UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
December 31, 2008
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Commission file
number: 0-17371
QUEST RESOURCE
CORPORATION
(Exact Name of Registrant as
Specified in Its Charter)
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Nevada
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90-0196936
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(State or Other Jurisdiction
of
Incorporation or Organization)
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(I.R.S. Employer
Identification No.)
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210 Park Avenue, Suite 2750
Oklahoma City, Oklahoma
(Address of Principal
Executive
Offices)
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73102
(Zip
Code)
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Registrants telephone number, including area code:
405-600-7704
Securities Registered Pursuant to Section 12(b) of the
Exchange Act:
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Stock
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NASDAQ Global Market
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Series B Junior Participating Preferred Stock Purchase
Rights
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NASDAQ Global Market
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Securities Registered Pursuant to Section 12(g) of the
Exchange Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes
o
No
þ
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or 15(d) of the
Act. Yes
o
No
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Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes
o
No
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Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate website, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§ 229.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files). Yes
o
No
o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(§ 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrants
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this
Form 10-K
or any amendment to this
Form 10-K.
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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
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Accelerated
filer
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Non-accelerated
filer
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Smaller
reporting
company
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(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes
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No
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The aggregate market value of the voting common equity held by
non-affiliates computed by reference to the last reported sale
of the registrants common stock on June 30, 2008, the
last business day of the registrants most recently
completed second fiscal quarter, at $11.41 per share was
$221,824,377. This figure assumes that only the directors and
officers of the registrant, their spouses and controlled
corporations were affiliates. There were 31,867,527 shares
outstanding of the registrants common stock as of
May 15, 2009.
DOCUMENTS
INCORPORATED BY REFERENCE
None
EXPLANATORY
NOTE
This Annual Report on
Form 10-K
for the year ended December 31, 2008 includes restated and
reaudited consolidated financial statements for Quest Resource
Corporation (QRCP or the Company) as of
December 31, 2007 and 2006 and for the periods ended
December 31, 2007, 2006 and 2005. QRCP will subsequently
file (i) an amended Quarterly Report on
Form 10-Q/A
for the quarter ended March 31, 2008 including restated
consolidated financial statements as of December 31, 2007
and March 31, 2008 and for the three month periods ended
March 31, 2008 and 2007; (ii) an amended Quarterly
Report on
Form 10-Q/A
for the quarter ended June 30, 2008 including restated
consolidated financial statements as of December 31, 2007
and June 30, 2008 and for the three and six month periods
ended June 30, 2008 and 2007; and (iii) a Quarterly
Report on
Form 10-Q
for the quarter ended September 30, 2008 including restated
consolidated financial statements as of December 31, 2007
and for the three and nine month periods ended
September 30, 2007.
Investigation
On August 22, 2008, in
connection with an inquiry from the Oklahoma Department of
Securities, the boards of directors of QRCP, Quest Energy GP,
LLC (Quest Energy GP), the general partner of Quest
Energy Partners, L.P. (NASDAQ: QELP) (Quest Energy
or QELP), which is a publicly traded limited
partnership controlled by QRCP, and Quest Midstream GP, LLC
(Quest Midstream GP), the general partner of Quest
Midstream Partners, L.P. (Quest Midstream or
QMLP), a private limited partnership controlled by
QRCP, held a joint working session to address certain
unauthorized transfers, repayments and re-transfers of funds
(the Transfers) to entities controlled by their
former chief executive officer, Mr. Jerry D. Cash.
A joint special committee comprised of one member designated by
each of the boards of directors of QRCP, Quest Energy GP, and
Quest Midstream GP was immediately appointed to oversee an
independent internal investigation of the Transfers. In
connection with this investigation, other errors were identified
in prior year financial statements and management and the board
of directors concluded that the Company had material weaknesses
in its internal control over financial reporting. As of
December 31, 2008, these material weaknesses continued to
exist.
As reported on a Current Report on
Form 8-K
filed on January 2, 2009, on December 31, 2008, the
board of directors of QRCP determined that the audited
consolidated financial statements of QRCP as of and for the
years ended December 31, 2007, 2006 and 2005 and
QRCPs unaudited consolidated financial statements as of
and for the three months ended March 31, 2008 and as of and
for the three and six months ended June 30, 2008 should no
longer be relied upon.
Restatement and Reaudit
In October 2008,
QRCPs audit committee engaged a new independent registered
public accounting firm to audit the Companys consolidated
financial statements for 2008 and, in January 2009, engaged them
to reaudit the Companys consolidated financial statements
as of December 31, 2007 and 2006 and for the years ended
December 31, 2007, 2006 and 2005.
The restated consolidated financial statements included in this
Form 10-K
correct errors in a majority of the financial statement line
items in the previously issued consolidated financial statements
for all periods presented. The most significant errors (by
dollar amount) consist of the following:
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The Transfers, which were not approved expenditures of QRCP,
were not properly accounted for as losses.
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Hedge accounting was inappropriately applied for QRCPs
commodity derivative instruments and the valuation of commodity
derivative instruments was incorrectly computed.
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Errors were identified in the accounting for the formation of
Quest Cherokee, LLC (Quest Cherokee) in December
2003 in which: (i) no value was ascribed to the Quest
Cherokee Class A units that were issued to Arclight Energy
Partners Fund I, L.P. (ArcLight) in connection
with the transaction, (ii) a debt discount (and related
accretion) and minority interest were not recorded,
(iii) transaction costs were inappropriately capitalized to
oil and gas properties, and (iv) subsequent to December
2003, interest expense was improperly stated as a result of
these errors. In 2005, the debt relating to this transaction was
repaid and the Class A units were repurchased from
ArcLight. Due to the errors that existed in the previous
accounting, additional errors resulted in 2005 including:
(i) a loss on extinguishment of debt was not recorded, and
(ii) oil and gas
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properties, pipeline assets and retained earnings were
overstated. Subsequent to the 2005 transaction, depreciation,
depletion and amortization expense was also overstated due to
these errors.
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Certain general and administrative expenses unrelated to oil and
gas production were inappropriately capitalized to oil and gas
properties, and certain operating expenses were inappropriately
capitalized to oil and gas properties being amortized. These
items resulted in errors in valuation of the full cost pool, oil
and gas production expenses and general and administrative
expenses.
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Invoices were not properly accrued resulting in the
understatement of accounts payable and numerous other balance
sheet and income statement accounts.
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Capitalized interest was not recorded on pipeline construction.
As a result, pipeline assets and accumulated deficit were
understated and interest expense was overstated in all periods
presented.
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Errors were identified in stock-based compensation expense,
including the use of incorrect grant dates, valuation errors,
and incorrect vesting periods.
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As a result of previously discussed errors and an additional
error related to the methods used in calculating depreciation,
depletion and amortization, errors existed in our depreciation,
depletion and amortization expense and our accumulated
depreciation, depletion and amortization.
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As a result of previously discussed errors relating to oil and
gas properties and hedge accounting and errors relating to the
treatment of deferred taxes, errors existed in our ceiling test
calculations.
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Errors were identified in the calculation of outstanding shares
in all periods as we inappropriately included restricted share
grants in our calculation of issued shares when the restrictions
lapsed, rather than the date at which the restricted shares were
granted. This error did not affect net income, but did impact
our issued and outstanding share amounts as well as our weighted
average share amounts.
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Although the items listed above comprise the most significant
errors (by dollar amount), numerous other errors were identified
and restatement adjustments made. The tables below present
previously reported stockholders (deficit) equity, major
restatement adjustments and restated stockholders
(deficit) equity as well as previously reported net income
(loss), major restatement adjustments and restated net income
(loss) as of and for the periods indicated (in thousands):
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As of December 31,
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2007
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2006
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2005
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Stockholders (deficit) equity as previously reported
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$
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91,853
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$
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117,354
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$
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115,673
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Effect of the Transfers
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(10,000
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(8,000
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(2,000
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Reversal of hedge accounting
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707
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(2,389
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(8,177
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Accounting for formation of Quest Cherokee
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(19,055
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(19,159
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(19,185
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Capitalization of costs in full cost pool
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(23,936
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(12,748
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(5,388
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Recognition of costs in proper periods
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(1,987
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(321
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(316
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Capitalized interest
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1,713
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1,367
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286
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Stock-based compensation
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Depreciation, depletion and amortization
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10,450
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7,209
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3,275
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Impairment of oil and gas properties
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30,719
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30,719
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Other errors
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(3,695
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809
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(383
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Stockholders (deficit) equity as restated
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$
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76,769
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$
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114,841
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$
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83,785
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4
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Years Ended December 31,
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2007
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2006
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2005
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Net income (loss) as previously reported
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$
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(30,414
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$
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(48,478
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$
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(31,951
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Effect of the Transfers
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(2,000
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(6,000
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(2,000
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Reversal of hedge accounting
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1,183
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53,387
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(42,854
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Accounting for formation of Quest Cherokee
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104
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26
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(14,402
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Capitalization of costs in full cost pool
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(11,188
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(7,360
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(5,388
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Recognition of costs in proper periods
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(1,666
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(5
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721
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Capitalized interest
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346
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1,081
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154
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Stock-based compensation
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(702
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405
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(790
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Depreciation, depletion and amortization
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3,241
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3,934
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757
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Impairment of oil and gas properties
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30,719
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Other errors(*)
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(3,058
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1,799
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(132
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Net income (loss) as restated
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$
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(44,154
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$
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29,508
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$
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(95,885
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* Includes minority interest impact.
Reconciliations from amounts previously included in QRCPs
consolidated financial statements to restated amounts on a
financial statement line item basis are presented in
Note 18 to the accompanying consolidated financial
statements.
Other Matters
In addition to the items for
which QRCP has restated its consolidated financial statements,
the Oklahoma Department of Securities has filed a lawsuit
alleging:
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An additional theft of approximately $1.0 million by David
Grose, the former chief financial officer of QRCP, and Brent
Mueller, the former purchasing manager of QRCP. The evidence
indicates that this theft occurred in the third quarter of 2008
and was uncovered prior to the preparation of the financial
statements for such period, and therefore did not result in a
restatement.
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A kickback scheme involving the former chief financial officer
and the former purchasing manager, in which the former chief
financial officer and the former purchasing manager received
kickbacks totaling approximately $0.9 million each from
several related suppliers beginning in 2005.
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QRCP experienced significant increased costs in the second half
of 2008 and continues to experience such increased costs in the
first half of 2009 due to, among other things (as more fully
described in Items 1. and 2. Business and
Properties Recent Developments Internal
Investigation; Restatements and Reaudits):
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the necessary retention of numerous professionals, including
consultants to perform the accounting and finance functions
following the termination of the chief financial officer,
independent legal counsel to conduct the internal investigation,
investment bankers and financial advisors, and law firms to
respond to the class action and derivative suits that have been
filed against QRCP and its affiliates and to pursue the claims
against the former employees;
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costs associated with amending the credit agreements of QRCP,
Quest Energy and Quest Midstream;
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preparing the restated consolidated financial statements; and
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conducting the reaudits of the restated consolidated financial
statements.
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All dollar amounts and other data presented in previously filed
Annual Reports on
Form 10-K
for prior years have been revised to reflect the restated
amounts throughout this
Form 10-K,
even where such amounts are not labeled as restated.
5
PART I
ITEMS 1.
AND 2.
BUSINESS AND PROPERTIES.
General
Quest Resource Corporation is a Nevada corporation. Our
principal executive offices are located at 210 Park Avenue,
Suite 2750, Oklahoma City, Oklahoma 73102 and our telephone
number is
(405) 600-7704.
Unless the context clearly requires otherwise, references in
this report to we, us, and
our refer to the Company and its subsidiaries and
affiliates, including Quest Energy and Quest Midstream, on a
consolidated basis. Quest Energy is a publicly traded limited
partnership engaged in oil and gas production operations. Quest
Midstream is a private limited partnership engaged in natural
gas pipeline operations.
We are an integrated independent energy company engaged in the
acquisition, exploration, development, production and
transportation of oil and natural gas.
We divide our operations into two reportable business segments:
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Oil and gas production, and
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Natural gas pipelines, including transporting, gathering,
treating and processing natural gas.
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Financial information by segment and revenues from our external
customers are located in Item 8. Financial Statements
and Supplementary Data to this Annual Report on
Form 10-K.
Quest
Resource Corporation
QRCPs assets as of May 15, 2009 consist of the
following:
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Approximately 45,732 net acres, five gross wells in various
stages of completion and approximately 183 miles of gas
gathering pipeline in the Appalachian Basin, owned by
QRCPs wholly-owned subsidiary, Quest Eastern Resource LLC
(Quest Eastern).
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3,201,521 common units and 8,857,981 subordinated units in Quest
Energy representing an approximate 55.9% limited partner
interest in Quest Energy.
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All of the membership interests in Quest Energy GP, the general
partner of Quest Energy, which owns the 2.0% general partner
interest in Quest Energy and all of the incentive distribution
rights in Quest Energy.
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35,134 Class A subordinated units and 4,900,000
Class B subordinated units in Quest Midstream representing
an approximate 35.69% limited partner interest in Quest
Midstream.
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85% of the membership interests in Quest Midstream GP, the
general partner of Quest Midstream, which owns the 2.0% general
partner interest in Quest Midstream and all of the incentive
distribution rights in Quest Midstream.
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6
The following chart reflects a simplified version of our
organizational structure to better illustrate how we own our
assets.
Since the initial public offering of Quest Energy in November
2007, QRCPs potential sources of revenue and cash flows
consist almost exclusively of distributions on its partnership
interests in Quest Energy and Quest Midstream, because its
Appalachian Basin assets largely consist of undeveloped acreage.
Both Quest Energy and Quest Midstream are required by the terms
of their partnership agreements to distribute all cash on hand
at the end of each quarter, less reserves established by their
general partners in their sole discretion to provide for the
proper conduct of their respective businesses or to provide for
future distributions.
In light of the decline in QELPs cash flows from
operations due to declines in oil and natural gas prices during
the last half of 2008, the costs of the investigation and
associated remedial actions, including the reaudit and
restatement of its financial statements, and concerns about a
potential borrowing base redetermination in the second quarter
of 2009 and the need to repay or refinance QELPs term loan
by September 30, 2009, the board of directors of Quest
Energy GP decided to suspend distributions on QELPs
subordinated units for the third quarter of 2008 and on all
units starting with the distribution for the fourth quarter of
2008 in order to conserve cash to properly conduct operations,
maintain strategic options and plan for future required
principal payments under Quest Energys debt instruments.
QRCP would have received approximately $20 million from
Quest Energy during 2009 if the minimum quarterly distribution
of $0.40 was paid on all of Quest Energys units for the
full year.
Quest Midstream did not pay any distributions on any of its
units for the third or fourth quarters of 2008 because of a
restriction imposed under the terms of an amendment to its
credit agreement which provided that no distributions could be
paid until the audited financial statements for the year ended
December 31, 2008 were delivered to the lenders and
thereafter could only be paid if, after the payment of such
distributions, the total leverage ratio was not greater than 4.0
to 1.0. The Quest Midstream audited financial statements for the
year ended December 31, 2008 were delivered on
March 31, 2009.
QRCP received cash distributions from Quest Energy of
$1.9 million during the first quarter of 2008,
$3.8 million during the second quarter of 2008,
$4.0 million during the third quarter of 2008 and
$0.2 million during the fourth quarter of 2008. QRCP did
not receive any cash distributions from Quest Midstream during
2008. No distributions have ever been paid on the Quest Energy
or Quest Midstream incentive distribution rights.
7
QRCP does not expect to receive any distributions from Quest
Energy or Quest Midstream in 2009 and is unable to estimate at
this time when such distributions may be resumed. In October and
November of 2008, QRCPs credit agreement and the credit
agreements for each of Quest Energy and Quest Midstream were
amended. See Item 7. Managements Discussion and
Analysis of Financial Condition and Results of
Operations Liquidity and Capital
Resources Credit Agreements. The amended terms
of the credit agreements restrict the ability of Quest Energy
and Quest Midstream to pay distributions, among other things.
Even if the restrictions on the payment of distributions under
Quest Energys and Quest Midstreams credit agreements
are removed, both partnerships may continue to not pay
distributions in order to conserve cash for the repayment of
indebtedness or other business purposes.
Arrearages accrue for the unpaid distributions on the common
units in Quest Energy and Quest Midstream and the related
distributions on the general partner units. Quest Energy and
Quest Midstream are not obligated to ever pay these amounts, but
they may not make distributions on the subordinated units QRCP
owns until all arrearages on the common units and the related
general partner units have been paid. The majority of the
interests QRCP owns, however, are subordinated units. QRCP owns
8,857,981 subordinated units in Quest Energy and 35,134
Class A subordinated units and 4,900,000 Class B
subordinated units in Quest Midstream. QRCP also indirectly owns
incentive distribution rights in Quest Energy and Quest
Midstream that would entitle it to receive an increasing
percentage of cash distributed by each of Quest Energy and Quest
Midstream if certain target distribution levels were reached. No
incentive distributions can be paid in a quarter until all
arrearages on the common units have been paid and the minimum
quarterly distribution has been paid for that quarter on all
common units and subordinated units. The subordinated units and
the incentive distribution rights do not accrue arrearages.
Even if Quest Energy and Quest Midstream do not pay
distributions, the Company and all other unitholders may be
liable for taxes on their share of each of Quest Energy and
Quest Midstreams taxable income.
Although QRCP is not currently receiving distributions from
Quest Energy or Quest Midstream, QRCP continues to require cash
to fund general and administrative expenses, debt service
requirements, capital expenditures to develop and maintain its
undeveloped acreage, drilling commitments and payments to
landowners necessary to maintain its oil and gas leases, which
are expected to average $2.7 million per quarter for 2009.
As of December 31, 2008, excluding QELP and QMLP, QRCP had
cash and cash equivalents of $4.0 million and no ability to
borrow under the terms of its credit agreement. QRCP currently
estimates that it will not have enough cash to pay its expenses,
including capital expenditures and debt service requirements,
after August 31, 2009. Our independent registered public
accounting firm has expressed doubt about our ability to
continue as a going concern. See Item 1A. Risk
Factors Risks Related to Our Business
Our independent registered public accounting firm has expressed
substantial doubt about our ability to continue as a going
concern. The August 31, 2009 date could be extended
if QRCP is able to restructure its debt obligations, issue
equity securities
and/or
sell
additional assets. If QRCP is not successful in obtaining
sufficient additional funds, there is a significant risk that
QRCP will be forced to file for bankruptcy protection. See
Item 1A. Risk Factors Risks Related to
Our Business QRCPs potential sources of
revenue and cash flows consist almost exclusively of
distributions from Quest Energy and Quest Midstream, neither of
which is expected to pay distributions in 2009 and as a result,
we do not expect QRCP to be able to meet its cash disbursement
obligations unless it engages in transactions outside the
ordinary course of business.
Oil
and Gas Production
Cherokee Basin.
We currently conduct our oil
and gas production operations in the Cherokee Basin through
QELP. QELPs oil and gas production operations are
primarily focused on the development of coal bed methane or CBM
in a 15-county region in southeastern Kansas and northeastern
Oklahoma known as the Cherokee Basin. As of December 31,
2008, QELP had 152.7 Bcfe of estimated net proved reserves
in the Cherokee Basin, of which approximately 97.7% were CBM and
81.6% were proved developed. QELP operates approximately 99% of
its existing Cherokee Basin wells, with an average net working
interest of approximately 99% and an average net revenue
interest of approximately 82%. We believe QELP is the largest
producer of natural gas in the Cherokee Basin with an average
net daily production of 57.3 Mmcfe for the year ended
December 31, 2008. QELPs estimated net proved
reserves in the Cherokee Basin at December 31, 2008 had
estimated future net revenues discounted at 10%, which we refer
to as the standardized measure, of
$129.8 million. QELPs Cherokee Basin reserves have an
8
average proved
reserve-to-production
ratio of 7.3 years (5.0 years for QELPs proved
developed properties) as of December 31, 2008. QELPs
typical Cherokee Basin CBM well has a predictable production
profile and a standard economic life of approximately
15 years.
As of December 31, 2008, QELP was operating approximately
2,438 gross gas wells in the Cherokee Basin, of which over
95% were multi-seam wells, and 27 gross oil wells. As of
December 31, 2008, QELP owned the development rights to
approximately 557,603 net acres throughout the Cherokee
Basin and had only developed approximately 59.6% of its acreage.
For 2009, QELP has budgeted approximately $3.8 million to
drill seven new gross wells, connect and complete 49 existing
gross wells, and connect and complete three existing salt water
disposal wells in the Cherokee Basin. All of these new gas wells
will be drilled on locations that are classified as containing
proved reserves in our December 31, 2008 reserve report. In
2009, QELP plans to recomplete an estimated 10 gross wells,
and has budgeted another $1.9 million for equipment,
vehicle replacement, and other capital purchases. Recompletions
generally consist of converting wells that were originally
completed with single seam completions into multi-seam
completions, which allows QELP to produce additional gas from
different depths. In addition, QELP has budgeted
$2.4 million related to lease renewals and extensions for
acreage that is expiring in 2009. However, QELP intends to fund
these capital expenditures only to the extent that QELP has
available cash from operations after taking into account its
debt service obligations. We can give no assurance that any such
funds will be available. For 2008, QELP had total capital
expenditures of approximately $79 million, including
$47 million to complete 328 gross wells and recomplete
or restimulate 70 gross wells, which was within the
budgeted amount. As of December 31, 2008, QELPs
undeveloped acreage contained approximately 1,893 gross CBM
drilling locations, of which approximately 624 were classified
as proved undeveloped. Over 97% of the CBM wells that have been
drilled on QELPs acreage to date have been successful.
Historically, QELPs Cherokee Basin acreage was developed
utilizing primarily
160-acre
spacing. However, during 2008, QELP developed some areas on
80-acre
spacing. QELP is currently evaluating the results of this
80-acre
spacing program. None of QELPs acreage or producing wells
are associated with coal mining operations.
Seminole County, Oklahoma.
We also currently
conduct our oil production operations in Seminole County,
Oklahoma through Quest Energy. QELP owns 55 gross
productive oil wells and the development rights to approximately
1,481 net acres in Seminole County, Oklahoma. As of
December 31, 2008, the oil producing properties had
estimated net proved reserves of 588,800 Bbls, all of which
are proved developed producing. During 2008, net production for
QELPs Seminole County properties was 148 Bbls/d.
QELPs oil production operations in Seminole County are
primarily focused on the development of the Hunton Formation. We
believe there are approximately 11 horizontal drilling
locations for the Hunton Formation on QELPs acreage.
QELPs ability to drill and develop these locations depends
on a number of factors, including the availability of capital,
seasonal conditions, regulatory approval, oil prices, costs and
drilling results. There were no proved undeveloped reserves
given to these locations as of December 31, 2008.
Appalachian Basin.
Both QELP and QRCP own
producing properties in Appalachia that are operated by Quest
Eastern, formerly PetroEdge Resources (WV), LLC
(PetroEdge), which we acquired on July 11,
2008. All production for 2008 was owned by QELP. In February
2009, QRCP began production in the Marcellus Shale in Wetzel
County, West Virginia.
Our oil and gas production operations in the Appalachian Basin
are primarily focused on the development of the Marcellus Shale.
We believe there are approximately 334 potential gross vertical
well locations and approximately 123 potential gross horizontal
well locations for the Marcellus Shale, including significant
development opportunities for Devonian Sands and Brown Shales.
These potential well locations are located within QRCPs
acreage in West Virginia and New York.
On July 11, 2008, QRCP consummated the acquisition of
PetroEdge for approximately $142 million, including
transaction costs, after taking into account post-closing
adjustments. The assets acquired were approximately
78,000 net acres of oil and natural gas producing
properties in the Appalachian Basin with estimated proved
reserves of 99.6 Bcfe as of May 1, 2008 and net production
of approximately 3.3 Mmcfe/d. Simultaneous with the closing,
QRCP sold oil and natural gas producing wells with estimated
proved developed reserves of 32.9 Bcfe as of May 1, 2008
and all of the current net production to QELP for cash
consideration of approximately $72 million, subject to
post-closing adjustment. As of December 31, 2008, there
were approximately 10.9 Bcfe of estimated net
9
proved developed reserves associated with the Appalachian Basin
assets sold to QELP. The remaining assets retained by QRCP had,
as of December 31, 2008, an additional 7.7 Bcfe of
estimated net proved undeveloped reserves. The 18.6 Bcfe of
estimated net proved reserves in the Appalachian Basin, as of
December 31, 2008 were approximately 68% proved developed.
The decrease in estimated reserves is due primarily to a
decrease in natural gas prices between May 1, 2008, the
date of the PetroEdge reserve report, and year-end
(35.5 Bcfe), and revisions due to further technical
analysis of the reserves (43.2 Bcfe). Upon further
technical analysis, we discovered that the Marcellus zone proved
developed non-producing reserves associated with 82 wells,
totaling 14.6 Bcfe, were not completed and were not
directly offset by productive wells, and were therefore removed.
Well performance for certain producing wells was judged not to
be meeting expectation and the reserves expected to be recovered
from such wells was reduced by 2.6 Bcfe. The proved
undeveloped reserves acquired were evaluated by an independent
reservoir engineering firm other than Cawley, Gillespie &
Associates, Inc. at the time of the PetroEdge acquisition. The
evaluation included proved undeveloped locations based upon acre
spacing, assuming blanket coverage of the area by productive
zones. Securities and Exchange Commission (SEC)
rules require a proved undeveloped location to be recorded in
reserves only if it is directly offset by a productive well. At
the time of the acquisition, 145 locations, totaling
26.0 Bcfe, were included in the reserve report that have
all been removed from the reserve report prepared at year end
December 31, 2008. The personnel responsible for analyzing
and validating the reserve report used for this acquisition are
no longer employed by the Company.
As of December 31, 2008, QELP owned approximately
500 gross gas wells in the Appalachian Basin. Quest Eastern
operates approximately 99% of these existing wells on behalf of
QELP, with QELP having an average net working interest of
approximately 93% and an average net revenue interest of
approximately 75%. QELPs average net daily production in
the Appalachian Basin was approximately 2.9 Mmcfe for the
year ended December 31, 2008. QELPs estimated net
proved reserves at December 31, 2008 were 10.9 Bcfe
and had a standardized measure of $19.6 million.
QELPs reserves in the Appalachian Basin have an average
proved reserve-to-production ratio of 17.5 years
(10.7 years for QELPs proved developed properties) as
of December 31, 2008. QELPs typical Marcellus Shale
well has a predictable production profile and a standard
economic life of approximately 50 years.
As of December 31, 2008, QRCP owned the development rights
to approximately 68,161 net acres throughout the
Appalachian Basin and had only developed approximately 12% of
its acreage. See Recent Developments below
for further information regarding our Appalachian Basin assets.
As of December 31, 2008, QRCPs proved undeveloped
acreage contained approximately 22 gross drilling locations.
For 2009, QRCP has budgeted approximately $2.4 million of
net expenditures to drill one gross vertical well, complete
three gross wells and connect four gross wells. This one
new well will be drilled on a location that is classified as
containing proved reserves in our December 31, 2008 reserve
report. QELP has budgeted another $1.4 million for
artificial lift equipment, vehicle replacement and purchases and
salt water disposal facilities. However, QRCP and QELP intend to
fund these capital expenditures only to the extent that they
have available cash after taking into account their debt service
and other obligations. We can give no assurance that any such
funds will be available based on current commodity prices and
other current conditions.
Natural
Gas Pipelines Operations
We conduct our natural gas pipelines operations through Quest
Midstream and Quest Eastern.
Cherokee Basin.
Bluestem Pipeline, LLC, a
wholly-owned subsidiary of Quest Midstream
(Bluestem), owns and operates a natural gas
gathering pipeline network of approximately 2,173 miles
that serves our acreage position in the Cherokee Basin.
Presently, this system has a maximum daily throughput of
approximately 85 Mmcf/d and is operating at about 90%
capacity. Quest Energy transports 99% of its Cherokee Basin gas
production through Bluestems gas gathering pipeline
network to interstate pipeline delivery points. Approximately 6%
of the current throughput on Bluestems natural gas
gathering pipeline system is for third parties.
As of December 31, 2008, QELP had an inventory of
approximately 185 gross drilled CBM wells awaiting connection to
QMLPs gas gathering system.
Interstate Pipeline System.
Quest Pipelines
(KPC), which we refer to as KPC, owns and operates a
1,120 mile interstate natural gas pipeline (the KPC
Pipeline) which transports natural gas from northern
Oklahoma and western
10
Kansas to the metropolitan Wichita and Kansas City markets.
