UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ
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Quarterly report under Section 13 or 15(d) of the Securities Exchange Act of 1934
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For the quarterly period ended 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: 001-33787
QUEST ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
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Delaware
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26-0518546
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(State or other jurisdiction of
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(I.R.S. Employer Identification No.)
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incorporation or organization)
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210 Park Avenue, Suite 2750, Oklahoma City, OK
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73102
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(Address of principal executive offices)
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(Zip Code)
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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
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Non-accelerated filer
þ
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Smaller reporting company
o
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(Do not check if a smaller reporting company)
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes
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No
þ
As of May 15, 2008, the issuer had 12,301,521common units outstanding.
QUEST ENERGY PARTNERS, L.P.
FORM 10-Q
FOR THE QUARTER ENDED MARCH 31, 2008
TABLE OF CONTENTS
-2-
GUIDE TO READING THIS REPORT
As used in this report, unless we indicate otherwise:
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when we use the terms Quest Energy Partners, the Company, Successor, our, we,
us and similar terms in a historical context prior to November 15, 2007, we are referring to
Predecessor, and when we use such terms in a historical context on or after November 15, 2007,
in the present tense or prospectively, we are referring to Quest Energy Partners, L.P. and its
subsidiaries, Quest Cherokee, LLC and Quest Cherokee Oilfield Service, LLC;
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when we use the term Predecessor, we are referring to the assets, liabilities and
operations of our Parent located in the Cherokee Basin (other than its midstream assets),
which our Parent contributed to us at the completion of our initial public offering on
November 15, 2007;
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when we use the terms Quest Energy GP or our general partner, we are referring to Quest
Energy GP, LLC, our general partner;
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when we use the term our Parent, we are referring to Quest Resource Corporation (Nasdaq:
QRCP), the owner of our general partner, and its subsidiaries (other than us); and
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when we use the term Quest Midstream, we are referring to Quest Midstream Partners, L.P.
and its subsidiaries.
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-3-
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
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Attached hereto as Pages F-1 through F-18 and incorporated herein by this reference are (i)
our unaudited interim financial statements, including a consolidated balance sheet as of March 31,
2008, a consolidated statement of operations and comprehensive income and a consolidated statement
of cash flows for the three month period ended March 31, 2008 and (ii) the Predecessors unaudited
interim financial statements, including a carve out statement of operations and comprehensive
income and a carve out statement of cash flows for the three month period ended March 31, 2007.
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 (the 2007 Form 10-K).
-4-
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
BALANCE SHEETS
($ in thousands)
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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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(Consolidated)
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(Unaudited)
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(Audited)
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ASSETS
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Current assets:
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Cash
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$
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740
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$
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10,170
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Restricted cash
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1,205
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1,205
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Accounts receivable, trade
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294
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297
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Due from affiliated companies
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29,726
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12,788
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Other current assets
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2,688
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2,923
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Inventory
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6,797
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4,956
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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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41,673
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39,068
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Property and equipment, net of accumulated
depreciation of $6,873 and $6,183
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17,057
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17,063
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Oil and gas properties:
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Properties being amortized
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435,296
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406,661
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Properties not being amortized
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20,331
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19,328
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455,627
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425,989
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Less: Accumulated depreciation,
depletion, amortization and impairment
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(137,444
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)
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(127,968
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Net property plant and equipment
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318,183
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298,021
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Other assets, net
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3,420
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3,526
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Long-term derivative asset
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599
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1,568
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Total assets
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$
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380,932
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$
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359,246
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LIABILITIES AND PARTNERS EQUITY
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Current liabilities:
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Accounts payable
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$
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13,012
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$
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15,195
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Accrued expenses
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12,084
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5,056
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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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54,289
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29,158
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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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1,820
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1,700
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Notes payable
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123,484
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94,708
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Less current maturities
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(448
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(666
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Non-current liabilities
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142,059
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101,328
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Total liabilities
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196,348
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130,486
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Commitments and contingencies
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Partners equity:
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Partners equity
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201,833
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230,245
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Accumulated other comprehensive income (loss)
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(17,249
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(1,485
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Total partners equity
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184,584
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228,760
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Total liabilities and partners equity
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$
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380,932
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$
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359,246
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See accompanying notes to unaudited consolidated/carve out financial statements.
F-1
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(UNAUDITED)
($ in thousands, except per unit data)
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Successor
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Predecessor
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Three months ended March 31,
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2008
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2007
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(Consolidated)
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(Carve out)
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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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Other revenue (expense)
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50
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(13
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Total revenues
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37,403
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25,536
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Costs and expenses:
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Oil and gas production
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16,845
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13,588
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General and administrative
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2,458
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1,753
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Depreciation, depletion and amortization
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9,511
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6,694
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Total costs and expenses
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28,814
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22,035
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Operating income
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8,589
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3,501
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Other income (expense):
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Other income (expense)
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19
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107
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Change in derivative fair value
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(23,831
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(464
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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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(2,140
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(6,971
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Total other income (expense)
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(25,935
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(7,151
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Income (loss) before income taxes
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(17,346
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(3,650
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Income tax expense deferred
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Net (loss)
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(17,346
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(3,650
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Other comprehensive income (loss), net of tax:
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Change in fixed-price contract and other
derivative fair value, net of tax of $0 and $0
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(15,764
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)
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(13,480
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)
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Other comprehensive income (loss)
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(15,764
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)
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(13,480
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)
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Comprehensive income (loss)
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$
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(33,110
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)
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$
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(17,130
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)
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General partners interest in net (loss)
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$
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(347
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)
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Limited partners interest in net (loss)
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$
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(16,999
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)
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Net loss per limited partner unit:
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Common units (basic and diluted)
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$
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(0.80
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)
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Subordinated units (basic and diluted)
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$
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(0.80
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)
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Weighted average limited partner units outstanding:
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Common units (basic and diluted)
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12,301,521
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Subordinated units (basic and diluted)
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8,857,981
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See accompanying notes to unaudited consolidated/carve out financial statements.
