on each of the
first three anniversaries of the date of the grant. The fair
value of the unit awards granted is recognized over the
applicable vesting period as compensation expense. Compensation
expense amounts are recognized in general and administrative
expenses or capitalized to oil and gas properties. For the three
months ended March 31, 2008, Quest Energy 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 months ended
March 31, 2008 was $203,000.
Quest Midstream GP, LLC, the general partner of Quest Midstream,
granted bonus units to certain employees and certain members of
its Board of Directors during the year ended December 31,
2007. The units are subject to a three-year vesting schedule.
The fair value of the unit awards granted is recognized over the
applicable vesting period 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 months ended March 31, 2008, Quest
Midstream 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
months ended March 31, 2008 was $472,000.
Stock Awards
. The Company granted
shares of common stock to certain employees in February 2008 and
February, March, April, September and December 2007. The shares
are subject to three-year and four-year vesting schedules. In
March 2008, the Company granted bonus units to its
independent directors in exchange for the cancellation of their
unvested stock options. See −Stock Options
above. The fair value of the stock awards granted is recognized
over the applicable vesting period 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 1,065,714 shares issued during the three months ended
March 31, 2008 includes 22,634 shares issued for
previously granted bonus shares and the issuance of
1,043,080 shares of restricted stock that had been
previously granted but not yet issued.
Accounting
for Derivative Instruments and Hedging Activities
The Company seeks to reduce its exposure to unfavorable changes
in natural gas and oil prices by utilizing energy swaps and
collars (collectively, fixed-price contracts). The
Company also enters into interest rate swaps and caps to reduce
its exposure to adverse interest rate fluctuations. The Company
has adopted SFAS 133, as amended by SFAS 138,
Accounting for Derivative Instruments and Hedging
Activities
, which contains accounting and reporting
guidelines for derivative instruments and hedging activities. It
requires that all derivative instruments be recognized as assets
or liabilities in the statement of financial position, measured
at fair value. The accounting for changes in the fair value of a
derivative depends on the intended use of the derivative and the
resulting designation. Designation is established at the
inception of a derivative, but re-designation is permitted. For
derivatives designated as cash flow hedges and meeting the
effectiveness guidelines of SFAS 133, changes in fair value
are recognized in other comprehensive income until the hedged
item is recognized in earnings. Hedge effectiveness
F-10
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
is measured at least quarterly based on the relative changes in
fair value between the derivative contract and the hedged item
over time. Any change in fair value resulting from
ineffectiveness is recognized immediately in earnings.
Pursuant to the provisions of SFAS 133, all hedging
designations and the methodology for determining hedge
ineffectiveness must be documented at the inception of the
hedge, and, upon the initial adoption of the standard, hedging
relationships must be designated anew. Based on the
interpretation of these guidelines by the Company, the changes
in fair value of all of its derivatives entered into during the
period from June 1, 2003 to December 22, 2003 are
required to be reported in results of operations, rather than in
other comprehensive income. Also, all changes in fair value of
the Companys interest rate swaps and caps were reported in
results of operations rather than in other comprehensive income
because the critical terms of the interest rate swaps and caps
did not comply with certain requirements set forth in
SFAS 133.
Although the Companys fixed-price contracts may not
qualify for special hedge accounting treatment from time to time
under the specific guidelines of SFAS 133, the Company has
continued to refer to these contracts in this document as hedges
inasmuch as this was the intent when such contracts were
executed, the characterization is consistent with the actual
economic performance of the contracts, and the Company expects
the contracts to continue to mitigate its commodity price and
interest rate risks in the future. The specific accounting for
these contracts, however, is consistent with the requirements of
SFAS 133. See Note 6 Financial Instruments
and Hedging Activities.
The Company has established the fair value of all derivative
instruments using estimates determined by its counterparties 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.
Asset
Retirement Obligations
The Company has adopted SFAS 143,
Accounting for Asset
Retirement Obligations.
SFAS 143 requires companies to
record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related
long-lived asset. Over time, the liability is accreted to its
present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. Upon
settlement of the liability, an entity either settles the
obligation for its recorded amount or incurs a gain or loss upon
settlement.
The Companys asset retirement obligations relate to the
plugging and abandonment of natural gas and oil properties and
its interstate pipeline assets. The Company is unable to predict
if and when its intrastate pipelines would become completely
obsolete and require decommissioning. Accordingly, the Company
has recorded no liability or corresponding asset for the
intrastate pipelines in conjunction with the adoption of
SFAS 143 because the future dismantlement and removal dates
of the Companys assets and the amount of any associated
costs are indeterminable.
Reclassification
Certain reclassifications have been made to the prior
years financial statements in order to conform to the
current presentation. These reclassifications had no effect on
previously reported results of operations or stockholders
equity.
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-11
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
On February 6, 2008, the FASB issued Financial Staff
Position
FAS 157-2,
Effective Date of FASB Statement No. 157. This
Staff Position delays the effective date of SFAS 157 for
all nonfinancial assets and nonfinancial liabilities, except
those that are recognized or disclosed at fair value in the
financial statements on a recurring basis (at least annually).
The delay is intended to allow the FASB and constituents
additional time to consider the effect of various implementation
issues that have arisen, or that may arise, from the application
of SFAS 157.
The remainder of SFAS 157 was adopted by us effective for
fiscal years beginning after November 15, 2007. The
adoption of SFAS 157 did not have an impact on the
Companys financial position, results of operations, or
cash flows.
In February 2007, the FASB issued SFAS 159,
The
Fair Value Option for Financial Assets and Financial
Liabilities
, an amendment of FASB SFAS 115.
SFAS 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 159 is effective for fiscal years beginning after
November 15, 2007, with earlier adoption permitted.
SFAS 159 had been adopted and did not have a material
impact on the Companys financial position, results of
operations, or cash flows.
In December 2007, the FASB issued SFAS 141R (revised 2007),
Business Combinations.
Although this
statement amends and replaces SFAS 141, it retains the
fundamental requirements in SFAS 141 that (i) the
purchase method of accounting be used for all business
combinations; and (ii) an acquirer be identified for each
business combination. SFAS 141R defines the acquirer as the
entity that obtains control of one or more businesses in the
business combination and establishes the acquisition date as the
date that the acquirer achieves control. This Statement applies
to all transactions or other events in which an entity (the
acquirer) obtains control of one or more businesses (the
acquiree), including combinations achieved without the transfer
of consideration; however, this Statement does not apply to a
combination between entities or businesses under common control.
Significant provisions of SFAS 141R concern principles and
requirements for how an acquirer (i) recognizes and
measures in its financial statements the identifiable assets
acquired, the liabilities assumed, and any noncontrolling
interest in the acquiree; (ii) recognizes and measures the
goodwill acquired in the business combination or a gain from a
bargain purchase; and (iii) determines what information to
disclose to enable users of the financial statements to evaluate
the nature and financial effects of the business combination.
This Statement applies prospectively to business combinations
for which the acquisition date is on or after the beginning of
the first annual reporting period beginning on or after
December 15, 2008 with early adoption not permitted.
Management is assessing the impact of the adoption of
SFAS 141R.
In December 2007, the FASB issued SFAS 160,
Noncontrolling Interests in Consolidated Financial
Statements, an amendment of ARB No. 51
. The
objective of this statement is to improve the relevant,
comparability, and transparency of the financial information
that a reporting entity provides in its consolidated financial
statements related to noncontrolling or minority interests. The
effective date for this Statement is for fiscal years, and
interim periods within those fiscal years, beginning on or after
December 15, 2008 with earlier adoption being prohibited.
Adoption of this Statement will change the method in which
minority interests are reflected on the Companys
consolidated financial statements and will add some additional
disclosures related to the reporting of minority interests.
Management is assessing the impact of the adoption of
SFAS 160.
In March 2008, the FASB issued SFAS 161,
Disclosures about Derivative Instruments and Hedging
Activities
. The objective of this statement is to
improve financial reporting about derivative instruments and
hedging activities by requiring enhanced disclosures to enable
investors to better understand their effects on an entitys
financial position, financial performance, and cash flows. The
effective date for this statement is for financial statements
issued for fiscal years and interim periods beginning after
November 15, 2008, with early application encouraged.
Management is assessing the impact of the adoption of
SFAS 161.
F-12
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
KPC
Pipeline
On November 1, 2007, Quest Midstream completed the purchase
of the KPC Pipeline pursuant to a Purchase and Sale Agreement
(the Purchase Agreement), dated as of
October 9, 2007, by and among Quest Midstream, Enbridge
Midcoast Energy, L.P. and Midcoast Holdings No. One,
L.L.C., whereby Quest Midstream purchased all of the membership
interests in the two general partners of Enbridge Pipelines
(KPC), the owner of the KPC Pipeline for a purchase price of
approximately $133 million in cash, subject to adjustment
for working capital at closing.
In accordance with the terms of the Purchase Agreement, the
purchase price, current assets and certain assumed liabilities
were allocated as follows (dollars in thousands):
|
|
|
|
|
Pipeline assets
|
|
$
|
135,069
|
|
Asset retirement obligation assumed
|
|
|
(2,069
|
)
|
|
|
|
|
|
Purchase price
|
|
$
|
133,000
|
|
|
|
|
|
|
Pro Forma
Summary Data (unaudited)
The following pro forma summary data for the three months ending
March 31, 2007 presents the consolidated results of
operations as if the KPC Pipeline acquisition made on
November 1, 2007 had occurred on January 1, 2007.