Further, it is one of only three pipeline systems currently
capable of delivering gas into the Kansas City metropolitan
market. The KPC system includes three compressor stations with a
total of 14,680 horsepower and has a throughput capacity of
approximately 160 Mmcf/d. KPC has supply interconnections
with pipelines owned
and/or
operated by Enogex Inc., Panhandle Eastern PipeLine Company and
ANR Pipeline Company, allowing QMLP to transport natural gas
volumes sourced from the Anadarko and Arkoma basins, as well as
the western Kansas and Oklahoma panhandle producing regions.
KPCs two primary customers are Kansas Gas Service (KGS)
and Missouri Gas Energy (MGE), both of which are served under
firm natural gas transportation contracts. KGS, a division of
ONEOK, Inc., is the local distribution company in Kansas for
Kansas City and Wichita as well as a number of other
municipalities. MGE, a division of Southern Union Company, is a
natural gas distribution company that serves over a half-million
customers in 155 western Missouri communities.
Appalachian Basin.
Quest Eastern owns and
operates a gas gathering pipeline network of approximately
183 miles that serves our acreage position in the
Appalachian Basin. The pipeline delivers both to intrastate
gathering and interstate pipeline delivery points. Presently,
this system has a maximum daily throughput of approximately
15.0 Mmcf/d and is operating at about 20% capacity. All of
QELPs Appalachian Basin gas production is transported by
Quest Easterns gas gathering pipeline network. Less than
1% of the current volumes transported on Quest Easterns
natural gas gathering pipeline system are for third parties.
Organizational
Structure
The following chart reflects our complete organizational
structure. The chart excludes 15,000 QELP common units issued,
or to be issued, to QELPs independent directors and
117,877 QMLP common units and 15,000 Class B subordinated
units issued, or to be issued, to QMLPs independent
directors and officers.
11
Recent
Developments
PetroEdge
Acquisition
As discussed above under General
Oil and Gas Production Appalachian Basin, on
July 11, 2008, QRCP acquired PetroEdge and simultaneously
transferred PetroEdges oil and natural gas producing wells
to Quest Energy. This acquisition followed closely after
QRCPs June 4, 2008 acquisition of a one-year option
to purchase certain drilling and other rights in and below the
Marcellus Shale (the Deep Rights) in and to certain
oil and gas leases covering approximately 28,700 acres in
Potter County, Pennsylvania for $4 million. Certain
provisions of the option agreement gave us rights to drill wells
in the Deep Rights during the one-year option period.
Quest Energy funded its purchase of the PetroEdge wellbores with
borrowings under its revolving credit facility, which was
increased from $160 million to $190 million as part of
the acquisition, and the proceeds of a $45 million,
six-month term loan under a Second Lien Senior Term Loan
Agreement (the Second Lien Loan Agreement) with
Royal Bank of Canada (RBC), as administrative agent
and collateral agent, KeyBank National Association, as
syndication agent, Société Générale, as
documentation agent, and the lenders party thereto.
QRCP funded the balance of the PetroEdge acquisition with
proceeds from a public offering of 8,800,000 shares of QRCP
common stock at a price of $10.25 per share that closed on
July 8, 2008. QRCP received net proceeds from this offering
of approximately $85.2 million. Simultaneously with the
closing of the PetroEdge acquisition, QRCP entered into an
Amended and Restated Credit Agreement (the Credit
Agreement) to convert its then existing $50 million
revolving credit facility to a $35 million term loan with a
maturity date of July 11, 2010. The Credit Agreement is
among QRCP, as the borrower, RBC, as administrative agent and
collateral agent, and the lenders party thereto. RBC required
QRCP to use $13 million of the proceeds from the equity
offering to reduce the outstanding indebtedness under the Credit
Agreement from $48 million to $35 million.
The purpose of the PetroEdge acquisition was to expand our
operations to another geologic basin with less basis
differential, that had significant resource potential. The
acquisition closed during the peak month of natural gas pricing
in 2008.
Internal
Investigation; Restatements and Reaudits
On August 23, 2008, only six weeks after the PetroEdge
transaction closed, our then chief executive officer resigned
following the discovery of the Transfers. The Transfers were
brought to the attention of the boards of directors of each of
the Company, Quest Energy GP and Quest Midstream GP as a result
of an inquiry and investigation that had been initiated by the
Oklahoma Department of Securities. The Companys board of
directors, jointly with the boards of directors of Quest Energy
GP and Quest Midstream GP, formed a joint special committee to
investigate the matter and to consider the effect on our
consolidated financial statements. The joint special committee
retained numerous professionals to assist with the internal
investigation and other matters during the period following the
discovery of the Transfers. To conduct the internal
investigation, independent legal counsel was retained to report
to the joint special committee and to interact with various
government agencies, including the Oklahoma Department of
Securities, the Federal Bureau of Investigation, the Department
of Justice, the Securities and Exchange Commission and the
Internal Revenue Service (IRS). We also retained a
new independent registered public accounting firm to reaudit our
consolidated financial statements.
The investigation is substantially complete. The investigation
revealed that the Transfers resulted in a loss of funds totaling
approximately $10 million by the Company. Further, it was
determined that our former chief financial officer directly
participated
and/or
materially aided our former chief executive officer in
connection with the unauthorized Transfers. In addition, the
Oklahoma Department of Securities has filed a lawsuit alleging
that our former chief financial officer and our former
purchasing manager each received kickbacks of approximately
$0.9 million from several related suppliers over a two-year
period and that during the third quarter of 2008, they also
engaged in the direct theft of $1 million for their
personal benefit and use. In March 2009, Mr. Mueller, the
former purchasing manager, pled guilty to one felony count of
misprision of justice. Sentencing is pending. We have filed
lawsuits against all three of these individuals seeking an asset
freeze and damages related to the Transfers, kickbacks and
thefts and we intend to pursue all remedies available under the
law. We settled the lawsuits against Mr. Cash on
May 19, 2009. See Settlement
Agreements below. There can be no assurance that we will
be
12
successful in recovering any additional amounts. Any additional
recoveries may consist of assets other than cash and accurately
valuing such assets in the current economic climate may be
difficult. Any amounts recovered will be recognized by us for
financial accounting purposes only in the period in which the
recovery occurs.
QRCP, Quest Energy, Quest Energy GP and certain of their
officers and directors have been named as defendants in a number
of securities class action lawsuits and stockholder derivative
lawsuits arising out of or related to the Transfers. See
Item 3. Legal Proceedings.
We experienced significant increased costs in the second half of
2008 and continue to experience such increased costs in the
first half of 2009 due to, among other things:
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We had costs associated with the internal investigation and our
responding to inquiries from the Oklahoma Department of
Securities, the Federal Bureau of Investigation, the Department
of Justice, the SEC and the IRS.
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As a result of the termination of the former chief executive
officer and chief financial officer, we immediately retained
consultants to perform the accounting and finance functions and
to assist in the determination of the intercompany debt
discussed below under Intercompany
Accounts.
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We retained law firms to respond to the class action and
derivative suits that have been filed against QRCP, Quest Energy
GP and QELP and to pursue the claims against the former
employees.
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We had costs associated with amending the credit agreements of
QRCP, QELP and QMLP and obtaining the necessary waivers from our
lenders thereunder as well as incremental increased interest
expense related thereto. See Item 7.
Managements Discussion and Analysis of Financial
Condition and Results of Operations Liquidity and
Capital Resources.
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We retained external auditors, who completed reaudits of the
restated consolidated financial statements for the years ended
December 31, 2007, 2006 and 2005.
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The Company, QELP and QMLP each retained financial advisors to
consider strategic options and each retained outside legal
counsel or increased the amount of work being performed by its
previously engaged outside legal counsel.
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We estimate that the increased costs related to the foregoing
will be between approximately $7.0 million and
$8.0 million.
Global
Financial Crisis and Impact on Capital Markets and Commodity
Prices
At about the same time as the Transfers were discovered, the
global economy experienced a significant downturn. The crisis
began over concerns related to the U.S. financial system
and quickly grew to impact a wide range of industries. There
were two significant ramifications to the exploration and
production industry as the economy continued to deteriorate. The
first was that capital markets essentially froze. Equity, debt
and credit markets shut down. Future growth opportunities have
been and are expected to continue to be constrained by the lack
of access to liquidity in the financial markets.
The second impact to the industry was that fear of global
recession resulted in a significant decline in oil and gas
prices. In addition to the decline in oil and gas prices, the
differential from NYMEX pricing to our sales point for our
Cherokee Basin gas production has widened and is still at
unprecedented levels of volatility.
Our operations and financial condition are significantly
impacted by these prices. During the year ended
December 31, 2008, the NYMEX monthly gas index price (last
day) ranged from a high of $13.58 per Mmbtu to a low of $5.29
per Mmbtu. Natural gas prices came under pressure in the second
half of the year as a result of lower domestic product demand
that was caused by the weakening economy and concerns over
excess supply of natural gas. In the Cherokee Basin, where we
produce and sell most of our gas, there has been a widening of
the historical discount of prices in the area to the NYMEX
pricing point at Henry Hub as a result of elevated levels of
natural gas drilling activity in the region and a lack of
pipeline takeaway capacity. During 2008, this discount (or basis
differential) in the Cherokee Basin ranged from $0.67 per Mmbtu
to $3.62 per Mmbtu.
13
The spot price for NYMEX crude oil in 2008 ranged from a high of
$145.29 per barrel in early July to a low of $33.87 per barrel
in late December. The volatility in oil prices during the year
was a result of the worldwide recession, geopolitical
activities, worldwide supply disruptions, actions taken by the
Organization of Petroleum Exporting Countries and the value of
the U.S. dollar in international currency markets as well
as domestic concerns about refinery utilization and petroleum
product inventories pushing prices up during the first half of
the year. Due to our relatively low level of oil production
relative to gas and our existing commodity hedge positions, the
volatility of oil prices had less of an effect on our operations.
Overall, as a result, our operating profitability was seriously
adversely affected during the second half of 2008 and is
expected to continue to be impaired during 2009. While our
existing commodity hedge position mitigates the impact of
commodity price declines, it does not eliminate the potential
effects of changing commodity prices.
See Item 1A. Risk Factors Risks Related
to Our Business The current financial crisis and
economic conditions may have a material adverse impact on our
business and financial condition that we cannot predict.
Management
Personnel Changes
In connection with the investigation of the Transfers, Jerry
Cash, our former Chairman of the Board and Chief Executive
Officer, resigned on August 23, 2008, and David Grose, our
former Chief Financial Officer, was placed on administrative
leave on August 22, 2008. On August 24, 2008, our
Chief Operating Officer, David Lawler, was appointed President,
and Jack Collins, our Executive Vice President of Investor
Relations, was appointed Interim Chief Financial Officer. On
September 13, 2008, Mr. Grose was terminated from all
positions with us. Eddie LeBlanc became our Chief Financial
Officer on January 9, 2009, with Mr. Collins becoming
our Executive Vice President of Finance/Corporate Development.
On May 7, 2009, Mr. Lawler was appointed our Chief
Executive Officer. On July 11, 2008, Richard Muncrief
resigned as President and Chief Operating Officer of Quest
Midstream GP to pursue other opportunities, and on
September 30, 2008, Michael Forbau was elected the Chief
Operating Officer of Quest Midstream GP.
NASDAQ
Non-compliance
Our common stock is currently listed on the NASDAQ Global
Market. On November 19, 2008, we received a letter from the
staff of NASDAQ indicating that, because of our failure to
timely file our
Form 10-Q
for the quarter ended September 30, 2008, we no longer
complied with the continued listing requirements set forth in
NASDAQ Marketplace Rule 4310(c)(14) (now
Rule 5250(c)(1)). As permitted by NASDAQ rules, we timely
submitted a plan to NASDAQ staff to regain compliance on
January 20, 2009. Following a review of this plan, NASDAQ
staff granted us an extension until May 11, 2009 to file
our
Form 10-Q.
We did not file our
Form 10-Q
for the quarter ended September 30, 2008 on that date. On
May 12, 2009, we received a staff determination notice (the
Staff Determination) from NASDAQ stating that our
common stock is subject to delisting since we were not in
compliance with the filing requirements for continued listing.
The NASDAQ Listing Qualifications Hearing Panel (the
Panel) granted our request for a hearing to appeal
the Staff Determination and has scheduled a hearing for
June 11, 2009. The Panel has stayed the delisting of our
common stock through such date to allow us additional time to
file our delinquent periodic reports with the SEC. If we have
not filed all of our delinquent periodic reports by
June 11, 2009, there can be no assurances that the Panel
will grant a further extension to allow us additional time to
file such reports or that our common stock will not be delisted.
Credit
Agreement Amendments
In October and November 2008, QRCP, Quest Cherokee and Quest
Energy, and Quest Midstream and Bluestem entered into amendments
to their respective credit agreements that, among other things,
amended
and/or
waived certain of the representations and covenants contained in
each credit agreement in order to rectify any possible covenant
violations or non-compliance with the representations and
warranties as a result of (1) the Transfers and
(2) not timely settling certain intercompany accounts among
QRCP, Quest Energy and Quest Midstream. The Quest Cherokee
amendment also extended the maturity date of the Second Lien
Loan Agreement from January 11, 2009 to September 30,
2009 due to our inability to refinance the Second Lien Loan
Agreement as a
14
result of a combination of the ongoing investigation and the
global financial crisis. The amendments also restricted the
ability of Quest Midstream and Quest Energy to pay distributions
to QRCP.
In May 2009, QRCP entered into an amendment to the Credit
Agreement to, among other things, waive certain events of
default related to its financial covenants and collateral
requirements, extend certain financial reporting deadlines and
permit the settlement agreements with Mr. Cash discussed
below.
See Managements Discussion and Analysis of Financial
Condition and Results of Operations Liquidity and
Capital Resources Credit Agreements for
additional information regarding our credit agreements.
Suspension
of Distributions and Asset Sales
As discussed above under General Quest
Resource Corporation, distributions were suspended on
Quest Energys subordinated units beginning with the third
quarter of 2008 and distributions were suspended on all of Quest
Energys units, beginning with the fourth quarter of 2008.
Distributions were suspended on all of Quest Midstreams
units beginning with the third quarter of 2008. Since these
distributions would have been substantially all of QRCPs
cash flows for 2009, the loss of the distributions was material
to QRCPs financial position.
In October 2008, we negotiated an additional $6 million
term loan under the Credit Agreement with a maturity date of
November 30, 2008. We agreed with our lenders that the
additional term loan would be repaid with the net proceeds from
asset sales by QRCP and that the first $4.5 million of net
proceeds in excess of any additional term loans that were
borrowed would be used to repay QRCPs $35 million
term loan.
On October 30, 2008, QRCP sold its interest in
approximately 22,600 net undeveloped acres and one well in
Somerset County, Pennsylvania to a private party for
approximately $6.8 million. On November 26, 2008, QRCP
sold its interest in the development rights and related purchase
option, which it had purchased on June 4, 2008 covering
approximately 28,700 acres in Potter County, Pennsylvania,
to an undisclosed party for approximately $3.2 million. On
February 13, 2009, QRCP sold its interest in approximately
23,076 net undeveloped acres in the Marcellus Shale and one
well in Lycoming County, Pennsylvania to a third party for
approximately $8.7 million. Management decided that these
undeveloped acres were good candidates for disposition in the
current environment given the lack of gathering and
transportation infrastructure in the immediate area and the cost
and time that would be involved in establishing significant flow
of natural gas.
In addition to these sales, on November 5, 2008, QRCP sold
a 50% interest in approximately 4,500 net undeveloped
acres, three wells in various stages of completion and existing
pipelines and facilities in Wetzel County, West Virginia to
another party for $6.1 million. QRCP will continue to
operate the Wetzel County property. All future development costs
will be split equally between QRCP and the other party. This
joint venture arrangement allows QRCP to retain a significant
interest in the Wetzel County property, which we believe is a
desirable asset due to established infrastructure, pipeline taps
and proved offset production in the area.
QRCP borrowed $2 million of the additional $6 million
term loan under its Credit Agreement in October 2008. A portion
of the net proceeds from the asset sales were used to repay the
$2 million additional term loan and to reduce QRCPs
$35 million term loan to $28.3 million as of
May 15, 2009.
Intercompany
Accounts
As part of the investigation, we determined that our former
chief financial officer had not been promptly settling
intercompany accounts among the Company, Quest Midstream and
Quest Energy. Intercompany balances as of September 30,
2008 were quantified and have been paid: QRCP paid Quest
Midstream $3.6 million in October 2008, $2.0 million
in November 2008 and an additional $0.2 million, including
interest, in February 2009; and Quest Energy paid Quest
Midstream $4.0 million, including interest, in February
2009. The Companys payments were funded with the proceeds
from the asset sales. The remainder of the proceeds from these
sales are being used to fund QRCPs ongoing operations.
15
Cost-cutting
Measures
In addition to the sales of assets and suspension of
distributions discussed above, during the third and fourth
quarters of 2008, we took significant actions to reduce our
costs and retain cash for anticipated debt service requirements
for QRCP and Quest Energy during 2009. Among other things, we
renegotiated and postponed drilling commitments related to the
PetroEdge properties, we significantly reduced our level of
maintenance and expansion capital expenditures, we hired
Mr. LeBlanc as our Chief Financial Officer (which allowed
us to terminate the consultants that had been hired to assist
our interim chief financial officer) and we eliminated 56 field
positions and 3 corporate positions. We continue to evaluate
additional options to further reduce our expenditures.
Decrease
in Year-End Reserves; Impairment
Due to the low price for natural gas as of December 31,
2008 as described above, revisions resulting from further
technical analysis (see Note 21 Supplemental
Information on Oil and Gas Producing Activities (Unaudited) to
the accompanying consolidated financial statements) and
production during the year, proved reserves decreased 17.2% to
174.8 Bcfe at December 31, 2008 from 211.1 Bcfe
at December 31, 2007, and the standardized measure of our
proved reserves decreased 49.1% to $164.1 million as of
December 31, 2008 from $286.2 million as of
December 31, 2007. The December 31, 2008 reserves were
calculated using a spot price of $5.71 per Mmbtu (adjusted for
basis differential, prices were $5.93 per Mmbtu in the
Appalachian Basin and $4.84 per Mmbtu in the Cherokee Basin). As
a result of this decrease, we recognized a non-cash impairment
of $298.9 million for the year ended December 31,
2008. As a result, the lenders under QELPs revolving
credit facility are likely to reduce QELPs borrowing base
in the near term. See Item 7. Managements
Discussion and Analysis of Financial Condition and Results of
Operations Liquidity and Capital
Resources Sources of Liquidity in 2009 and Capital
Requirements Quest Energy.
Seminole
County Acreage Acquisition
In early February 2008, QELP purchased certain oil producing
properties in Seminole County, Oklahoma from a private company
for $9.5 million. In connection with the acquisition, QELP
entered into crude oil swaps for approximately 80% of the
estimated production from the propertys proved developed
producing reserves at WTI-NYMEX prices per barrel of oil of
approximately $96.00 in 2008, $90.00 in 2009, and $87.50 for
2010. The acquisition was financed with borrowings under Quest
Energys credit facility. As of December 31, 2008, the
properties had estimated net proved reserves of
588,800 Bbls, all of which were proved developed producing.
Settlement
Agreements
As discussed above, QRCP and QELP filed lawsuits against
Mr. Cash, the entity controlled by Mr. Cash that was
used in connection with the Transfers and two former officers,
who are the other owners of the controlled-entity, seeking,
among other things, to recover the funds that were transferred.
On May 19, 2009, QRCP, QELP and QMLP entered into
settlement agreements with Mr. Cash, the controlled-entity
and the other owners to settle this litigation. Under the terms
of the settlement agreements, QRCP received
(1) approximately $2.4 million in cash and
(2) 60% of the controlled-entitys interest in a gas
well located in Louisiana and a landfill gas development project
located in Texas. While QRCP estimates the value of these assets
to be less than the amount of the Transfers and cost of the
internal investigation, they represent the majority of the value
of the controlled-entity. We did not take Mr. Cashs
stock in QRCP, which he represented had been pledged to secure
personal loans with a principal balance far in excess of the
current market value of the stock. QELP received all of
Mr. Cashs equity interest in STP Newco, Inc.
(STP), which owns certain oil producing properties
in Oklahoma, and other assets as reimbursement for all of the
costs of the internal investigation and the costs of the
litigation against Mr. Cash that have been paid by QELP.
Pinnacle
Merger
On October 15, 2007, we and Pinnacle Gas Resources, Inc.
(Pinnacle) entered into an Agreement and Plan of
Merger, pursuant to which we and Pinnacle agreed to combine our
operations (the Merger Agreement). On May 16,
2008, the Merger Agreement was terminated. Pursuant to the terms
of the Merger Agreement, either we or
16
Pinnacle had the right to terminate the Merger Agreement if the
proposed merger was not completed by May 16, 2008. No
termination fee was payable by either of us as a result of the
termination of the Merger Agreement.
2008
Operating Results
Our strategy prior to the events discussed above was to create
value through the growth of the master limited partnerships of
Quest Energy and Quest Midstream. This strategy was supported by
a talented engineering and operating team assembled over the
last two years. This team separated approximately
400 employees at our peak level of activity into discrete,
highly focused groups: Capital Development, Production
Operations, Well Servicing, Compression and Pipeline. These
teams met or exceeded a number of performance-related goals that
were established by management at the beginning of the year. For
example, Quest Energy planned to drill 325 wells in the
Cherokee Basin in 2008. Quest Energy drilled 338 wells in
eight months, three months ahead of schedule, and delivered the
results within its capital budget for the year. We did not drill
any wells during the final four months of the year due to
limited capital availability and low commodity prices. In
addition, we had historically struggled to maintain a low level
of wells offline due to well failures. For December 2008, on
average less than 2% of our approximately 2,500 Cherokee Basin
wells were offline per day. This level of performance was
achieved through the implementation of rigorous engineering
reviews, statistical failure analysis and the latest
de-liquification process control technology. Our net production
for 2008 was 21.75 Bcfe, which is a 23.4% increase over our net
production in 2007 of 17.02 Bcfe. With respect to our midstream
activities, we connected 328 wells to our Cherokee Basin
gathering system and integrated the KPC Pipeline assets into our
operations. We have also improved our safety culture by
decreasing OSHA recordable incidents by 35% in 2008 as compared
to 2007.
Outlook
for 2009; Recombination
Given the liquidity challenges facing the Company, Quest
Midstream and Quest Energy, each entity has undertaken a
strategic review of its assets and may enter into one or more
transactions to dispose of assets in order to raise additional
funds for operations
and/or
to
repay indebtedness. In addition, in the current economic
environment we believe the complexity and added overhead costs
of our structure is negatively affecting our ability to
restructure our indebtedness and raise additional equity. See
Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations
Liquidity and Capital Resources. On April 28, 2009,
the Company, Quest Midstream and Quest Energy entered into a
non-binding letter of intent pursuant to the terms of which all
three companies would form a new publicly traded holding company
that would wholly-own all three entities (the
Recombination). The new company would continue to
develop the unconventional resources of the Cherokee and
Appalachian Basins with a clear focus on value creation through
efficient operations. The closing of the Recombination is
subject to the satisfaction of a number of conditions, including
the entry into a definitive merger agreement, the negotiation of
a new credit facility for the new company, regulatory approval
and the approval of the transaction by the stockholders of the
Company and the unitholders of Quest Energy and Quest Midstream.
There can be no assurance that the definitive documentation will
be agreed to or that the Recombination will close.
Business
Strategy
Our business strategy for 2009 has been adjusted in response to
the recent turmoil in the financial markets and the economy in
general, including the reduction in commodity prices which was
then exacerbated by the significantly increased general and
administrative costs we have incurred as a result of the
investigation and the reaudits and restatements of our
consolidated financial statements. See Recent
Developments. We are focusing on negotiating documentation
and other activities necessary to complete the Recombination
while still maintaining a stable asset base, improving the
profitability of our assets by increasing their utilization
while controlling costs and reducing capital expenditures as
discussed elsewhere in this Annual Report on
Form 10-K,
renegotiating with our lenders and possibly raising equity
capital.
17
Prior to the events discussed above, our goal was to create
stockholder value by growing our two master limited partnerships
and investing capital to increase reserves, production and cash
flow. In favorable product price markets and credit markets, we
would accomplish this goal by focusing on the following key
strategies:
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Seek out opportunities to grow our upstream and midstream master
limited partnerships and hence the distributions they make to us;
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Efficiently control the drilling and development of our acreage
position in the Cherokee and Appalachian Basins and other
acquired acreage positions;
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Expand Quest Midstreams gas gathering system throughout
the Cherokee Basin in order to accommodate the development of a
wider acreage footprint;
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Accumulate additional acreage in the Cherokee Basin through
Quest Energy in areas where management believes the most
attractive development opportunities exist;
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Pursue selected strategic acquisitions in the Cherokee Basin
through Quest Energy and Quest Midstream that would add
attractive development opportunities and critical gas gathering
infrastructure;
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Maintain operational control over our assets whenever possible;
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Limit our reliance on third party contractors with respect to
the completion, stimulation and connection of our wells in the
Cherokee Basin;
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Maintain a low cost and efficient operating structure through
the use of remote data monitoring technology;
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Pursue opportunities to apply our expertise with conventional
and unconventional resource development in other basins; and
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Pursue opportunities to apply our expertise with building and
operating natural gas gathering and transportation
infrastructure in other basins.
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We believe the acquisition of PetroEdge was an opportunity to
grow our upstream business just as the acquisition of KPC by
QMLP in November 2007 was for the midstream business. However,
the significant decline in natural gas prices since the
PetroEdge acquisition closed has substantially reduced the
opportunity for an economic return on the PetroEdge assets.
Additionally, as discussed in more detail under
Recent Developments, we have instituted
cost control measures, such as work force reductions and other
cost savings actions, and have concentrated attention on
managing cash flow and planning for future required principal
payments. If the Quest entities are not recombined, deployment
of any growth strategy will be highly unlikely. Furthermore,
should the three individual entities continue without a
significant increase in product prices in the near term,
combined with longer term forbearance under their credit
facilities, each entity would likely face liquidation or
bankruptcy.
Description
of Our Exploration and Production Properties and
Projects
Cherokee
Basin
We produce CBM gas out of Quest Energys properties located
in the Cherokee Basin. The Cherokee Basin is located in
southeastern Kansas and northeastern Oklahoma. Geologically, it
is situated between the Forest City Basin to the north, the
Arkoma Basin to the south, the Ozark Dome to the east and the
Nemaha Ridge to the west. The Cherokee Basin is a mature
producing area with respect to conventional reservoirs such as
the Bartlesville sandstones and the Mississippian limestones,
which were developed beginning in the early 1900s.
The Cherokee Basin is part of the Western Interior Coal Region
of the central United States. The coal seams we target for
development are found at depths of 300 to 1,400 feet. The
principal formations we target include the Mulky,
Weir-Pittsburgh and the Riverton. These coal seams are blanket
type deposits, which extend across large areas of the basin.
Each of these seams generally range from two to five feet thick.
Additional minor coal seams such as the Summit, Bevier, Fleming
and Rowe are found at varying locations throughout the basin.
These seams range in thickness from one to two feet.
18
The rock containing conventional gas, referred to as
source rock, is usually different from reservoir
rock, which is the rock through which the conventional gas is
produced, while in CBM, the coal seam serves as both the source
rock and the reservoir rock. The storage mechanism is also
different. Gas is stored in the pore or void space of the rock
in conventional gas, but in CBM, most, and frequently all, of
the gas is stored by adsorption. This adsorption allows large
quantities of gas to be stored at relatively low pressures. A
unique characteristic of CBM is that the gas flow can be
increased by reducing the reservoir pressure. Frequently, the
coal bed pore space, which is in the form of cleats or
fractures, is filled with water. The reservoir pressure is
reduced by pumping out the water, releasing the methane from the
molecular structure, which allows the methane to flow through
the cleat structure to the well bore. Because of the necessity
to remove water and reduce the pressure within the coal seam,
CBM, unlike conventional hydrocarbons, often will not show
immediately on initial production testing. Coalbed formations
typically require extensive dewatering and depressuring before
desorption can occur and the methane begins to flow at
commercial rates. Our Cherokee Basin CBM properties typically
dewater for a period of 12 months before peak production
rates are achieved.
CBM and conventional gas both have methane as their major
component. While conventional gas often has more complex
hydrocarbon gases, CBM rarely has more than 2% of the more
complex hydrocarbons. Once coalbed methane has been produced, it
is gathered, transported, marketed and priced in the same manner
as conventional gas. The CBM produced from our Cherokee Basin
properties has an Mmbtu content of approximately 970 Mmbtu,
compared to conventional natural gas hydrocarbon production
which can typically vary from 1,050-1,300 Mmbtus.