F-2
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
STATEMENTS OF CASH FLOWS
(UNAUDITED)
($ in thousands)
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Successor
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Predecessor
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For the three months ended
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March 31,
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2008
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2007
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(Consolidated)
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(Carve out)
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Cash flows from operating activities:
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Net (loss)
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$
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(17,346
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)
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$
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(3,650
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)
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Adjustments to reconcile net income (loss) to cash provided by
(used in) operations:
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Depreciation and depletion
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10,191
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7,332
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Change in derivative fair value
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23,831
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464
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Capital contributions for directors fees
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203
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Capital contributions for employees
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868
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120
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Amortization of loan origination fees
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177
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479
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Amortization of gas swap fees
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62
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(Gain) loss on sale of assets
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(47
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)
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(65
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)
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Change in assets and liabilities:
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Accounts receivable
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30
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(2,059
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)
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Other receivables
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(24
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)
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(1,044
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)
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Other current assets
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233
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(806
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)
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Inventory
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(1,842
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)
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(604
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Due from affiliates
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(21,093
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)
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Accounts payable
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(1,989
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)
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|
1,028
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Revenue payable
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|
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1,900
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Accrued expenses
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34
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(429
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)
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Net cash provided by (used in) operating activities
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(6,774
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)
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2,728
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Cash flows from investing activities:
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Equipment, development and leasehold costs
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(19,261
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)
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(20,864
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)
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Oil and gas property acquisition
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(9,500
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)
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Net additions to other property and equipment
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(627
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)
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(2,458
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)
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Proceeds from sale of property and equipment
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922
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Net cash used in investing activities
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(29,388
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)
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(22,400
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)
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Cash flows from financing activities:
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Proceeds from bank borrowings
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29,000
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Repayments of note borrowings
|
|
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(223
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)
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(221
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)
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Syndication costs
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|
|
(201
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)
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Capital contributions (distributions)
|
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|
(1,859
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)
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|
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23,077
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Refinancing costs
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|
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(71
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)
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|
|
|
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Change in other long-term liabilities
|
|
|
86
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|
|
|
40
|
|
|
|
|
|
|
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Net cash provided by financing activities
|
|
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26,732
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|
|
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22,896
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|
|
|
|
|
|
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Net increase (decrease) in cash
|
|
|
(9,430
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)
|
|
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3,224
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Cash, beginning of period
|
|
|
10,170
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|
|
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21,334
|
|
|
|
|
|
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Cash, end of period
|
|
$
|
740
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|
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$
|
24,558
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|
|
|
|
|
|
|
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Supplemental disclosure of cash flow information:
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Cash paid during the period for:
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|
|
|
|
|
|
|
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Interest expense
|
|
$
|
1,944
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|
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$
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5,845
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Income taxes
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|
$
|
|
|
|
$
|
|
|
See accompanying notes to unaudited consolidated/carve out financial statements.
F-3
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(UNAUDITED)
1. Formation of the Company and Description of Business
Quest Energy Partners, L.P., a Delaware limited partnership (the Company), was formed in
July 2007 by Quest Resource Corporation (together with its subsidiaries, QRC) to acquire,
exploit, and develop oil and natural gas properties and to acquire, own, and operate related
assets. On November 15, 2007, the Company completed an initial public offering of its common units
representing limited partner interests (the Offering). At the closing of the Offering, QRC
contributed Quest Cherokee, LLC to the Company in exchange for general partner units, the incentive
distribution rights, common units and subordinated units in the Company. At the time, Quest
Cherokee owned all of QRCs natural gas and oil properties and related assets in the Cherokee
Basin, a fifteen-county region in southeastern Kansas and northeastern Oklahoma (the Cherokee
Basin Operations).
The Companys operations are currently focused on developing coal bed methane gas production
in the Cherokee Basin. In addition to its producing properties, the Company has a significant
inventory of potential drilling locations and acreage in the Cherokee Basin.
QRC currently owns an approximate 57% limited partner interest in the Company. Quest Energy
GP, LLC (the General Partner) is a wholly-owned subsidiary of QRC and is the general partner of
the Company.
2. Basis of Presentation
The Companys unaudited condensed consolidated/carve out financial statements included herein
have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission.
Accordingly, certain information and disclosures normally included in financial statements prepared
in accordance with accounting principles generally accepted in the United States of America have
been condensed or omitted. The Company believes that the presentations and disclosures herein are
adequate to make the information not misleading. The unaudited condensed consolidated/carve out
financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary
for a fair presentation of the interim periods. The results of operations for the interim periods
are not necessarily indicative of the results of operations to be expected for the full year. These
interim financial statements should be read in conjunction with the Companys Annual Report on Form
10-K for the year ended December 31, 2007 (the 2007 Form 10-K).
All intercompany accounts and transactions have been eliminated in preparing the
consolidated/carve out financial statements. In the Notes to Unaudited Consolidated/Carve out
Financial Statements, all dollar and unit amounts in tabulations are in thousands of dollars and
units, respectively, unless otherwise indicated.
The accompanying carve out financial statements and related notes thereto represent the carve
out financial position, results of operations and cash flows of the Cherokee Basin Operations,
referred to as Quest Energy Partners, L.P. Predecessor (the Predecessor). The carve out financial
statements have been prepared in accordance with Regulation S-X, Article 3 General instructions as
to financial statements and Staff Accounting Bulletin (SAB) Topic 1-B Allocations of Expenses
and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business
Components of Another Entity. Certain expenses incurred by QRC are only indirectly attributable to
its ownership of the Cherokee Basin Operations as QRC owns interests in midstream assets and other
gas and oil properties. As a result, certain assumptions and estimates were made in order to
allocate a reasonable share of such expenses to the Predecessor, so that the accompanying carve out
financial statements reflect substantially all the costs of doing business. The allocations and
related estimates and assumptions are described more fully in Note 3 Summary of Significant
Accounting Policies below.
3. Summary of Significant Accounting Policies
Reference is hereby made to the 2007 Form 10-K, which contains a summary of significant
accounting policies followed by the Company in the preparation of its consolidated/carve out
financial statements. These policies were also followed in preparing the consolidated/carve out
financial statements as of March 31, 2008 and for the three months ended March 31, 2008 and 2007.
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.
F-4
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(UNAUDITED)
Under this method, an
Investee companys balance sheet and results of operations are reflected within the Companys
financial statements. All significant intercompany accounts and transactions have been eliminated.