These pro forma results have been prepared for comparative
purposes only and do not purport to be indicative of what would
have occurred had the acquisitions been made at January 1,
2007 or of results that may occur in the future.
|
|
|
|
|
|
|
For the Three Months
|
|
|
|
Ended March 31, 2007
|
|
|
Pro forma revenue
|
|
$
|
32,064,000
|
|
Pro forma net (loss)
|
|
$
|
(2,263,000
|
)
|
Pro forma net (loss) per share
|
|
$
|
(0.10
|
)
|
Searight
Quest Energy purchased certain oil producing properties in
Seminole County, Oklahoma from a private company for
$9.5 million in a transaction that closed in early February
2008. The properties have estimated proved reserves of
712,000 barrels, all of which are proved developed
producing. In addition, Quest Energy entered into crude oil
swaps for approximately 80% of the estimated production from the
propertys proved developed producing reserves at WTI-NYMEX
prices per barrel of oil of approximately $96.00 in 2008, $90.00
in 2009, and $87.50 for 2010. The acquisition was financed with
borrowings under Quest Energys credit facility.
|
|
4.
|
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 months
ended March 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Dollars in thousand)
|
|
|
Asset retirement obligation beginning balance
|
|
$
|
3,813
|
|
|
$
|
1,410
|
|
Liabilities incurred
|
|
|
86
|
|
|
|
42
|
|
Liabilities settled
|
|
|
(1
|
)
|
|
|
(1
|
)
|
F-13
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Dollars in thousand)
|
|
|
Accretion expense
|
|
|
100
|
|
|
|
26
|
|
Revisions in estimated cash flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation ending balance
|
|
$
|
3,998
|
|
|
$
|
1,477
|
|
|
|
|
|
|
|
|
|
|
Long-term debt consists of the following:
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Dollars in thousands)
|
|
|
Senior credit facilities
|
|
$
|
273,000
|
|
|
$
|
233,000
|
|
Notes payable to banks and finance companies, secured by
equipment and vehicles, due in installments through October 2013
with interest ranging from 5.5% to 11.5% per annum
|
|
|
613
|
|
|
|
712
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
273,613
|
|
|
|
233,712
|
|
Less current maturities
|
|
|
448
|
|
|
|
666
|
|
|
|
|
|
|
|
|
|
|
Total long term debt, net of current maturities
|
|
$
|
273,165
|
|
|
$
|
233,046
|
|
|
|
|
|
|
|
|
|
|
The aggregate scheduled maturities of notes payable and
long-term debt for the period ending December 31, 2013 and
thereafter were as follows as of March 31, 2008 (assuming
no payments were made on the revolving credit facilities prior
to their maturity) (dollars in thousands):
|
|
|
|
|
2008
|
|
$
|
448
|
|
2009
|
|
|
15
|
|
2010
|
|
|
123,006
|
|
2011
|
|
|
6
|
|
2012
|
|
|
150,132
|
|
2013
|
|
|
5
|
|
Thereafter
|
|
|
1
|
|
|
|
|
|
|
|
|
$
|
273,613
|
|
|
|
|
|
|
Credit
Facilities
The Company and its subsidiaries are parties to three credit
facilities. See Note 3 to the consolidated financial
statements included in the 2007
Form 10-K
for descriptions of the material terms of the credit facilities.
Quest Energy Partners, L.P. and Quest Cherokee,
LLC.
Quest Cherokee, LLC is a party to an Amended
and Restated Credit Agreement dated as of November 15, 2007
with Royal Bank of Canada, as administrative agent and
collateral agent (RBC), KeyBank National
Association, as documentation agent, and the lenders party
thereto. Quest Energy is a guarantor of the credit agreement. As
of March 31, 2008, the borrowing base under this credit
agreement was $160 million and the amount borrowed under
the credit agreement was $123 million. The weighted average
interest rate under this credit agreement for the three months
ended March 31, 2008 was 6.88%. See
Note 11 Subsequent Events for a description of
amendments to this credit agreement.
F-14
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Quest Resource Corporation.
The Company is a
party to a Credit Agreement dated as of November 15, 2007
with RBC, as administrative agent and collateral agent, and the
lenders party thereto. As of March 31, 2008, the borrowing
base under this credit agreement was $50 million and the
amount borrowed under the credit agreement was $44 million.
The weighted average interest rate under this credit agreement
for the three months ended March 31, 2008 was 8.25%.
Quest Midstream Partners, L.P. and Bluestem Pipeline,
LLC.
Quest Midstream and Bluestem are parties to
an Amended and Restated Credit Agreement dated as of
November 1, 2007 with RBC, as administrative agent and
collateral agent, and the lenders party thereto. As of
March 31, 2008, the amount borrowed under the credit
agreement was $106 million and the total amount available
was $135 million. The weighted average interest rate under
this credit agreement for the three months ended March 31,
2008 was 7.23%.
Other
Long-Term Indebtedness
$613,000 of notes payable to banks and finance companies
were outstanding at March 31, 2008 and are secured by
equipment and vehicles, with payments due in monthly
installments through October 2013 with interest ranging from
5.5% to 11.5% per annum.
|
|
6.
|
Financial
Instruments and Hedging Activities
|
Natural
Gas and Oil Hedging Activities
The Company seeks to reduce its exposure to unfavorable changes
in natural gas and oil 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 and collars. These contracts allow the Company to predict
with greater certainty the effective natural gas and oil 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 three months ended March 31, 2008 and
2007, fixed-price contracts hedged approximately 59.05% and
71.6%, respectively, of the Companys natural gas
production. As of March 31, 2008, fixed-price contracts are
in place to hedge 38.2 Bcf of estimated future natural gas
production. Of this total volume, 9.0 Bcf are hedged for
2008 and 29.1 Bcf thereafter. As of March 31, 2008,
fixed-price contracts are in place to hedge 93,000 Bbls of
estimated future oil production. Of this total volume,
27,000 Bbls are hedged for 2008 and 66,000 Bbls
thereafter.
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 and oil 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 or oil 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 or oil is between the call and the put strike
price, then no payments are due from either party.
F-15
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the estimated volumes, fixed
prices, fixed-price sales and fair value attributable to the
fixed-price contracts as of March 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
Years Ending December 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Total
|
|
|
|
(Dollars in thousands, except per MMBtu and Bbl data)
|
|
|
Natural Gas Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (MMBtu)
|
|
|
3,752,000
|
|
|
|
14,629,000
|
|
|
|
12,499,000
|
|
|
|
|
|
|
|
2,000,000
|
|
|
|
32,880,000
|
|
Weighted average fixed price per MMBtu(1)
|
|
$
|
8.16
|
|
|
$
|
7.85
|
|
|
$
|
7.42
|
|
|
$
|
|
|
|
$
|
8.11
|
|
|
$
|
7.74
|
|
Fixed-price sales
|
|
$
|
30,620
|
|
|
$
|
114,861
|
|
|
$
|
92,778
|
|
|
$
|
|
|
|
$
|
16,220
|
|
|
$
|
254,479
|
|
Fair value, net
|
|
$
|
(11,402
|
)
|
|
$
|
(13,749
|
)
|
|
$
|
(8,085
|
)
|
|
$
|
|
|
|
$
|
434
|
|
|
$
|
(32,802
|
)
|
Natural Gas Collars:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (MMBtu)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
|
5,281,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,281,000
|
|
Ceiling
|
|
|
5,281,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,281,000
|
|
Weighted average fixed price per MMBtu(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
$
|
6.54
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
6.54
|
|
Ceiling
|
|
$
|
7.54
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
7.54
|
|
Fixed-price sales(2)
|
|
$
|
34,542
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
34,542
|
|
Fair value, net
|
|
$
|
(11,803
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(11,803
|
)
|
Total Natural Gas Contracts(3):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (MMBtu)
|
|
|
9,033,000
|
|
|
|
14,629,000
|
|
|
|
12,499,000
|
|
|
|
|
|
|
|
2,000,000
|
|
|
|
38,161,000
|
|
Weighted average fixed price per MMBtu(1)
|
|
$
|
7.21
|
|
|
$
|
7.85
|
|
|
$
|
7.42
|
|
|
$
|
|
|
|
$
|
8.11
|
|
|
$
|
7.57
|
|
Fixed-price sales(2)
|
|
$
|
65,162
|
|
|
$
|
114,861
|
|
|
$
|
92,778
|
|
|
$
|
|
|
|
$
|
16,220
|
|
|
$
|
289,021
|
|
Fair value, net
|
|
$
|
(23,205
|
)
|
|
$
|
(13,749
|
)
|
|
$
|
(8,085
|
)
|
|
$
|
|
|
|
$
|
434
|
|
|
$
|
(44,605
|
)
|
Oil Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Bbl)
|
|
|
27,000
|
|
|
|
36,000
|
|
|
|
30,000
|
|
|
|
|
|
|
|
|
|
|
|
93,000
|
|
Weighted average fixed price per Bbl(1)
|
|
$
|
95.92
|
|
|
$
|
90.07
|
|
|
$
|
87.50
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
90.94
|
|
Fixed-price sales
|
|
$
|
2,590
|
|
|
$
|
3,243
|
|
|
$
|
2,625
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
8,458
|
|
Fair value, net
|
|
$
|
(128
|
)
|
|
$
|
(205
|
)
|
|
$
|
(188
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(521
|
)
|
|
|
|
(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.
|
|
(3)
|
|
Does not include basis swaps with notional volumes by year, as
follows: 2008: 4,716,000 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
F-16
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 March 31, 2008 and 2007, oil and gas
sales included $1.2 million and $996,000, respectively, of
net losses associated with realized losses under fixed-price
contracts.