The content of gas within a coal seam is measured through gas
desorption testing. The ability to flow gas and water to the
wellbore in a CBM well is determined by the fracture or cleat
network in the coal. While, at shallow depths of less than
500 feet, these fractures are sometimes open enough to
produce the fluids naturally, at greater depths the networks are
progressively squeezed shut, reducing the ability to flow. It is
necessary to provide other avenues of flow such as hydraulically
fracturing the coal seam. By pumping fluids at high pressure,
fractures are opened in the coal and a slurry of fluid and sand
is pumped into the fractures so that the fractures remain open
after the release of pressure, thereby enhancing the flow of
both water and gas to allow the economic production of gas.
Cherokee
Basin Projects
Historically, we have developed our CBM reserves in the Cherokee
Basin on
160-acre
spacing. However, during 2008 we developed some areas on
80-acre
spacing. We are currently evaluating the results of this
80-acre
spacing program. Our wells generally reach total depth in
1.5 days and our average cost in 2008 to drill and complete
a well, excluding the related pipeline infrastructure, was
approximately $135,000. We estimate that for 2009, Quest
Energys average cost for drilling and completing a well
will be between $113,000 and $125,000 excluding the related
pipeline infrastructure. For 2009, in the Cherokee Basin, we
have budgeted approximately $3.8 million to drill seven new
gross wells, connect and complete 49 existing gross wells, and
connect and complete three existing salt water disposal wells.
All of these new gas wells will be drilled on locations that are
classified as containing proved reserves in our
December 31, 2008 reserve report. In 2009, QELP plans to
recomplete an estimated 10 gross wells and it has budgeted
another $1.9 million for equipment, vehicle replacement,
and other capital purchases, including the replacement of some
of QELPs existing pumps with submersible pumps that we
believe provide enhanced removal of water from the wells. In
addition, QELP has budgeted $2.4 million related to lease
renewals and extensions for acreage that is expiring in 2009.
However, we intend to fund these capital expenditures only to
the extent that QELP has available cash from operations after
taking into account its debt service. We can give no assurance
that any such funds will be available.
We perforate and frac the multiple coal seams present in each
well. Our typical Cherokee Basin multi-seam CBM well has net
reserves of 130 Mmcf. Our general production profile for a
CBM well averages an initial production rate of
5-10 Mcf/d
(net), steadily rising for the first twelve months while water
is pumped off and the formation pressure is lowered. A period of
relatively flat production of
50-55 Mcf/d
(net) follows the initial dewatering period for a period of
approximately twelve months. After 24 months, production
begins to decline. The standard economic life is approximately
15 years. Our completed wells rely on very basic industry
technology.
Our development activities in the Cherokee Basin also include a
program to recomplete CBM wells that produce from a single coal
seam to wells that produce from multiple coal seams. During the
year ended
19
December 31, 2008, we recompleted approximately
10 wellbores in Kansas and an additional
four wellbores in Oklahoma. For 2009, we plan to recomplete
an estimated 10 gross wells. We believe we have
approximately 200 additional wellbores that are candidates for
recompletion to multi-seam producers. The recompletion strategy
is to add four to five additional pay zones to each wellbore, in
a two-stage process at an average cost of approximately $16,000
per well. Adding new zones to a well has a brief negative effect
on production by first taking the well offline to perform the
work and then by introducing a second dewatering phase of the
newly completed formations. However, in the long term, we
believe the impact of the multi-seam recompletions will be
positive as a result of an increase in the rate of production
and the ultimate recoverable reserves available per well.
Wells are equipped with small pumping units to facilitate the
dewatering of the producing coal seams. Generally, upon initial
production, a single coal seam will produce
50-60 Bbls
of water per day. A multi-seam completion produces about
150 Bbls of water per day. Eventually, water production
subsides to
30-50 Bbls
per day. Produced water is disposed through injection wells we
drill into the underlying Arbuckle formation. One disposal well
will generally handle the water produced from 25 CBM wells.
Appalachian
Basin
The Appalachian Basin is one of the largest and oldest producing
basins within the United States. It is a northeast to southwest
trending, elongated basin that deepens with thicker sections to
the east. This basin takes in southern New York, Pennsylvania,
eastern Ohio, extreme western Maryland, West Virginia, Kentucky,
extreme western/northwestern Virginia, and portions of
Tennessee. The basin is bounded on the east by a line of
metamorphic rocks known as the Blue Ridge province which is
thrusted to the west over the basin margin. Most prospective
sedimentary rocks containing hydrocarbons are found at depths of
approximately 1,000-9,000 feet with shallowest production
in areas where oil and gas are seeping from the outcrop. Most
productive horizons are found in sedimentary strata of
Pennsylvanian, Mississippian, Devonian, Silurian, and Ordovician
age. The Appalachian Basin has been an active area for oil and
gas exploration, production and marketing since the mid-1800s.
Although deeper zones are of interest, the main exploration and
development targets are the Mississippian and Devonian sections.
Our main area of interest is within West Virginia, where there
are producing formations at depths of 1,500 feet to
approximately 8,000 feet. Specifically, our main production
targets are the lower Devonian Marcellus Shale, the shallow
Mississippian (Big Injun, Maxton, Berea, Pocono, Big Lime) and
the Upper Devonian (Riley, Benson, Java, Alexander, Elk,
Cashaqua, Middlesex, West River and Genesee, including the Huron
Shale members, Rhinestreet Shales). Although deeper targets are
of interest (Onondaga and Oriskany), they are of lesser
importance. The Mississippian formations are a conventional
petroleum reservoir with the Devonian sections being a
non-conventional energy resource.
The method for exploring and drilling these targets is different
in several aspects. The Mississippian and Upper Devonian
sections are explored through vertical drilling. The lower
Marcellus section is explored by both vertical and horizontal
drilling. The Mississippian section is identified by distinct
sand and limestone zones with conventional porosity and
permeability. Depths range from 1,000-2,500 feet deep. The
Upper Devonian sands, siltstones, and shales are identified as
multiple stacked pay lenses with depths ranging from
2,500-7,000 feet deep. The Marcellus Shale ranges in depth
from 5,900 feet in portions of West Virginia to
7,100 feet in other portions of West Virginia. In certain
areas of our leasehold, vertical wells are drilled with
combination completions in the Mississippian, Upper Devonian,
and the Marcellus. Occasionally, vertical wells might only
complete a single section of the three prospective pay intervals.
Our technical team has extensive experience in vertical and
horizontal exploration, development and production. We have
identified areas within the Appalachian Basin that we believe
are prospective for both vertical and horizontal targets. Our
leases cover approximately eighteen counties within the
Appalachian Basin. Certain counties are vertical drilling
targets for development and other counties are horizontal
development targets. We believe there are over 334 gross
vertical locations that would include potential production from
one or all three of the Mississippian, Upper Devonian Sands, and
Siltstones. We believe there are approximately 123 gross
horizontal locations that would include the primary target for
the Marcellus formation. We have recently drilled and set
production pipe on two horizontal wells located in Wetzel
County, West Virginia. This county in particular, along
20
with Lewis County, West Virginia and Steuben County, New York,
is prospective for horizontal drilling in the Marcellus. Depths
to the Marcellus in Lewis County and Wetzel County range from
6,700 feet to 7,100 feet. The thickness of the
Marcellus in these counties ranges from just over fifty feet
thick to over ninety feet thick.
Appalachian
Basin Projects
As discussed under Recent Developments,
in July 2008, we completed the PetroEdge acquisition, which
expanded our position in the Appalachian Basin. At
December 31, 2008, the Appalachian estimated net proved
reserves totaled 18.6 Bcfe and were producing approximately
2.9 Mmcfe/d. During 2008, QRCP drilled one gross vertical
well in Lycoming County, Pennsylvania, completed one gross
vertical well in Somerset County, Pennsylvania, drilled one
gross vertical well in Ritchie County, West Virginia, and
drilled two gross horizontal wells in Wetzel County, West
Virginia. The wells in Lycoming and Somerset Counties were
subsequently sold as part of the asset sales discussed under
Recent Developments Suspension of
Distributions and Asset Sales. Connections to interstate
pipelines have recently been installed near the Wetzel County
wells and QRCP intends to complete the wells as soon as capital
is available. We can give no assurance that any funds will be
available prior to the closing of the Recombination or at all.
For 2009, QRCP has budgeted net capital expenditures of
approximately $2.4 million to drill one gross vertical well
and complete three gross wells. The new well will be
drilled on a location that is classified as containing proved
reserves in our December 31, 2008 reserve report. QRCP
expects to connect all four of these gross wells in 2009. Quest
Energy has budgeted another $1.4 million for artificial
lift equipment, vehicle replacement and purchases and salt water
disposal facilities. The expenditure of these funds is subject
to capital being available. We can give no assurance that any
funds will be available prior to the closing of the
Recombination or at all.
Seminole
County, Oklahoma
Our Seminole County, Oklahoma oil producing property is located
in south central Oklahoma. This mature oil producing property
was originally discovered in 1926 and has undergone several
periods of re-development since that time. Two producing
horizons include the Hunton Limestone at approximately
4,100 feet and the First Wilcox Sand at approximately
4,300 feet. The Hunton Limestone is the main current
producing horizon in the field. Produced water is disposed
on-site.
Primary oil recovery from the Hunton with vertical wells was
limited by discontinuous porosity development in the Hunton
reservoir. Early attempts to waterflood this horizon met with
poor results. We plan to further develop the Hunton horizon with
horizontal drilling.
Oil and
Gas Data
Estimated
Net Proved Reserves
The following table presents our estimated net proved oil and
gas reserves relating to our oil and natural gas properties as
of the dates presented based on our reserve reports as of the
dates listed below. The data was prepared by the petroleum
engineering firm Cawley, Gillespie & Associates, Inc.
in Ft. Worth, Texas. We filed estimates of our oil and gas
reserves for the calendar years 2008, 2007 and 2006 with the
Energy Information Administration of the U.S. Department of
Energy on
Form EIA-23.
The data on
Form EIA-23
was presented on a different basis, and included 100% of the oil
and gas volumes from our operated properties only, regardless of
our net interest. The difference between the oil and gas
reserves reported on
Form EIA-23
and those reported in this table exceeds 5%. The standardized
measure values shown in the table are not intended to represent
the current market value of our estimated oil and gas reserves
and do not reflect any hedges. Proved reserves at
December 31, 2008 were determined using year-end prices of
$44.60 per barrel of oil and $5.71 per Mcf of gas, compared to
$96.10 per barrel
21
of oil and $6.43 per Mcf of gas at December 31, 2007, and
$61.06 per barrel of oil and $6.03 per Mcf of gas at
December 31, 2006.
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December 31,
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2008(3)
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2007
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2006
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Proved reserves
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Gas (Mcf)
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170,629,373
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210,923,406
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198,040,000
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Oil (Bbls)
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694,620
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36,556
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32,272
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Total (Mcfe)
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174,797,093
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211,142,742
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198,233,632
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Proved developed gas reserves (Mcf)
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136,544,572
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140,966,295
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|
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122,390,360
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Proved undeveloped gas reserves (Mcf)
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34,084,849
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69,957,117
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75,649,610
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Proved developed oil reserves (Bbls)(1)
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682,030
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36,566
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32,272
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Proved developed reserves as a percentage of total proved
reserves
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80.46
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%
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66.87
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%
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61.84
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%
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Standardized measure (in thousands)(2)
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$
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164,094
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$
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286,177
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$
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230,832
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(1)
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Although we have proved undeveloped oil reserves, they are
insignificant, so no effort was made to calculate such reserves.
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(2)
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Standardized measure is the present value of estimated future
net revenue to be generated from the production of proved
reserves, determined in accordance with the rules and
regulations of the SEC (using prices and costs in effect as of
the date of estimation), less future development, production and
income tax expenses, and discounted at 10% per annum to reflect
the timing of future net revenues. Standardized measure does not
give effect to commodity derivative transactions. For a
description of our derivative transactions, see
Note 8 Financial Instruments and
Note 7 Derivative Financial Instruments, in the
notes to the consolidated financial statements of this
Form 10-K.
The standardized measure shown should not be construed as the
current market value of the reserves. The 10% discount factor
used to calculate present value, which is required by Financial
Accounting Standards Board (FASB) pronouncements, is
not necessarily the most appropriate discount rate. The present
value, no matter what discount rate is used, is materially
affected by assumptions as to timing of future production, which
may prove to be inaccurate.
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(3)
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The total estimated reserves for 2008 reflects all reserves
regardless of basin or entity. The table below identifies the
estimated reserves owned by QELP and QRCP as of
December 31, 2008. As of December 31, 2007, all
reserves were owned by Quest Energy. As of December 31,
2006 and prior to the formation of Quest Energy on
November 14, 2007, all reserves were owned by QRCP.
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December 31, 2008
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QELP
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QRCP
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Total
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Proved reserves
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Gas (Mcf)
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162,984,141
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7,645,232
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170,629,373
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Oil (Bbls)
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682,031
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12,589
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694,620
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Total (Mcfe)
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167,076,327
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7,720,766
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174,797,093
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Proved developed gas reserves (Mcf)
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134,837,105
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1,707,467
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136,544,572
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Proved undeveloped gas reserves (Mcf)
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28,147,084
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5,937,765
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34,084,849
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Proved developed oil reserves (BBls)
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682,030
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682,030
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Proved developed reserves as a percentage of total proved
reserves
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83.15
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%
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22.12
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%
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80.46
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%
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Standardized measure in (thousands)
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$
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156,057
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$
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8,037
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$
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164,094
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The data in the table above represents estimates only. Oil and
gas reserve engineering is inherently a subjective process of
estimating underground accumulations of oil and gas that cannot
be measured exactly. The accuracy of any reserve estimate is a
function of the quality of available data and engineering and
geological interpretation and judgment. Accordingly, reserve
estimates may vary from the quantities of oil and gas that are
ultimately recovered. See Item 1A. Risk
Factors Risks Related to Our Business
Our estimated proved reserves are based on many
22
assumptions that may prove to be inaccurate. Any material
inaccuracies in these reserve estimates or underlying
assumptions will materially affect the quantities and present
value of our reserves.
Production
Volumes, Sales Prices and Production Costs
The following table sets forth information regarding the oil and
natural gas properties owned by us through our subsidiaries and
affiliates. The oil and gas production figures reflect the net
production attributable to our revenue interest and are not
indicative of the total volumes produced by the wells. All sales
data excludes the effects of our derivative financial
instruments.
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Year Ended December 31,
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2008
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2007
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2006
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Net Production:
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Gas (Bcf)
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21.33
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16.98
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12.30
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Oil (Bbls)
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69,812
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7,070
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9,808
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Gas equivalent (Bcfe)
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21.75
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17.02
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12.36
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Oil and Gas Sales ($ in thousands):
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Gas sales
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$
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141,489
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$
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104,853
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$
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71,836
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Oil sales
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6,448
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432
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574
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Total oil and gas sales
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$
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147,937
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$
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105,285
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$
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72,410
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Avg Sales Price:
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Gas ($ per Mcf)
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$
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6.63
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$
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6.18
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$
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5.81
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Oil ($ per Bbl)
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$
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92.36
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$
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61.10
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$
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58.52
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Gas equivalent ($ per Mcfe)
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$
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6.80
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$
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6.19
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$
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5.86
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Oil and gas operating expenses ($ per Mcfe):
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Lifting
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$
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1.58
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$
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1.71
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$
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1.56
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Production and property tax
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$
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0.45
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$
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0.42
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$
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0.49
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Net Revenue ($ per Mcfe)
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$
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4.77
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$
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4.06
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$
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3.81
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Producing
Wells and Acreage
The following tables set forth information regarding our
ownership of productive wells and total acres as of
December 31, 2006, 2007 and 2008. For purposes of the table
below, productive wells consist of producing wells and wells
capable of production.
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Productive Wells
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Gas(1)
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Oil
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Total
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Gross
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Net
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Gross
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Net
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Gross
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Net
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December 31, 2006
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1,653
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1,635.0
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29
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28.1
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1,682
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1,637.8
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December 31, 2007
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2,225
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2,218.2
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29
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28.1
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2,254
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2,210.1
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December 31, 2008(2)
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2,873
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2,825.0
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82
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80.2
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2,920
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2,863.6
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(1)
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At December 31, 2008, we had approximately 2,346 gross
wells in the Cherokee Basin that were producing from multiple
seams.
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(2)
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Includes approximately 500 gross productive Appalachian Basin
wells acquired in the PetroEdge acquisition and 55 gross
productive oil wells acquired in Seminole County, Oklahoma.
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Leasehold Acreage
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Producing(1)
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Nonproducing
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Total
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Gross
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Net
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Gross
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Net
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Gross
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Net
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December 31, 2006
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394,795
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385,148
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132,189
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124,774
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526,984
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509,923
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December 31, 2007(2)
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403,048
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393,480
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204,104
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187,524
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607,152
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581,004
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December 31, 2008(3)(4)
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464,702
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446,537
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208,224
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180,707
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672,926
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627,244
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(1)
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Includes acreage held by production under the terms of the lease.
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23
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(2)
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The leasehold acreage data as of December 31, 2007 includes
non-producing leasehold acreage in the States of New Mexico,
Texas and Pennsylvania of approximately 24,740 gross and
22,694 net acres. Approximately 45,000 net acres that
were included in the 2006 leasehold acreage amounts have expired.
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(3)
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The leasehold acreage data as of December 31, 2008 includes
acreage held by QRCP and QELP in the States of Kansas, Oklahoma,
New York, Pennsylvania, and West Virginia.
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(4)
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The leasehold acreage data as of December 31, 2008 includes
approximately 37,723 gross and 31,565 net acres attributable to
various farm-out agreements or other mechanisms in the
Appalachian Basin. Approximately 6,912 net acres are earned and
approximately 24,653 net acres are unearned under these
agreements. There are certain drilling or payment obligations
that must be met before this unearned acreage is earned.
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As of December 31, 2008, in the Cherokee Basin, we had
332,401 net developed acres and 225,202 net
undeveloped acres. As of December 31, 2008, in the
Appalachian Basin, we had 8,798 net developed acres and
59,592 net undeveloped acres. Subsequent to the divestiture
of our acreage in Lycoming County, Pennsylvania, as of
March 31, 2009, we had 8,758 net developed acres and
36,974 net undeveloped acres in the Appalachian Basin.
Developed acres are acres spaced or assigned to productive
wells/units based upon governmental authority or standard
industry practice. Undeveloped acres are acres on which wells
have not been drilled or completed to a point that would permit
the production of commercial quantities of oil or gas,
regardless of whether such acreage contains proved reserves.
Drilling
Activities
The table below sets forth the number of wells completed at any
time during the period, regardless of when drilling was
initiated. Our drilling, recompletion, abandonment, and
acquisition activities for the periods indicated are shown below
(this information is inclusive of all basins and areas):
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Year Ended
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Year Ended
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Year Ended
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December 31,
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December 31,
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December 31,
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2008
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2007
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2006
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Oil & Gas
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Gas(1)
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Gas(1)
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Gross
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Net
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Gross
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Net
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Gross
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Net
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Exploratory wells drilled:
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Capable of production
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1
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1
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Dry
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1
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1
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Development wells drilled:
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Capable of production
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339
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338
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572
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572
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621
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621
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Dry
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Wells plugged and abandoned
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17
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17
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Wells acquired capable of production(2)
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551
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514.5
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Net increase in capable wells
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875
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837.5
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572
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572
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621
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621
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Recompletion of old wells:
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Capable of production
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14
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14
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50
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49
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125
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122
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(1)
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No change to oil wells for the years ended December 31,
2007 and 2006.
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(2)
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Includes 53.5 net and 55 gross oil wells capable of production
acquired in Seminole County, Oklahoma in February 2008. The
remainder of the acquired wells were acquired as part of the
PetroEdge acquisition.
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Exploration
and Production
General
As the operator of wells in which we have an interest, we design
and manage the development of a well and supervise operation and
maintenance activities on a day-to-day basis. Quest Energy
Service, LLC, our wholly-owned subsidiary, manages all of our
properties and employs production and reservoir engineers,
geologists and
24
other specialists. Quest Cherokee Oilfield Service, LLC, a
wholly-owned subsidiary of Quest Energy, employs our Cherokee
Basin and Appalachian Basin field personnel.
Field operations conducted by our personnel include duties
performed by pumpers or employees whose primary
responsibility is to operate the wells. Other field personnel
are experienced and involved in the activities of well
servicing, the development and completion of new wells and the
construction of supporting infrastructure for new wells (such as
electric service, salt water disposal facilities, and gas feeder
lines). The primary equipment categories owned by us are trucks,
well service rigs, stimulation assets and construction
equipment. We utilize third party contractors on an as
needed basis to supplement our field personnel.
In the Cherokee Basin, we provide, on an in-house basis, many of
the services required for the completion and maintenance of our
CBM wells. Internally sourcing these functions significantly
reduces our reliance on third party contractors, which typically
provide these services. We are also able to realize significant
cost savings because we can reduce delays in executing our plan
of development, avoid paying price markups and are able to
purchase our own supplies at bulk discounts. We rely on third
party contractors to drill our wells. Once a well is drilled,
either we or a third party contractor will run the casing. We
will perform the cementing, fracturing, stimulation and complete
our own well site construction. We have our own fleet of
24 well service units that we use in the process of
completing our wells, and to perform remedial field operations
required to maintain production from our existing wells. In the
Appalachian Basin, we rely on third party contractors for these
services.
Oil
and Gas Leases
As of December 31, 2008, we had over 4,500 leases covering
approximately 627,244 net acres. The typical oil and gas
lease provides for the payment of royalties to the mineral owner
for all oil or gas produced from any well drilled on the lease
premises. This amount ranges from 12.5% to 18.75% resulting in
an 81.25% to 87.5% net revenue interest to us.
Because the acquisition of oil and gas leases is a very
competitive process, and involves certain geological and
business risks to identify productive areas, prospective leases
are sometimes held by other oil and gas operators. In order to
gain the right to drill these leases, we may purchase leases
from other oil and gas operators. In some cases, the assignor of
such leases will reserve an overriding royalty interest, ranging
from 3.125% to 16.5% which further reduces the net revenue
interest available to us to between 71.0% and 84.375%.
As of December 31, 2008, approximately 65% of our oil and
gas leases were held by production, which means that for as long
as our wells continue to produce oil or gas, we will continue to
own those respective leases.
Natural
Gas Pipelines
Gas
Gathering Systems
QMLPs approximately 2,173-mile low pressure gas gathering
pipeline network is owned by Bluestem, a wholly-owned subsidiary
of Quest Midstream. QMLPs natural gas gathering pipeline
network is located in the Cherokee Basin and provides a market
outlet for natural gas in a region of approximately
1,000 square miles in size and has connections to both
intrastate and interstate delivery pipelines. It is the largest
gathering system in the Cherokee Basin with a current throughput
capacity of approximately 85 Mmcf/d and delivers virtually
all its gathered gas into Southern Star Central Gas Pipeline at
multiple interconnects. This gathering system includes
83 field compression units comprising approximately 51,000
horsepower of compression in the field (most of which are
currently rented) as well as seven
CO
2
amine treating facilities.
The pipelines gather all of the natural gas produced by QELP in
the Cherokee Basin pursuant to a midstream services and gas
dedication agreement (see Midstream Services
Agreement below) in addition to some natural gas produced
by other companies. The pipeline network is a critical asset for
our future growth in the Cherokee Basin because natural gas
gathering pipelines are a costly component of the infrastructure
required for natural gas production and such pipelines are not
easily constructed.
25
We intend to expand our gas gathering pipeline infrastructure
through the development of new pipelines and to a lesser extent,
through the acquisition of existing pipelines, if the outlook
for commodity prices improves to the point where we believe
future development in the Cherokee Basin is justified and Quest
Midstream has available capital.
For 2008, our average cost for pipeline infrastructure to
connect a Cherokee Basin well was approximately $65,500 per
well. We estimate that our cost for pipeline infrastructure to
connect a Cherokee Basin well will be approximately $61,000 per
well for 2009. We expect to connect 56 wells in the
Cherokee Basin in 2009, if the outlook for commodity prices
improves to the point where we believe the connection of these
wells is justified and Quest Midstream has available capital.
Quest Eastern owns and operates a gas gathering pipeline network
of approximately 183 miles that serves our acreage position
in the Appalachian Basin. The pipeline delivers both to
intrastate gathering and interstate pipeline delivery points.
Presently, this system has a maximum daily throughput of
approximately 15 Mmcf/d and is operating at about 20%
capacity. All of QELPs Appalachian gas production is
transported by Quest Easterns gas gathering pipeline
network. Less than 1% of the current volumes transported on
Quest Easterns natural gas gathering pipeline system are
for third parties.
The following table sets forth the number of miles of gas
gathering pipeline acquired or constructed by Quest Midstream
and Quest Eastern during the periods indicated.
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Year Ended December 31,
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2008
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2007
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2006
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Miles constructed
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184
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315
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392
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Miles acquired(1)
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178
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(1)
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Consists of gas gathering system acquired by Quest Eastern as
part of the PetroEdge acquisition.
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The table below sets forth the natural gas volumes gathered on
our gas gathering pipeline networks during the years ended
December 31, 2008 and 2007.
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Year Ended December 31,
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2008
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2007
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Pipeline Natural Gas Vols (Mmcf)
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Cherokee Basin
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27,093
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22,562
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Quest Eastern
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476
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Midstream
Services Agreement
Quest Energy and Quest Midstream are parties to a midstream
services and gas dedication agreement entered into on
December 22, 2006, but effective as of December 1,
2006. Pursuant to the midstream services agreement, Quest
Midstream gathers and provides certain midstream services,
including dehydration, treating and compression, to Quest Energy
for all gas produced from Quest Energys 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 extension
periods that may be exercised by either party upon
180 days notice. The fees charged under the midstream
services agreement are subject to renegotiation upon the
exercise of each five-year extension period.
Under the midstream services agreement, Quest Energy agreed to
pay Quest Midstream an initial fee equal to $0.50 per Mmbtu of
gas for gathering, dehydration and treating services and $1.10
per Mmbtu of gas for compression services, subject to an annual
adjustment to be determined by multiplying each of the gathering
services fee and the compression services fee by the sum of
(i) 0.25 times the percentage change in the producer price
index for the prior calendar year and (ii) 0.75 times the
percentage change in the Southern Star first of month index for
the prior calendar year. Such adjustment will be calculated
within 60 days after the beginning of each year, but will
be retroactive to the beginning of the year. Such fees will
never be reduced below the initial rates described above. For
2008, the fees were $0.51 per Mmbtu of gas for gathering,
dehydration and treating services and $1.13
26
per Mmbtu of gas for compression services. For 2009, the fees
are $0.596 per Mmbtu of gas for gathering, dehydration and
treating services and $1.319 per Mmbtu of gas for compression
services. Such fees are subject to renegotiation in connection
with each renewal 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.
In accordance with the midstream services agreement, Quest
Energy bears the cost to remove and dispose of free water from
its gas prior to delivery to Quest Midstream and of all fuel
requirements necessary to perform the gathering and midstream
services, plus any lost and unaccounted for gas.
Quest Midstream has an exclusive option for sixty days to
connect to its gathering system each of the gas wells that Quest
Energy develops in the Cherokee Basin. In addition, Quest
Midstream will be required to connect to its gathering system,
at its expense, any new gas wells that Quest Energy 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. Quest Midstream also has the sole discretion to
cease providing services on all or any part of its gathering
system if it determines that continued operation is not
economically justified. If Quest Midstream elects to do so, it
must provide Quest Energy with 90 days written notice and
will offer Quest Energy the right to purchase that part of the
terminated system. If Quest Energy does acquire that part of the
system and it remains connected to any other portion of Quest
Midstreams gathering system, then Quest Energy may deliver
its gas from the terminated system to Quest Midstreams
system, and a fee for any services provided by Quest Midstream
will be negotiated.
In addition, Quest Midstream agreed to install the saltwater
disposal lines for Quest Energys gas wells connected to
Quest Midstreams gathering system for an initial fee of
$1.25 per linear foot and connect such lines to Quest
Energys 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 were $1.29 per linear foot to
install saltwater disposal lines and $1,030 per well to connect
such lines to Quest Energys saltwater disposal wells. For
2009, the fees are $1.33 per linear foot to install saltwater
disposal lines and $1,061 per well to connect such lines to
Quest Energys saltwater disposal wells.
Appalachian
Gathering Agreement
Quest Cherokee and Quest Eastern are parties to a gas
transportation agreement effective as of July 1, 2008.
Pursuant to the gas transportation agreement, Quest Eastern
receives, transports and processes all gas delivered by Quest
Cherokee at certain specified receipt points and redelivers to
or for the account of Quest Cherokee at the delivery points the
thermal equivalent of the gas received from Quest Cherokee.