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 for the Company.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting
principles requires the Company to make estimates and assumptions that affect the amounts reported
in the consolidated/carve out financial statements and accompanying notes. Actual results could
differ from those estimates.
Estimates made in preparing the consolidated/carve out 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 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 its operations in the States of Kansas and Oklahoma and operates
exclusively in the natural gas and oil industry. The Companys joint interest and natural gas and
oil sales 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.
F-5
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(UNAUDITED)
Inventory
Inventory, which is included in current assets, includes tubular goods and other lease and
well equipment which the Company plans to utilize in its 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 and the Predecessors 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 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.
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 SEC 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-6
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(UNAUDITED)
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 March 31,
2008, 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:
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Buildings:
25 years
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Equipment:
10 years
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Vehicles:
7 years
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Debt Issue Costs
Included in other assets are costs associated with bank credit facilities. The remaining
unamortized debt issue costs at March 31, 2008 totaled $3.4 million 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, the Company did not have any investments in its investment portfolio classified
as available for sale and held to maturity.
Income Taxes
We are not a taxable entity for federal income tax purposes. As such, we do not directly pay
federal income tax. Our taxable income or loss, which may vary substantially from the net income
or net loss we report in our consolidated statement of income, is includable in the federal income
tax returns of each partner. The aggregate difference in the basis of our net assets for financial
and tax reporting purposes cannot be readily determined as we do not have access to information
about each partners tax attributes in us.
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.
F-7
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(UNAUDITED)
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 Predecessor has
entered into interest rate swaps and caps in the past 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 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 Predecessors 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. Please read Note 7 Financial Instruments and
Hedging Activities below.
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 FASBs 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.
Net Income per Limited Partner Unit
The Company calculates net income per limited partner unit in accordance with Emerging Issues
Task Force 03-06,
Participating Securities and the Two-Class Method under FASB Statement No. 128
(EITF 03-06). EITF 03-06 requires that in any accounting period where the Companys aggregate net
income exceeds its aggregate distribution for such period, it is required to present earnings per
unit as if all of the earnings for the periods were distributed, regardless of whether those
earnings would actually be distributed during a particular period from an economic or practical
perspective.
Business Segment Reporting
The Company operates in one reportable segment engaged in the exploitation, development and
production of oil and natural gas properties and all of its operations are located in the United
States.
F-8
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(UNAUDITED)
Allocation of Costs
The accompanying carve out financial statements of the Predecessor have been prepared in
accordance with SAB Topic 1-B. These rules require allocations of costs for salaries and benefits,
depreciation, rent, accounting, and legal services, and other general and administrative expenses.
QRC has allocated general and administrative expenses to the Predecessor based on time and other
costs required to properly manage the assets. In managements estimation, the allocation
methodologies used are reasonable and result in an allocation of the cost of doing business borne
by QRC on behalf of the Predecessor; however, these allocations may not be indicative of the cost
of future operations or the amount of future allocations.
Historical financial statements of the Cherokee Basin Operations for the three months ended
March 31, 2007 are presented. The historical financial statements were prepared as follows:
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Revenues include all revenues earned by the Cherokee Basin Operations, before
elimination of intercompany sales with QRC and its subsidiaries. Pursuant to the
midstream services agreement with an affiliate of the Company, Bluestem Pipeline, LLC
(Bluestem), for 2007 the fee for gathering, dehydration and treating services was
$0.50 per MMBtu of gas and $1.10 per MMBtu of gas for compression services, subject to
annual adjustment. Please read Note 12 Related Party Transactions.
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Certain common expenses of QRCs operations and the Cherokee Basin Operations
were treated as follows:
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general and administrative expenses associated with the pipeline
operations were eliminated;
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costs associated with the salt water disposal system, which were
previously reported in Bluestem operations prior to the formation of Quest Midstream
Partners, L.P. (Quest Midstream) in December 2006, were allocated to the Cherokee
Basin Operations; and
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third party costs incurred at the QRC level that are clearly identifiable
as Cherokee Basin Operations costs, such as insurance premiums related to the
Cherokee Basin Operations and legal fees of outside counsel related to contracts
entered into or claims made by or against the Cherokee Basin Operations and salaries
and benefits of Cherokee Basin Operations executives paid by QRC, were allocated to
the Cherokee Basin Operations.
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Non-producing acreage located outside of the Cherokee Basin and not transferred
to the Company was eliminated from the balance sheet and related expenses were
eliminated.
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To the extent that the common expenses described above were charged to the
Cherokee Basin Operations in the past, the reduction in expenses was retroactively
reflected with the offsetting debit to partners equity.
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Since the Company is not subject to entity level income taxes, no allocation of
income taxes or deferred income taxes was reflected in the financial statements.
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Derivative transactions remained with the Cherokee Basin Operations.
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Managements estimates of the expenses of the Cherokee Basin Operations on a
stand-alone basis were not expected to be significantly different from those reflected
in the statements.
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Earnings per Unit
During the three months ended March 31, 2007, the Cherokee Basin Operations were wholly-owned
by QRC. Accordingly, earnings per unit have not been presented for that period.
Reclassifications
Certain reclassifications have been made to the prior years financial statements to conform
to the current year presentation. These reclassifications had no effect on previously reported
results of operations or partners capital.
Recently Issued Accounting Standards
The Financial Accounting Standards Board recently issued the following standards which the
Company reviewed to determine the potential impact on its financial statements upon adoption.
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
F-9
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(UNAUDITED)
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
(SFAS 159), an amendment of 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.
4. Equity-Based Compensation
The General Partner granted 30,000 bonus units to its independent 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. In
addition, the directors are entitled to quarterly cash distribution equivalents equal to the number
of unvested bonus units and the amount of the cash distribution that the Company pays per common
unit.
For the three months ended March 31, 2008, the Company 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.
F-10
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(UNAUDITED)
5. Acquisition
Quest Cherokee 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 Cherokee 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 $87.50 for 2010. The
acquisition was financed with borrowings under Quest Cherokees credit facility.