For contracts that did not qualify as cash flow hedges, the
realized contract profit and loss is included in other revenue
and expense in the period for which the underlying production
was hedged. For the three months ended March 31, 2008 and
2007, other revenue and expense included $0 and $0,
respectively, of net losses associated with realized 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 March 31, 2008, the estimated
amount of unrealized gains 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
$28.6 million.
Interest
Rate Hedging Activities
At March 31, 2008, the Company had no outstanding interest
rate cap or swap agreements.
Change
in Derivative Fair Value
Change in derivative fair value in the statements of operations
for the three months ended March 31, 2008 and 2007 is
comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
($ in thousands)
|
|
|
Change in fair value of derivatives not qualifying as cash flow
hedges
|
|
$
|
(23,548
|
)
|
|
$
|
(1,036
|
)
|
Ineffective portion of derivatives qualifying as cash flow hedges
|
|
|
(283
|
)
|
|
|
572
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(23,831
|
)
|
|
$
|
(464
|
)
|
|
|
|
|
|
|
|
|
|
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.
Credit
Risk
Energy swaps and collars and interest rate swaps and caps
provide for a net settlement due to or from the respective party
as discussed previously. The counterparties to the derivative
contracts are financial institutions. Should a counterparty
default on a contract, there can be no assurance that we 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.
F-17
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Cancellation or termination of a fixed-price contract would
subject a greater portion of the Companys natural gas or
oil production to market prices, which, in a low price
environment, could have an adverse effect on its future
operating results. Cancellation or termination of an interest
rate swap or cap would subject a greater portion of the
Companys long-term debt to market interest rates, which,
in an inflationary environment, could have an adverse effect on
its future net income. 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 our production is termed basis and is
the result of differences in location, quality, contract terms,
timing and other variables. For instance, some of our fixed
price contracts are tied to commodity prices on the New York
Mercantile Exchange (NYMEX), that is, we receive the
fixed price amount stated in the contract and pay to our
counterparty the current market price for gas as listed on the
NYMEX. However, due to the geographic location of our natural
gas assets and the cost of transporting the natural gas to
another market, the amount that we receive when we actually sell
our natural gas is based on the Southern Star Central TX/KS/OK
(Southern Star) first of month index, with a small
portion 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 crude oil
production for which we have entered into swap agreements is
sold at a contract price based on the average daily settling
price of NYMEX less $1.10/bbl, which eliminates our
exposure to changing differentials on this production. This
contract runs through March 2009 with automatic extensions
thereafter unless terminated by either party. Recently, the
basis differential has been increasingly volatile and has on
occasion resulted in us receiving a net price for our natural
gas and oil that is significantly below the price stated in the
fixed price contract.
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 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 and oil 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 and oil are
expected to be offset by changes in the price received for
hedged natural gas and oil production.
F-18
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 March 31, 2008 and December 31,
2007 and the methods and assumptions used to estimate their fair
value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2008
|
|
|
December 31, 2007
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
Carrying
|
|
|
Fair
|
|
|
|
Amount
|
|
|
Value
|
|
|
Amount
|
|
|
Value
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
Derivative assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis swaps
|
|
$
|
223
|
|
|
$
|
223
|
|
|
$
|
281
|
|
|
$
|
281
|
|
Fixed-price natural gas swaps
|
|
$
|
599
|
|
|
$
|
599
|
|
|
$
|
2,742
|
|
|
$
|
2,742
|
|
Fixed-price natural gas collars
|
|
$
|
|
|
|
$
|
|
|
|
$
|
5,274
|
|
|
$
|
5,274
|
|
Derivative liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis swaps
|
|
$
|
(8,470
|
)
|
|
$
|
(8,470
|
)
|
|
$
|
(856
|
)
|
|
$
|
(856
|
)
|
Fixed-price natural gas swaps
|
|
$
|
(25,154
|
)
|
|
$
|
(25,154
|
)
|
|
$
|
(5,586
|
)
|
|
$
|
(5,585
|
)
|
Fixed-price natural gas collars
|
|
$
|
(11,803
|
)
|
|
$
|
(11,803
|
)
|
|
$
|
(7,385
|
)
|
|
$
|
(7,386
|
)
|
Fixed-price oil swaps
|
|
$
|
(521
|
)
|
|
$
|
(521
|
)
|
|
$
|
|
|
|
$
|
|
|
Credit facilities
|
|
$
|
(273,000
|
)
|
|
$
|
(273,000
|
)
|
|
$
|
(233,000
|
)
|
|
$
|
(233,000
|
)
|
Other financing agreements
|
|
$
|
(613
|
)
|
|
$
|
(613
|
)
|
|
$
|
(712
|
)
|
|
$
|
(712
|
)
|
The Companys financial instruments consist of cash,
receivables, deposits, hedging contracts, accounts payable,
accrued expenses and notes payable. The carrying amount of cash,
receivables, deposits, accounts payable and accrued expenses
approximates fair value because of the short-term nature of
those instruments. The hedging contracts are recorded in
accordance with the provisions of SFAS 133,
Accounting
for Derivative Instruments and Hedging Activities.
The
carrying amounts for notes payable approximate fair value due to
the variable nature of the interest rates of the notes payable.
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 months ended March 31, 2008 and 2007,
dilutive shares do not include the assumed exercise of
outstanding stock options because the effects were antidilutive.
|
|
|
|
For the three months ended March 31, 2008 and 2007,
dilutive shares do not include the assumed exercise of
outstanding stock awards because the effects were antidilutive.
|
F-19
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 March 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss)
|
|
$
|
(11,643
|
)
|
|
|
|
|
|
|
|
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic EPS available to common shareholders
|
|
$
|
(11,643
|
)
|
|
|
23,295,476
|
|
|
$
|
(0.50
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
None
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS available to common shareholders
|
|
$
|
(11,643
|
)
|
|
|
23,295,476
|
|
|
$
|
(0.50
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended March 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss)
|
|
$
|
(3,311
|
)
|
|
|
|
|
|
|
|
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic EPS available to common shareholders
|
|
$
|
(3,311
|
)
|
|
|
22,206,014
|
|
|
$
|
(0.15
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
None
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS available to common shareholders
|
|
$
|
(3,311
|
)
|
|
|
22,206,014
|
|
|
$
|
(0.15
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.
|
Partners
Capital and Cash Distributions
|
Quest
Energy Distributions to Unit Holders
Minimum Quarterly Distribution.
Quest Energy
will distribute to the holders of its common units and
subordinated units on a quarterly basis at least the minimum
quarterly distribution of $0.40 per unit, or $1.60 per year, to
the extent Quest Energy has sufficient cash from its operations
after establishment of cash reserves and payment of fees and
expenses, including payments to its general partner. However,
there is no guarantee that Quest Energy will pay the minimum
quarterly distribution on the units in any quarter. Even if
Quest Energys cash distribution policy is not modified or
revoked, the amount of distributions paid under its policy and
the decision to make any distribution is determined by its
general partner, taking into consideration the terms of Quest
Energys partnership agreement. Quest Energy will be
prohibited from making any distributions to unitholders if it
would cause an event of default, or an event of default is
existing, under its credit facility. Please read Note 3 to
the consolidated financial statements included in the 2007
Form 10-K
for a discussion of the restrictions included in Quest
Energys credit facility that may restrict its ability to
make distributions.
General Partner Interest and Incentive Distribution
Rights.
Initially, Quest Energys general
partner will be entitled to 2% of all quarterly distributions
since inception that Quest Energy makes prior to its
liquidation. The 2% general partner interest in the
distributions may be reduced if Quest Energy issues additional
units in the future and its general partner does not contribute
a proportionate amount of capital to Quest Energy to maintain
its 2% general partner interest. See Item 5. Market
for Registrants Common Equity, Related Unitholder Matters
and Issuer Purchases of Equity Securities Cash
Distributions to Unitholders in Quest Energys Annual
Report on
Form 10-K
for the year ended December 31, 2007 for further discussion
of its cash distributions.
As of March 31, 2008, Quest Energy has accrued cash
distributions for the quarter ended March 31, 2008 to all
of its unit holders totaling $8.0 million or $0.41 per unit
on all of its units.
F-20
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Quest
Midstream Distributions to Unit Holders
Minimum Quarterly Distribution.