Pursuant to the gas transportation agreement, Quest Cherokee has
agreed to pay Quest Eastern a fee equal to $0.70 per Mmbtu.
Should Quest Cherokee fail to timely remit the full amount owed
to Quest Eastern when due, unless such failure is caused by
Quest Cherokee disputing in good faith the amount owed to Quest
Eastern, Quest Cherokee must pay interest on the unpaid and
undisputed portion, which will accrue at a rate equal to prime
plus 1%.
The gas transportation agreement will continue until terminated
upon 90 days written notice by either party. Upon
termination of the agreement, Quest Eastern may require Quest
Cherokee to resize the compression within Quest Easterns
infrastructure and facilities to the capacity necessary without
Quest Cherokees gas as of the date of termination.
In accordance with the gas transportation agreement, Quest
Eastern has the right to decrease or halt the receipt of Quest
Cherokees gas without prior notification if at any time
Quest Cherokees gas will materially adversely affect the
normal operation of Quest Easterns facilities due to the
failure of gas delivered by Quest Cherokee to meet the quality
standards as outlined in the agreement.
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Third
Party Gas Gathering
For services rendered to parties other than Quest Energy, Quest
Midstream retains a portion of the gas volumes sold.
Approximately 6% of the gas transported on Quest
Midstreams natural gas gathering pipeline system in the
Cherokee Basin is for third parties.
Interstate
Pipelines
KPC, an indirect subsidiary of Quest Midstream, owns and
operates an approximately 1,120-mile interstate gas pipeline,
which transports natural gas from Oklahoma and western Kansas to
the metropolitan Wichita and Kansas City markets. Further, it is
one of only three pipeline systems currently capable of
delivering gas into the Kansas City metropolitan market. The KPC
system includes three compressor stations with a total of 14,680
horsepower and has a throughput capacity of approximately
160 Mmcf/d. KPC has supply interconnections with pipelines
owned
and/or
operated by Enogex Inc., Panhandle Eastern PipeLine Company and
ANR Pipeline Company, allowing QMLP to transport natural gas
volumes sourced from the Anadarko and Arkoma basins, as well as
the western Kansas and Oklahoma panhandle producing regions.
Marketing
and Major Customers
Exploration
and Production
We market our own natural gas. In the Cherokee Basin for 2008,
approximately 98% of our gas production was sold to ONEOK Energy
Marketing and Trading Company (ONEOK). More than 79%
of our natural gas production was sold to ONEOK and 21% was sold
to Tenaska Marketing Ventures in 2007. More than 95% of our
natural gas production was sold to ONEOK in 2006.
Our oil in the Cherokee Basin is currently being sold to
Coffeyville Refining. Previously, it had been sold to Plains
Marketing, L.P.
During the year ended December 31, 2008, we sold 100% of
our oil in Seminole County, Oklahoma to Sunoco Partners
Marketing & Terminals L.P. under sale and purchase
contracts, which have varying terms and cannot be terminated by
either party, other than following an event of default.
Approximately 73% of our 2008 Appalachian Basin production was
sold to Dominion Field Services under contracts with a mix of
fixed price and index based sales in place at the time of the
PetroEdge acquisition in July 2008. Reliable Wetzel transported
and sold approximately 10% of our 2008 Appalachian Basin
production under a market sensitive contract that expires in
2010. Another 8% was sold to Hess Corporation under a mix of
fixed price and index based sales. The remainder of the
Appalachian production was sold to various purchasers under
market sensitive pricing arrangements. None of these remaining
sales exceeded 4% of total Appalachian Basin production. Due to
the history of problematic Northeastern pipeline constraints, we
have secured a firm transportation agreement to ensure
uninterrupted deliveries of our natural gas production.
Under various sale and purchase contracts, 100% of our oil
produced in the Appalachian Basin was sold to Appalachian Oil
Purchasers, a division of Clearfield Energy.
If we were to lose any of these oil or gas purchasers, we
believe that we would be able to promptly replace them.
Gas
Gathering
Approximately 94% of the throughput on Quest Midstreams
gas gathering pipeline system is attributable to Quest Energy
production with the balance being other third party customers.
Approximately 99% of the throughput on Quest Easterns gas
gathering pipeline system in the Appalachian Basin is
attributable to Quest Energy production.
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Interstate
Pipelines
KPCs two primary customers are Kansas Gas Service (KGS)
and Missouri Gas Energy (MGE), both of which are served under
firm natural gas transportation contracts. For the period from
November 1, 2007, the date of the KPC Pipeline acquisition,
through December 31, 2007, approximately 60% of KPCs
revenue was from KGS and 36% was from MGE. During 2008,
approximately 58% and 36% of KPCs revenue was from KGS and
MGE, respectively. KGS, a division of ONEOK, Inc., is the local
distribution company in Kansas for Kansas City and Wichita as
well as a number of other municipalities; while MGE, a division
of Southern Union Company, is a natural gas distribution company
that serves over one-half million customers in 155 western
Missouri communities.
Commodity
Derivative Activities
Quest Energy sells the majority of its gas in the Cherokee
Basin based on the Southern Star first of month index, with the
remainder sold on the daily price on the Southern Star index.
Quest Energy sells the majority of its gas in the
Appalachian Basin based on the Dominion Southpoint index, with
the remainder sold on local basis. Quest Energy sells the
majority of its oil production under a contract priced at a
fixed discount to NYMEX oil prices. Due to the historical
volatility of oil and natural gas prices, Quest Energy has
implemented a hedging strategy aimed at reducing the variability
of prices it receives for the sale of its future production.
While we believe that the stabilization of prices and production
afforded Quest Energy by providing a revenue floor for its
production is beneficial, this strategy may result in lower
revenues than Quest Energy would have if it was not a party
to derivative instruments in times of rising oil or natural gas
prices. As a result of rising commodity prices,
Quest Energy may recognize additional charges to future
periods. Quest Energy holds derivative contracts based on
Southern Star and NYMEX natural gas and oil prices and it has
fixed price sales contracts with certain customers in the
Appalachian Basin. These derivative contracts and fixed price
contracts mitigate Quest Energys risk to fluctuating
commodity prices but do not eliminate the potential effects of
changing commodity prices. Quest Energys derivative
contracts limit its exposure to basis differential risk as it
generally enters into derivative contracts that are based on the
same indices on which the underlying sales contracts are based
or by entering into basis swaps for the same volume of hedges
that settle based on NYMEX prices.
As of December 31, 2008, Quest Energy held derivative
contracts and fixed price sales contracts totaling approximately
39.8 Bcf of natural gas and 66,000 Bbls of oil through
2012. Approximately 14.6 Bcf of Quest Energys
Cherokee Basin natural gas production is hedged utilizing
Southern Star contracts at a weighted average price of
$7.78/Mmbtu for 2009 and approximately 22.5 Bcf of its
Cherokee Basin natural gas production is hedged utilizing
Southern Star contracts at a weighted average price of
$7.42/Mmbtu for 2010 through 2012. Approximately 0.75 Bcf
of Quest Energys Appalachian Basin natural gas
production is hedged utilizing NYMEX contracts at a weighted
average price of $11.00/Mmbtu for 2009 and approximately
1.2 Bcf of its Appalachian Basin natural gas is hedged
utilizing NYMEX contracts at a weighted average price of
$9.77/Mmbtu for 2010 through 2012. Quest Energys
fixed price sales contracts hedge approximately 0.65 Bcf of
its Appalachian Basin natural gas production at a weighted
average price of $8.38/Mmbtu in 2009 and 0.1 Bcf of its
Appalachian Basin natural gas production at a weighted average
price of $8.96/Mmbtu in 2010.
As of December 31, 2008, approximately 36,000 Bbls of
Quest Energys Seminole County crude oil production is
hedged utilizing NYMEX contracts at a weighted average price of
$90.07/Bbl for 2009 and approximately 30,000 Bbls of our
Seminole County crude oil production is hedged utilizing NYMEX
contracts for 2010 through 2012 at a weighted average price of
$87.50/Bbl. For more information on our derivative contracts,
see Note 8 Financial Instruments and
Note 7 Derivative Financial Instruments, in the
notes to the consolidated financial statements in Item 8 of
this
Form 10-K.
Competition
Exploration
and Production
We operate in a highly competitive environment for acquiring
properties, marketing oil and gas and securing trained
personnel. Many of our competitors possess and employ financial,
technical and personnel resources substantially greater than
ours, which can be particularly important in the areas in which
we operate. As a result, our competitors may be able to pay more
for productive oil and gas properties and exploratory prospects
and to evaluate,
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bid for and purchase a greater number of properties and
prospects than our financial or personnel resources permit. Our
ability to acquire additional prospects and to find and develop
reserves in the future will depend on our ability to evaluate
and select suitable properties and to consummate transactions in
a highly competitive environment. Also, there is substantial
competition for capital available for investment in the oil and
gas industry.
Gas
Gathering
Quest Midstreams and Quest Easterns gas gathering
systems experience minimal competition because approximately 94%
and 99%, respectively, of these systems throughput is
attributable to Quest Energy production.
Interstate
Pipelines
We compete with other interstate and intrastate pipelines in the
transportation of natural gas for transportation customers
primarily on the basis of transportation rates, access to
competitively priced supplies of natural gas, markets served by
the pipelines, and the quality and reliability of transportation
services. Major competitors include Southern Star Central Gas
Pipeline, Kinder Morgan Interstate Gas Transmissions Pony
Express Pipeline and Panhandle Eastern Pipeline Company in the
Kansas City market, and Southern Star Central Gas Pipeline,
Peoples Natural Gas and Mid-Continent Market Center in the
Wichita market.
Title to
Properties
Oil
and Gas Properties
As is customary in the oil and gas industry, we initially
conduct only a cursory review of the title to our properties on
which we do not have proved reserves. Prior to the commencement
of development operations on those properties, we conduct a
thorough title examination and perform curative work with
respect to significant defects. To the extent title opinions or
other investigations reflect title defects on those properties,
we are typically responsible for curing any title defects at our
expense. We generally will not commence development operations
on a property until we have cured any material title defects on
such property. Prior to completing an acquisition of producing
oil and gas leases, we perform title reviews on the most
significant leases and, depending on the materiality of
properties, we may obtain a title opinion or review previously
obtained title opinions. As a result, we believe that we have
satisfactory title to our producing properties in accordance
with standards generally accepted in the oil and gas industry.
Although title to these properties is subject to encumbrances in
some cases, such as customary interests generally retained in
connection with the acquisition of real property, customary
royalty interests and contract terms and restrictions, liens
under operating agreements, liens related to environmental
liabilities associated with historical operations, liens for
current taxes and other burdens, easements, restrictions and
minor encumbrances customary in the oil and gas industry, we
believe that none of these liens, restrictions, easements,
burdens and encumbrances will materially detract from the value
of these properties or from our interest in these properties or
will materially interfere with our use in the operation of our
business. In some cases lands over which leases have been
obtained are subject to prior liens which have not been
subordinated to the leases. In addition, we believe that we have
obtained sufficient rights-of-way grants and permits from public
authorities and private parties for us to operate our business
in all material respects.
On a small percentage of our acreage (less than 1.0%), the
landowner in the past transferred the rights to the coal
underlying their land to a third party. With respect to those
properties, we have obtained oil and gas leases from the owners
of the oil, gas, and minerals other than coal underlying those
lands. In Oklahoma and Kansas, the law is unsettled as to
whether the owner of the gas rights or the coal rights is
entitled to the CBM gas. We are currently involved in litigation
with the owner of the coal rights on these lands to determine
who has the rights to the CBM gas.
Pipeline
Rights-of-Way
Substantially all of our gathering systems and our transmission
pipeline are constructed within rights-of-way granted by
property owners named in the appropriate land records. All of
our compressor stations are located on property owned in fee or
on property obtained via long-term leases or surface easements.
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Our property or rights-of-way are subject to encumbrances,
restrictions and other imperfections. These imperfections have
not interfered, and we do not expect that they will materially
interfere, with the conduct of our business. In many instances,
lands over which rights-of-way have been obtained are subject to
prior liens which have not been subordinated to the right-of-way
grants. In some cases, not all of the owners named in the
appropriate land records have joined in the right-of-way grants,
but in substantially all such cases signatures of the owners of
majority interests have been obtained. Substantially all permits
have been obtained from public authorities to cross over or
under, or to lay facilities in or along, water courses, county
roads, municipal streets, and state highways, where necessary.
Substantially all permits have also been obtained from railroad
companies to cross over or under lands or rights-of-way, many of
which are also revocable at the grantors election.
Certain of our rights to lay and maintain pipelines are derived
from recorded oil and gas leases, for wells that are currently
in production; however, the leases are subject to termination if
the wells cease to produce. In most cases, the right to maintain
existing pipelines continues in perpetuity, even if the well
associated with the lease ceases to be productive. In addition,
because some of these leases affect wells at the end of lines,
these rights-of-way will not be used for any other purpose once
the related wells cease to produce.
Seasonal
Nature of Business
Exploration
and Production and Gas Gathering
Seasonal weather conditions and lease stipulations can limit our
development activities and other operations and, as a result, we
seek to perform a significant percentage of our development
during the spring and summer months. These seasonal anomalies
can pose challenges for meeting our well development objectives
and increase competition for equipment, supplies and personnel
during the spring and summer months, which could lead to
shortages and increase costs or delay our operations.
In addition, freezing weather, winter storms and flooding in the
spring and summer have in the past resulted in a number of our
wells being off-line for a short period of time, which adversely
affects our production volumes and revenues and increases our
lease operating costs due to the time spent by field employees
to bring the wells back on-line.
Generally, but not always, the demand for gas decreases during
the summer months and increases during the winter months thereby
affecting the price we receive for gas. Seasonal anomalies such
as mild winters and hot summers sometimes lessen this
fluctuation.
Interstate
Pipelines
Due to the nature of the markets served by the KPC Pipeline,
primarily the metropolitan Wichita and Kansas City markets
heating load, the utilization rate of the KPC Pipeline has
traditionally been much higher in the winter months (December
through April) than in the remainder of the year. However, due
to the nature of the firm transportation agreements under which
the vast majority of the KPC Pipeline revenue is derived, we
are, to a material degree, profit neutral to these seasonal
fluctuations.
Environmental
Matters and Regulation
General
Our operations are subject to stringent and complex federal,
state and local laws and regulations governing environmental
protection as well as the discharge of materials into the
environment. These laws and regulations may, among other things:
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require the acquisition of various permits before drilling
commences;
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enjoin some or all of the operations of facilities deemed in
non-compliance with permits;
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restrict the types, quantities and concentration of various
substances that can be released into the environment in
connection with oil and gas drilling, production and
transportation activities;
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limit or prohibit drilling activities on certain lands lying
within wilderness, wetlands, areas inhabited by endangered or
threatened species, and other protected areas; and
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require remedial measures to mitigate pollution from former and
ongoing operations, such as requirements to close pits and plug
abandoned wells.
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These laws, rules and regulations may also restrict the rate of
oil and gas production below the rate that would otherwise be
possible. The regulatory burden on the oil and gas industry
increases the cost of doing business in the industry and
consequently affects profitability. Additionally, Congress and
federal and state agencies frequently revise environmental laws
and regulations, and the clear trend in environmental regulation
is to place more restrictions and limitations on activities that
may affect the environment. Any changes that result in more
stringent and costly waste handling, disposal and cleanup
requirements for the oil and gas industry could have a
significant impact on our operating costs.
The following is a summary of some of the existing laws, rules
and regulations to which our business operations are subject.
Waste
Handling
The Resource Conservation and Recovery Act, or RCRA, and
comparable state statutes, regulate the generation,
transportation, treatment, storage, disposal and cleanup of
hazardous and non-hazardous solid wastes. Under the auspices of
the federal Environmental Protection Agency, or EPA, the
individual states administer some or all of the provisions of
RCRA, sometimes in conjunction with their own, more stringent
requirements. Drilling fluids, produced waters, and most of the
other wastes associated with the exploration, development,
production and transportation of oil and gas are currently
regulated under RCRAs non-hazardous waste provisions.
However, it is possible that certain oil and gas exploration and
production wastes now classified as non-hazardous could be
classified as hazardous wastes in the future. Any such change
could result in an increase in our costs to manage and dispose
of wastes, which could have a material adverse effect on our
results of operations and financial position. Also, in the
course of our operations, we generate some amounts of ordinary
industrial wastes, such as paint wastes, waste solvents, and
waste oils, which may be regulated as hazardous wastes. The
transportation of natural gas in pipelines may also generate
some hazardous wastes that are subject to RCRA or comparable
state law requirements.
Comprehensive
Environmental Response, Compensation and Liability
Act
The Comprehensive Environmental Response, Compensation and
Liability Act, or CERCLA, also known as the Superfund law,
imposes joint and several liabilities, without regard to fault
or legality of conduct, on classes of persons who are considered
to be responsible for the release of a hazardous substance into
the environment. These persons include the current and past
owner or operator of the site where the release occurred, and
anyone who disposed or arranged for the disposal of a hazardous
substance released at the site. Under CERCLA, such persons may
be subject to joint and several liabilities for the costs of
cleaning up the hazardous substances that have been released
into the environment, for damages to natural resources, and for
the costs of certain environmental studies. In addition, it is
not uncommon for neighboring landowners and other third parties
to file claims for personal injury and property damage allegedly
caused by the hazardous substances released into the environment.
We currently own, lease or operate numerous properties that have
been used for oil and gas exploration, production, and
transportation for many years. Although we believe that we have
utilized operating and waste disposal practices that were
standard in the industry at the time, hazardous substances,
wastes, or hydrocarbons may have been released on or under the
properties owned or leased by us, or on or under other
locations, including off-site locations, where such substances
have been taken for disposal. In addition, some of our
properties have been operated by third parties or by previous
owners or operators whose treatment and disposal of hazardous
substances, wastes, or hydrocarbons was not under our control.
In fact, there is evidence that petroleum spills or releases
have occurred in the past at some of the properties owned or
leased by us. These properties and the substances disposed or
released on them may be subject to CERCLA, RCRA, and analogous
state laws. Under such laws, we could be required to remove
previously disposed substances and wastes, remediate
contaminated property, or perform plugging or pit closure
operations to prevent future contamination.
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Water
Discharges
The Clean Water Act (CWA) and analogous state laws,
impose restrictions and strict controls with respect to the
discharge of pollutants in waste water and storm water,
including spills and leaks of oil and other substances, into
waters of the United States. The discharge of pollutants into
regulated waters is prohibited, except in accordance with the
terms of a permit issued by EPA or an analogous state agency.
The CWA regulates storm water run-off from oil and gas
production operations and requires a storm water discharge
permit for certain activities. Such a permit requires the
regulated facility to monitor and sample storm water run-off
from its operations. The CWA and regulations implemented
thereunder also prohibit the discharge of dredge and fill
material into regulated waters, including wetlands, unless
authorized by an appropriately issued permit. Spill prevention,
control and countermeasure requirements of the CWA may require
appropriate containment berms and similar structures to help
prevent the contamination of navigable waters in the event of a
petroleum hydrocarbon tank spill, rupture or leak. Federal and
state regulatory agencies can also impose administrative, civil
and criminal penalties for non-compliance with discharge permits
or other requirements of the CWA and analogous state laws and
regulations.
Our operations also produce wastewaters that are disposed via
underground injection wells. These activities are regulated by
the Safe Drinking Water Act (SDWA) and analogous
state and local laws. The underground injection well program
under the SDWA classifies produced wastewaters and imposes
controls relating to the drilling and operation of the wells as
well as the quality of the injected wastewaters. This program is
designed to protect drinking water sources and requires a permit
from the EPA or the designated state agency. Currently, our
operations comply with all applicable requirements and have a
sufficient number of operating injection wells. However, a
change in the regulations or the inability to obtain new
injection well permits in the future may affect our ability to
dispose of the produced waters and ultimately affect the results
of operations.
The primary federal law for oil spill liability is the Oil
Pollution Act, or OPA, which addresses three principal areas of
oil pollution: prevention, containment, and cleanup. OPA applies
to vessels, offshore facilities, and onshore facilities,
including exploration and production facilities that may affect
waters of the United States. Under OPA, responsible parties,
including owners and operators of onshore facilities, may be
subject to oil cleanup costs and natural resource damages as
well as a variety of public and private damages that may result
from oil spills.
Air
Emissions
The Federal Clean Air Act (CAA) and comparable state
laws regulate emissions of various air pollutants through air
emissions permitting programs and the imposition of other
requirements. Such laws and regulations may require a facility
to obtain pre-approval for the construction or modification of
certain projects or facilities expected to produce air emissions
or result in the increase of existing air emissions, obtain or
strictly comply with air permits containing various emissions
and operational limitations or utilize specific emission control
technologies to limit emissions. In addition, EPA has developed,
and continues to develop, stringent regulations governing
emissions of toxic air pollutants at specified sources.
Moreover, depending on the state-specific statutory authority,
states may be able to impose air emissions limitations that are
more stringent than the federal standards imposed by EPA.
Federal and state regulatory agencies can also impose
administrative, civil and criminal penalties for non-compliance
with air permits or other requirements of the federal CAA and
associated state laws and regulations.
Permits and related compliance obligations under the CAA, as
well as changes to state implementation plans for controlling
air emissions in regional non-attainment areas, may require oil
and gas exploration, production and transportation operations to
incur future capital expenditures in connection with the
addition or modification of existing air emission control
equipment and strategies. In addition, some oil and gas
facilities may be included within the categories of hazardous
air pollutant sources, which are subject to increasing
regulation under the CAA. Failure to comply with these
requirements could subject a regulated entity to monetary
penalties, injunctions, conditions or restrictions on operations
and enforcement actions. Oil and gas exploration and production
facilities may be required to incur certain capital expenditures
in the future for air pollution control equipment in connection
with obtaining and maintaining operating permits and approvals
for air emissions.
Such laws and regulations may require that we obtain
pre-approval for the construction or modification of certain
projects or facilities expected to produce air emissions or
result in the increase of existing air emissions, obtain and
strictly comply with air permits containing various emissions
and operational limitations, or use specific
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emission control technologies to limit emissions. Our failure to
comply with these requirements could subject us to monetary
penalties, injunctions, conditions or restrictions on
operations, and potentially criminal enforcement actions.
Historically, air pollution control has become more stringent
over time. This trend is expected to continue. The cost of
technology and systems to control air pollution to meet
regulatory requirements is significant today. These costs are
expected to increase as air pollution control requirements
increase. We believe, however, that our operations will not be
materially adversely affected by such requirements, and the
requirements are not expected to be any more burdensome to us
than to any other similarly situated companies.
The Kyoto Protocol to the United Nations Framework Convention on
Climate Change, or the Protocol, became effective in February
2005. Under the Protocol, participating nations are required to
implement programs to reduce emissions of certain gases,
generally referred to as greenhouse gases, that are
suspected of contributing to global warming. The United States
is not currently a participant in the Protocol; however,
Congress has recently considered proposed legislation directed
at reducing greenhouse gas emissions, and certain
states have adopted legislation, regulations
and/or
initiatives addressing greenhouse gas emissions from various
sources, primarily power plants. Additionally, on April 2,
2007, the U.S. Supreme Court ruled in
Massachusetts v. EPA
that the EPA has authority
under the CAA to regulate greenhouse gas emissions from mobile
sources (
e.g.
, cars and trucks). The Court also held that
greenhouse gases fall within the CAAs definition of
air pollutant, which could result in future
regulation of greenhouse gas emissions from stationary sources,
including those used in oil and gas exploration, production and
transportation operations. The oil and gas industry is a direct
source of certain greenhouse gas emissions, namely carbon
dioxide and methane, and future restrictions on such emissions
could impact our future operations. Our operations are not
adversely impacted by the current state and local climate change
initiatives and, at this time, it is not possible to accurately
estimate how potential future laws or regulations addressing
greenhouse gas emissions would impact our business.
Hydrogen
Sulfide
Hydrogen sulfide gas is a byproduct of sour gas treatment.
Exposure to unacceptable levels of hydrogen sulfide (known as
sour gas) is harmful to humans, and prolonged exposure can
result in death. We employ numerous safety precautions to ensure
the safety of our employees. There are various federal and state
environmental and safety requirements that apply to facilities
using or producing hydrogen sulfide gas. Notwithstanding
compliance with such requirements, common law causes of action
are available to persons damaged by exposure to hydrogen sulfide
gas.
National
Environmental Policy Act
Oil and gas exploration and production activities on federal
lands are subject to the National Environmental Policy Act, or
NEPA. NEPA requires federal agencies, including the Department
of Interior, to evaluate major agency actions having the
potential to significantly impact the environment. In the course
of such evaluations, an agency will prepare an Environmental
Assessment that assesses the potential direct, indirect and
cumulative impacts of a proposed project and, if necessary, will
prepare a more detailed Environmental Impact Statement that may
be made available for public review and comment. If we were to
conduct any exploration and production activities on federal
lands in the future, those activities would need to obtain
governmental permits that are subject to the requirements of
NEPA. This process has the potential to delay the development of
oil and gas projects.
Endangered
Species Act
The Endangered Species Act (ESA) and analogous state
laws restrict activities that may affect endangered or
threatened species or their habitats. Although we believe that
our current operations do not affect endangered or threatened
species or their habitats, the existence of endangered or
threatened species in areas of future operations and development
could cause us to incur additional mitigation costs or become
subject to construction or operating restrictions or bans in the
affected areas.
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OSHA
and Other Laws and Regulation
We are subject to the requirements of the federal Occupational
Safety and Health Act, or OSHA, and comparable state statutes.
These laws and the implementing regulations strictly govern the
protection of the health and safety of employees. The
Occupational Safety and Health Administrations hazard
communication standard, EPA community right-to-know regulations
under the Title III of CERCLA and similar state statutes
require that we organize
and/or
disclose information about hazardous materials used or produced
in our operations. We believe that we are in substantial
compliance with these applicable requirements and with other
comparable laws.
We believe that we are in substantial compliance with all
existing environmental and safety laws and regulations
applicable to our current operations and that our continued
compliance with existing requirements will not have a material
adverse impact on our financial condition and results of
operations. For instance, we did not incur any material capital
expenditures for remediation or pollution control activities for
the year ended December 31, 2008. Additionally, as of the
date of this report, we are not aware of any environmental
issues or claims that will require material capital expenditures
during 2009. However, accidental spills or releases may occur in
the course of our operations, and we cannot assure you that we
will not incur substantial costs and liabilities as a result of
such spills or releases, including those relating to claims for
damage to property and persons. Moreover, we cannot assure you
that the passage of more stringent laws or regulations in the
future will not have a negative impact on our business,
financial condition, or results of operations.
Other
Regulation of the Oil and Gas Industry
The oil and gas industry is extensively regulated by numerous
federal, state and local authorities. Legislation affecting the
oil and gas industry is under constant review for amendment or
expansion, frequently increasing the regulatory burden. Also,
numerous departments and agencies, both federal and state, are
authorized by statute to issue rules and regulations binding on
the oil and gas industry and its individual members, some of
which carry substantial penalties for failure to comply.
Although the regulatory burden on the oil and gas industry
increases our cost of doing business and, consequently, affects
our profitability, these burdens generally do not affect us any
differently or to any greater or lesser extent than they affect
other companies in the industry with similar types, quantities
and locations of production.
Legislation continues to be introduced in Congress and
development of regulations continues in the Department of
Homeland Security and other agencies concerning the security of
industrial facilities, including gas and oil facilities. Our
operations may be subject to such laws and regulations.
Presently, it is not possible to accurately estimate the costs
we could incur to comply with any such facility security laws or
regulations, but such expenditures could be substantial.
Exploration
and Production
Our operations are subject to various types of regulation at
federal, state and local levels. These types of regulation
include requiring permits for the drilling of wells, drilling
bonds and reports concerning operations. Most states, and some
counties and municipalities, in which we operate also regulate
one or more of the following:
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the location of wells;
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the method of drilling and casing wells;
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the surface use and restoration of properties upon which wells
are drilled;
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the plugging and abandoning of wells; and
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notice to surface owners and other third parties.
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Some state laws regulate the size and shape of drilling and
spacing units or proration units governing the pooling of oil
and gas properties. Some states allow forced pooling or
integration of tracts to facilitate exploration while other
states rely on voluntary pooling of lands and leases. In some
instances, forced pooling or unitization may be implemented by
third parties and may reduce our interest in the unitized
properties. In addition, some state conservation laws establish
maximum rates of production from oil and gas wells. These laws
generally prohibit the
35
venting or flaring of gas and impose requirements regarding the
ratability of production. These laws and regulations may limit
the amount of oil and gas we can produce from our wells or limit
the number of wells or the locations at which we can drill.