6. Long-Term Debt
Long-term debt consists of the following:
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March 31, 2008
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December 31, 2007
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($ in thousands)
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Senior credit facility
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$
|
123,000
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$
|
94,000
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Other notes payable
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484
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708
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Total long-term debt
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123,484
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94,708
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Less current maturities
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448
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666
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Total long-term debt, net of current maturities
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$
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123,036
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$
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94,042
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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 facility prior to its maturity) (dollars in thousands):
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2008
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$
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448
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2009
|
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|
15
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2010
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123,006
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2011
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6
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2012
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8
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2013
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1
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Thereafter
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$
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123,484
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Credit Facility
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. The Company
is a guarantor of the credit agreement. See Note 4 to the financial statements included in the
2007 Form 10-K for a more detailed description of the material terms of the credit agreement. As
of March 31, 2008, the borrowing base under the credit agreement was $160 million and the amount
borrowed under the credit agreement was $123 million. The weighted average interest rate under the
credit agreement for the three months ended March 31, 2008 was 6.88%. See Note 13 Subsequent
Events for a description of the amendments to the credit agreement that became effective April 15,
2008.
Other Long-Term Indebtedness
As of March 31, 2008, $484,000 of notes payable to banks and finance companies were
outstanding. These notes are secured by equipment and vehicles, with payments due in monthly
installments through October 2013 with interest rates ranging from 5.5% to 11.5% per annum.
F-11
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(UNAUDITED)
7. 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.
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
|
)
|
F-12
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(UNAUDITED)
|
|
|
(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 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 either the board of directors of the
Predecessor or the General Partner. 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, none of the Companys fixed price
contracts qualified as cash flow hedges.
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 $28.6 million.
Interest Rate Hedging Activities
At March 31, 2008, the Company had no outstanding interest rate cap or swap agreements.
Change in Derivative Fair Value
Change in derivative fair value in the statements of operations for the three months ended
March 31, 2008 and 2007 is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
For the Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
($ 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.
F-13
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(UNAUDITED)
Credit Risk
Energy swaps, collars and basis swaps 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
the Company would be able to enter into a new contract with a third party on terms comparable to
the original contract. The Company has not experienced non-performance by its counterparties.
Cancellation or termination of a fixed-price contract would subject a greater portion of the
Companys natural gas and oil production to market prices, which, in a low price environment, could
have an adverse effect on its future operating results. In addition, the associated carrying value
of the derivative contract would be removed from the balance sheet.
Market Risk
The differential between the floating price paid under each energy swap or collar contract and
the price received at the wellhead for the Companys production is termed basis and is the result
of differences in location, quality, contract terms, timing and other variables. For instance, some
of the Companys fixed price contracts are tied to commodity prices on the New York Mercantile
Exchange (NYMEX), that is, the Company receives the fixed price amount stated in the contract and
pays to its counterparty the current market price for gas as listed on the NYMEX. However, due to
the geographic location of the Companys natural gas assets and the cost of transporting the
natural gas to another market, the amount that the Company receives when it actually sells its
natural gas is generally based on the Southern Star Central TX/KS/OK (Southern Star) first of
month index, with 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.
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.
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
|
|
$
|
(123,000
|
)
|
|
$
|
(123,000
|
)
|
|
$
|
(94,000
|
)
|
|
$
|
(94,000
|
)
|
Other financing agreements
|
|
$
|
(484
|
)
|
|
$
|
(484
|
)
|
|
$
|
(708
|
)
|
|
$
|
(708
|
)
|
F-14
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(UNAUDITED)
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 Statement of Financial Accounting Standards 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.
8. 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:
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
Predecessor
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2008
|
|
2007
|
|
|
($ in thousand)
|
Asset retirement obligation beginning balance
|
|
$
|
1,700
|
|
|
$
|
1,410
|
|
Liabilities incurred
|
|
|
87
|
|
|
|
42
|
|
Liabilities settled
|
|
|
(1
|
)
|
|
|
(1
|
)
|
Accretion expense
|
|
|
34
|
|
|
|
26
|
|
Revisions in estimated cash flows
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation ending balance
|
|
$
|
1,820
|
|
|
$
|
1,477
|
|
|
|
|
9. Partners Equity
On January 21, 2008, the board of directors of the General Partner declared a $0.2043 per unit
distribution for the fourth quarter of 2007 on all common and subordinated units. This distribution
was based on the initial quarterly distribution rate of $0.40 per unit, but was prorated for the
actual number of days the units were outstanding. The distribution was paid on February 14, 2008 to
unitholders of record at the close of business on February 7, 2008. The aggregate amount of the
distribution was $4.4 million.
On April 25, 2008, the board of directors of the General Partner declared a $0.41 per unit
distribution for the first quarter of 2008 on all common and subordinated units. The distribution
will be paid on May 15, 2008 to unitholders of record at the close of business on May 5, 2008. The
aggregate amount of the distribution will be $8.85 million.
10. Net Loss Per Limited Partner Unit
The computation of net loss per limited partner unit is based on the weighted average number
of common and subordinated units outstanding during the year. Basic and diluted net loss per
limited partner unit is determined by dividing net loss, after deducting the amount allocated to
the general partner interest (including its incentive distribution in excess of its 2% interest),
by the weighted average number of outstanding limited partner units during the period in accordance
with Emerging Issues Task Force 03-06,
Participating Securities and the Two-Class Method under FASB
Statement No. 128
.
F-15
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(UNAUDITED)
The following sets forth the net loss allocation using this method:
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
|
Three Months Ended
|
|
|
|
March 31, 2008
|
|
|
|
|
|
|
|
Per Limited
|
|
|
|
$
|
|
|
Partner Unit
|
|
Net loss
|
|
$
|
(17,346
|
)
|
|
|
|
|
Less: General partners 2% interest in net loss
|
|
|
347
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss available for limited partners
|
|
$
|
(16,999
|
)
|
|
$
|
(0.80
|
)
|
|
|
|
|
|
|
|
We did not declare a cash distribution during the period January 1, 2008 through March 31,
2008 which would result in an incentive distribution to the general partner as indicated above.
11. 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, 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.
F-16
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(UNAUDITED)
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 intends 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.
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
F-17
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(UNAUDITED)
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.
12. Related Party Transactions
The Company employs its own field employees and first level supervisor. The management level
and general and administrative employees supporting the operations of the Company are employees of
Quest Energy Service, LLC, a Company affiliate. In addition to employee payroll-related expenses,
QRC incurred general and administrative expenses related to leasing of office space and other
corporate overhead type expenses during the period covered by these financial statements. A portion
of the consolidated general and administrative and indirect lease operating overhead expenses of
QRC, determined based on time and other
costs required to properly manage the assets, has been allocated to the Company and included
in the accompanying statements of operations for each of the periods presented.