Quest
Midstream will distribute to the holders of its common units and
subordinated units on a quarterly basis at least the minimum
quarterly distribution of $0.425 per unit, or $1.70 per year,
plus any arrearages in payment of the minimum quarterly
distribution on common units from prior quarters, to the extent
Quest Midstream has sufficient cash from its operations after
establishment of cash reserves and payment of fees and expenses,
including payments to its general partner. However, there is no
guarantee that Quest Midstream will pay the minimum quarterly
distribution on the units in any quarter. Even if Quest
Midstreams cash distribution policy is not modified or
revoked, the amount of distributions paid under its policy and
the decision to make any distribution is determined by its
general partner, taking into consideration the terms of Quest
Midstreams partnership agreement. Quest Midstream will be
prohibited from making any distributions to unitholders if it
would cause an event of default, or an event of default is
existing, under its credit facility. Please read Note 3 to
the consolidated financial statements included in the 2007
Form 10-K
for a discussion of the restrictions included in Quest
Midstreams credit facility that may restrict its ability
to make distributions.
General Partner Interest and Incentive Distribution
Rights.
Initially, Quest Midstreams general
partner will be entitled to 2% of all quarterly distributions
since inception that Quest Midstream makes prior to its
liquidation. The 2% general partner interest in the
distributions may be reduced if Quest Midstream issues
additional units in the future and its general partner does not
contribute a proportionate amount of capital to Quest Midstream
to maintain its 2% general partner interest.
During the three months ended March 31, 2008, Quest
Midstream accrued cash distributions for the quarter ended
March 31, 2008 to its unit holders totaling
$3.8 million or $0.425 per unit on its common units.
|
|
9.
|
Commitments
and Contingencies
|
Quest Resource Corporation, Bluestem Pipeline, LLC, STP, Inc.,
Quest Cherokee, LLC, Quest Energy Service, LLC, Quest Midstream
Partners, LP, Quest Midstream GP, LLC, and STP Cherokee, Inc.
(now STP Cherokee, LLC) have been named Defendants in a
lawsuit filed by Plaintiffs, Eddie R. Hill,
et al
.
in the District Court for Craig County, Oklahoma (Case
No. CJ-2003-30).
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 and
breached fiduciary duties owed to Plaintiffs, and that
Defendants have acted fraudulently toward the Plaintiffs.
Plaintiffs also allege that the gathering fees and related
charges should not be deducted in paying royalties.
Plaintiffs claims relate to a total of 84 wells
located in Oklahoma and Kansas. Plaintiffs are seeking
unspecified actual and punitive damages. Defendants intend to
defend vigorously against Plaintiffs claims.
STP, Inc., STP Cherokee, Inc. (now STP Cherokee, LLC), Bluestem
Pipeline, LLC, Quest Cherokee, LLC, and Quest Energy Service,
LLC (improperly named Quest Energy Services, LLC) have been
named defendants in a lawsuit by Plaintiffs John C. Kirkpatrick
and Suzan M. Kirkpatrick in the District Court for Craig County
(Case
No. CJ-2005-143).
Plaintiffs allege that STP, Inc.,
et al.
, sold natural
gas from wells owned by the Plaintiffs without providing the
requisite notice to Plaintiffs. Plaintiffs further allege that
Defendants failed to include deductions on the check stubs of
Plaintiffs in violation of state law and that Defendants
deducted for items other than compression in violation of the
lease terms. Plaintiffs assert claims of actual and constructive
fraud and further seek an accounting stating that if Plaintiffs
have suffered any damages for failure to properly pay royalties,
Plaintiffs have a right to recover those damages. Plaintiffs
have not quantified their alleged damages. Discovery is ongoing
and Defendants intend to defend vigorously against
Plaintiffs claims.
Quest Cherokee Oilfield Services, LLC has been named in this
lawsuit filed by Plaintiffs Segundo Francisco Trigoso and Dana
Jara De Trigoso in the District Court of Oklahoma County,
Oklahoma (Case
No. CJ-2007-11079).
Plaintiffs allege that Plaintiff Segundo Trigoso was injured
while working for Defendant on September 29, 2006 and that
such injuries were intentionally caused by Defendant. Plaintiffs
seek unspecified damages for physical injuries,
F-21
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
emotional injuries, loss of consortium and pain and suffering.
Plaintiffs also seek punitive damages. Defendant intends to
defend vigorously against Plaintiffs 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 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 some of that
land and has drilled wells that produce coal bed methane gas on
that land. Bluestem purchases and gathers the gas produced by
Quest Cherokee. 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 that Bluestem
converted the gas and seeks an accounting for all gas purchased
by Bluestem 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. If Quest Cherokee prevails on that issue, then the
plaintiffs claims against Bluestem fail. All issues
relating to ownership of the coal bed methane gas and damages
have been bifurcated. Cross motions for summary judgment on the
ownership of the coal bed methane were filed by Quest Cherokee
and the plaintiff, with summary judgment being awarded in Quest
Cherokees favor. The plaintiff has appealed the summary
judgment and that appeal is pending. Quest Cherokee and Bluestem
intend to defend vigorously against these claims.
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
2,250 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 they were damaged in the
amount of $202,375. Discovery in that case is ongoing and Quest
Cherokee intend to defend vigorously against the
plaintiffs claims.
Quest Cherokee was named as a defendant in a putative class
action lawsuit (Case
No. 07-1225-MLB)
filed by several royalty owners in the U.S. District Court
for the District of Kansas. The plaintiffs have not yet filed a
motion asking the court to certify the class and the court has
not determined that the case may properly proceed as a class
action. The case was filed by the named plaintiffs on behalf of
a putative class consisting of all Quest Cherokees royalty
and overriding royalty owners in the Kansas portion of the
Cherokee Basin. Plaintiffs contend that Quest Cherokee 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 measured at the wellheads, by
allocating expenses in excess of the actual costs of the
services represented, by allocating production costs to the
royalty owners, by improperly allocating marketing costs to the
royalty owners, and by making the royalty payments after the
statutorily proscribed time for doing so without providing the
required interest. Quest Cherokee has answered the complaint and
denied plaintiffs claims. Discovery in that case is
ongoing. Quest Cherokee intends to defend vigorously against
these claims.
F-22
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Quest Cherokee has been named as a defendant in several lawsuits
in which the plaintiff claims that an oil and gas lease owned
and operated by Quest Cherokee has either expired by their terms
or, for various reasons, have been forfeited by Quest Cherokee.
Those lawsuits are pending in the district courts of Labette,
Montgomery, and Wilson Counties, Kansas. Quest Cherokee has
drilled wells on some of the oil and gas leases in issue and
some of those oil and gas leases do not have a well located
thereon but have been unitized with other oil and gas leases
upon which a well has been drilled. 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 May 7, 2008,
the total amount of acreage covered by the leases at issue in
these lawsuits was approximately 7,481 acres. Discovery in
those cases is ongoing. Quest Cherokee intends to vigorously
defend against those claims.
Quest Cherokee was named in an Order to Show Cause issued by the
Kansas Corporation Commission (the KCC) (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 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.
Quest Cherokee was named as a defendant in two lawsuits (Case
No. 07-CV-141
and Case
No. 08-CV-20)
filed in Neosho County District Court by Richard Winder, d/b/a
Winder Oil Company. Plaintiff claims to own an oil and gas lease
covering lands upon which Quest Cherokee also claims to own an
oil and gas lease and upon which Quest Cherokee has drilled two
producing wells. Plaintiff claims that his lease is prior and
superior to Quest Cherokees leases and seeks damages for
trespass and conversion. Quest Cherokee contends that plaintiffs
leases have expired by their terms and that Quest
Cherokees leases are valid. Discovery in that case is
ongoing. Quest Cherokee intends to vigorously defend against the
Plaintiffs 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.
|
|
10.
|
Operating
Segment Information
|
We divide our operations into two reportable business segments:
|
|
|
|
|
Quest Energy gas and oil production focused on coal
bed methane production in the Cherokee Basin; and
|
|
|
|
Quest Midstream transporting, selling, gathering,
treating and processing natural gas.
|
Each segment uses the same accounting policies as those
described in the summary of significant accounting policies (see
Note 2). Our reportable segments are strategic business
units that offer different products and services. Each segment
is managed separately because each segment involves different
products and marketing strategies. The Company does not allocate
income taxes to its operating segments.