Moreover, some states impose a production or severance tax with
respect to the production and sale of oil, gas and gas liquids
within its jurisdiction.
The Cherokee Basin has been an active oil and gas producing
region for a number of years. Many of our properties had
abandoned oil and conventional gas wells on them at the time the
current lease was entered into with the landowner. A number of
these wells remain unplugged or were improperly plugged by a
prior landowner or operator. Many of the former operators of
these wells have ceased operations and cannot be located or do
not have the financial resources to plug these wells. We believe
that we are not responsible for plugging an abandoned well on
one of our leases, unless we have used, attempted to use or
invaded the abandoned well bore in our operations on the land or
have otherwise agreed to assume responsibility for plugging the
wells. The Kansas Corporation Commissions current
interpretation of Kansas law is consistent with our position.
Interstate
Pipelines
The availability, terms and cost of transportation significantly
affect sales of gas. The interstate transportation of gas and
sale for resale of gas is subject to federal regulation,
including regulation of the terms, conditions and rates for
interstate transportation, storage and various other matters,
primarily by the Federal Energy Regulatory Commission
(FERC). Federal and state regulations govern the
price and terms for access to gas pipeline transportation. FERC
is continually proposing and implementing new rules and
regulations affecting those segments of the gas industry, most
notably interstate gas transmission companies that remain
subject to FERCs jurisdiction. These initiatives also may
affect the intrastate transportation of gas under certain
circumstances. The stated purpose of many of these regulatory
changes is to promote competition among the various sectors of
the gas industry. We cannot predict the ultimate impact of these
regulatory changes to our operations, and we note that some of
FERCs more recent proposals may adversely affect the
availability and reliability of interruptible transportation
service on interstate pipelines. We do not believe that we will
be affected by any such FERC action materially differently than
other interstate pipelines with which we compete.
The Energy Policy Act of 2005, or EP Act 2005, gave FERC
increased oversight and penalty authority regarding market
manipulation and enforcement. EP Act 2005 amended the Natural
Gas Act of 1938, or NGA, to prohibit market manipulation and
also amended the NGA and the Natural Gas Policy Act of 1978, or
NGPA, to increase civil and criminal penalties for any
violations of the NGA, NGPA and any rules, regulations or orders
of FERC to up to $1,000,000 per day, per violation. In addition,
FERC issued a final rule effective January 26, 2006
regarding market manipulation, which makes it unlawful for any
entity, in connection with the purchase or sale of gas or
transportation service subject to FERCs jurisdiction, to
defraud, make an untrue statement or omit a material fact or
engage in any practice, act or course of business that operates
or would operate as a fraud. This final rule works together with
FERCs enhanced penalty authority to provide increased
oversight of the gas marketplace.
Although gas prices are currently unregulated, FERC promulgated
regulations in December 2007 requiring natural gas sellers to
submit an annual report, beginning in July 2009, reporting
certain information regarding natural gas purchases and sales
(
e.g.
, total volumes bought and sold, volumes bought and
sold and index prices, etc.). Additionally, Congress
historically has been active in the area of gas regulation. We
cannot predict whether new legislation to regulate gas might be
proposed, what proposals, if any, might actually be enacted by
Congress or the various state legislatures, and what effect, if
any, the proposals might have on the operations of the
underlying properties. Sales of condensate and gas liquids are
not currently regulated and are made at market prices.
State
Regulation
The various states regulate the drilling for, and the
production, gathering and sale of, oil and gas, including
imposing severance taxes and requirements for obtaining drilling
permits. For example, Kansas currently imposes a severance tax
on the gross value of oil and gas produced from wells having an
average daily production during a calendar month with a gross
value of more than $87 per day. Kansas also imposes oil and gas
conservation assessments per barrel of oil and per 1,000 cubic
feet of gas produced. In general, oil and gas leases and oil and
gas
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wells (producing or capable of producing), including all
equipment associated with such leases and wells, are subject to
an ad valorem property tax.
Oklahoma imposes a monthly gross production tax and excise tax
based on the gross value of the oil and gas produced. Oklahoma
also imposes an excise tax based on the gross value of oil and
gas produced. All property used in the production of oil and gas
is exempt from ad valorem taxation if gross production taxes are
paid. Lastly, the rate of taxation of locally assessed property
varies from county to county and is based on the fair cash value
of personal property and the fair cash value of real property.
West Virginia imposes a severance tax equal to five percent of
the gross value of oil and gas produced and a similar severance
tax on CBM produced. West Virginia also imposes an additional
annual privilege tax equal to 4.7 cents per Mcf of natural gas
produced. New York imposes an annual oil and gas charge based on
the amount of oil or natural gas produced each year.
States may regulate rates of production and may establish
maximum daily production allowables from oil and gas wells based
on market demand or resource conservation, or both. States do
not regulate wellhead prices or engage in other similar direct
economic regulation, but there can be no assurance that they
will not do so in the future. The effect of these regulations
may limit the amounts of oil and gas that may be produced from
our wells and may limit the number of wells or locations drilled.
Federal
Regulation of Transportation of Gas
FERC regulates interstate natural gas pipelines pursuant to the
NGA, NGPA and EP Act 2005. Generally, FERCs authority over
interstate natural gas pipelines extends to:
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rates and charges for natural gas transportation services;
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certification and construction of new facilities;
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extension or abandonment of services and facilities;
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maintenance of accounts and records;
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relationships between pipelines and certain affiliates;
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terms and conditions of service;
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depreciation and amortization policies;
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acquisition and disposition of facilities; and
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initiation and discontinuation of services.
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Rates charged by interstate natural gas pipelines may generally
not exceed the just and reasonable rates approved by FERC,
unless they are filed as negotiated rates and
accepted by the FERC. In addition, interstate natural gas
pipelines are prohibited from granting any undue preference to
any person, or maintaining any unreasonable difference in their
rates, terms, or conditions of service. Consistent with these
requirements, the rates, terms, and conditions of the natural
gas transportation services provided by interstate pipelines are
governed by tariffs approved by FERC.
We own and operate one interstate natural gas pipeline system
that is subject to these regulatory requirements. KPC owns and
operates a 1,120-mile interstate natural gas pipeline system,
which transports natural gas from Oklahoma and western Kansas to
the metropolitan markets of Wichita and Kansas City. As an
interstate natural gas pipeline, KPC is subject to FERCs
jurisdiction and the regulatory requirements summarized above.
Maintaining compliance with these requirements on a continuing
basis requires KPC to incur various expenses. Additional
compliance expenses could be incurred if new or amended laws or
regulations are enacted or existing laws or regulations are
reinterpreted. KPCs customers, the state commissions that
regulate certain of those customers, and other interested
parties also have the right to file complaints seeking changes
in the KPC tariff, including with respect to the transportation
rates stated therein.
37
Our remaining natural gas pipeline facilities are generally
exempt from FERCs jurisdiction and regulation pursuant to
Section 1(b) of the NGA, which exempts pipeline facilities
that perform primarily a gathering function, rather than a
transportation function. We believe our pipeline facilities
(other than the KPC system) meet the traditional tests used by
FERC to distinguish gathering facilities from transportation
facilities. However, if FERC were to determine that the
facilities perform primarily a transportation function, rather
than a gathering function, these facilities may become subject
to regulation as interstate natural gas pipeline facilities. We
believe the expenses associated with seeking certificate
authority for construction, service and abandonment,
establishing rates and a tariff for these other facilities, and
meeting the detailed regulatory accounting and reporting
requirements would substantially increase our operating costs
and would adversely affect our profitability.
Additionally, while generally exempt from FERCs
jurisdiction, FERC adopted new internet posting requirements in
November 2008 that are applicable to certain gathering
facilities and other non-interstate pipelines meeting size and
other thresholds. Various parties have requested rehearing of
the FERC rule adopting the new posting requirements and the FERC
has granted an extension of time to comply with the new
requirements until 150 days following the issuance of an
order addressing the requests for rehearing. If the rules are
upheld on rehearing and become applicable to our gathering
facilities, they would likely require us to post certain
pipeline operational information on a daily basis, which could
require us to incur additional compliance expenses.
State
Regulation of Natural Gas Gathering Pipelines
Our natural gas gathering pipeline operations are currently
limited to the States of Kansas, Oklahoma, New York, and West
Virginia. State regulation of gathering facilities generally
includes various safety, environmental and, in some
circumstances, nondiscriminatory take requirements, and
compliant-based rate regulation. Bluestem is licensed as an
operator of a natural gas gathering system with the KCC and is
required to file periodic information reports with the KCC. We
are not required to be licensed as an operator or to file
reports in Oklahoma, New York or West Virginia.
On those portions of our gas gathering system that are open to
third party producers, the producers have the ability to file
complaints challenging our gathering rates, terms of services
and practice. Our fees, terms and practice must be just,
reasonable, not unjustly discriminatory and not unduly
preferential. If the KCC or the Oklahoma Corporation Commission
(OCC), as applicable, were to determine that the rates charged
to a complainant did not meet this standard, the KCC or the OCC,
as applicable, would have the ability to adjust our rates with
respect to the wells that were the subject of the complaint. We
are not aware of any instance in which either the KCC or the OCC
has made such a determination in the past.
These regulatory burdens may affect profitability, and
management is unable to predict the future cost or impact of
complying with such regulations. While state regulation of
pipeline transportation does not materially affect our
operations, we do own several small, discrete delivery laterals
in Kansas that are subject to a limited jurisdiction certificate
issued by the KCC. As with FERC regulation described above,
state regulation of pipeline transportation may influence
certain aspects of our business and the market price for our
products.
Sales
of Natural Gas
The price at which we buy and sell natural gas currently is not
subject to federal regulation and, for the most part, is not
subject to state regulation. Our sales of natural gas are
affected by the availability, terms and cost of pipeline
transportation. As noted above, the price and terms of access to
pipeline transportation are subject to extensive federal and
state regulation. FERC is continually proposing and implementing
new rules and regulations affecting those segments of the
natural gas industry, most notably interstate natural gas
transmission companies that remain subject to FERCs
jurisdiction. These initiatives also may affect the intrastate
transportation of natural gas under certain circumstances. The
stated purpose of many of these regulatory changes is to promote
competition among the various sectors of the natural gas
industry, and these initiatives generally reflect more
light-handed regulation. We cannot predict the ultimate impact
of these regulatory changes to our natural gas marketing
operations, and we note that some of FERCs more recent
proposals may adversely affect the availability and reliability
of interruptible transportation service on interstate pipelines.
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Pipeline
Safety
Our pipelines are subject to regulation by the
U.S. Department of Transportation, or the DOT, under the
Natural Gas Pipeline Safety Act of 1968, as amended, or the
NGPSA, pursuant to which the DOT has established requirements
relating to the design, installation, testing, construction,
operation, replacement and management of pipeline facilities.
The NGPSA covers the pipeline transportation of natural gas and
other gases and requires any entity that owns or operates
pipeline facilities to comply with the regulations under the
NGPSA, to permit access to and allow copying of records and to
make certain reports and provide information as required by the
Secretary of Transportation. We believe that our pipeline
operations are in substantial compliance with applicable NGPSA
requirements; however, if new or amended laws and regulations
are enacted or existing laws and regulations are reinterpreted,
future compliance with the NGPSA could result in increased costs.
Other
In addition to existing laws and regulations, the possibility
exists that new legislation or regulations may be adopted which
would have a significant impact on our operations or our
customers ability to use gas and may require us or our
customers to change their operations significantly or incur
substantial costs. Additional proposals and proceedings that
might affect the gas industry are pending before Congress, FERC,
the Minerals Management Service, state commissions and the
courts. We cannot predict when or whether any such proposals may
become effective. In the past, the natural gas industry has been
heavily regulated. There is no assurance that the regulatory
approach currently pursued by various agencies will continue
indefinitely.
Failure to comply with these laws and regulations may result in
the assessment of administrative, civil
and/or
criminal penalties, the imposition of injunctive relief or both.
Moreover, changes in any of these laws and regulations could
have a material adverse effect on our business. In view of the
many uncertainties with respect to current and future laws and
regulations, including their applicability to us, we cannot
predict the overall effect of such laws and regulations on our
future operations.
Management believes that our operations comply in all material
respects with applicable laws and regulations and that the
existence and enforcement of such laws and regulations have no
more restrictive effect on our method of operations than on
other similar companies in the energy industry. We have internal
procedures and policies to ensure that our operations are
conducted in substantial regulatory compliance.
Employees
At December 31, 2008, we had a staff of 177 field employees
in offices located in Kansas, Oklahoma, Pennsylvania, and West
Virginia. We have 61 pipeline operations employees. Our staff
consists of 72 executive and administrative personnel at the
headquarters office in Oklahoma City and the Quest Midstream
office in Houston, Texas. None of our employees are covered by a
collective bargaining agreement. Management considers its
relations with our employees to be satisfactory.
Administrative
Facilities
The office space for the corporate headquarters for us and our
subsidiaries and affiliates is leased and is located at 210 Park
Avenue, Suite 2750, Oklahoma City, Oklahoma 73102. The
office lease is for 10 years expiring August 31, 2017
covering approximately 35,000 square feet. We own three
buildings located in Chanute, Kansas that are used for
administrative offices, a geological laboratory, an operations
terminal and a repair facility. We own an additional building
and storage yard in Lenapah, Oklahoma.
The office space for Quest Eastern is leased and is located at
2200 Georgetowne Drive, Suite 301, Sewickley, Pennsylvania
15143. The office lease is for five years expiring
August 1, 2013 covering approximately 4,744 square
feet. Quest Eastern owns a 50% interest in a nine acre lot with
building improvements in Wetzel County, West Virginia that
is used for equipment storage and office space.
Quest Midstream has 9,801 square feet of office space for
some of its management personnel that is leased and is located
at 3 Allen Center, 333 Clay Street, Suite 4060, Houston,
Texas 77002. The office lease expires on May 6, 2015. Quest
Midstream also owns an operational office that is located east
of Chanute, Kansas. KPC has leased
39
facilities at Olathe, Wichita, and Medicine Lodge, Kansas for
the operations of its interstate pipeline. The Olathe office
consists of approximately 7,650 square feet for a lease
term of five years expiring October 31, 2011. The Wichita
office consists of approximately 1,240 square feet on a one
year lease, with an extension expiring December 31, 2009.
The Medicine Lodge field office is leased on a month to month
basis.
Where To
Find Additional Information
Additional information about us can be found on our website at
www.questresourcecorp.com. We also provide free of charge on our
website our filings with the SEC, including our annual reports,
quarterly reports, and current reports along with any amendments
thereto, as soon as reasonably practicable after we have
electronically filed such material with, or furnished it to, the
SEC.
40
GLOSSARY
OF SELECTED TERMS
The following is a description of the meanings of some of the
oil and natural gas industry terms used in this
Form 10-K.
Appalachian Basin.
One of the United
States oldest oil and natural gas producing regions that
extends from Alabama to Maine.
Bbl.
One stock tank barrel, or 42
U.S. gallons liquid volume, of crude oil or other liquid
hydrocarbons.
Bcf.
One billion cubic feet of gas.
Bcfe.
One billion cubic feet equivalent,
determined using the ratio of six Mcf of gas to one Bbl of crude
oil, condensate or gas liquids.
Brown Shales.
Fine grained rocks composed
largely of clay minerals that contain little organic matter.
Some of these shales immediately overlay the Marcellus Shale.
Btu or British Thermal Unit.
The quantity of
heat required to raise the temperature of a one pound mass of
water by one degree Fahrenheit.
CBM.
Coal bed methane.
Cherokee Basin.
A fifteen-county region in
southeastern Kansas and northeastern Oklahoma.
Completion.
The installation of permanent
equipment for the production of oil or gas, or in the case of a
dry hole, the reporting of abandonment to the appropriate agency.
Developed acreage.
The number of acres that
are allocated or assignable to productive wells or wells capable
of production.
Development well.
A well drilled within the
proved boundaries of an oil or gas reservoir to the depth of a
stratigraphic horizon known to be productive.
Devonian Sands.
Sands generally younger and
shallower than the Marcellus Shale that occur in portions of
Ohio, New York, Pennsylvania, West Virginia, Kentucky and
Tennessee and generally located at depths of less than
5,000 feet.
Dry hole.
A well found to be incapable of
producing hydrocarbons in paying quantities.
Dth.
One dekatherm, equivalent to one million
British Thermal Units.
Earned acreage.
The number of acres that has
been assigned as a result of fulfilling conditions or
requirements of an agreement.
Exploitation.
A development or other project
which may target proven or unproven reserves (such as probable
or possible reserves), but which generally has a lower risk than
that associated with exploration projects.
Exploratory well.
A well drilled: a) to
find and produce oil or gas in an area previously considered
unproductive; b) to find a new reservoir in a known field,
i.e., one previously producing oil and gas from another
reservoir, or c) to extend the limit of a known oil or gas
reservoir.
Farm-in or farm-out.
An agreement under which
the owner of a working interest in an oil or gas lease assigns
the working interest or a portion of the working interest to
another party who desires to drill on the leased acreage.
Generally, the assignee is required to drill one or more wells
in order to earn its interest in the acreage. The assignor
usually retains a royalty or reversionary interest in the lease.
The interest received by an assignee is a farm-in
while the interest transferred by the assignor is a
farm-out. Acreage is considered to be unearned,
until the conditions of the agreement are met, and an assignment
of interest has been made.
Field.
An area consisting of either a single
reservoir or multiple reservoirs, all grouped on or related to
the same individual geological structural feature
and/or
stratigraphic condition.
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Frac/fracturing.
The method used to increase
the deliverability of a well by pumping a liquid or other
substance into a well under pressure to crack and prop open the
hydrocarbon formation.
Gas.
Hydrocarbon gas found in the earth,
composed of methane, ethane, butane, propane and other gases.
Gathering system.
Pipelines and other
equipment used to move gas from the wellhead to the trunk or the
main transmission lines of a pipeline system.
Gross acres or gross wells.
The total acres or
wells, as the case may be, in which we have a working interest.
Horizon or formation.
The section of rock,
from which gas is expected to be produced.
Marcellus Shale.
A black, organic-rich shale
formation in the Appalachian Basin that occurs in much of Ohio,
West Virginia, Pennsylvania and New York and portions of
Maryland, Kentucky, Tennessee and Virginia. The fairway of the
Marcellus Shale is generally located at depths between 3,500 and
8,000 feet and ranges in thickness from 50 to 150 feet.
Mcf.
One thousand cubic feet of gas.
Mcf/d.
One Mcf per day.
Mcfe.
One thousand cubic feet equivalent,
determined using the ratio of six Mcf of gas to one Bbl of crude
oil, condensate or gas liquids.
Mmbtu.
One million British thermal units.
Mmcf.
One million cubic feet of gas.
Mmcf/d.
One
Mmcf per day.
Mmcfe.
One million cubic feet equivalent,
determined using the ratio of six Mcf of gas to one Bbl of crude
oil, condensate or gas liquids.
Mmcfe/d.
One million cubic feet equivalent per
day.
Net acres or net wells.
The sum of the
fractional working interests owned in gross acres or wells, as
the case may be.
Net production.
Production that is owned by us
less royalties and production due others.
Net revenue interest.
The percentage of
revenues due an interest holder in a property, net of royalties
or other burdens on the property.
NGLs.
Natural gas liquids being the
combination of ethane, propane, butane and natural gasoline that
when removed from natural gas become liquid under various levels
of higher pressure and lower temperature.
NYMEX.
The New York Mercantile Exchange.
Oil.
Crude oil, condensate and NGLs.
Permeability.
The ability, or measurement of a
rocks ability, to transmit fluids, typically measured in
darcies or millidarcies.
Perforation.
The making of holes in casing and
cement (if present) to allow formation fluids to enter the well
bore.
Productive well.
A well that produces
commercial quantities of hydrocarbons exclusive of its capacity
to produce at a reasonable rate of return.
Proved developed non-producing
reserves.
Proved developed reserves expected to
be recovered from zones behind casings in existing wells.
Proved developed reserves.
Proved reserves
that can be expected to be recovered from existing wells with
existing equipment and operating methods. This definition of
proved developed reserves has been abbreviated from the
applicable definitions contained in
Rule 4-10(a)(2-4)
of
Regulation S-X.
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Proved reserves.
The estimated quantities of
crude oil, natural gas and NGLs that geological and engineering
data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and
operating conditions. This definition of proved reserves has
been abbreviated from the applicable definitions contained in
Rule 4-10(a)(2-4)
of
Regulation S-X.
Proved undeveloped reserves.
Proved reserves
that are expected to be recovered from new wells drilled to
known reservoirs on acreage yet to be drilled for which the
existence and recoverability of such reserves can be estimated
with reasonable certainty, or from existing wells where a
relatively major expenditure is required to establish
production. This definition of proved undeveloped reserves has
been abbreviated from the applicable definitions contained in
Rule 4-10(a)(2-4)
of
Regulation S-X.
Recompletion.
The completion for production of
an existing wellbore in another formation from that which the
well has been previously completed.
Reserve.
That part of a mineral deposit which
could be economically and legally extracted or produced at the
time of the reserve determination.
Reserve-to-production ratio.
This ratio is
calculated by dividing estimated net proved reserves by the
production from the previous year to estimate the number of
years of remaining production.
Reservoir.
A porous and permeable underground
formation containing a natural accumulation of producible oil
and/or
gas
that is confined by impermeable rock or water barriers and is
individual and separate from other reservoirs.
Royalty Interest.
A real property interest
entitling the owner to receive a specified portion of the gross
proceeds of the sale of oil and natural gas production or, if
the conveyance creating the interest provides, a specific
portion of oil or natural gas produced, without any deduction
for the costs to explore for, develop or produce the oil and
gas. A royalty interest owner has no right to consent to or
approve the operation and development of the property, while the
owners of the working interests have the exclusive right to
exploit the mineral on the land.
Shut in.
To close down a well temporarily.
Standardized measure.
The present value of
estimated future net revenue to be generated from the production
of proved reserves, determined in accordance with the rules and
regulations of the SEC (using prices and costs in effect as of
the date of estimation), less future development, production and
income tax expenses, and discounted at 10% per annum to reflect
the timing of future net revenue. Standardized measure does not
give effect to derivative transactions.
Unconventional resource development.
A
development in which the targeted reservoirs generally fall into
three categories: (1) tight sands, (2) coal beds, and
(3) gas shales. The reservoirs tend to cover large areas
and lack the readily apparent traps, seals and discrete
hydrocarbon-water boundaries that typically define conventional
reservoirs. These reservoirs generally require stimulation
treatments or other special recovery processes in order to
produce economic flow rate.
Undeveloped acreage.
Lease acreage on which
wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil or gas
regardless of whether or not such acreage contains proved
reserves.
Unearned acreage.
The number of acres that has
not yet been assigned, but may be developed per the terms of an
agreement.
Working interest.
The operating interest that
gives the owner the right to drill, produce and conduct
operating activities on the property and receive a share of
production.
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ITEM 1A.
RISK
FACTORS
Risks
Related to Our Business
Our
independent registered public accounting firm has expressed
substantial doubt about our ability to continue as a going
concern.
The independent auditors report accompanying the audited
consolidated financial statements included herein contains a
statement expressing substantial doubt as to our ability to
continue as a going concern. The factors contributing to this
concern include our recurring losses from operations,
stockholders (deficit) equity, and inability to generate
sufficient cash flow to meet our obligations and sustain our
operations. Please read Item 7. Managements
Discussion and Analysis of Financial Condition and Results of
Operations Liquidity and Capital Resources.
Unless QRCP is able to sell additional assets, restructure its
indebtedness, issue equity securities and/or complete some other
strategic transaction, we may be forced to make a bankruptcy
filing or take other actions that could have a material adverse
effect on our business, the price of our common stock and our
results of operations. Furthermore, the presence of this concern
may have an adverse impact on our relationship with third
parties with whom we do business, including our customers,
vendors and employees and could make it more challenging for us
to raise additional financing or refinance our existing
indebtedness.
QRCPs
potential sources of revenue and cash flows consist almost
exclusively of distributions from Quest Energy and Quest
Midstream, neither of which is expected to pay distributions in
2009 and as a result, we do not expect QRCP to be able to meet
its cash disbursement obligations unless it engages in
transactions outside the ordinary course of
business.
QRCPs potential sources of revenue and cash flows consist
almost exclusively of distributions from Quest Energy and Quest
Midstream on the partnership interests it owns. We do not expect
either Quest Energy or Quest Midstream to pay any distributions
to their unitholders in 2009 and are unable to estimate at this
time when such distributions may be resumed.
In October and November of 2008, QRCPs credit agreement
and the credit agreement for each of Quest Energy and Quest
Midstream were amended. See Item 7. Managements
Discussion and Analysis of Financial Condition and Results of
Operations Liquidity and Capital
Resources Credit Agreements. The amended terms
of the credit agreements restrict the ability of Quest Energy
and Quest Midstream to pay distributions, among other things.
Even if they do not pay distributions, the Company and all other
unitholders may be liable for taxes on their share of each of
Quest Energy and Quest Midstreams taxable income. As a
result, we currently anticipate that QRCP will not be able to
meet its cash disbursement obligations after August 31,
2009, unless QRCP is able to restructure its debt obligations,
issue equity securities and/or sell additional assets, in which
case there can still be no assurances that QRCP will be able to
avoid bankruptcy or the liquidation of its assets.
Quest Energys credit agreements allow the payment of
distributions only on its common units and the general partner
units and only up to $0.40 per unit per quarter as long as the
Second Lien Loan Agreement has not been paid in full. Since the
majority of the units the Company owns in Quest Energy are
subordinated units, Quest Energy is only permitted to pay
distributions on approximately one-third of the interests the
Company owns, which significantly reduces what was previously
anticipated in cash flows. Furthermore, after giving effect to
each quarterly distribution, Quest Energy must be in compliance
with certain financial covenants which require its Available
Liquidity (as defined in each of its credit agreements) to be no
less than $14 million at March 31, 2009 and no less
than $20 million at June 30, 2009.
Quest Midstreams credit agreement prohibits the payment of
distributions to its unitholders until the total leverage ratio
is not greater than 4.0 to 1.0 after giving effect to each
quarterly distribution.
Quest Midstream did not pay any distributions on any of its
units for the third or fourth quarter of 2008 or the first
quarter of 2009 and Quest Energy only paid distributions on its
common units and the general partner interest for the third
quarter of 2008 and did not pay any distributions on any of its
units for the fourth quarter of 2008 or the first quarter of
2009. There is no assurance that unpaid distributions on
QRCPs common units and general partner units will be paid
or that any future distributions will be declared and paid on
any units.
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In addition, even if the credit agreements did not restrict the
payment of distributions, Quest Energy and Quest Midstream may
not have sufficient available cash each quarter to pay
distributions to their unitholders. The amount of cash each of
Quest Energy and Quest Midstream can distribute to its
unitholders each quarter depends upon the amount of cash it
generates from its operations, which fluctuate from quarter to
quarter based on, among other things:
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the amount of gas transported by Quest Midstream in its
gathering and transmission pipelines;
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the price of oil and gas;
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operating costs;
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prevailing economic conditions;
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timing and collectibility of receivables;
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the level of capital expenditures they make;
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their ability to make borrowings under their credit agreements
to pay distributions;
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their debt service requirements and other liabilities;
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fluctuations in their working capital needs; and
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the amount of cash reserves established by their general partner
for the proper conduct of their business.
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We
have identified significant and pervasive material weaknesses in
our internal controls, which have and could continue to affect
our ability to ensure timely and reliable financial reports and
the ability of our auditors to attest to the effectiveness of
our internal controls.
During managements review of our internal controls as of
December 31, 2008, control deficiencies that constituted
material weaknesses related to the following items were
identified:
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We did not maintain an effective control environment. The
control environment, which is the responsibility of senior
management, sets the tone of the organization, influences the
control consciousness of its people, and is the foundation for
all other components of internal control over financial
reporting.
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We did not maintain effective monitoring controls to determine
the adequacy of our internal control over financial reporting
and related policies and procedures.
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We did not establish and maintain effective controls over
certain of our period-end financial close and reporting
processes, including the preparation and review of financial
statements and schedules and journal entries.
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We did not establish and maintain effective controls to ensure
the correct application of generally accepted accounting
principles in the United States of America (GAAP)
related to derivative instruments.
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We did not establish and maintain effective controls to ensure
completeness and accuracy of stock compensation costs.
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We did not establish and maintain effective controls to ensure
completeness and accuracy of depreciation, depletion and
amortization expense.
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We did not establish and maintain effective controls to ensure
the accuracy and application of GAAP related to the
capitalization of costs related to oil and gas properties and
the required evaluation of impairment of such costs.