Midstream Services Agreement
. QRC controls Quest Midstream through its 85% ownership of Quest
Midstreams general partner and its ownership of approximately 35% of Quest Midstreams limited
partner interests. Quest Midstream owns and operates an over 1,800 mile gas gathering pipeline
system in the Cherokee Basin. Effective November 15, 2007, Quest Resource assigned all of its
rights in that certain Midstream Services and Gas Dedication Agreement (Midstream Services
Agreement) to the Company. Under the Midstream Services Agreement, Quest Midstream gathers and
provides certain midstream services to the Company for all gas produced from the Companys wells in
the Cherokee Basin that are connected to Quest Midstreams gathering system. The initial term of
the Midstream Services Agreement expires on December 1, 2016, with two additional five-year renewal
periods that may be exercised by either party upon 180 days notice. Under the Midstream Services
Agreement, the Company pays Quest Midstream $0.51 per MMBtu of gas for gathering, dehydration and
treating services and $1.13 per MMBtu of gas for compression services, subject to annual adjustment
based on changes in gas prices and the producer price index. Such fees are subject to renegotiation
upon the exercise of each five-year extension period. In addition, at any time after each five year
anniversary of the date of the midstream services agreement, each party will have a one-time option
to elect to renegotiate the fees and/or the basis for the annual adjustment to the fees if the
party believes there has been a material change to the economic returns or financial condition of
either party. If the parties are unable to agree on the changes, if any, to be made to such terms,
then the parties will enter into binding arbitration to resolve any dispute with respect to such
terms.
Under the terms of some of the Cherokee Basin Operations gas leases, the Company may not be
able to charge the full amount of these fees to royalty owners, which would increase the average
fees per MMBtu that the Company effectively pays under the Midstream Services Agreement.
Quest Midstream has an exclusive option for sixty days to connect to its gathering system all
of the gas wells that the Company develops in the Cherokee Basin. In addition, Quest Midstream is
required to connect to its gathering system, at its expense, any new gas wells that the Company
completes in the Cherokee Basin if Quest Midstream would earn a specified internal rate of return
from those wells. This rate of return is subject to renegotiation once after the fifth anniversary
of the agreement and once during each renewal period at the election of either party. The Midstream
Services Agreement also requires the drilling of a minimum of 750 new wells in the Cherokee Basin
during the two year period ending December 1, 2008.
In addition, Quest Midstream agreed to install the saltwater disposal lines for the Companys
gas wells connected to Quest Midstreams gathering system for a fee of $1.25 per linear foot and
connect such lines to the Companys saltwater disposal wells for a fee of $1,000 per well, subject
to an annual adjustment based on changes in the Employment Cost Index for Natural Resources,
Construction, and Maintenance. For 2008, the fees are $1.29 per linear foot to install saltwater
disposal lines and $1,030 per well to connect such lines to the Companys saltwater disposal wells.
Management Services Agreement.
The Company and Quest Energy Service are parties to a
management services agreement, dated November 15, 2007, pursuant to which Quest Energy Service
provides the Company with legal, information technology, accounting, finance, insurance, tax,
property management, engineering, administrative, risk management, corporate development,
commercial and marketing, treasury, human resources, audit, investor relations and acquisition
services in respect of opportunities for the Company to acquire long-lived, stable and proved gas
and oil reserves.
The Company reimburses Quest Energy Service for the reasonable costs of the services it
provides to the Company. The employees of Quest Energy Service also manage the operations of QRC
and Quest Midstream and will be reimbursed by QRC and
F-18
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(UNAUDITED)
Quest Midstream for general and
administrative services incurred on their respective behalf. These expenses include salary, bonus,
incentive compensation and other amounts paid to persons who perform services for the Company or on
its behalf, and expenses allocated to Quest Energy Service by its affiliates. The General Partner
is entitled to determine in good faith the expenses that are allocable to the Company.
The General Partner has the right and the duty to review the services provided, and the costs
charged, by Quest Energy Service under the management services agreement. The General Partner may
in the future cause the Company to hire additional personnel to supplement or replace some or all
of the services provided by Quest Energy Service, as well as employ third-party service providers.
If the Company were to take such actions, they could increase the overall costs of the Companys
operations.
The management services agreement is not terminable by the Company without cause so long as
QRC controls the General Partner. Thereafter, the agreement is terminable by either the Company or
Quest Energy Service upon six months notice. The
management services agreement is terminable by the Company or QRC upon a material breach of
the agreement by the other party and failure to remedy such breach for 60 days (or 30 days in the
event of nonpayment) after receiving notice of the breach.
Quest Energy Service will not be liable to the Company for its performance of, or failure to
perform, services under the management services agreement unless its acts or omissions constitute
gross negligence or willful misconduct.
Omnibus Agreement.
The Company and QRC are parties to an omnibus agreement, dated November
15, 2007, which governs the Companys relationship with QRC and its subsidiaries with respect to
certain matters not governed by the management services agreement.
Under the omnibus agreement, QRC and its subsidiaries agreed to give the Company a right to
purchase any natural gas or oil wells or other natural gas or oil rights and related equipment and
facilities that they acquire within the Cherokee Basin, but not including any midstream or
downstream assets. Except as provided above, QRC is not restricted, under either the Companys
partnership agreement or the omnibus agreement, from competing with the Company and may acquire,
construct or dispose of additional gas and oil properties or other assets in the future without any
obligation to offer the Company the opportunity to acquire those assets.
Under the omnibus agreement, QRC will indemnify the Company for three years after November 15,
2007 against certain potential environmental claims, losses and expenses associated with the
operation of the assets occurring before the closing date of the offering. Additionally, QRC will
indemnify the Company for losses attributable to title defects (for three years after November 15,
2007), retained assets and income taxes attributable to pre-closing operations (for the applicable
statute of limitations). QRCs maximum liability for the environmental indemnification obligations
will not exceed $5.0 million and QRC will not have any indemnification obligation for environmental
claims or title defects until the Companys aggregate losses exceed $500,000. QRC will have no
indemnification obligations with respect to environmental claims made as a result of additions to
or modifications of environmental laws promulgated after November 15, 2007. The Company has agreed
to indemnify QRC against environmental liabilities related to the Companys assets to the extent
QRC is not required to indemnify the Company. The Company also will indemnify QRC for all losses
attributable to post-November 15, 2007 operations of the assets contributed to the Company, to the
extent not subject to QRCs indemnification obligations.