F-23
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Operating segment data for the three months ended March 31,
2008 and 2007 follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Quest Energy (Gas and Oil Production):
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
37,353
|
|
|
$
|
25,549
|
|
Costs and expenses
|
|
|
(54,813
|
)
|
|
|
(29,471
|
)
|
|
|
|
|
|
|
|
|
|
Segment profit (loss)
|
|
$
|
(17,460
|
)
|
|
$
|
(3,922
|
)
|
|
|
|
|
|
|
|
|
|
Quest Midstream (Natural Gas Pipelines):
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
Third party
|
|
$
|
6,901
|
|
|
$
|
1,542
|
|
Intercompany
|
|
|
8,663
|
|
|
|
6,361
|
|
|
|
|
|
|
|
|
|
|
Total natural gas pipeline revenue
|
|
$
|
15,564
|
|
|
$
|
7,903
|
|
Costs and expenses
|
|
|
(14,297
|
)
|
|
|
(7,087
|
)
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
1,267
|
|
|
$
|
816
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of segment profit (loss) to net income before tax
Segment profit (loss)
|
|
|
|
|
|
|
|
|
Quest Energy (Gas and oil production)
|
|
$
|
(17,460
|
)
|
|
$
|
(3,922
|
)
|
Quest Midstream (Natural gas pipelines)
|
|
|
1,267
|
|
|
|
816
|
|
|
|
|
|
|
|
|
|
|
Total segment profit (loss)
|
|
|
(16,193
|
)
|
|
|
(3,106
|
)
|
Intercompany pipeline revenue
|
|
|
(8,663
|
)
|
|
|
(6,361
|
)
|
Intercompany transportation expense
|
|
|
8,663
|
|
|
|
6,361
|
|
Corporate general and administrative expenses
|
|
|
(547
|
)
|
|
|
|
|
Corporate depreciation expense
|
|
|
(68
|
)
|
|
|
(44
|
)
|
Corporate interest expense
|
|
|
(983
|
)
|
|
|
|
|
Other income (expenses)
|
|
|
98
|
|
|
|
271
|
|
|
|
|
|
|
|
|
|
|
Net (loss) before tax
|
|
$
|
(17,693
|
)
|
|
$
|
(2,879
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Total Assets:
|
|
|
|
|
|
|
|
|
Gas and oil production
|
|
$
|
372,995
|
|
|
$
|
364,310
|
|
Gas pipeline
|
|
|
320,358
|
|
|
|
309,873
|
|
Corporate and other
|
|
|
20,347
|
|
|
|
7,427
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
713,700
|
|
|
$
|
681,610
|
|
|
|
|
|
|
|
|
|
|
Operating profit per segment represents total revenues less
costs and expenses attributable thereto, excluding general
corporate expenses.
On April 17, 2008, Quest Energy and Quest Cherokee entered
into an amendment to the Amended and Restated Credit Agreement
with the Royal Bank of Canada, as administrative agent and
collateral agent, Keybank National Association, as documentation
agent, and the lenders party thereto (the
Amendment). The Amendment changed the maturity date
from November 15, 2012 to November 15, 2010, and
increased the applicable rate at
F-24
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
which interest will accrue by 1% to either LIBOR plus a margin
ranging from 2.25% to 2.875% (depending on the utilization
percentage) or the base rate plus a margin ranging from 1.25% to
1.875% (depending on the utilization percentage). The Amendment
also eliminated the accordion feature in the credit
agreement, which gave Quest Cherokee the option to request an
increase in the aggregate revolving commitment from
$250 million to $350 million. There was no commitment
on the part of the lenders to agree to such a request.
F-25
|
|
Item 2.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations Forward-looking Information
|
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 2,000 miles in length within this basin.
Additionally, we own a 1,120-mile interstate natural gas
transmission pipeline that runs from Oklahoma to Missouri (the
KPC Pipeline). 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 Three Months Ended March 31,
2008
During the first quarter of 2008, we continued to be focused on
drilling and completing new wells. We drilled 118 gross
wells and completed the connection of 101 gross wells
during this period. As of March 31, 2008, we had
approximately 130 additional gas wells (gross) that we were in
the process of completing and connecting to our gas gathering
pipeline system.
We completed approximately 70 miles of pipeline
infrastructure expansion and acquired additional natural gas
leases covering approximately 16,000 acres (gross).
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.
For the three months ended March 31, 2008, our average net
daily production was 55.6 Mmcfe/d.
Quest Energy purchased certain oil producing properties in
Seminole County, Oklahoma from a private company for
$9.5 million in a transaction that closed in early February
2008. The properties have estimated net proved reserves of
712,000 barrels, all of which are proved developed
producing. In addition, Quest Energy entered into crude oil
swaps for approximately 80% of the estimated net production from
the propertys proved developed producing reserves at
WTI-NYMEX prices per barrel of oil of approximately $96.00 in
2008, $90.00 in 2009, and $87.50 for 2010. The acquisition was
financed with borrowings under Quest Energys credit
facility.
Part of our business strategy is to expand our exploration,
development and production activities beyond the Cherokee Basin.
We currently own approximately 23,000 net undeveloped acres
in Pennsylvania, Maryland, Texas and New Mexico. We expect our
first vertical well in Pennsylvania to be completed and tested
by the end of the second quarter of 2008. We plan to drill and
complete additional wells during 2008 if the first well is
successful. Our test well in New Mexico was unsuccessful and was
plugged and abandoned in May 2008. We currently do not plan
any additional activity in New Mexico. Overall, we plan to
spend between $2 million and $3 million on drilling
and completion of exploratory wells in 2008.
Results
of Operations
As a result of the acquisition of KPC Pipeline in November 2007
we have begun reporting our results of operations as two
segments: Quest Energy (natural gas and oil production) and
Quest Midstream (natural gas pipelines). Previously reported
amounts have been adjusted to reflect this change, which did not
impact our consolidated financial statements.
The following discussion is based on the consolidated operations
of all our subsidiaries and should be read in conjunction with
the financial statements included in this report; and should
further be read in conjunction with the audited financial
statements and notes thereto included in our 2007
Form 10-K.
Comparisons made between reporting periods herein are for the
three month periods ended March 31, 2008 as compared to the
same period in 2007.
-4-
Quest
Energy (Gas and Oil Production Segment)
Overview.
The following discussion of results
of operations will compare balances for the three months ended
March 31, 2008 and 2007, as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
|
|
|
|
|
|
|
Ended March 31,
|
|
|
Increase
|
|
|
|
2008
|
|
|
2007
|
|
|
(Decrease)
|
|
|
|
($ in thousands)
|
|
|
Oil and gas sales
|
|
$
|
37,353
|
|
|
$
|
25,549
|
|
|
$
|
11,804
|
|
|
|
46.2
|
%
|
Other revenue/(expense)
|
|
$
|
50
|
|
|
$
|
(13
|
)
|
|
$
|
63
|
|
|
|
484.6
|
%
|
Oil and gas production costs
|
|
$
|
8,211
|
|
|
$
|
7,227
|
|
|
$
|
984
|
|
|
|
13.6
|
%
|
Transportation expense (intercompany)
|
|
$
|
8,663
|
|
|
$
|
6,361
|
|
|
$
|
2,302
|
|
|
|
36.2
|
%
|
Depreciation, depletion and amortization
|
|
$
|
9,511
|
|
|
$
|
6,694
|
|
|
$
|
2,817
|
|
|
|
42.1
|
%
|
General and administrative expense
|
|
$
|
2,458
|
|
|
$
|
1,753
|
|
|
$
|
705
|
|
|
|
40.2
|
%
|
Change in derivative fair value
|
|
$
|
(23,831
|
)
|
|
$
|
(464
|
)
|
|
$
|
(23,367
|
)
|
|
|
5036.0
|
%
|
Interest expense
|
|
$
|
2,140
|
|
|
$
|
6,971
|
|
|
$
|
(4,831
|
)
|
|
|
(69.3
|
)%
|
Production.
The following table presents the
primary components of revenues of our Gas and Oil Production
Segment (gas and oil production and average gas and oil prices),
as well as the average costs per Mcfe, for the three months
ended March 31, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
|
|
|
|
|
|
|
Ended March 31,
|
|
|
Increase
|
|
|
|
2008
|
|
|
2007
|
|
|
(Decrease)
|
|
|
Production Data (net):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas production (MMcf)
|
|
|
4,991
|
|
|
|
3,716
|
|
|
|
1,275
|
|
|
|
34.3
|
%
|
Oil production (Bbl)
|
|
|
11,188
|
|
|
|
2,020
|
|
|
|
9,168
|
|
|
|
453.9
|
%
|
Total production (MMcfe)
|
|
|
5,058
|
|
|
|
3,728
|
|
|
|
1,330
|
|
|
|
35.7
|
%
|
Average daily production (MMcfe/d)
|
|
|
55.6
|
|
|
|
41.4
|
|
|
|
13.2
|
|
|
|
31.9
|
%
|
Average Sales Price per Unit (Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excluding hedges
|
|
$
|
7.62
|
|
|
$
|
6.99
|
|
|
$
|
0.63
|
|
|
|
9.0
|
%
|
Including hedges
|
|
$
|
7.38
|
|
|
$
|
7.12
|
|
|
$
|
0.26
|
|
|
|
3.7
|
%
|
Natural gas (Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excluding hedges
|
|
$
|
7.51
|
|
|
$
|
6.99
|
|
|
$
|
0.52
|
|
|
|
7.4
|
%
|
Including hedges
|
|
$
|
7.26
|
|
|
$
|
7.12
|
|
|
$
|
0.14
|
|
|
|
2.0
|
%
|
Oil (Bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excluding hedges
|
|
$
|
98.12
|
|
|
$
|
50.33
|
|
|
$
|
47.79
|
|
|
|
95.0
|
%
|
Including hedges
|
|
$
|
98.12
|
|
|
$
|
50.33
|
|
|
$
|
47.79
|
|
|
|
95.0
|
%
|
Average Unit Costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
$
|
1.62
|
|
|
$
|
1.94
|
|
|
$
|
(0.32
|
)
|
|
|
(16.5
|
)%
|
Transportation expense (intercompany)
|
|
$
|
1.72
|
|
|
$
|
1.71
|
|
|
$
|
(0.01
|
)
|
|
|
1.0
|
%
|
Depreciation, depletion and amortization
|
|
$
|
1.88
|
|
|
$
|
1.80
|
|
|
$
|
0.08
|
|
|
|
4.4
|
%
|
General and administrative expense
|
|
$
|
0.49
|
|
|
$
|
0.47
|
|
|
$
|
0.02
|
|
|
|
4.3
|
%
|
Interest expense
|
|
$
|
0.42
|
|
|
$
|
1.87
|
|
|
$
|
(1.45
|
)
|
|
|
(77.5
|
)%
|
Oil and Gas Sales.