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We did not establish and maintain effective controls to
adequately segregate the duties over cash management.
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These material weaknesses resulted in the misstatement of our
annual and interim consolidated financial statements as of and
for the years ended December 31, 2007, 2006 and 2005, the
seven months ended December 31, 2004 and the fiscal year
ended May 31, 2004 (including the interim periods within
those periods) and as of and for the three months ended
March 31, 2008 and as of and for the three and six months
ended June 30, 2008.
45
Based on managements evaluation, because of the material
weaknesses described above, management has concluded that our
internal control over financial reporting was not effective as
of December 31, 2008. Our independent registered public
accounting firm, UHY LLP, has audited managements
assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2008, and their
report appears in this Annual Report on
Form 10-K.
While we have taken certain actions to address the deficiencies
identified, additional measures will be necessary and these
measures, along with other measures we expect to take to improve
our internal controls over financial reporting, may not be
sufficient to address the deficiencies identified or ensure that
our internal control over financial reporting is effective. If
we are unable to provide reliable and timely financial external
reports, our business and prospects could suffer material
adverse effects. In addition, we may in the future identify
further material weaknesses or significant deficiencies in our
internal control over financial reporting.
Events
of default are anticipated under the QRCP credit agreement,
which could expose our assets to foreclosure or other collection
efforts.
Events of default have recently occurred under our QRCP credit
agreement. The QRCP credit agreement contains both financial and
ratio covenants. Due to the cancellation of distributions by
QELP and QMLP, the decline in oil and gas prices and the decline
in the fair market value of the units in QELP and QMLP that it
owns, QRCP was not in compliance with all of its financial and
ratio covenants as of December 31, 2008 and March 31,
2009. On May 29, 2009, QRCP obtained a waiver of these
defaults from the QRCP lender. We do not expect that QRCP will
be in compliance with all of its financial and ratio covenants
for the remainder of 2009 therefore it may be required to obtain
additional waivers or its lender may foreclose on its assets.
QRCP is required to maintain as of the end of each quarter, an
Interest Coverage Ratio of not less than 2.5 to 1.0 and a
Leverage Ratio of no more than 2.0 to 1.0. As a result of the
suspension of the distributions to QRCP from Quest Energy and
Quest Midstream discussed above, QRCP was not in compliance with
these financial covenants as of December 31, 2008 and
March 31, 2009. On May 29, 2009, QRCP obtained a
waiver of these defaults from QRCPs lenders. QRCP does not
anticipate that it will be in compliance with these financial
covenants and ratios at any time in the foreseeable future. QRCP
is also required to make quarterly principal payments of
$1.5 million. QRCP has prepaid the quarterly principal
payments through and including June 30, 2009 and its next
quarterly principal payment is due September 30, 2009. QRCP
currently does anticipate being able to make this payment.
QRCPs credit agreement limits the amount that can be
outstanding under its term loan to an amount that is equal to
(i) 50% of the market value of the common and subordinated
units of Quest Energy and Quest Midstream that QRCP has pledged
to the lenders and (ii) the value of the oil and gas
properties that QRCP has pledged to the lenders. QRCP is
required to make a mandatory prepayment equal to any such excess
amount outstanding. On May 29, 2009, QRCP obtained a waiver
of this mandatory prepayment for the quarters ended
December 31, 2008, March 31, 2009 and June 30,
2009. If a deficiency exists after June 30, 2009 that is
not waived by QRCPs lenders, QRCP will be required to sell
assets, issue additional equity securities or refinance its
credit agreement in order to cure such deficiency, none of which
may be possible. Additionally, if the lenders exposure
under letters of credit exceeds this amount after all borrowings
under the credit agreements have been repaid, QRCP will be
required to provide additional cash collateral which it may not
have.
The
QELP borrowing base under its first lien credit agreement could
be redetermined to an amount that creates a deficiency that QELP
does not have the ability to pay.
Quest Energy is required to be in compliance as of the end of
each quarter, with certain financial ratios. Quest Energy is not
anticipated to be in compliance with its Total Reserve Leverage
Ratio as of June 30, 2009 in light of the significantly
reduced capital expenditure program and low natural gas prices
or in future periods if conditions do not change. In addition,
Quest Energy is required to have Available Liquidity of
$14 million and $20 million as of March 31, 2009
and June 30, 2009, respectively. Quest Energy may not be in
compliance with this covenant as of June 30, 2009. Quest
Energys credit facility limits the amount it can borrow to
a borrowing base amount, determined by the lenders in their sole
discretion. Outstanding borrowings in excess of the borrowing
base will be required to be repaid (1) in four equal
monthly installments following receipt of notice of the new
borrowing base or (2) immediately if the borrowing base is
reduced in connection with a sale or disposition of certain
properties in excess of 5% of the
46
borrowing base. The lead agent for QELPs credit agreement
initially proposed that QELPs borrowing base be reduced,
as part of the redetermination being made in connection with the
delivery of its year-end reserve report to its lenders, by
approximately $50 million to $140 million. Quest
Energy is currently pursuing various alternatives, including
entering into additional commodity derivative contracts
and/or
repricing certain existing commodity derivative contracts in
order to reduce the borrowing base deficiency. There can be no
assurance that such efforts will be successful or that Quest
Energy will be able to repay any remaining amount of the
deficiency in accordance with the terms of its revolving credit
agreement.
The proposed new borrowing base of $140 million has not
been approved by the required lenders under the QELP credit
agreement. QELP and its lenders are in the process of
negotiating the repricing of certain existing hedges and adding
new hedges, in order to have the lead agent propose a new
borrowing base that would consider such actions. The existing
lenders under the first lien credit agreement will not enter
into the required new hedges. However, they have agreed in
principle to an amendment to the credit agreement which would
allow for a major oil and gas company to be the hedge
counterparty on such new hedges. In order to accomplish the
inclusion of the major oil and gas company into the credit
facility, which would allow them to rank pari passu with the
existing lenders for their hedge position, the lenders need to
execute an intercreditor agreement with the major oil and gas
company and are currently negotiating that agreement.
QELP is not able to enter into new hedges and reprice its
existing hedges until the amendment to the QELP credit agreement
and the related intercreditor agreement between the major oil
and gas company and the lenders under the QELP credit agreement
are executed. There is no certainty that such amendment and
agreement will be executed. Furthermore, QELP is at risk for
product price movements that would cause the repricing of
existing hedges and adding QELPs desired new hedges, to no
longer satisfy the currently proposed deficiency.
If either the amendment and intercreditor agreement are not
executed or the product price environment when such agreement is
executed does not allow QELP to satisfy the proposed deficiency,
QELP would likely enter a default condition under the first lien
credit facility. Such default could lead to foreclosure or other
collection efforts.
Additionally, if the lenders exposure under letters of
credit exceeds this amount after all borrowings under the credit
agreements have been repaid, Quest Energy will be required to
provide additional cash collateral.
A
default under the QELP first lien credit agreement would cause a
cross default under the QELP second lien credit
agreement.
Under the terms of Quest Energys second lien credit
agreement, Quest Energy is required to make quarterly payments
of $3.8 million. The next payment is due August 15,
2009. The balance remaining, after such payment of
$29.8 million, is due on September 30, 2009. Due to
the likely principal payments required to be made on its
revolving credit facility in connection with the borrowing base
redetermination, no assurance can be given that Quest Energy
will be able to repay such amount in accordance with the terms
of its second lien credit agreement.
A default under QELPs first lien credit agreement would
cause a default under the second lien credit agreement, which
could cause payment acceleration. If payment under the second
lien credit agreement were accelerated, payment under the first
lien credit agreement would be accelerated. Such acceleration of
payments could lead to foreclosure, other collection efforts, or
bankruptcy of QELP.
The
definitive agreement for Recombination, if entered into, is
expected to be subject to closing conditions that could result
in the completion of the Recombination being delayed or not
consummated, which could lead to liquidation or
bankruptcy.
It is expected that if definitive documentation is executed,
completion of the Recombination will be conditioned upon the
satisfaction of closing conditions, including approval of a
definitive merger agreement by the Companys stockholders
and Quest Energys and Quest Midstreams unitholders.
The required conditions to closing may not be satisfied in a
timely manner, if at all, or, if permissible, waived, and the
Recombination may not be consummated. Failure to consummate the
Recombination could negatively impact the Companys stock
price, future business and operations, and financial condition.
Any delay in the consummation of the Recombination or
47
any uncertainty about the consummation of the Recombination may
lead to liquidation or bankruptcy and may adversely affect our
future business, growth, revenue and results of operations.
Failure
to complete the proposed Recombination could negatively impact
the market price of the Companys common stock and our
future business and financial results because of, among other
things, the disruption that would occur as a result of
uncertainties relating to a failure to complete the
Recombination.
The Companys stockholders and Quest Energys and
Quest Midstreams unitholders may not approve the matters
relating to the Recombination, if presented to them. If the
definitive agreement for the Recombination is not agreed to or
if the Recombination is not completed for any reason, we could
be subject to several risks including the following:
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the diversion of managements attention directed toward the
Recombination and other affirmative and negative covenants in
the definitive merger agreement that may restrict our business;
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the failure to pursue other beneficial opportunities as a result
of managements focus on the Recombination without
realizing any of the anticipated benefits of the Recombination;
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the market price of the Companys common stock may decline
to the extent that the current market price reflects a market
assumption that the Recombination will be completed; and
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incurring substantial transaction costs related to the
Recombination, such as investment banking, legal and accounting
fees, printing expenses and other related charges that must be
paid even if the Recombination is not completed.
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The realization of any of these risks may materially adversely
affect our business, financial results, and financial condition.
The
current financial crisis and economic conditions may have a
material adverse impact on our business and financial condition
that we cannot predict.
The economic conditions in the United States and throughout the
world have deteriorated. Since the second half of 2008, global
financial markets have been experiencing a period of
unprecedented turmoil and upheaval characterized by extreme
volatility and declines in prices of securities, diminished
liquidity and credit availability, inability to access capital
markets, the bankruptcy, failure, collapse or sale of financial
institutions and an unprecedented level of intervention from the
U.S. federal government and other governments. In
particular, the cost of raising money in the debt and equity
capital markets has increased substantially while the
availability of funds from those markets generally has
diminished significantly. Also, as a result of concerns about
the stability of financial markets generally and the solvency of
counterparties specifically, the cost of obtaining money from
the credit markets generally has increased as many lenders and
institutional investors have increased interest rates, enacted
tighter lending standards, refused to refinance existing debt at
maturity at all or on terms similar to our current debt and
reduced and, in some cases, ceased to provide any new funding.
A continuation of the economic crisis could result in further
reduced demand for oil and natural gas and keep downward
pressure on the prices for oil and natural gas, which have
fallen dramatically since reaching historic highs in July 2008.
These price declines have negatively impacted our revenues and
cash flows. Although we cannot predict the impacts on us of the
deteriorating economic conditions, they could materially
adversely affect our business and financial condition. For
example:
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our ability to obtain credit and access the capital markets has
been and may continue to be restricted at a time when we would
need to raise capital for our business, including for
exploration or development of our reserves;
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our hedging arrangements could become ineffective if our
counterparties are unable to perform their obligations or seek
bankruptcy;
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the values we are able to realize in asset sales or other
transactions we engage in to raise capital may be reduced, thus
making these transactions more difficult to consummate and less
economic; and
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the demand for oil and natural gas may decline due to
deteriorating economic conditions, which could adversely affect
our business, financial condition or results of operations.
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Due to these factors, we cannot be certain that funding will be
available if needed and to the extent required, on acceptable
terms. If funding is not available when needed, or if funding is
available only on unfavorable terms, we may be unable to meet
our obligations as they come due or be required to post
collateral to support our obligations, or we may be unable to
implement our development plans, enhance our existing business,
complete acquisitions or otherwise take advantage of business
opportunities or respond to competitive pressures, any of which
could have a material adverse effect on our production,
revenues, results of operations, or financial condition.
Energy
prices are very volatile, and if commodity prices remain low or
continue to decline for a temporary or prolonged period, our
revenues, profitability and cash flows will decline. A sustained
or further decline in oil and natural gas prices may adversely
affect our business, financial condition or results of
operations and our ability to meet our capital expenditure
obligations and financial commitments.
The current global credit and economic environment has resulted
in significantly lower oil and natural gas prices. The prices we
receive for our oil and natural gas production heavily influence
our revenue, profitability, access to capital and future rate of
growth. Oil and natural gas are commodities, and therefore their
prices are subject to wide fluctuations in response to
relatively minor changes in supply and demand. Historically, the
markets for oil and natural gas have been volatile. These
markets will likely continue to be volatile in the future. The
prices we receive for our production, and the levels of our
production, depend on a variety of additional factors that are
beyond our control, such as:
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the domestic and foreign supply of and demand for oil and
natural gas;
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the price and level of foreign imports of oil and natural gas;
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the level of consumer product demand;
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weather conditions;
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overall domestic and global economic conditions;
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political and economic conditions in oil and gas producing
countries, including embargoes and continued hostilities in the
Middle East and other sustained military campaigns, acts of
terrorism or sabotage;
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actions of the Organization of Petroleum Exporting Countries and
other state-controlled oil companies relating to oil price and
production controls;
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the impact of the U.S. dollar exchange rates on oil and gas
prices;
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technological advances affecting energy consumption;
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domestic and foreign governmental regulations and taxation;
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the impact of energy conservation efforts;
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the costs, proximity and capacity of gas pipelines and other
transportation facilities; and
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the price and availability of alternative fuels.
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In the past, the prices of gas have been extremely volatile, and
we expect this volatility to continue. For example, during the
year ended December 31, 2008, the near month NYMEX natural
gas futures price ranged from a high of $13.58 per Mmbtu to a
low of $5.29 per Mmbtu.
Our revenue, profitability and cash flow depend upon the prices
and demand for oil and gas, and a drop in prices can
significantly affect our financial results and impede our
growth. In particular, declines in commodity prices will:
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negatively impact the value of our reserves because declines in
oil and natural gas prices would reduce the amount of oil and
natural gas we can produce economically;
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reduce the amount of cash flow available for capital
expenditures; and
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limit our ability to borrow money or raise additional capital.
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Future
price declines may result in a write-down of our asset carrying
values.
Lower gas prices may not only decrease our revenues,
profitability and cash flows, but also reduce the amount of oil
and gas that we can produce economically. This may result in our
having to make substantial downward adjustments to our estimated
proved reserves. Substantial decreases in oil and gas prices
would render a significant number of our planned exploration and
development projects uneconomic. If this occurs, or if our
estimates of development costs increase, production data factors
change or drilling results deteriorate, accounting rules may
require us to write down, as a non-cash charge to earnings, the
carrying value of our oil or gas properties for impairments. We
are required to perform impairment tests on our assets
periodically and whenever events or changes in circumstances
warrant a review of our assets. To the extent such tests
indicate a reduction of the estimated useful life or estimated
future cash flows of our assets, the carrying value may not be
recoverable and may, therefore, require a write-down of such
carrying value. For example, for the year ended
December 31, 2008, we had an impairment charge of
$298.9 million. Due to a further decline in natural gas
prices between December 31, 2008 and March 31, 2009,
we will incur an additional impairment charge of approximately
$75 million to $95 million for the quarter ended
March 31, 2009. We may incur further impairment charges in
the future, which could have a material adverse effect on our
results of operations in the period incurred and on our ability
to borrow funds under our credit agreements.
Unless
we replace the reserves that we produce, our existing reserves
and production will decline, which would adversely affect our
revenues, profitability and cash flows.
Producing oil and gas reservoirs generally are characterized by
declining production rates that vary depending upon reservoir
characteristics and other factors. CBM production generally
declines at a shallow rate after initial increases in production
as a consequence of the dewatering process. Our future oil and
gas reserves, production, cash flow and ability to make
distributions depend on our success in developing and exploiting
our current reserves efficiently and finding or acquiring
additional recoverable reserves economically. We may not be able
to develop, find or acquire additional reserves to replace our
current and future production at acceptable costs, which would
adversely affect our business, financial condition and results
of operations. Factors that may hinder our ability to acquire
additional reserves include competition, access to capital,
prevailing gas prices and attractiveness of properties for sale.
Because of our financial condition, we will not be able to
replace in 2009 the reserves we expect to produce in 2009.
As of December 31, 2008, our proved reserve-to-production
ratio was 7.8 years. Because this ratio includes our proved
undeveloped reserves, we expect that this ratio will not
increase even if those proved undeveloped reserves are developed
and the wells produce as expected. The proved
reserve-to-production ratio reflected in our reserve report as
of December 31, 2008 will change if production from our
existing wells declines in a different manner than we have
estimated and can change when we drill additional wells, make
acquisitions and under other circumstances.
We may
not be able to replace our reserves or generate cash flows if we
are unable to raise capital.
In order to increase our asset base, we will need to make
substantial capital expenditures for the exploration,
development, production and acquisition of oil and gas reserves
and the construction of additional gas gathering pipelines and
related facilities. These maintenance capital expenditures may
include capital expenditures associated with drilling and
completion of additional wells to offset the production decline
from our producing properties or additions to our inventory of
unproved properties or our proved reserves to the extent such
additions maintain our asset base. These expenditures could
increase as a result of:
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changes in our reserves;
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changes in oil and gas prices;
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changes in labor and drilling costs;
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our ability to acquire, locate and produce reserves;
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changes in leasehold acquisition costs; and
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government regulations relating to safety and the environment.
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Our cash flow from operations and access to capital is subject
to a number of variables, including:
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our proved reserves;
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the level of oil and gas we are able to produce from existing
wells;
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the prices at which our oil and gas is sold; and
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our ability to acquire, locate and produce new reserves.
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Historically, we have financed these expenditures primarily with
cash generated by operations and proceeds from bank borrowings
and equity financings. If our revenues or borrowing base
decreases, which is expected, as a result of lower oil and
natural gas prices, operating difficulties or declines in
reserves, we may have limited ability to expend the capital
necessary to undertake or complete future drilling programs.
Additional debt or equity financing or cash generated by
operations may not be available to meet these requirements. Due
to the current low prices for oil and gas and the restrictions
in the capital markets due to the global financial crisis, we
anticipate that we will not have any significant amounts
available during 2009 for capital expenditures.
We
face the risks of leverage.
As of December 31, 2008, QRCP had borrowed
$29 million, Quest Energy had borrowed $230.2 million,
and Quest Midstream had borrowed $128 million under their
respective credit agreements. We anticipate that we may in the
future incur additional debt for financing our growth. Our
ability to borrow funds will depend upon a number of factors,
including the condition of the financial markets. In fact,
during 2008, availability of credit became severely restricted.
Under certain circumstances, the use of leverage may provide a
higher return to you on your investment, but will also create a
greater risk of loss to you than if we did not borrow. The risk
of loss in such circumstances is increased because we would be
obligated to meet fixed payment obligations on specified dates
regardless of our revenue. If we do not make our debt service
payments when due, we may sustain the loss of our equity
investment in any of our assets securing such debt, upon the
foreclosure on such debt by a secured lender. The interest
payable on our debt varies with the movement of interest rates
charged by financial institutions. An increase in our borrowing
costs due to a rise in interest rates in the market may reduce
the amount of income and cash available for the payment of
dividends to the holders of our common stock.
Our future level of debt could have important consequences to
us, including the following:
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our ability to obtain additional debt or equity financing, if
necessary, for drilling, expansion, working capital and other
business needs may be impaired or such financing may not be
available on favorable terms;
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a substantial decrease in our revenues as a result of lower oil
and natural gas prices, decreased production or other factors
could make it difficult for us to pay our liabilities or remain
in compliance with the covenants in our credit agreements. Any
failure by us to meet these obligations could result in
litigation, non-performance by contract counterparties or
bankruptcy;
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our funds available for operations and future business
opportunities will be reduced by that portion of our cash flow
required to make interest payments on our debt;
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we may be more vulnerable to competitive pressures or a downturn
in our business or the economy generally; and
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our flexibility in responding to changing business and economic
conditions may be limited.
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Our ability to service our debt will depend upon, among other
things, our future financial and operating performance, which
will be affected by prevailing economic conditions and
financial, business, regulatory and other factors, some of which
are beyond our control. If our operating results are not
sufficient to service our current or future indebtedness, we
will be forced to take actions such as reducing or delaying
business activities, acquisitions,
51
investments
and/or
capital expenditures, selling assets, restructuring or
refinancing our indebtedness or seeking additional equity
capital or bankruptcy protection. We may not be able to affect
any of these remedies on satisfactory terms or at all.
Our
credit agreements have substantial restrictions and financial
covenants that may restrict our business and financing
activities.
The operating and financial restrictions and covenants in our
credit agreements and any future financing agreements may
restrict our ability to finance future operations or capital
needs or to engage, expand or pursue our business activities or
to pay distributions. Our credit agreements and any future
financings agreements may restrict our ability to:
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incur indebtedness;
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grant liens;
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make distributions on or redeem or repurchase equity interests;
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make certain acquisitions and investments, loans or advances;
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lease equipment;
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enter into a merger, consolidation or sale of assets;
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dispose of property;
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enter into hedging arrangements with certain counterparties;
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limit the use of loan proceeds;
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make capital expenditures above specified amounts; and
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enter into transactions with affiliates.
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We are also required to comply with certain financial covenants
and ratios. In the past, we have not satisfied all of the
financial covenants and ratios contained in our credit
facilities. In January 2005, we determined that we were not in
compliance with the leverage and interest coverage ratios under
a prior secured credit agreement and, in connection with a
February 2005 amendment to such credit agreement, we were unable
to drill any additional wells until our gross daily production
reached certain levels. We were unable to reach these production
goals without the drilling of additional wells and, in the
fourth quarter of 2005, we undertook a significant
recapitalization that included a private placement of our common
stock and the refinancing of our credit facilities. For the
quarter ended March 31, 2007, QRCPs total debt to
EBITDA ratio was 4.77 to 1.0, which exceeded the permitted
maximum total debt to EBITDA ratio of 4.5 to 1.0 under its
credit facilities. We obtained a waiver of this default from
QRCPs lenders. We refinanced QRCPs credit facilities
in November 2007. In October 2008, we obtained waivers of any
defaults or potential defaults under the credit agreements of
QRCP, Quest Energy and Quest Midstream related to or arising out
of the internal investigation and our not promptly settling
intercompany accounts. The current credit agreements for QRCP,
Quest Midstream and Quest Energy each contain financial
covenants. QRCP was not in compliance with all of these
covenants as of December 31, 2008 and March 31, 2009
and we do not expect that QRCP and Quest Energy will be in
compliance with all of these covenants for the remainder of
2009. See Risks Related to Our
Business Events of default are anticipated under the
QRCP credit agreement, which could expose our assets to
foreclosure or other collection efforts. QRCP has obtained
a waiver of these defaults from its lenders and we are currently
in the process of seeking waivers from QRCPs and
QELPs lenders with respect to anticipated defaults and to
restructure their required principal payments; however, there
can be no assurance that we will be successful in obtaining such
waivers or restructuring such principal payments.
Our ability to comply with these restrictions and covenants in
the future is uncertain and will be affected by our results of
operations and financial conditions and events or circumstances
beyond our control. If market or other economic conditions do
not improve, our ability to comply with these covenants may be
impaired. If we violate any of the restrictions, covenants,
ratios or tests in our credit agreements, a significant portion
of our indebtedness may become immediately due and payable, the
interest rates on our credit agreements may increase and the
lenders
52
commitment, if any, to make further loans to us may terminate.
We might not have, or be able to obtain, sufficient funds to
make these accelerated payments.
An
increase in interest rates will cause our debt service
obligations to increase.
Borrowings under our credit agreements bear interest at floating
rates. The rates are subject to adjustment based on fluctuations
in the London Interbank Offered Rate (LIBOR) and
RBCs base rate. An increase in the interest rates
associated with our floating-rate debt would increase our debt
service costs and affect our results of operations and cash
flow. In addition, an increase in our interest expense could
adversely affect our future ability to obtain financing or
materially increase the cost of any additional financing.
We are
exposed to trade credit risk in the ordinary course of our
business activities.
We are exposed to risks of loss in the event of nonperformance
by our customers and by counterparties to our derivative
contracts. Some of our customers and counterparties may be
highly leveraged and subject to their own operating and
regulatory risks. Even if our credit review and analysis
mechanisms work properly, we may experience financial losses in
our dealings with other parties. Any increase in the nonpayment
or nonperformance by our customers
and/or
counterparties could adversely affect our results of operations
and financial condition.
U.S. government and internal investigations could
affect our results of operations.
We are currently involved in government and internal
investigations involving various of our operations. As discussed
in the Explanatory Note immediately preceding Part I of
this Annual Report on
Form 10-K,
an inquiry and investigation initiated by the Oklahoma
Department of Securities revealed questionable Transfers of
funds belonging to the Company to an entity controlled by our
former chief executive officer. The Oklahoma Department of
Securities has filed lawsuits against our former chief executive
officer, former chief financial officer and former purchasing
manager, and the Oklahoma Department of Securities, the Federal
Bureau of Investigation, the Department of Justice, the
Securities and Exchange Commission, the Internal Revenue Service
and other government agencies are currently conducting
investigations related to the Transfers and these individuals.
The joint special committee retained independent legal counsel
to conduct the investigation and to interact with various
government agencies, including the Oklahoma Department of
Securities, the Federal Bureau of Investigation, the Department
of Justice, the Securities and Exchange Commission, the Internal
Revenue Service and other government agencies.
These investigations are ongoing, and we cannot anticipate the
timing, outcome or possible impact of these investigations,
financial or otherwise. The governmental agencies involved in
these investigations have a broad range of civil and criminal
penalties they may seek to impose against corporations and
individuals for violations of securities laws, and other federal
and state statutes, including, but not limited to, injunctive
relief, disgorgement, fines, penalties and modifications to
business practices and compliance programs. In recent years,
these agencies and authorities have entered into agreements
with, and obtained a broad range of penalties against, several
public corporations and individuals in similar investigations,
under which civil and criminal penalties were imposed, including
in some cases multi-million dollar fines and other penalties and
sanctions. Any injunctive relief, disgorgement, fines,
penalties, sanctions or imposed modifications to business
practices resulting from these investigations could adversely
affect our results of operations and our ability to continue as
a going concern.
There
is a significant delay between the time QELP drills and
completes a CBM well and when the well reaches peak production.
As a result, there will be a significant lag time between when
QELP expends capital expenditures and when QELP will begin to
recognize significant cash flow from those
expenditures.
Our general production profile for a CBM well averages an
initial 5-10 Mcf/d (net), steadily rising for the first
twelve months while water is pumped off and the formation
pressure is lowered until the wells reach peak production (an
average of
50-55 Mcf/d
(net)). In addition, there could be significant delays between
the time a well is drilled and completed and when the well is
connected to a gas gathering system. This delay between the time
when QELP expends capital expenditures to drill and complete a
well and when QELP will begin to recognize significant cash flow
from those expenditures may adversely affect QELPs cash
flow from operations.
53
Our
estimated proved reserves are based on assumptions that may
prove to be inaccurate. Any material inaccuracies in these
reserve estimates or underlying assumptions will materially
affect the quantities and present value of our
reserves.
It is not possible to measure underground accumulations of oil
and gas in an exact way. Oil and gas reserve engineering
requires subjective estimates of underground accumulations of
oil and gas and assumptions concerning future oil and gas
prices, production levels and operating and development costs.
In estimating our level of oil and gas reserves, we and our
independent reserve engineers make certain assumptions that may
prove to be incorrect, including assumptions relating to:
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a constant level of future oil and gas prices;
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geological conditions;
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production levels;
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capital expenditures;
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operating and development costs;
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the effects of governmental regulations and taxation; and
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availability of funds.
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If these assumptions prove to be incorrect, our estimates of
proved reserves, the economically recoverable quantities of oil
and gas attributable to any particular group of properties, the
classifications of reserves based on risk of recovery and our
estimates of the future net cash flows from our reserves could
change significantly.
Our standardized measure is calculated using unhedged oil and
gas prices and is determined in accordance with the rules and
regulations of the SEC. Over time, we may make material changes
to reserve estimates to take into account changes in our
assumptions and the results of actual drilling and production.
The present value of future net cash flows from our estimated
proved reserves is not necessarily the same as the current
market value of our estimated proved reserves. We base the
estimated discounted future net cash flows from our estimated
proved reserves on prices and costs in effect on the day of
estimate. However, actual future net cash flows from our oil and
gas properties also will be affected by factors such as:
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the actual prices we receive for oil and gas;
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our actual operating costs in producing oil and gas;
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the amount and timing of actual production;
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the amount and timing of our capital expenditures;
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supply of and demand for oil and gas; and
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changes in governmental regulations or taxation.