Any or all of the provisions of the omnibus agreement, other than the indemnification
provisions described above, are terminable by QRC at its option if the General Partner is removed
without cause and units held by the General Partner and its affiliates are not voted in favor of
that removal. The omnibus agreement will also terminate in the event of a change of control of the
Company or the General Partner.
Midstream Omnibus Agreement.
The Company is subject to a midstream omnibus agreement dated as
of December 22, 2006, among Quest Midstream, Quest Midstreams general partner, Quest Midstreams
operating subsidiary and QRC so long as the Company is an affiliate of QRC and QRC or any of its
affiliates controls Quest Midstream.
The midstream omnibus agreement restricts the Company from engaging in the following
businesses (each of which is referred to as a Restricted Business):
|
|
|
the gathering, treating, processing and transporting of gas in North America;
|
|
|
|
|
the transporting and fractionating of gas liquids in North America;
|
F-19
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(UNAUDITED)
|
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any other midstream activities, including but not limited to crude oil storage, transportation, gathering and terminaling;
|
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|
constructing, buying or selling any assets related to the foregoing businesses; and
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any line of business other than those described in the preceding bullet points that generates qualifying income, within
the meaning of Section 7704(d) of the Code, other than any business that is primarily engaged in the exploration for and
production of oil or gas and the sale and marketing of gas and oil derived from such exploration and production
activities.
|
If a business described in the last bullet point above has been offered to Quest Midstream and
it has declined the opportunity to purchase that business, then that line of business is no longer
considered a Restricted Business.
The following are not considered a Restricted Business:
|
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the ownership of a passive investment of less than 5% in an entity engaged in a Restricted Business;
|
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any business in which Quest Midstream permits the Company to engage;
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the ownership or operation of assets used in a Restricted Business if the value of the assets is less than $4 million; and
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any business that the Company has given Quest Midstream the option to acquire and it has elected not to purchase.
|
Subject to certain exceptions, if the Company were to acquire any midstream assets in the
future pursuant to the above provisions, then Quest Midstream will have a preferential right to
acquire those midstream assets in the event of a sale or transfer of those assets by the Company.
If the Company acquires any acreage located outside the Cherokee Basin that is not subject to
any existing agreement with an unaffiliated party to provide midstream services, Quest Midstream
will have a preferential right to offer to provide midstream services to the Company in connection
with wells to be developed by the Company on that acreage.
Contribution, Conveyance and Assumption Agreement.
On November 15, 2007, the Company and QRC
entered into a contribution, conveyance and assumption agreement to effect, among other things, the
transfer of QRCs Cherokee Basin Operations to the Company, the issuance of 3,201,521 common units
and 8,857,981 subordinated units to QRC and the issuance to the General Partner of 431,827 general
partner units and the incentive distribution rights. The Company agreed to indemnify QRC for
liabilities arising out of or related to existing litigation relating to the assets, liabilities
and operations located in the Cherokee Basin transferred to the Company.
13. Subsequent Events
On April 17, 2008, the Company 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 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-20
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
Business of Issuer
We are a Delaware limited partnership formed in July 2007 by Quest Resource to acquire,
exploit and develop oil and natural gas properties. Our primary business objective is to generate
stable cash flows allowing us to make quarterly cash distributions to our unitholders at our
initial distribution rate and, over time, to increase our quarterly cash distributions. Our
operations are currently focused on the development of coal bed methane in the Cherokee Basin.
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 Quest Midstreams gas gathering pipeline system.
For the three months ended March 31, 2008, our average net daily production was 55.6 Mmcfe/d.
We 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, we 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 $87.50 for 2010. The acquisition was financed
with borrowings under our credit facility.
Results of Operations
The following discussion of the results of operations and period-to-period comparisons
presented below includes the historical results of the Predecessor. This discussion should be read
in conjunction with the financial statements included in this report; and should further be read in
conjunction with the audited financial statements and notes thereto of the Predecessor included in
our 2007 Form 10-K. Comparisons made between reporting periods herein are for the three month
periods ended March 31, 2008 as compared to the same period in 2007. As discussed under Item 7.
Managements Discussion and Analysis of Financial Condition and Results of Operations Factors
That Significantly Affect Comparability of Our Results in our 2007 Form 10-K, the Predecessors
historical results of operations and period-to-period comparisons of its results may not be
indicative of our future results.
Overview.
The following discussion of results of operations will compare balances for the
three months ended March 31, 2008 and 2007.
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|
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Successor
|
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Predecessor
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Three Months
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Ended
|
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|
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March 31,
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Increase/
|
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|
2008
|
|
2007
|
|
(Decrease)
|
|
|
|
|
|
|
($ 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
|
|
$
|
8,182
|
|
|
$
|
7,227
|
|
|
$
|
955
|
|
|
|
13.2
|
%
|
Transportation expense (related affiliate)
|
|
$
|
8,663
|
|
|
$
|
6,361
|
|
|
$
|
2,302
|
|
|
|
36.2
|
%
|
Depreciation, depletion and amortization
|
|
$
|
9,511
|
|
|
$
|
6,694
|
|
|
$
|
2,814
|
|
|
|
41.8
|
%
|
General and administrative expenses
|
|
$
|
2,458
|
|
|
$
|
1,753
|
|
|
$
|
705
|
|
|
|
40.2
|
%
|
Change in derivative fair value
|
|
$
|
(23,831
|
)
|
|
$
|
(464
|
)
|
|
$
|
(23,367
|
)
|
|
|
(5,036.0
|
)%
|
Interest expense
|
|
$
|
2,140
|
|
|
$
|
6,971
|
|
|
$
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(4,831
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)
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(69.3
|
)%
|
5
Production.
The following table presents the primary components of revenues, as well as the
average costs per Mcfe, for the three months ended March 31, 2008 and 2007.