The $11.8 million
(46.2%) increase in oil and gas sales from $25.5 million
for the quarter ended March 31, 2007 to $37.4 million
for the quarter ended March 31, 2008 was primarily
attributable to the increase in production volumes and sales
prices reflected in the table above. The increase in production
volumes 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. The additional wells
contributed to the production of 4,991,000 Mcf of net gas
for the quarter ended March 31, 2008, as compared to
3,716,000 net Mcf produced in the same quarter last
-5-
year. Our product prices on an equivalent basis (Mcfe) increased
from an average of $6.99 per Mcfe for the quarter ended
March 31, 2007 to an average of $7.62 per Mcfe for the
quarter ended March 31, 2008. For the quarter ended
March 31, 2008, the net product price, after accounting for
the loss on hedging settlements of $1.2 million during the
quarter, averaged $7.38 per Mcfe. For the quarter ended
March 31, 2007, the net product price, after accounting for
the gain on hedging settlements of $996,000 during the quarter,
averaged $7.12 per Mcfe.
Other revenue/(expense).
Other revenue for the
three months ended March 31, 2008 was $50,000 as compared
to other expense of $13,000 for the three-month period ended
March 31, 2007, that was due to a reduction in overhead
fees.
Operating Expenses.
Operating expenses, which
consist of oil and gas production costs and transportation
expense, totaling $16.9 million for the three months ended
March 31, 2008, were comprised of lease operating costs of
$5.6 million, production taxes of $1.7 million, ad
valorem taxes of $804,000, and transportation expenses of
$8.6 million. The current operating expenses compared to
$13.6 million for the three months ended March 31,
2007, comprised of lease operating costs of $5.5 million,
production taxes of $1.1 million, ad valorem taxes of
$888,000, and transportation expenses of $6.1 million, a
total increase of $3.3 million, or 24%.
During the three months ended March 31, 2008, management
implemented cost controls which have kept lease operating costs
relatively flat, while connecting approximately 600 new wells
since the same quarter of 2007. Unit production costs, excluding
gross production and ad valorem taxes, were $1.12 per Mcfe for
the three months ended March 31, 2008 compared to $1.47 per
Mcfe for the three months ended March 31, 2007 representing
a 23.8% decrease. Unit production costs, inclusive of gross
production and ad valorem taxes, were $1.94 per Mcfe for the
2007 period as compared to $1.62 per Mcfe for the three months
ended March 31, 2008 period, representing a 16.5% decrease.
Transportation expense increased $2.3 million from
$6.4 million for the three months ended March 31,2007
compared to $8.7 million for the three months ended
March 31,2008, resulting in $1.72 per Mcfe for 2008. This
increase primarily resulted from the annual increase in the fees
charged under the midstream services agreement with Quest
Midstream and increased production.
Depreciation, Depletion and Amortization.
We
are subject to variances in our depletion rates from period to
period, including the periods described below. These variances
result from changes in our oil and gas reserve quantities,
production levels, product prices and changes in the depletable
cost basis of our gas and oil properties. Our depletion of gas
and oil properties as a percentage of gas and oil revenues was
25% in the three months ended March 31, 2008 compared to
26% in 2007. Depreciation, depletion and amortization expense
was $1.88 per Mcfe in March 31, 2008 compared to $1.80 per
Mcfe in 2007. Increases in our depletable basis and production
volumes caused depletion expense to increase $2.8 million
to $9.5 million in 2008 compared to $6.7 million in
2007.
General and Administrative Expense.
General
and administrative expenses increased from $1.8 million for
the quarter ended March 31, 2007 to $2.5 million for
the quarter ended March 31, 2008. This increase resulted
from a non-cash charge for amortization of stock and unit
awards. The remainder of the increase is due to an increase in
staff personnel, legal, accounting and professional fees, travel
expenses for presentations to increase our visibility with
investors, increased staffing to support the higher levels of
development and operational activity and the added resources to
enhance our internal controls.
Change in Derivative Fair Value.
Change in
derivative fair value was a non-cash loss of $23.8 million
for the three months ended March 31, 2008, which included a
$23.5 million loss attributable to the change in fair value
for certain derivative contracts that did not qualify as cash
flow hedges pursuant to SFAS 133 and a loss of $283,000
relating to hedge ineffectiveness. Change in derivative fair
value was a non-cash loss of $464,000 for the three months ended
March 31, 2007, which included a $1.04 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 $572,000 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.
Interest Expense.
Interest expense decreased
to $2.1 million for the quarter ended March 31, 2008
from $7.0 million for the quarter ended March 31,
2007, due to refinancing of our credit facilities attributable
to the
-6-
segment during 2007 resulting in lower average interest rates
and lower outstanding borrowings attributable to the segment.
Quest
Midstream (Natural Gas Pipelines Segment)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended March 31,
|
|
|
Increase
|
|
|
|
2008
|
|
|
2007
|
|
|
(Decrease)
|
|
|
|
($ in thousands)
|
|
|
Pipeline Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas pipeline revenue Third Party
|
|
$
|
6,901
|
|
|
$
|
1,542
|
|
|
$
|
5,359
|
|
|
|
347.5%
|
|
Gas pipeline revenue Intercompany
|
|
|
8,663
|
|
|
|
6,361
|
|
|
|
2,302
|
|
|
|
36.2%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gas pipeline revenue
|
|
$
|
15,564
|
|
|
$
|
7,903
|
|
|
$
|
7,661
|
|
|
|
96.9%
|
|
Pipeline operating expense
|
|
$
|
7,249
|
|
|
$
|
4,934
|
|
|
$
|
2,315
|
|
|
|
46.9%
|
|
Depreciation and amortization
|
|
$
|
3,222
|
|
|
$
|
1,126
|
|
|
$
|
2,096
|
|
|
|
186.1%
|
|
General and administrative expense
|
|
$
|
1,825
|
|
|
$
|
886
|
|
|
$
|
939
|
|
|
|
106.1%
|
|
Interest expense
|
|
$
|
2,001
|
|
|
$
|
142
|
|
|
$
|
1,859
|
|
|
|
1309.0%
|
|
Throughput Data (MMcf):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput Third Party
|
|
|
430
|
|
|
|
400
|
|
|
|
30
|
|
|
|
7.5%
|
|
Throughput Intercompany
|
|
|
6,513
|
|
|
|
4,970
|
|
|
|
1,543
|
|
|
|
31.0%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total throughput (MMcf)
|
|
|
6,943
|
|
|
|
5,370
|
|
|
|
1,573
|
|
|
|
29.3%
|
|
Average Pipeline Operating Costs per MMcf:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline operating
|
|
$
|
1.04
|
|
|
$
|
0.92
|
|
|
$
|
0.12
|
|
|
|
13.0%
|
|
Depreciation and amortization
|
|
$
|
0.46
|
|
|
$
|
0.32
|
|
|
$
|
0.14
|
|
|
|
43.8%
|
|
General and administrative expense
|
|
$
|
0.26
|
|
|
$
|
0.16
|
|
|
$
|
0.10
|
|
|
|
62.5%
|
|
Interest expense
|
|
$
|
0.29
|
|
|
$
|
0.03
|
|
|
$
|
0.26
|
|
|
|
866.7%
|
|
Pipeline Revenue.
Our third party transmission
and gathering revenues were $6.9 million for the three
months ended March 31, 2008, an increase of
$5.4 million (348%) from $1.5 million for the three
months ended March 31, 2007. 91% of the increase was
attributable to revenue contributions from Quest Pipelines
(KPC), which was acquired November 1, 2007, totaling
$4.9 million. The remaining increase was due to additional
third party volumes on our gathering system.
The intercompany gas pipeline revenues were $8.7 million
for the three months ended March 31, 2008 as compared to
$6.4 million for the three months ended March 31,
2007, an increase of $2.3 million, or 36%. The increase is
due to the 31% increase in throughput volumes from our Cherokee
Basin properties and the increase in gathering and compression
fees resulting from the annual price adjustment under the
midstream services agreement that became effective
January 1, 2008, which provided for a fixed transportation
fee that was higher than the fees in the year earlier period.
Pipeline Operating Expense.