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The timing of both our production and our incurrence of expenses
in connection with the development and production of oil and gas
properties will affect the timing of actual future net cash
flows from proved reserves, and thus their actual present value.
In addition, the 10% discount factor we use when calculating
discounted future net cash flows in compliance with the
FASBs Statement of Financial Accounting Standards
No. 69,
Disclosures about Oil and Gas Producing
Activities
, may not be the most appropriate discount factor
based on interest rates in effect from time to time and risks
associated with us or the oil and gas industry in general.
Drilling
for and producing oil and gas is a costly and high-risk activity
with many uncertainties that could adversely affect our
financial condition or results of operations.
Our drilling activities are subject to many risks, including the
risk that we will not discover commercially productive
reservoirs. The cost of drilling, completing and operating a
well is often uncertain, and cost factors, as
54
well as the market price of oil and natural gas, can adversely
affect the economics of a well. Furthermore, our drilling and
producing operations may be curtailed, delayed or canceled as a
result of other factors, including:
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high costs, shortages or delivery delays of drilling rigs,
equipment, labor or other services;
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adverse weather conditions;
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difficulty disposing of water produced as part of the coal bed
methane production process;
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equipment failures or accidents;
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title problems;
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pipe or cement failures or casing collapses;
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compliance with environmental and other governmental
requirements;
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environmental hazards, such as gas leaks, oil spills, pipeline
ruptures and discharges of toxic gases;
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lost or damaged oilfield drilling and service tools;
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loss of drilling fluid circulation;
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unexpected operational events and drilling conditions;
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increased risk of wellbore instability due to horizontal
drilling;
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unusual or unexpected geological formations;
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natural disasters, such as fires;
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blowouts, surface craterings and explosions; and
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uncontrollable flows of oil, gas or well fluids.
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A productive well may become uneconomic in the event water or
other deleterious substances are encountered, which impair or
prevent the production of oil or gas from the well. In addition,
production from any well may be unmarketable if it is
contaminated with water or other deleterious substances. We may
drill wells that are unproductive or, although productive, do
not produce oil or gas in economic quantities. Unsuccessful
drilling activities could result in higher costs without any
corresponding revenues. Furthermore, a successful completion of
a well does not ensure a profitable return on the investment.
We
have limited experience in drilling wells to the Marcellus Shale
and less information regarding reserves and decline rates in the
Marcellus Shale than in the Cherokee Basin. Wells drilled to the
Marcellus Shale are deeper, more expensive and more susceptible
to mechanical problems in drilling and completing than wells in
the Cherokee Basin.
We have limited experience in drilling wells in the Marcellus
Shale reservoir. As of May 1, 2009, we have drilled two
vertical and two horizontal gross wells to the Marcellus Shale.
Other operators in the Appalachian Basin also have limited
experience in the drilling of Marcellus Shale wells. As a
result, we have much less information with respect to the
ultimate recoverable reserves and the production decline rate in
the Marcellus Shale than we have in the Cherokee Basin. The
wells to be drilled in the Marcellus Shale will be drilled
deeper than in the Cherokee Basin and some may be horizontal
wells, which makes the Marcellus Shale wells more expensive to
drill and complete. The wells, especially any horizontal wells,
will also be more susceptible than those in the Cherokee Basin
to mechanical problems associated with the drilling and
completion of the wells, such as casing collapse and lost
equipment in the wellbore. The fracturing of the Marcellus Shale
will be more extensive and complicated than fracturing the
geological formations in the Cherokee Basin and requires greater
volumes of water than conventional gas wells. The management of
water and treatment of produced water from Marcellus Shale wells
may be more costly than the management of produced water from
other geologic formations.
55
Our
hedging activities could result in financial losses or reduce
our income.
To achieve more predictable cash flow and to reduce our exposure
to adverse fluctuations in the prices of oil and gas, we
currently and may in the future enter into derivative
arrangements for a significant portion of our oil and gas
production that could result in both realized and unrealized
hedging losses. The extent of our commodity price exposure is
related largely to the effectiveness and scope of our hedging
activities.
Our actual future production may be significantly higher or
lower than we estimate at the time we enter into hedging
transactions for such period. If the actual amount is higher
than we estimate, we will have greater commodity price exposure
than we intended. If the actual amount is lower than the nominal
amount that is subject to our derivative financial instruments,
we might be forced to satisfy all or a portion of our derivative
transactions without the benefit of the cash flow from our sale
or purchase of the underlying physical commodity, resulting in a
substantial diminution of our liquidity. As a result of these
factors, our hedging activities may not be as effective as we
intend in reducing the volatility of our cash flows, and in
certain circumstances may actually increase the volatility of
our cash flows. In addition, our hedging activities are subject
to the following risks:
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a counterparty may not perform its obligation under the
applicable derivative instrument;
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there may be a change in the expected differential between the
underlying commodity price in the derivative instrument and the
actual price received; and
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the steps we take to monitor our derivative financial
instruments may not detect and prevent violations of our risk
management policies and procedures.
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Because
of our lack of asset and geographic diversification, adverse
developments in our operating area would adversely affect our
results of operations.
Substantially all of our assets are currently located in the
Cherokee Basin and Appalachian Basin. As a result, our business
is disproportionately exposed to adverse developments affecting
these regions. These potential adverse developments could result
from, among other things, changes in governmental regulation,
capacity constraints with respect to the pipelines connected to
our wells, curtailment of production, natural disasters or
adverse weather conditions in or affecting these regions. Due to
our lack of diversification in asset type and location, an
adverse development in our business or these operating areas
would have a significantly greater impact on our financial
condition and results of operations than if we maintained more
diverse assets and operating areas.
We may
be unable to compete effectively with larger companies, which
may adversely affect our results of operations.
The oil and gas industry is intensely competitive with respect
to acquiring prospects and productive properties, marketing oil
and gas and securing equipment and trained personnel, and we
compete with other companies that have greater resources. Many
of our competitors are major and large independent oil and gas
companies, and they not only drill for and produce oil and gas,
but also carry on refining operations and market petroleum and
other products on a regional, national or worldwide basis. Our
larger competitors also possess and employ financial, technical
and personnel resources substantially greater than ours. These
companies may be able to pay more for oil and gas properties and
evaluate, bid for and purchase a greater number of properties
than our financial or human resources permit. In addition, there
is substantial competition for investment capital in the oil and
gas industry. These larger companies may have a greater ability
to continue drilling activities during periods of low oil and
gas prices and to absorb the burden of present and future
federal, state, local and other laws and regulations. Our
inability to compete effectively with larger companies could
have a material impact on our business activities, results of
operations and financial condition.
We may
have difficulty managing growth in our business.
Because of the relatively small size of our business, growth in
accordance with our long-term business plans, if achieved, will
place a significant strain on our financial, technical,
operational and management resources. As we increase our
activities and the number of projects we are evaluating or in
which we participate, there will be additional demands on our
financial, technical, operational and management resources. The
failure to continue to
56
upgrade our technical, administrative, operating and financial
control systems or the occurrence of unexpected expansion
difficulties, including the recruitment and retention of
required personnel could have a material adverse effect on our
business, financial condition and results of operations and our
ability to timely execute our business plan.
Our
business involves many hazards and operational risks, some of
which may not be fully covered by insurance. If a significant
accident or event occurs that is not fully insured, our
operations and financial results could be adversely
affected.
There are a variety of risks inherent in our operations that may
generate liabilities, including contingent liabilities, and
financial losses to us, such as:
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damage to wells, pipelines, related equipment and surrounding
properties caused by hurricanes, tornadoes, floods, fires and
other natural disasters and acts of terrorism;
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inadvertent damage from construction, farm and utility equipment;
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leaks of gas or oil spills as a result of the malfunction of
equipment or facilities;
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fires and explosions; and
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other hazards that could also result in personal injury and loss
of life, pollution and suspension of operations.
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Any of these or other similar occurrences could result in the
disruption of our operations, substantial repair costs, personal
injury or loss of human life, significant damage to property,
environmental pollution, impairment of our operations and
substantial revenue losses.
In accordance with typical industry practice, we currently
possess property, business interruption and general liability
insurance at levels we believe are appropriate; however,
insurance against all operational risk is not available to us.
We are not fully insured against all risks, including drilling
and completion risks that are generally not recoverable from
third parties or insurance. We do not have property insurance on
any of Quest Midstreams underground pipeline systems that
would cover damage to the pipelines. Pollution and environmental
risks generally are not fully insurable. Additionally, we may
elect not to obtain insurance if we believe that the cost of
available insurance is excessive relative to the perceived risks
presented. Losses could, therefore, occur for uninsurable or
uninsured risks or in amounts in excess of existing insurance
coverage. Moreover, insurance may not be available in the future
at commercially reasonable costs and on commercially reasonable
terms. Changes in the insurance markets subsequent to the
terrorist attacks on September 11, 2001 and the hurricanes
in 2005 have made it more difficult for us to obtain certain
types of coverage. There can be no assurance that we will be
able to obtain the levels or types of insurance we would
otherwise have obtained prior to these market changes or that
the insurance coverage we do obtain will not contain large
deductibles or fail to cover certain hazards or cover all
potential losses. Losses and liabilities from uninsured and
underinsured events and delay in the payment of insurance
proceeds could have a material adverse effect on our business,
financial condition and results of operations.
We
have been named a defendant in a number of securities class
action lawsuits and stockholder derivative lawsuits. These, and
potential similar or related litigation, could result in
significant expenses, monetary damages, penalties or injunctive
relief against us that could significantly reduce our earnings
and cash flows and harm our business.
As discussed in Items 1. and 2. Business and
Properties Recent Developments Internal
Investigation; Restatements and Reaudits, we conducted an
internal investigation into the Transfers of funds effected by
our former chief executive officer that totaled approximately
$10 million. During the course of the investigation,
management identified material errors in our previously issued
consolidated financial statements and has restated our
previously filed consolidated financial statements. The
investigation and restatement have exposed us to risks and
expenses associated with litigation and government
investigations. Certain putative class action lawsuits and
stockholder derivative lawsuits have been asserted against QRCP,
Quest Energy, Quest Energy GP and certain of their current and
former officers and directors. See Item 3. Legal
Proceedings for a discussion of the lawsuits. No assurance
can be given regarding the outcome of such litigation, and
additional claims may arise. The investigation
57
and restatement and any settlements, payment of claims and other
costs could lead to substantial expenses, may materially affect
our cash balance and cash flows from operations and may divert
managements attention from our business. In addition, we
are a party to indemnification agreements under which we are
required to indemnify and advance defense costs to our current
and certain of our former directors and officers. Furthermore,
considerable legal, accounting and other professional services
expenses related to these matters have been incurred to date and
significant expenditures may continue to be incurred in the
future. We could be required to pay damages and might face
remedies that could harm our business, financial condition and
results of operations. While we maintain directors and officers
liability insurance, there can be no assurance that the proceeds
of this insurance will be available with respect to all or part
of any damages, costs or expenses that we may incur in
connection with the class action and derivative stockholder
lawsuits.
We may
incur significant costs and liabilities in the future resulting
from a failure to comply with new or existing environmental and
operational safety regulations or an accidental release of
hazardous substances into the environment.
We may incur significant costs and liabilities as a result of
environmental, health and safety requirements applicable to our
oil and gas exploration, development and production activities.
These costs and liabilities could arise under a wide range of
federal, state and local environmental, health and safety laws
and regulations, including regulations and enforcement policies,
which have tended to become increasingly strict over time.
Failure to comply with these laws and regulations may result in
the assessment of administrative, civil and criminal penalties,
imposition of cleanup and site restoration costs and liens, and
to a lesser extent, issuance of injunctions to limit or cease
operations.
Our operations are subject to stringent and complex federal,
state and local environmental laws and regulations. These
include, for example, (1) the federal CAA and comparable
state laws and regulations that impose obligations related to
air emissions, (2) the federal RCRA and comparable state
laws that impose requirements for the handling, storage,
treatment or discharge of waste from our facilities,
(3) the federal CERCLA, also known as
Superfund, and comparable state laws that regulate
the cleanup of hazardous substances that may have been released
at properties currently or previously owned or operated by us or
locations to which we have sent waste for disposal and
(4) the federal CWA and analogous state laws and
regulations that impose detailed permit requirements and strict
controls regarding the discharge of pollutants into waters of
the United States and state waters. Failure to comply with these
laws and regulations or newly adopted laws or regulations may
trigger a variety of administrative, civil and criminal
enforcement measures, including the assessment of monetary
penalties, the imposition of remedial requirements, and the
issuance of orders enjoining future operations or imposing
additional compliance requirements on such operations. Certain
environmental regulations, including CERCLA and analogous state
laws and regulations, impose strict, joint and several liability
for costs required to clean up and restore sites where hazardous
substances or hydrocarbons have been disposed or otherwise
released. Moreover, it is not uncommon for neighboring
landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the release of
hazardous substances, hydrocarbons or other waste products into
the environment.
There is inherent risk of the incurrence of environmental costs
and liabilities in our business due to our handling of oil and
natural gas, air emissions related to our operations, and
historical industry operations and waste disposal practices. For
example, an accidental release from one of our pipelines could
subject us to substantial liabilities arising from environmental
cleanup and restoration costs, claims made by neighboring
landowners and other third parties for personal injury and
property damage and fines or penalties for related violations of
environmental laws or regulations. Moreover, the possibility
exists that stricter laws, regulations or enforcement policies
could significantly increase our compliance costs and the cost
of any remediation that may become necessary. We may not be able
to recover these costs from insurance.
We may
face unanticipated water disposal costs.
We are subject to regulation that restricts our ability to
discharge water produced as part of our gas production
operations. Productive zones frequently contain water that must
be removed in order for the gas to detach produce, and our
ability to remove and dispose of sufficient quantities of water
from the various zones will determine whether
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we can produce gas in commercial quantities. The produced water
must be transported from the lease and injected into disposal
wells. The availability of disposal wells with sufficient
capacity to receive all of the water produced from our wells may
affect our ability to produce our wells. Also, the cost to
transport and dispose of that water, including the cost of
complying with regulations concerning water disposal, may reduce
our profitability.
Where water produced from our projects fail to meet the quality
requirements of applicable regulatory agencies, our wells
produce water in excess of the applicable volumetric permit
limits, the disposal wells fail to meet the requirements of all
applicable regulatory agencies, or we are unable to secure
access to disposal wells with sufficient capacity to accept all
of the produced water, we may have to shut in wells, reduce
drilling activities, or upgrade facilities for water handling or
treatment. The costs to dispose of this produced water may
increase if any of the following occur:
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we cannot obtain future permits from applicable regulatory
agencies;
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water of lesser quality or requiring additional treatment is
produced;
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our wells produce excess water;
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new laws and regulations require water to be disposed in a
different manner; or
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costs to transport the produced water to the disposal wells
increase.
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Shortages
of crews could delay our operations, adversely affect our
ability to increase our reserves and production and adversely
affect our results of operations.
Higher oil and gas prices generally stimulate increased demand
and result in increased wages for crews and personnel in our
production operations. These types of shortages or wage
increases in the future could increase our costs
and/or
restrict or delay our ability to drill wells and conduct our
operations. Any delay in the drilling of new wells or
significant increase in labor costs could adversely affect our
ability to increase our reserves and production and reduce our
revenue and cash available for distribution. Additionally,
higher labor costs could cause certain of our projects to become
uneconomic and therefore not be implemented or for existing
wells to become shut-in, reducing our production and adversely
affecting our results of operations.
Quest
Energy depends on one customer for sales of its natural gas. A
reduction by this customer in the volumes of gas it purchases
from Quest Energy could indirectly result in a substantial
decline in our revenues and net income.
During the year ended December 31, 2008, Quest Energy sold
approximately 98% of its natural gas produced in the Cherokee
Basin to ONEOK Energy Marketing and Trading Company
(ONEOK) under a sale and purchase contract, which
has an indefinite term but may be terminated by either party on
30 days notice, other than with respect to pending
transactions, or less following an event of default. If ONEOK
was to reduce the volume of gas it purchases under this
agreement, Quest Energys revenue and cash flow will
decline to the extent it is not able to find new customers for
the natural gas it sells.
Certain
of our undeveloped leasehold acreage is subject to leases that
may expire in the near future.
In the Cherokee Basin, as of December 31, 2008, we held oil
and gas leases on approximately 557,603 net acres, of which
150,922 net acres are undeveloped and not currently held by
production. Unless we establish commercial production on the
properties subject to these leases during their term, these
leases will expire. Leases covering approximately
29,760 net acres are scheduled to expire before
December 31, 2009 and an additional 77,149 net acres
are scheduled to expire before December 31, 2010. If our
leases expire, we will lose our right to develop the related
properties. We typically acquire a three-year primary term when
the original lease is acquired, with an option to extend the
term for up to three additional years, if the primary three-year
term reaches expiration without a well being drilled to
establish production for holding the lease.
Subsequent to the divestiture of the Lycoming County,
Pennsylvania properties on February 13, 2009, we held oil
and gas leases and development rights, by virtue of farm-out
agreements or similar mechanisms, on 31,490 net acres in
the Appalachian Basin that are still within their original lease
or agreement term and are not earned or are
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not held by production. Unless we establish commercial
production on the properties, or fulfill the requirements
specified by the various agreements, during the prescribed time
periods, these leases or agreements will expire. Leases or
agreements covering approximately 3,600 net acres are
scheduled to expire before December 31, 2009 and an
additional approximately 6,000 net acres are scheduled to
expire before December 31, 2010. Of this acreage,
approximately 8,200 net acres can be maintained and held
beyond December 31, 2010 by drilling five wells before
December 31, 2009 and an additional six wells before
December 31, 2010.
Because of our financial condition, we do not expect to be able
to meet the drilling and payment obligations to earn or maintain
all of this leasehold acreage.
Our
identified drilling location inventories will be developed over
several years, making them susceptible to uncertainties that
could materially alter the occurrence or timing of their
drilling, resulting in temporarily lower cash from operations,
which may impact our results of operations.
Our management has specifically identified drilling locations
for our future multi-year drilling activities on our existing
acreage. We have identified, as of December 31, 2008,
approximately 292 gross proved undeveloped drilling
locations and approximately 2,034 additional gross potential
drilling locations in the Cherokee Basin and approximately 22
gross proved undeveloped drilling locations and approximately
435 additional gross potential drilling locations in the
Appalachian Basin. These identified drilling locations represent
a significant part of our future long-term development drilling
program. Our ability to drill and develop these locations
depends on a number of factors, including the availability of
capital, seasonal conditions, regulatory approvals, gas prices,
costs and drilling results. In addition, no proved reserves are
assigned to any of the approximately 2,034 Cherokee Basin and
435 Appalachian Basin potential drilling locations we have
identified and therefore, there may exist greater uncertainty
with respect to the likelihood of drilling and completing
successful commercial wells at these potential drilling
locations. Our final determination of whether to drill any of
these drilling locations will be dependent upon the factors
described above, our current financial condition, our ability to
obtain additional capital as well as, to some degree, the
results of our drilling activities with respect to our proved
drilling locations. Because of these uncertainties, it is
unlikely that all of the numerous drilling locations we have
identified will be drilled within the timeframe specified in the
reserve report or will ever be drilled, and we do not know if we
will be able to produce gas from these or any other potential
drilling locations. As such, our actual drilling activities may
materially differ from those presently identified, which could
have a significant adverse effect on our financial condition and
results of operations.
We may
incur losses as a result of title deficiencies in the properties
in which we invest.
If an examination of the title history of a property reveals
that an oil or gas lease has been purchased in error from a
person who is not the owner of the mineral interest desired, our
interest would be worthless. In such an instance, the amount
paid for such oil or gas lease or leases would be lost. It is
our practice, in acquiring oil and gas leases, or undivided
interests in oil and gas leases, not to incur the expense of
retaining lawyers to examine the title to the mineral interest
to be placed under lease or already placed under lease. Rather,
we rely upon the judgment of oil and gas lease brokers or
landmen who perform the fieldwork in examining records in the
appropriate governmental office before attempting to acquire a
lease in a specific mineral interest.
Prior to drilling an oil or gas well, however, it is the normal
practice in the oil and gas industry for the person or company
acting as the operator of the well to obtain a preliminary title
review of the spacing unit within which the proposed oil or gas
well is to be drilled to ensure there are no obvious
deficiencies in title to the well. Frequently, as a result of
such examinations, certain curative work must be done to correct
deficiencies in the marketability of the title, and such
curative work entails expense. The work might include obtaining
affidavits of heirship or causing an estate to be administered.
Our failure to obtain these rights may adversely impact its
ability in the future to increase production and reserves.
On a small percentage of our acreage (less than 1.0%), the land
owner in the past transferred the rights to the coal underlying
their land to a third party. With respect to those properties we
have obtained oil and gas leases from the owners of the oil,
gas, and minerals other than coal underlying those lands. In
Oklahoma and Kansas, the law is unsettled as to whether the
owner of the gas rights or the coal rights is entitled to the
CBM gas. We are currently
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involved in litigation with the owner of the coal rights on
these lands to determine who has the rights to the CBM gas. In
the event that the courts were to determine that the owner of
the coal rights is entitled to extract the CBM gas, we would
lose these leases and the associated wells and reserves. In
addition, we may be required to reimburse the owner of the coal
rights for some of the gas produced from those wells.
A
change in the jurisdictional characterization of some of Quest
Midstreams gathering assets by federal, state or local
regulatory agencies or a change in policy by those agencies may
result in increased regulation of its gathering assets, which
may indirectly cause our revenues to decline and operating
expenses to increase.
Section 1(b) of the Natural Gas Act of 1938, or NGA,
exempts natural gas gathering facilities from FERC jurisdiction.
We believe that the facilities comprising Quest Midstreams
gathering system meet the traditional tests used by FERC to
distinguish nonjurisdictional gathering facilities from
jurisdictional transportation facilities, and that, as a result,
the gathering system is not subject to FERCs jurisdiction.
However, FERC regulation still affects Quest Midstreams
gathering business and the markets for its natural gas.
FERCs policies and practices across the range of its
natural gas regulatory activities, including, for example, its
policies on open access transportation, ratemaking, capacity
release and market center promotion, indirectly affect Quest
Midstreams gathering business. In recent years, FERC has
pursued pro-competitive policies in its regulation of interstate
natural gas pipelines. However, we cannot assure you that FERC
will continue this approach as it considers matters such as
pipeline rates and rules and policies that may affect rights of
access to oil and natural gas transportation capacity. In
addition, the distinction between FERC-regulated transmission
services and federally unregulated gathering services has been
the subject of regular litigation. The classification and
regulation of some of Quest Midstreams gathering
facilities may be subject to change based on future
determinations by FERC, the courts or Congress.
State regulation of gathering facilities generally includes
various safety, environmental and, in some circumstances,
nondiscriminatory take requirements, and complaint-based rate
regulation. Natural gas gathering may receive greater regulatory
scrutiny at both the state and federal levels now that FERC has
taken a more light-handed approach to regulation of the
gathering activities of interstate pipeline transmission
companies and a number of such companies have transferred
gathering facilities to unregulated affiliates. Quest
Midstreams gathering operations are currently limited to
the States of Kansas and Oklahoma. Bluestem, a wholly owned
subsidiary of Quest Midstream and the owner of the gathering
system, is licensed as an operator of a natural gas gathering
system with the KCC and is required to file periodic information
reports with the KCC. Quest Midstream is not required to be
licensed as an operator or to file reports in Oklahoma.
Third party producers on our Cherokee Basin gathering system
have the ability to file complaints challenging the rates that
Quest Midstream charges. The rates must be just, reasonable, not
unjustly discriminatory and not duly preferential. If the KCC or
the OCC, as applicable, were to determine that the rates charged
to a complainant did not meet this standard, the KCC or the OCC,
as applicable, would have the ability to adjust the rates with
respect to the wells that were the subject of the complaint.
Quest Midstreams gathering operations also may be or
become subject to safety and operational regulations relating to
the design, installation, testing, construction, operation,
replacement and management of gathering facilities. Additional
rules and legislation pertaining to these matters are considered
or adopted from time to time. We cannot predict what effect, if
any, such changes might have on Quest Midstreams
operations, but the industry could be required to incur
additional capital expenditures and increased costs depending on
future legislative and regulatory changes.
The
KPC Pipeline is subject to regulation by FERC, which could have
an adverse impact on Quest Midstreams ability to establish
transportation rates that would allow it to recover the full
cost of operating the KPC pipeline, including a reasonable
return, which may affect Quest Midstreams business and
results of operations.
As an interstate natural gas pipeline, the KPC Pipeline is
subject to regulation by FERC under the NGA. FERCs
regulation of interstate natural gas pipelines extends to such
matters as:
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transportation of natural gas;
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rates, operating terms and conditions of service;
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the types of services KPC may offer to its customers;
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construction of new facilities;
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acquisition, extension or abandonment of services or facilities;
accounting and recordkeeping;
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commercial relationships and communications with affiliated
companies involved in certain aspects of the natural gas
business; and
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the initiation and discontinuation of services.
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KPC may only charge transportation rates that it has been
authorized to charge by FERC. In addition, FERC prohibits
natural gas companies from unduly preferring or unreasonably
discriminating against any person with respect to pipeline rates
or terms and conditions of service.
The maximum recourse rates that it may charge for transportation
services are established through FERCs ratemaking process,
and those recourse rates, as well as the terms and conditions of
service, are set forth in KPCs FERC-approved interstate
tariff. Pipelines may also negotiate rates that are higher than
the maximum recourse rates stated in their tariffs, provided
such rates are filed with, and approved by, FERC. Pursuant to
FERCs jurisdiction over rates, existing rates may be
challenged by complaint, proposed rate increases may be
challenged by protest, and either may be challenged sua sponte
by FERC. Any successful challenge against KPCs rates could
have an adverse impact on Quest Midstreams revenues and
ability to pay distributions.
Generally and absent settlement, the maximum filed recourse
rates for interstate pipelines are based on the cost of service
plus an approved return on equity, which may be determined
through the use of a proxy group of similarly situated
companies. Specifically, FERC uses a discounted cash flow model
that incorporates the use of proxy groups to develop a range of
reasonable returns earned on equity interests in companies with
corresponding risks. FERC then assigns a rate of return on
equity within that range to reflect specific risks of that
pipeline when compared to the proxy group companies. Other key
determinants in the ratemaking process are capital costs and
costs of providing service, including an income tax allowance,
and volume throughput and contractual capacity commitment
assumptions.
We cannot give any assurance regarding the likely future
regulations under which KPC will operate the KPC Pipeline or the
effect such regulation could have on its business, financial
condition, and results of operations. FERC periodically revises
and refines its ratemaking and other policies in the context of
rulemakings, generic proceedings, and pipeline-specific cases.
FERCs policies may also be modified when FERC decisions
are subjected to judicial review. Changes to ratemaking policies
may in turn affect the rates we may charge for transportation
service. For example, on April 17, 2008, FERC issued a
policy statement that, among other things, provides for the
inclusion of master limited partnerships in the proxy groups it
will use to decide the return on equity of natural gas
pipelines. Once this policy is applied in individual rate cases,
it may be subject to further review (including judicial review)
and potential modification. The final resolution of this issue
may reduce the rate of return KPC is allowed in future rate
cases.
The
outcome of certain rate cases involving FERC policy statements
is uncertain and could affect KPCs ability to include an
income tax allowance in its cost of service based rates, which
would in turn impact Quest Midstreams revenues and ability
to pay distributions.
In May 2005, FERC issued a policy statement permitting the
inclusion of an income tax allowance in the cost of
service-based rates of a pipeline organized as a tax
pass-through entity to reflect actual or potential income tax
liability on public utility income, if the pipeline proves that
the ultimate owner of its interests has an actual or potential
income tax liability on such income. In May 2007, the
U.S. Court of Appeals for the D.C. Circuit issued a
decision upholding the policy statement as applied to an
individual pipeline. More recent proceedings at FERC have
addressed a variety of implementation and application issues,
for example, whether the recovery of an income tax allowance by
a pipeline should be taken into consideration when establishing
return on equity rates for the pipeline. The ultimate outcome of
these proceedings, as well as future proceedings in which these
types of issues will be adjudicated, could result in changes to
FERCs treatment of income tax allowances or related cost
of service components. Depending upon how the policy statement
on income tax allowances is applied in practice to pipelines
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organized as pass through entities, these decisions might
adversely affect Quest Midstream. Under FERCs current
income tax allowance policy, if the KPC Pipeline was to file a
rate case or its rates were to otherwise become subject to
review for justness and reasonableness before FERC, Quest
Midstream would be required to demonstrate that the equity
interest owners in the pipeline incur actual or potential income
tax liability on their respective shares of partnership public
utility income. If Quest Midstream is unable to do so, FERC
could decide to reduce its rates from current levels. We can
give no assurance that in the future FERCs current income
tax allowance policy or its application will not be changed.