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Successor
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Predecessor
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For the three months ended
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|
March 31,
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Increase
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2008
|
|
2007
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|
(Decrease)
|
Production Data (net):
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|
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|
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|
|
|
|
|
|
Natural gas production (MMcf)
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|
4,991
|
|
|
|
3,716
|
|
|
|
1,275
|
|
|
|
34.3
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%
|
Oil production (Bbl)
|
|
|
11,188
|
|
|
|
2,020
|
|
|
|
9,168
|
|
|
|
453.9
|
%
|
Total production (MMcfe)
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|
|
5,058
|
|
|
|
3,728
|
|
|
|
1,330
|
|
|
|
35.7
|
%
|
Average daily production (MMcfe/d)
|
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|
55.6
|
|
|
|
41.4
|
|
|
|
14.2
|
|
|
|
34.3
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%
|
Average Sales Price per Unit (Mcfe):
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excluding hedges
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$
|
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 (related affiliate)
|
|
$
|
1.72
|
|
|
$
|
1.71
|
|
|
$
|
0.01
|
|
|
|
0.6
|
%
|
Depreciation, depletion and amortization
|
|
$
|
1.88
|
|
|
$
|
1.80
|
|
|
$
|
0.08
|
|
|
|
4.4
|
%
|
General and administrative expenses
|
|
$
|
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
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 $16.8 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 $5.2 million, production taxes of $1.1 million, ad valorem taxes of $888,000, and
transportation expenses of $6.4 million, a total increase of $3.2 million, or 23.5%.
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 $1.41 per Mcfe for the three
months ended March 31, 2007 representing a 20.6% 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.
6
General and Administrative Expenses.
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 is due to an increase in board fees, professional fees, Nasdaq listing fees,
travel expenses for presentations to increase our visibility with investors, larger corporate
offices, 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 approximately $2.1 million for the quarter
ended March 31, 2008 from $7.0 million for the quarter ended March 31, 2007, due to the refinancing
of our credit facilities in 2007 in connection with our initial public offering and lower
outstanding borrowings.
Net Income
We recorded a net loss of $17.3 million for the quarter ended March 31, 2008 as compared to a
net loss of $3.7 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 for the
quarter ended March 31, 2008.
Liquidity and Capital Resources
Liquidity
Our primary sources of liquidity are cash generated from our operations, amounts available
under our revolving credit facility and funds from future private and public equity and debt
offerings. In connection with the closing of our initial public offering, Quest Cherokee, our
principal operating subsidiary, entered into a new 5-year $250 million revolving credit agreement,
with an initial borrowing base of $160.0 million, with a syndicate of financial institutions. As
of March 31, 2008, we had $123 million borrowed under our revolving credit facility. Please read
Notes 6 and 13 to our financial statements included in this report for additional information
regarding our revolving credit facility.
At March 31, 2008, we had $37 million of availability under our revolving credit facility,
which was available to fund the drilling and completion of additional gas wells, the recompletion
of single seam wells into multi-seam wells, the acquisition of additional acreage, equipment and
vehicle replacement and purchases and the construction of salt water disposal facilities.
Our partnership agreement requires that we distribute our available cash. In making cash
distributions, our general partner will attempt to avoid large variations in the amount we
distribute from quarter to quarter. In order to facilitate this, our partnership agreement permits
our general partner to establish cash reserves to be used to pay distributions for any one or more
of the next four quarters. In addition, our partnership agreement allows our general partner to
borrow funds to make distributions.
At March 31, 2008, we had current assets of $41.7 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 $15.9 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 $11.4 million at December 31, 2007. The changes in working capital were primarily
due to the change in derivative fair value.
Because of the seasonal nature of gas and oil, we may make short-term working capital
borrowings in order to level out our distributions during the year. In addition, a substantial
portion of our production is hedged. We are generally required to settle a portion of our commodity
hedges on each of the 5
th
and 25
th
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 25
th
day of the following month. As a result,
7
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.
If this were to occur, we may make working capital borrowings to fund our distributions. Because
we will distribute our available cash, we will not have those amounts available to reinvest in our
business to increase our reserves and production. Because we will distribute a substantial amount
of our cash flows (after making principal and interest payments on our indebtedness) rather than
reinvest those cash flows in our business, we may not grow as quickly as other companies or at all.
Capital Expenditures
During
the three months ended March 31, 2008, a total of approximately
$29.4 million of
capital expenditures was invested as follows: $25.8 million was invested in new natural gas wells
and properties, $3.0 million in acquiring leasehold and $627,000 in other additional capital items.
These investments were funded by cash flow from operations, and remaining cash from the proceeds of our
borrowings of $29 million under our credit facility.
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;
|
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 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 and our asset base over the long term.
|
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. 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 4 Long-Term Debt to our financial statements included our 2007 Form 10-K for a
description of the financial covenants contained in our revolving credit facility. 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 used in operating
activities totaled $6.8
million for the three months ended March 31, 2008 as compared to
$2.7 million in net cash provided by operating activities for the three months
ended March 31, 2007. This decrease resulted from a change in derivative fair value, an increase in
accounts receivable, inventory and accrued expenses.
Cash
Flows Used in Investing Activities.
Net cash used in investing
activities totaled $29.4
million for the three months ended March 31, 2008 as compared to $22.4 million for the three months
ended March 31, 2007. During the three months ended
March 31, 2008, a total of approximately $29.4
million of capital expenditures was invested as follows: $25.8 million was invested in new natural
gas wells and properties, $3.0 million in acquiring leasehold and $627,000 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 $22.9 million for the three months ended March 31, 2007,
and related to the financing of capital
8
expenditures. The net cash provided from financing
activities during the three months ended March 31, 2008 was due primarily to $29 million of
borrowings under the Quest Cherokee credit facility.