Pipeline operating
costs for the three months ended March 31, 2008 totaled
approximately $7.2 million ($1.04 per Mcf) as compared to
pipeline operating costs of $4.9 million ($0.92 per Mcf)
for the three months ended March 31, 2007. This increase in
operating costs was due to the delivery of additional
compressors in anticipation of increased pipeline volumes, the
number of wells completed and operated during the year, the
increased miles of pipeline in service, the increase in property
taxes and the operations of the KPC Pipeline.
Depreciation and Amortization.
Depreciation
and amortization expense was $3.2 million for the three
months ended March 31, 2008 compared to $1.1 million
in 2007. The increase is due to the acquisition of the KPC
Pipeline on November 1, 2007 and the additional natural gas
gathering pipeline installed during the year ended
December 31, 2007 and the three months ended March 31,
2008.
-7-
General and Administrative Expense.
General
and administrative expenses increased from $886,000 for the
quarter ended March 31, 2007 to $1.8 million for the
quarter ended March 31, 2008. This increase resulted from a
non-cash charge of approximately $450,000 for amortization of
stock and unit awards. The remainder of the increase is due to
an increase in staff personnel, legal, accounting and
professional fees, travel expenses for presentations to increase
our visibility with investors, costs for establishing a Houston
office and staffing requirements, increased staffing to support
the higher levels of development and operational activity and
the added resources to enhance our internal controls.
Interest Expense.
Interest expense increased
to $2.0 million for the quarter ended March 31, 2008
from $142,000 for the quarter ended March 31, 2007, due to
additional borrowings under of our credit facility to finance
the KPC Pipeline acquisition during 2007 and the construction of
additional gas gathering pipeline.
Corporate
Unallocated Items
Overview.
The following discussion of results
of operations will compare balances for the three months ended
March 31, 2008 and 2007, as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
|
|
|
|
|
|
|
Ended March 31,
|
|
|
Increase
|
|
|
|
2008
|
|
|
2007
|
|
|
(Decrease)
|
|
|
|
($ in thousands)
|
|
|
General and administrative expenses
|
|
$
|
547
|
|
|
$
|
|
|
|
$
|
547
|
|
|
|
100%
|
|
Depreciation expenses
|
|
$
|
68
|
|
|
$
|
44
|
|
|
$
|
24
|
|
|
|
54.5%
|
|
Interest expense
|
|
$
|
983
|
|
|
$
|
|
|
|
$
|
983
|
|
|
|
100.0%
|
|
General and Administrative expenses.
General
and administrative expenses increased from $0 for the quarter
ended March 31, 2007 to $547,000 for the quarter ended
March 31, 2008. This increase resulted from a non-cash
charge of approximately $547,000 for amortization of stock and
unit awards.
Depreciation expenses.
Depreciation and
amortization expense was $68,000 for the three months ended
March 31, 2008 compared to $44,000 for the three months
ended March 31, 2007. The increase is due to new office
space and furniture and equipment to meet staffing requirements.
Interest Expense.
Interest expense increased
to $983,000 for the quarter ended March 31, 2008 from no
interest expense for the quarter ended March 31, 2007.
During the first three months of 2007, all of the indebtedness
under our prior Guggenheim credit facilities was allocated to
our oil and production segment. In connection with the formation
of Quest Energy, the portion of this debt that was not
refinanced with the proceeds from Quest Energys initial
public offering and new credit facility was deemed to be
unallocated.
Net
Income
We recorded a net loss of $11.6 million for the quarter
ended March 31, 2008 as compared to a net loss of
$3.3 million for the quarter ended March 31, 2007,
each period inclusive of the non-cash net gain or loss derived
from the change in derivative fair value as stated above and
inclusive of the gain from our minority interest in continuing
operations of Quest Midstream and Quest Energy for the quarter
ended March 31, 2008.
Liquidity
and Capital Resources
Our primary sources of liquidity are cash generated from our
operations, amounts available under our revolving credit
facilities and funds from future private and public equity and
debt offerings. Please read Note 3 Long-Term
Debt to our consolidated financial statements included in our
2007
Form 10-K
for additional information relating to our credit facilities,
including a description of the financial covenants contained in
each of the credit facilities.
At March 31, 2008, we had $6 million of availability
under our revolving credit facility, which was available for
general corporate purposes.
-8-
At March 31, 2008, Quest Energy had $37 million of
availability under its 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 March 31, 2008, Quest Midstream had $29 million of
availability under its revolving credit facility, which was
available to fund additional pipeline construction and related
facilities, the connection of additional wells to our pipeline
system, pipeline acquisitions and working capital for our
pipeline operations.
At March 31, 2008, we had current assets of
$57.7 million. Our working capital (current assets minus
current liabilities, excluding the short-term derivative asset
and liability of $223,000 and $28.7 million, respectively)
was $14.4 million at March 31, 2008, compared to
working capital (excluding the short-term derivative asset and
liability of $6.7 million and $8.2 million,
respectively) of $1.2 million at December 31, 2007.
The changes in working capital were primarily due to a decrease
in revenue payable of $1.6 million and accrued expenses of
$2.8 million; and an increase of $3.1 million in
receivables.
Additionally, inventory, accounts payable and accrued expenses
balances increased as we expanded our operations. A substantial
portion of our production is hedged. We are generally required
to settle a portion of our commodity hedges on each of the
5th and 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.
Capital
Expenditures
During the three months ended March 31, 2008, a total of
approximately $39.5 million of capital expenditures was
invested as follows: $25.8 million was invested in new
natural gas wells and properties, $9.5 million in new
pipeline facilities, $3.0 million in acquiring leasehold
and $1.2 million in other additional capital items. These
investments were funded by cash flow from operations, remaining
cash from the proceeds of the Quest Midstream borrowings of
$11 million and Quest Energy borrowings of $29 million
under their credit facilities.
During 2008, we intend to focus on drilling and completing up to
325 new wells in the Cherokee Basin. Management currently
estimates that it will require for each of 2008 and 2009 capital
investments of:
|
|
|
|
|
$41.0 million to drill and complete these wells and
recomplete an estimated 52 gross wells in the Cherokee
Basin;
|
|
|
|
$37.5 million for acreage, the acquisition of properties in
Seminole County, Oklahoma, equipment and vehicle replacement and
purchases and salt water disposal facilities in the Cherokee
Basin;
|
|
|
|
$21.5 million for the pipeline expansion to connect the new
wells to our existing gas gathering pipeline network in the
Cherokee Basin;
|
|
|
|
$15.5 million for line looping, KPC activities, and the
building of a new processing plant; and
|
|
|
|
$2.0 million for exploration and production activities in
areas outside of the Cherokee Basin.
|
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 and Quest Midstream will be responsible for the
Cherokee Basin capital expenditures described above. Quest
Midstream will be responsible for the KPC expenditures described
above. In general, Quest Energy and Quest Midstream intend to
finance future maintenance capital expenditures generally from
cash flow from
-9-
operations and expansion capital expenditures generally with
borrowings under their credit facilities
and/or
the
issuance of debt or equity securities.
We will be responsible for the capital expenditures outside the
Cherokee Basin described above. We intend to finance these
capital expenditures through either borrowings under our
revolving credit facility, the issuance of debt or equity
securities
and/or
distributions from Quest Energy
and/or
Quest
Midstream.
In the event we make one or more additional 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 and Quest Energy. 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 5.
Long-Term Debt 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 $9.3 million for
the three months ended March 31, 2008 as compared to net
cash provided by operations of $10.4 million for the three
months ended March 31, 2007. This resulted from the change
in derivative fair value, a decrease in restricted cash, an
increase in accounts receivable and a decrease in revenue
payable and accrued expenses.
Cash Flows Used in Investing Activities.
Net
cash used in investing activities totaled $39.7 million for
the three months ended March 31, 2008 as compared to
$32.4 million for the three months ended March 31,
2007. During the three months ended March 31, 2008, a total
of approximately $32.7 million of capital expenditures was
invested as follows: $31.1 million was invested in new
natural gas wells and properties, $1.0 million in acquiring
leasehold, $6.4 million in the construction of new
pipeline, and $1.2 million in other additional capital
items.
Cash Flows from Financing Activities.
Net cash
provided by financing activities totaled $26.7 million for
the three months ended March 31, 2008 as compared to
$27.0 million for the three months ended March 31,
2007, and related to the financing of capital expenditures. The
net cash provided from financing activities during the three
months ended March 31, 2008 was due primarily to
$29 million of borrowings under the Quest Cherokee credit
facilities. The net cash provided from financing activities for
the three months ended March 31, 2007 was due primarily to
$27.2 million of capital contributions.