Contractual Obligations
Future payments due on our contractual obligations as of March 31, 2008 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due By Period
|
|
|
|
|
|
|
|
Less
|
|
|
|
|
|
|
|
|
|
|
More
|
|
|
|
|
|
|
|
Than 1
|
|
|
1-3
|
|
|
4-5
|
|
|
Than 5
|
|
|
|
Total
|
|
|
Year
|
|
|
Years
|
|
|
Years
|
|
|
Years
|
|
|
|
($ in thousands)
|
|
|
|
|
Revolving Credit Facility (2)
|
|
$
|
123,000
|
|
|
$
|
|
|
|
$
|
123,000
|
|
|
$
|
|
|
|
$
|
|
|
Notes payable
|
|
|
484
|
|
|
|
448
|
|
|
|
21
|
|
|
|
14
|
|
|
|
1
|
|
Interest expense obligation (1)(2)
|
|
|
22,373
|
|
|
|
6,580
|
|
|
|
15,790
|
|
|
|
2
|
|
|
|
1
|
|
Drilling contractor
|
|
|
2,548
|
|
|
|
2,548
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation
|
|
|
1,820
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,820
|
|
Derivatives
|
|
|
45,948
|
|
|
|
28,745
|
|
|
|
17,203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
196,173
|
|
|
$
|
38,321
|
|
|
$
|
156,014
|
|
|
$
|
16
|
|
|
$
|
1,822
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The interest expense 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 $4.8 million. Effective April 15, 2008, the interest rate on our
revolving credit facility was increased by 1%. This change has been reflected in the table
above. See Note 13 to the financial statements included in this report.
|
|
(2)
|
|
Effective April 15, 2008, the maturity date for the revolving credit facility was
changed from November 15, 2012 to November 14, 2010. This change has been reflected in
the table above. See Note 13 to the financial statements included in this report.
|
Critical Accounting Policies and Estimates
The consolidated/carve out 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 3 to our
consolidated carve out financial statements. See also Item 7. Managements Discussion and
Analysis of Financial Condition and Results of OperationsCritical 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.
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;
|
9
|
|
|
business strategy;
|
|
|
|
|
budgets;
|
|
|
|
|
amount, nature and timing of capital expenditures;
|
|
|
|
|
drilling of wells;
|
|
|
|
|
acquisition and development of natural gas and oil properties;
|
|
|
|
|
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;
|
|
|
|
|
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;
|
|
|
|
|
fluctuations in the commodity prices for natural gas and crude oil;
|
|
|
|
|
engineering and mechanical or technological difficulties with operational equipment, in well completions
and workovers, and in drilling new wells;
|
|
|
|
|
land issues;
|
|
|
|
|
the effects of government regulation and permitting and other legal requirements;
|
|
|
|
|
labor problems;
|
|
|
|
|
environmental related problems;
|
|
|
|
|
the uncertainty inherent in estimating future natural gas and oil production or reserves;
|
|
|
|
|
production variances from expectations;
|
|
|
|
|
the substantial capital expenditures required for the drilling of wells and the related need to fund such capital requirements through commercial banks and/or public securities markets;
|
10
|
|
|
disruptions, capacity constraints in or other limitations on Quest Midstreams pipeline systems;
|
|
|
|
|
costs associated with perfecting title for natural gas and oil rights in some of our properties;
|
|
|
|
|
the need to develop and replace reserves;
|
|
|
|
|
competition;
|
|
|
|
|
dependence upon key personnel;
|
|
|
|
|
the lack of liquidity of our equity securities;
|
|
|
|
|
operating hazards attendant to the natural gas and oil business;
|
|
|
|
|
down-hole drilling and completion risks that are generally not recoverable from third parties or insurance;
|
|
|
|
|
potential mechanical failure or under-performance of significant wells;
|
|
|
|
|
climatic conditions;
|
|
|
|
|
natural disasters;
|
|
|
|
|
acts of terrorism;
|
|
|
|
|
availability and cost of material and equipment;
|
|
|
|
|
delays in anticipated start-up dates;
|
|
|
|
|
our ability to find and retain skilled personnel;
|
|
|
|
|
availability of capital;
|
|
|
|
|
the strength and financial resources of our competitors; and
|
|
|
|
|
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 7 to our
consolidated/carve out financial statements.
Item 4(T). Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We have established and maintain a system of disclosure controls and procedures to provide
reasonable assurances that information required to be disclosed by us in the reports that we file
or submit under the Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the SECs rules and forms. Based on the evaluation of our disclosure controls
and procedures as of the end of the period covered by this report, the principal executive officer
and principal financial officer of our general partner have concluded that our disclosure controls
and procedures as of March 31, 2008 were effective, at a reasonable assurance level, in ensuring
that the information required to be disclosed by us in reports filed under the Exchange Act is
recorded,
11
processed, summarized and reported within the time periods specified in the rules and
forms of the SEC and is accumulated and communicated to our management, including our principal
executive officer and principal financial officer of our general partner, 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 11 to our consolidated/carve out financial statements entitled
Commitments and Contingencies, which is incorporated herein by reference.
In addition, from time to time, we may be subject to legal proceedings and claims that arise
in the ordinary course of our business. Although no assurance can be given, management believes,
based on its experiences to date, that the ultimate resolution of such items will not have a
material adverse impact on our business, financial position or results of operations.
Item 1A. Risk Factors
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.
12
Item 6. Exhibits
|
|
|
|
|
3.1*
|
|
Amendment No. 1 to 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 Energy Partners, L.P.s Current Report on
Form 8-K filed on April 11, 2008).
|
|
|
|
|
3.2*
|
|
First Amended and Restated Agreement of Limited Partnership of Quest
Energy Partners, L.P., dated as of November 15, 2007, by and between
Quest Energy GP, LLC and Quest Resource Corporation (incorporated
herein by reference to Exhibit 3.1 to Quest Energy Partners, L.P.s
Current Report on Form 8-K filed on November 21, 2007).
|
|
|
|
|
10.1*
|
|
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 Quest
Energy Partners, L.P.s Current Report on Form 8-K filed on April
23, 2008).
|
|
|
|
|
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.
|
13
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant caused
this report to be signed on its behalf by the undersigned, thereunto
duly authorized this 15th day
of May, 2008.
QUEST ENERGY PARTNERS, L.P.
By: Quest Energy GP, LLC, its general partner
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|
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By:
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/s/ Jerry D. Cash
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Jerry D. Cash
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Chief Executive Officer
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By:
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/s/ David E. Grose
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David E. Grose
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Chief Financial Officer
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14
Quest Energy Partners, L.P. (MM) (NASDAQ:QELP)
Historical Stock Chart
From Jun 2024 to Jul 2024
Quest Energy Partners, L.P. (MM) (NASDAQ:QELP)
Historical Stock Chart
From Jul 2023 to Jul 2024