-10-
Contractual
Obligations
Future payments due on our contractual obligations as of
March 31, 2008 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
Less Than
|
|
|
1-3
|
|
|
4-5
|
|
|
More Than
|
|
|
|
Total
|
|
|
1 Year
|
|
|
Years
|
|
|
Years
|
|
|
5 Years
|
|
|
|
(In thousands)
|
|
|
Revolving Credit Facility Quest Resource
|
|
$
|
44,000
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
44,000
|
|
|
$
|
|
|
Revolving Credit Facility Quest Energy(2)
|
|
|
123,000
|
|
|
|
|
|
|
|
123,000
|
|
|
|
|
|
|
|
|
|
Revolving Credit Facility Quest Midstream
|
|
|
106,000
|
|
|
|
|
|
|
|
|
|
|
|
106,000
|
|
|
|
|
|
Notes Payable
|
|
|
613
|
|
|
|
448
|
|
|
|
21
|
|
|
|
138
|
|
|
|
6
|
|
Interest expense obligation(1)(2)
|
|
|
67,495
|
|
|
|
14,078
|
|
|
|
35,420
|
|
|
|
17,997
|
|
|
|
|
|
Drilling contractor
|
|
|
2,548
|
|
|
|
2,548
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
|
3,998
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,998
|
|
Lease obligations
|
|
|
9,475
|
|
|
|
899
|
|
|
|
2,432
|
|
|
|
2,373
|
|
|
|
3,771
|
|
Derivatives
|
|
|
45,948
|
|
|
|
28,745
|
|
|
|
17,203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
403,077
|
|
|
$
|
46,718
|
|
|
$
|
178,076
|
|
|
$
|
170,508
|
|
|
$
|
7,775
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The interest payment obligation was computed using the LIBOR
interest rate as of March 31, 2008. If the interest rate
were to change 1%, then the total interest payment obligation
would change by $11.7 million. Effective April 15,
2008, the interest rate on Quest Energys revolving credit
facility was increased by 1%. This change has been reflected in
the table above. See Note 11 to the consolidated financial
statements included in this report.
|
|
(2)
|
|
Effective April 15, 2008, the maturity date for Quest
Energys revolving credit facility was changed from
November 15, 2012 to November 14, 2010. This change
has been reflected in table above. See Note 11 to the
consolidated financial statements included in this report.
|
Critical
Accounting Policies
The consolidated financial statements are prepared in conformity
with accounting principles generally accepted in the United
States. As such, we are required to make certain estimates,
judgments and assumptions that we believe are reasonable based
upon the information available. These estimates and assumptions
affect the reported amounts of assets and liabilities at the
date of the financial statements and the reported amounts of
revenue and expenses during the reporting period. A summary of
the significant accounting policies is contained in Note 2
to our consolidated financial statements. See also Item 7.
Managements Discussion and Analysis of Financial Condition
and Results of Operations Critical Accounting
Policies and Estimates in our 2007
Form 10-K.
Off-Balance
Sheet Arrangements
At March 31, 2008 and December 31, 2007, 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.
-11-
Cautionary
Statements for Purpose of the Safe Harbor Provisions
of the Private Securities Litigation Reform Act of
1995
We are including the following discussion to inform you of some
of the risks and uncertainties that can affect our company and
to take advantage of the safe harbor protection for
forward-looking statements that applicable federal securities
law affords. Various statements this report contains, including
those that express a belief, expectation, or intention, as well
as those that are not statements of historical fact, are
forward-looking statements. These include such matters as:
|
|
|
|
|
projections and estimates concerning the timing and success of
specific projects;
|
|
|
|
financial position;
|
|
|
|
business strategy;
|
|
|
|
budgets;
|
|
|
|
amount, nature and timing of capital expenditures;
|
|
|
|
drilling of wells and construction of pipeline infrastructure;
|
|
|
|
acquisition and development of natural gas and oil properties
and related pipeline infrastructure;
|
|
|
|
timing and amount of future production of natural gas and oil;
|
|
|
|
operating costs and other expenses;
|
|
|
|
estimated future net revenues from natural gas and oil reserves
and the present value thereof;
|
|
|
|
cash flow and anticipated liquidity; and
|
|
|
|
other plans and objectives for future operations.
|
When we use the words believe, intend,
expect, may, will,
should, anticipate, could,
estimate, plan, predict,
project, or their negatives, or other similar
expressions, the statements which include those words are
usually forward-looking statements. When we describe strategy
that involves risks or uncertainties, we are making
forward-looking statements. The forward-looking statements in
this report speak only as of the date of this report; we
disclaim any obligation to update these statements unless
required by securities law, and we caution you not to rely on
them unduly. We have based these forward-looking statements on
our current expectations and assumptions about future events.
While our management considers these expectations and
assumptions to be reasonable, they are inherently subject to
significant business, economic, competitive, regulatory and
other risks, contingencies and uncertainties, most of which are
difficult to predict and many of which are beyond our control.
All subsequent oral and written forward-looking statements
attributable to the Company or persons acting on its behalf are
expressly qualified in their entirety by these factors. These
risks, contingencies and uncertainties relate to, among other
matters, the following:
|
|
|
|
|
our ability to implement our business strategy;
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|
|
|
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;
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|
|
|
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;
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|
land issues;
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|
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|
the effects of government regulation and permitting and other
legal requirements;
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|
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|
labor problems;
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|
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|
environmental related problems;
|
-12-
|
|
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|
|
the uncertainty inherent in estimating future natural gas and
oil production or reserves;
|
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|
|
production variances from expectations;
|
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|
|
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;
|
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|
costs associated with perfecting title for natural gas rights
and pipeline easements and rights of way in some of our
properties;
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|
the need to develop and replace reserves;
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competition;
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dependence upon key personnel;
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|
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|
the lack of liquidity of our equity securities;
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|
operating hazards attendant to the natural gas and oil business;
|
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|
|
down-hole drilling and completion risks that are generally not
recoverable from third parties or insurance;
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|
potential mechanical failure or under-performance of significant
wells;
|
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|
climatic conditions;
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natural disasters;
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|
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.
|
When you consider these forward-looking statements, you should
keep in mind these risk factors and the other factors discussed
under Item 1A. Risk Factors in our 2007
Form 10-K.
|
|
Item 3.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
There have been no material changes in market risk exposures
that would affect the quantitative and qualitative disclosures
presented as of December 31, 2007, in Item 7A of our
2007
Form 10-K.
For more information on our risk management activities, see
Note 6 to our consolidated financial statements in this
report.
|
|
Item 4.
|
Controls
and Procedures
|
Conclusion
Regarding the Effectiveness of Disclosure Controls and
Procedures
Under the supervision and with the participation of our
management, including our Chief Executive Officer (our principal
executive officer) and our Chief Financial Officer (our
principal financial officer), we evaluated the effectiveness of
our disclosure controls and procedures (as defined under
Rule 13a-15(e)
and
15d-15(e)
of
the Securities Exchange Act of 1934, as amended (the
Exchange Act)). Based on this evaluation, our Chief
Executive Officer and our Chief Financial Officer believe that
the disclosure controls and procedures as of March 31, 2008
were effective at a reasonable assurance level to ensure that
information we are required to disclose in the reports that we
file or submit under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified in the
SECs rules and forms and are effective to ensure that
information required to be disclosed
-13-
by us 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 March 31, 2008 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 9 to our 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.
There have been no material changes to the risk factors
disclosed in Item 1A Risk Factors in our 2007
Form 10-K.
|
|
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
|
|
|
|
|
|
3
|
.1
|
|
The Third Amended and Restated Bylaws of the Company.
|
|
10
|
.1*
|
|
Amendment No. 1 to the First Amended and Restated Agreement
of Limited Partnership of Quest Energy Partners, L.P., effective
as of January 1, 2007, by Quest Energy GP, LLC
(incorporated herein by reference to Exhibit 3.1 to Quest
Energys Current Report on
Form 8-K
on April 11, 2008).
|
|
10
|
.2*
|
|
First Amended and Restated Agreement of Limited Partnership of
Quest Energy Partners, L.P., dated as of November 15, 2007,
by and between the Company and Quest Energy GP, LLC
(incorporated herein by reference to Exhibit 3.1 to Quest
Energys Current Report on Form 8-K on November 21,
2007).
|
|
10
|
.3
|
|
Amendment No. 1 to the Second Amended and Restated
Agreement of Limited Partnership of Quest Midstream Partners,
L.P., effective as of January 1, 2007, by Quest Midstream
GP, LLC.
|
-14-
|
|
|
|
|
|
10
|
.4*
|
|
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, the Company, 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).
|
|
10
|
.5*
|
|
First Amendment to Amended and Restated Credit Agreement,
effective as of April 15, 2008, by and among Quest
Cherokee, LLC, Royal Bank of Canada, Keybank National
Association, and the Lenders Party Thereto (incorporated herein
by reference to Exhibit 10.1 to the Companys Current
Report on
Form 8-K
filed on April 23, 2008).
|
|
10
|
.6
|
|
First Amendment to Office Lease, dated as of February 7,
2008, by and between Quest Midstream Partners, L.P. and Cullen
Allen Holdings L.P.
|
|
10
|
.7
|
|
Assignment and Assumptions of Leases, dated as of
February 28, 2008, by and between Chesapeake Energy
Corporation and Quest Resource Corporation.
|
|
12
|
.1
|
|
Ratio of Earnings to Fixed Charges
|
|
31
|
.1
|
|
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.
|
|
31
|
.2
|
|
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.
|
|
32
|
.1
|
|
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.
|
|
32
|
.2
|
|
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.
|
|
|
|
*
|
|
Incorporated by reference
|
-15-
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act,
the registrant caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized this 12th day of
May, 2008.
QUEST RESOURCE CORPORATION
Jerry D. Cash
Chief Executive Officer
David E. Grose
Chief Financial Officer
-16-
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