We
lack experience with and could be subject to penalties and fines
if we fail to comply with FERC regulations.
Quest Midstream acquired the KPC Pipeline, which is its only
FERC regulated asset, in November 2007. Given Quest
Midstreams limited experience with FERC regulated pipeline
operations, and the complex and evolving nature of FERC
regulation, it may incur significant costs related to compliance
with FERC regulations. Should Quest Midstream fail to comply
with all applicable FERC-administered statutes, rules,
regulations and orders, it could be subject to substantial
penalties and fines. Under the EP Act 2005, FERC has civil
penalty authority under the NGA to impose penalties for current
violations of up to $1,000,000 per day for each violation, to
revoke existing certificate authority, and to order disgorgement
of profits associated with any violation. Since enactment of the
EP Act 2005, FERC has initiated a number of enforcement
proceedings and issued penalties to various regulated entities,
including other interstate natural gas pipelines.
Pipeline
integrity programs and repairs may impose significant costs and
liabilities.
Pursuant to the Pipeline Safety Improvement Act of 2002, the DOT
has adopted regulations requiring pipeline operators to develop
integrity management programs for intrastate and interstate
natural gas and natural gas liquids pipelines located near high
consequence areas, where a leak or rupture could do the most
harm. The regulations require operators to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline
segments that could impact a high consequence area;
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improve data collection, integration and analysis;
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repair and remediate the pipeline as necessary; and
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implement preventive and mitigating actions.
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We currently estimate that Quest Midstream will incur costs of
approximately $1.0 million through 2009 to complete the
last year of the initial high consequence area integrity testing
and $1.5 million in 2012 to implement pipeline integrity
management program testing along certain segments of natural gas
pipelines. We also estimate that Quest Midstream will incur
costs of approximately $0.5 million through 2009 to complete the
last year of a Stray Current Survey resulting from a 2004 DOT
audit. These costs may be significantly higher and Quest
Midstreams cash available for distribution correspondingly
reduced due to the following factors:
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Our estimate does not include the costs of repairs, remediation
or preventative or mitigating actions that may be determined to
be necessary as a result of the testing program, which could be
substantial;
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Additional regulatory requirements that are enacted could
significantly increase the amount of these expenditures;
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The actual implementation costs may be materially higher than we
estimate because of increased industry-wide demand for
contractors and service providers and the related increase in
costs; or
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Failure to comply with DOT regulations and any corresponding
deadlines, which could subject Quest Midstream to penalties and
fines.
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Growing
our business by constructing new assets is subject to
regulatory, political, legal and economic risks.
One of the ways Quest Midstream intends to grow its business in
the long term is through the construction of new midstream
assets.
The construction of additions or modifications to the Cherokee
Basin gathering system
and/or
the
KPC Pipeline, and the construction of new midstream assets,
involve numerous operational, regulatory, environmental,
political and legal risks beyond our control and may require the
expenditure of significant amounts of capital. These potential
risks include, among other things:
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inability to complete construction of these projects on schedule
or at the budgeted cost due to the unavailability of required
construction personnel or materials;
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failure to receive any material increases in revenues until the
project is completed, even though Quest Midstream may have
expended considerable funds during the construction phase, which
may be prolonged;
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facilities may be constructed to capture anticipated future
growth in production in a region in which such growth does not
materialize;
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reliance on third party estimates of reserves in making a
decision to construct facilities, which estimates may prove to
be inaccurate because there are numerous uncertainties inherent
in estimating reserves;
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inability to obtain rights-of-way to construct additional
pipelines or the cost to do so may be uneconomical; and
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the construction of additions or modifications to the KPC
Pipeline may require the issuance of certificates of public
convenience and necessity from FERC, which may result in delays
or increase costs.
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If
third party pipelines and other facilities interconnected to
Quest Midstreams natural gas pipelines become unavailable
to transport or produce natural gas, its revenues and cash
available for distribution could be adversely
affected.
Quest Midstream depends upon third party pipelines and other
facilities that provide delivery options to and from its
pipelines and facilities for the benefit of its customers. Since
Quest Midstream does not own or operate any of these pipelines
or other facilities, their continuing operation is not within
its control. If any of these third party pipelines and other
facilities become unavailable to transport or produce natural
gas, Quest Midstreams revenues and cash available for
distribution could be adversely affected.
Failure
of the natural gas that Quest Midstream gathers on its gas
gathering system to meet the specifications of interconnecting
interstate pipelines could result in curtailments by the
interstate pipelines.
Natural gas gathered on Quest Midstreams gathering system
is delivered into interstate pipelines. These interstate
pipelines establish specifications for the natural gas that they
are willing to accept, which include requirements such as
hydrocarbon dewpoint, temperature, and foreign content including
water, sulfur, carbon dioxide and hydrogen sulfide. These
specifications vary by interstate pipeline. If the natural gas
delivered from the gathering system fails to meet the
specifications of a particular interstate pipeline that pipeline
may refuse to accept all or a part of the natural gas scheduled
for delivery to it. In those circumstances, Quest Midstream may
be required to find alternative markets for that natural gas or
to shut-in the producers of the non-conforming natural gas,
potentially reducing its throughput volumes or revenues.
Quest
Midstreams interstate natural gas pipeline has recorded
certain assets that may not be recoverable from its
customers.
Accounting policies for FERC-regulated companies permit certain
assets that result from the regulated ratemaking process to be
recorded on our balance sheet that could not be recorded under
GAAP for nonregulated entities. We consider factors such as
regulatory changes and the impact of competition to determine
the probability of future recovery of these assets. If Quest
Midstream determines future recovery is no longer probable, it
would be
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required to write off the regulatory assets at that time,
potentially reducing its revenues and cash available for
distribution.
Reduction
in firm reservation agreements and the demand for interruptible
services could cause significant reductions in Quest
Midstreams revenues and operating results.
For the year ended December 31, 2008, approximately 63% of
Quest Midstreams firm contracted capacity on our KPC
pipeline system was under long-term contracts (i.e., contracts
with remaining terms longer than one year). A decision by
customers upon the expiration of long-term agreements to
substantially reduce or cease to ship volumes of natural gas on
Quest Midstreams KPC pipeline system could cause a
significant decline in its revenues. Quest Midstreams
results of operations and cash available for distribution could
also be adversely affected by decreased demand for interruptible
services.
Operational
limitations of the pipeline system could cause a significant
decrease in Quest Midstreams revenues and operating
results.
During peak demand periods, failures of compression equipment or
pipelines could limit KPCs ability to meet firm
commitments, which may limit its ability to collect reservation
charges from its customers and, if so, could negatively impact
Quest Midstreams revenues and ability to make cash
distributions.
Quest
Midstreams industry is highly competitive, and increased
competitive pressures could adversely affect its business and
operating results.
With respect to its Cherokee Basin gathering system, Quest
Midstream may face competition in its efforts to obtain
additional natural gas volumes from parties other than Quest
Energy. Quest Midstream competes principally against other
producers in the Cherokee Basin with natural gas gathering
services. Its competitors may expand or construct gathering
systems in the Cherokee Basin that would create additional
competition for the services Quest Midstream provides to its
customers.
With respect to the KPC Pipeline, Quest Midstream competes with
other interstate and intrastate pipelines in the transportation
of natural gas for transportation customers primarily on the
basis of transportation rates, access to competitively priced
supplies of natural gas, markets served by the pipelines, and
the quality and reliability of transportation services. Major
competitors include Southern Star Central Gas Pipeline, Kinder
Morgan Interstate Gas Transmissions Pony Express Pipeline
and Panhandle Eastern Pipeline Company in the Kansas City market
and Southern Star Pipeline, Peoples Natural Gas and
Mid-Continent Market Center in the Wichita market.
Natural gas also competes with other forms of energy available
to Quest Midstreams customers, including electricity,
coal, hydroelectric power, nuclear power and fuel oil. The
impact of competition could be significantly increased as a
result of factors that have the effect of significantly
decreasing demand for natural gas in the markets served by Quest
Midstreams pipelines, such as competing or alternative
forms of energy, adverse economic conditions, weather, higher
fuel costs, and taxes or other governmental or regulatory
actions that directly or indirectly increase the cost or limit
the use of natural gas.
Quest
Midstream does not own all of the land on which its pipelines
are located or on which it may seek to locate pipelines in the
future, which could disrupt its operations and
growth.
Quest Midstream does not own the land on which its pipelines
have been constructed, but does have right-of-way and easement
agreements from landowners and governmental agencies, some of
which require annual payments to maintain the agreements and
most of which have a perpetual term. New pipeline infrastructure
construction may subject Quest Midstream to more onerous terms
or to increased costs if the design of a pipeline requires
redirecting. Such costs could have a material adverse effect on
Quest Midstreams business, results of operations and
financial condition and ability to make cash distributions.
In addition, the construction of additions to the KPC Pipeline
may require Quest Midstream to obtain new rights-of-way prior to
constructing new pipelines. Quest Midstream may be unable to
obtain such rights-of-way to expand the KPC Pipeline or
capitalize on other attractive expansion opportunities.
Additionally, it may become
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more expensive to obtain new rights-of-way. If the cost of
obtaining new rights-of-way increases, then Quest
Midstreams cash flows and its ability to make
distributions could be adversely affected.
The
revenues of Quest Midstreams interstate pipeline business
are generated under contracts that must be renegotiated
periodically.
Substantially all of KPC Pipelines revenues are generated
under contracts which expire periodically and must be
renegotiated and extended or replaced. Quest Midstreams
contracts with Kansas Gas Service and Missouri Gas Energy
represent commitments in the amount of approximately 144,000
Dth/d, of which approximately 55,000 Dth/d extend through
October 2009, approximately 12,000 Dth/d extend through 2013,
approximately 63,000 Dth/d extend through 2014, and
approximately 14,000 Dth/d extend through 2017. If Quest
Midstream is unable to extend or replace these contracts when
they expire or renegotiate contract terms as favorable as the
existing contracts, Quest Midstream could suffer a material
reduction in revenues, earnings and cash flows. In particular,
Quest Midstreams ability to extend and replace contracts
could be adversely affected by factors it cannot control,
including:
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competition by other pipelines, including the change in rates or
upstream supply of existing pipeline competitors, as well as the
proposed construction by other companies of additional pipeline
capacity in markets served by our interstate pipelines;
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changes in state regulation of local distribution companies,
which may cause them to negotiate short-term contracts or turn
back their capacity when their contracts expire;
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reduced demand and market conditions in the areas Quest
Midstream serves;
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the availability of alternative energy sources or natural gas
supply points; and
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regulatory actions.
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Fluctuations
in energy commodity prices could adversely affect Quest
Midstreams pipeline businesses.
Revenues generated by Quest Midstreams transmission
contracts depend, in part, on volumes and rates, both of which
can be affected by the prices of natural gas. Increased prices
could result in a reduction of the volumes transported by
customers. Increased prices could also result in industrial
plant shutdowns or load losses to competitive fuels as well as
local distribution companies loss of customer base. The
success of Quest Midstreams transmission operations is
subject to continued development of additional gas supplies to
offset the natural decline from existing wells connected to its
systems, which requires the development of additional oil and
natural gas reserves and obtaining additional supplies from
interconnecting pipelines on or near our systems. A decline in
energy prices could cause a decrease in these development
activities and could cause a decrease in the volume of reserves
available for transmission through Quest Midstreams
systems. Pricing volatility may impact the value of under or
over recoveries of retained natural gas and imbalances. If
natural gas prices in the supply basins connected to Quest
Midstreams pipeline systems are higher than prices in
other natural gas producing regions, its ability to compete with
other transporters may be negatively impacted on a short-term
basis, as well as with respect to long-term recontracting
activities. Furthermore, fluctuations in pricing between supply
sources and market areas could negatively impact Quest
Midstreams transportation revenues.
Our
success, and the success of Quest Energy and Quest Midstream,
depends on our key management personnel, the loss of any of whom
could disrupt our respective businesses.
The success of our operations and activities is dependent to a
significant extent on the efforts and abilities of our
management. We share a large majority of our management and
operational personnel with Quest Energy and Quest Midstream,
which are similarly dependent on these management and personnel
for their continued success. We have not obtained, and do not
anticipate that we will obtain, key man insurance
for any of our management. The loss of services of any of our
key management personnel could have a material adverse effect on
our business. These key management personnel provide services to
two public companies (Quest Energy and QRCP), and a private
company (Quest Midstream). As a result, there could be material
competition for their time and effort. If the
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key personnel do not devote significant time and effort to the
management and operation of each of these businesses, our
financial results may suffer.
If we
do not make acquisitions on economically acceptable terms, our
future growth and profitability will be limited.
Our ability to grow and to increase our profitability depends in
part on our ability to make acquisitions that result in an
increase in our net income. We may be unable to make such
acquisitions because we are: (1) unable to identify
attractive acquisition candidates or negotiate acceptable
purchase contracts with them, (2) unable to obtain
financing for these acquisitions on economically acceptable
terms or (3) outbid by competitors. If we are unable to
acquire properties containing proved reserves, our total level
of proved reserves will decline as a result of our production,
which will adversely affect our results of operations.
Even if we do make acquisitions that we believe will increase
our net income and cash flows, these acquisitions may
nevertheless result in a decrease in net income
and/or
cash
flows. Any acquisition involves potential risks, including,
among other things:
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mistaken assumptions about reserves, future production, volumes,
revenues and costs, including synergies;
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an inability to integrate successfully the businesses we acquire;
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a decrease in our liquidity as a result of our using a
significant portion of our available cash or borrowing capacity
to finance the acquisition;
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a significant increase in our interest expense or financial
leverage if we incur additional debt to finance the acquisition;
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the assumption of unknown liabilities for which we are not
indemnified or for which our indemnity is inadequate;
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an inability to hire, train or retain qualified personnel to
manage and operate our growing business and assets;
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limitations on rights to indemnity from the seller;
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mistaken assumptions about the overall costs of equity or debt;
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the diversion of managements and employees attention
from other business concerns;
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the incurrence of other significant charges, such as impairment
of goodwill or other intangible assets, asset devaluation or
restructuring charges;
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unforeseen difficulties operating in new product areas or new
geographic areas; and
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customer or key employee losses at the acquired businesses.
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If we consummate any future acquisitions, our capitalization and
results of operations may change significantly, and investors
will not have the opportunity to evaluate the economic,
financial and other relevant information that we will consider
in determining the application of these funds and other
resources.
In addition, we may pursue acquisitions outside the Cherokee and
Appalachian Basins. Because we currently operate substantially
in the Cherokee and Appalachian Basins, we do not have the same
level of experience in other basins. Consequently acquisitions
in areas outside the Cherokee and Appalachian Basins may not
allow us the same operational efficiencies we benefit from in
those basins. In addition, acquisitions outside the Cherokee and
Appalachian Basins will expose us to different operational risks
due to potential differences, among others, in:
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geology;
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well economics;
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availability of third party services;
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transportation charges;
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content, quantity and quality of oil and gas produced;
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volume of waste water produced;
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state and local regulations and permit requirements; and
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production, severance, ad valorem and other taxes.
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Our decision to acquire a property will depend in part on the
evaluation of data obtained from production reports and
engineering studies, geophysical and geological analyses and
seismic and other information, the results of which are often
inconclusive and subject to various interpretations. Also, our
reviews of acquired properties are inherently incomplete because
it generally is not feasible to perform an in-depth review of
the individual properties involved in each acquisition. Even a
detailed review of records and properties may not necessarily
reveal existing or potential problems, nor will it permit a
buyer to become sufficiently familiar with the properties to
assess fully their deficiencies and potential. Inspections may
not always be performed on every well, and environmental
problems, such as ground water contamination, are not
necessarily observable even when an inspection is undertaken.
Even when problems are identified, we often assume environmental
and other risks and liabilities in connection with acquired
properties.
Risks
Relating to Our Common Stock
We
currently are not in compliance with NASDAQs continued
listing requirements, and if our common stock is delisted, it
could negatively impact the price of our common stock, our
ability to access the capital markets and the liquidity of our
common stock.
Our common stock is currently listed on the NASDAQ Global
Market. To maintain our listing, we are required to maintain a
minimum closing bid price of at least $1.00 per share for our
common stock for 30 consecutive business days. Since October
2008, the bid price for our common stock has continuously closed
below the minimum $1.00 per share; however, given the current
extraordinary market conditions, NASDAQ has suspended
enforcement of the minimum bid price requirement through
July 19, 2009. As a result, if the closing bid price for
our common stock is less than $1.00 for a period of 30
consecutive days after July 19, 2009, we may receive
notification from NASDAQ that our common stock will be delisted
from the NASDAQ Global Market, unless the stock closes at or
above $1.00 per share for at least 10 consecutive days during
the
180-day
period following such notification.
Additionally, on November 19, 2008, we received a letter
from the staff of NASDAQ indicating that, because of our failure
to timely file our
Form 10-Q
for the quarter ended September 30, 2008, we no longer
complied with the continued listing requirements set forth in
NASDAQ Marketplace Rule 4310(c)(14) (now
Rule 5250(c)(1)). As permitted by NASDAQ rules, we timely
submitted a plan to NASDAQ staff to regain compliance on
January 20, 2009. Following a review of this plan, NASDAQ
staff granted us an extension until May 11, 2009 to file
our
Form 10-Q.
We did not file our
Form 10-Q
for the quarter ended September 30, 2008 on that date and
on May 12, 2009, we received a Staff Determination from
NASDAQ stating that our common stock is subject to delisting
since we were not in compliance with the filing requirements for
continued listing. We requested and were granted a hearing
before the NASDAQ Panel to appeal the Staff Determination. The
hearing is scheduled for June 11, 2009. The Panel has
stayed the delisting of our common stock through such date to
allow us additional time to file our delinquent periodic reports
with the SEC. If we have not filed all of our delinquent
periodic reports by June 11, 2009, there can be no
assurances that the Panel will grant a further extension to
allow us additional time to file such reports or that our common
stock will not be delisted.
Any potential delisting of our common stock from the NASDAQ
Global Market would make it more difficult for our stockholders
to sell our stock in the public market. Additionally, the
delisting of our common stock could materially adversely affect
our ability to raise capital that may be needed for future
operations. Delisting could also have other negative results,
including the potential loss of confidence by customers and
employees, the loss of institutional investor interest, and
fewer business development opportunities and would likely result
in decreased liquidity and increased volatility for our common
stock.
68
Our
stock price may be volatile.
The following factors could affect our stock price:
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the Recombination and the uncertainty whether it will be
successful;
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our operating and financial performance and prospects;
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quarterly variations in the rate of growth of our financial
indicators, such as net income per share, net income and
revenues;
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changes in revenue or earnings estimates or publication of
research reports by analysts about us or the exploration and
production industry;
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liquidity and registering our common stock for public resale;
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material weaknesses in the control environment;
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actual or anticipated variations in our reserve estimates and
quarterly operating results;
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changes in oil and natural gas prices;
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speculation in the press or investment community;
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sales of our common stock by significant stockholders;
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short-selling of our common stock by investors;
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pending litigation, including securities class action and
derivative lawsuits;
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issuance of a significant number of shares to raise additional
capital to fund our operations;
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increases in our cost of capital;
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changes in applicable laws or regulations, court rulings and
enforcement and legal actions;
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changes in market valuations of similar companies;
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adverse market reaction to any increased indebtedness we incur
in the future;
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additions or departures of key management personnel;
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actions by our stockholders;
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general market conditions, including fluctuations in and the
occurrence of events or trends affecting the price of oil and
natural gas; and
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domestic and international economic, legal and regulatory
factors unrelated to our performance.
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It is
unlikely that we will be able to pay dividends on our common
stock.
We have never paid dividends on our common stock. We cannot
predict with certainty that our operations will result in
sufficient revenues to enable us to operate profitably and with
sufficient positive cash flow so as to enable us to pay
dividends to the holders of common stock. In addition,
QRCPs credit agreement prohibits it from paying any
dividend to the holders of our common stock without the consent
of the lenders under the credit agreement, other than dividends
payable solely in equity interests of the Company.
The
percentage ownership evidenced by the common stock is subject to
dilution.
We are authorized to issue up to 200,000,000 shares of
common stock and are not prohibited from issuing additional
shares of such common stock. Moreover, to the extent that we
issue any additional common stock, a holder of the common stock
is not necessarily entitled to purchase any part of such
issuance of stock. The holders of the common stock do not have
statutory preemptive rights and therefore are not
entitled to maintain a proportionate share of ownership by
buying additional shares of any new issuance of common stock
before others are given the opportunity to purchase the same.
Accordingly, you must be willing to assume the risk that your
69
percentage ownership, as a holder of the common stock, is
subject to change as a result of the sale of any additional
common stock, or other equity interests in the Company.
Our
common stock is an unsecured equity interest.
Just like any equity interest, our common stock will not be
secured by any of our assets. Therefore, in the event of our
liquidation, the holders of our common stock will receive
distributions only after all of our secured and unsecured
creditors have been paid in full. There can be no assurance that
we will have sufficient assets after paying its secured and
unsecured creditors to make any distribution to the holders of
our common stock.
Provisions
in Nevada law could delay or prevent a change in control, even
if that change would be beneficial to our
stockholders.
Certain provisions of Nevada law may delay, discourage, prevent
or render more difficult an attempt to obtain control of us,
whether through a tender offer, business combination, proxy
contest or otherwise. The provisions of Nevada law are designed
to discourage coercive takeover practices and inadequate
takeover bids. These provisions are also designed to encourage
persons seeking to acquire control of us to first negotiate with
our board of directors.
Specifically, the Nevada Revised Statutes contain a provision
prohibiting certain combinations (generally defined
to include certain mergers, disposition of assets transactions,
and share issuance or transfer transactions) between a resident
domestic corporation and an interested stockholder
(generally defined to be the beneficial owner of 10% or more of
the voting power of the outstanding shares of the corporation),
except those combinations which are approved by the board of
directors before the interested stockholder first obtained a 10%
interest in the corporations stock. There are additional
exceptions to the prohibition, which apply to combinations if
they occur more than three years after the interested
stockholders date of acquiring shares. This provision
applies unless the corporation elects against its application in
its original articles of incorporation or an amendment thereto.
Our restated articles of incorporation, as amended, do not
currently contain a provision rendering this provision
inapplicable.
We
have various mechanisms in place to discourage takeover
attempts, which may reduce or eliminate our stockholders
ability to sell their shares for a premium in a change of
control transaction.
Various provisions of our articles of incorporation and bylaws
may discourage, delay or prevent a change in control or takeover
attempt of our company by a third party that is opposed to by
our management and board of directors. Public stockholders who
might desire to participate in such a transaction may not have
the opportunity to do so. These anti-takeover provisions could
substantially impede the ability of public stockholders to
benefit from a change of control or change in our management and
board of directors. These provisions include:
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the right of our board of directors to issue and determine the
rights and preferences of preferred stock to make it more
difficult for a third party to acquire, or to discourage a third
party from acquiring, a majority of our outstanding voting stock;
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classification of our directors into three classes with respect
to the time for which they hold office;
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non-cumulative voting for directors;
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control by our board of directors of the size of our board of
directors;
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limitations on the ability of stockholders to call special
meetings of stockholders; and
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advance notice requirements for nominations by stockholders of
candidates for election to our board of directors or for
proposing matters that can be acted upon by our stockholders at
stockholder meetings.
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We have also approved a stockholders rights agreement (the
Rights Agreement) between us and UMB Bank, N.A.,
(subsequently acquired by Computershare Limited) as Rights
Agent. Pursuant to the Rights Agreement, holders of our common
stock are entitled to purchase one one-thousandth (1/1,000) of a
share (a Unit) of Series B Junior Participating
Preferred Stock at a price of $75.00 per Unit upon certain
events. The purchase price is subject to appropriate adjustment
upon the happening of certain events. Generally, in the event a
person or entity
70
acquires, or initiates a tender offer to acquire, at least 15%
of our then outstanding common stock, the Rights will become
exercisable for shares of common stock equal to (i) the
number of Units held by a stockholder multiplied by the
then-current purchase price, and (ii) divided by one-half
of our then-current stock price. The existence of the Rights
Agreement may discourage, delay or prevent a change of control
or takeover attempt of us by a third party that is opposed to by
our management and board of directors.
ITEM 1B.
UNRESOLVED
STAFF COMMENTS.
None.
ITEM 3.
LEGAL
PROCEEDINGS.
We are subject, from time to time, to certain legal proceedings
and claims in the ordinary course of conducting our business. We
will record a liability related to our legal proceedings and
claims when we have determined that it is probable that we will
be obligated to pay and the related amount can be reasonably
estimated, and we will disclose the related facts in the
footnotes to our financial statements, if material. If we
determine that an obligation is reasonably possible, we will, if
material, disclose the nature of the loss contingency and the
estimated range of possible loss, or include a statement that no
estimate of loss can be made. We are currently a defendant in
the following litigation. We intend to defend vigorously against
the claims described below. We are unable to predict the outcome
of these proceedings or reasonably estimate a range of possible
loss that may result. Like other oil and natural gas producers
and marketers, our 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.
Federal
Securities Class Actions
Michael Friedman, individually and on behalf of all others
similarly situated v. Quest Energy Partners LP, Quest
Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David
E. Grose
, Case
No. 08-cv-936-M
U.S., District Court for the Western District of Oklahoma, filed
September 5, 2008
James Jents, individually and on behalf of all others
similarly situated v. Quest Resource Corporation, Jerry
Cash, David E. Grose, and John Garrison,
Case
No. 08-cv-968-M,
U.S. District Court for the Western District of Oklahoma,
filed September 12, 2008
J. Braxton Kyzer and Bapui Rao, individually and on
behalf of all others similarly situated v. Quest Energy
Partners LP, Quest Energy GP LLC, Quest Resource Corporation and
David E. Grose,
Case
No. 08-cv-1066-M,
U.S. District Court for the Western District of Oklahoma,
filed October 6, 2008
Paul Rosen, individually and on behalf of all others
similarly situated v. Quest Energy Partners LP, Quest
Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David
E. Grose,
Case
No. 08-cv-978-M,
U.S. District Court for the Western District of Oklahoma,
filed September 17, 2008
Four putative class action complaints were filed in the United
States District Court for the Western District of Oklahoma
against the Company, Quest Energy Partners, L.P., and Quest
Energy GP, LLC and certain of our current and former officers
and directors. The complaints were filed by certain stockholders
on behalf of themselves and other stockholders who purchased our
common stock between May 2, 2005 and August 25, 2008
and Quest Energy common units between November 7, 2007 and
August 25, 2008. The complaints assert claims under
Sections 10(b) and 20(a) of the Securities Exchange Act of
1934 and
Rule 10b-5
promulgated thereunder, and Sections 11 and 15 of the
Securities Act of 1933. The complaints allege that the
defendants violated the federal securities laws by issuing false
and misleading statements
and/or
concealing material facts concerning certain unauthorized
transfers of funds from subsidiaries of the Company to entities
controlled by the Companys former chief executive officer,
Mr. Jerry D. Cash. The complaints also allege that, as a
result of these actions, our stock price and the unit price of
Quest Energy was artificially inflated during the class period.
On December 29, 2008 the court consolidated these
complaints as
Michael Friedman, individually and on behalf of
all others similarly situated v. Quest Energy Partners LP,
Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and
David E. Grose
, Case
No. 08-cv-936-M,
in the
71
Western District of Oklahoma. Various individual plaintiffs have
filed multiple rounds of motions seeking appointment as lead
plaintiff, however the court has not yet ruled on these motions
and appointed a lead plaintiff. Once a lead plaintiff is
appointed, the lead plaintiff must file a consolidated amended
complaint within 60 days after being appointed. No further
activity is expected in the purported class action until a lead
plaintiff is appointed and an amended consolidated complaint is
filed. The Company, Quest Energy and Quest Energy GP intend to
defend vigorously against plaintiffs claims.
Federal
Derivative Case
James Stephens, derivatively on behalf of nominal
defendant Quest Resource Corporation. v. William H. Damon
III, Jerry Cash, David Lawler, David E. Grose, James B. Kite
Jr., John C. Garrison and Jon H. Rateau,
Case
No. 08-cv-1025-M,
U.S. District Court for the Western District of Oklahoma,
filed September 25, 2008
On September 25, 2008 a complaint was filed in the United
States District Court for the Western District of Oklahoma,
purportedly on our behalf, entitled
James Stephens,
derivatively on behalf on nominal defendant Quest Resource
Corporation v. William H. Damon III, Jerry Cash, David
Lawler, David E. Grose, James B. Kite Jr., John C. Garrison and
Jon H. Rateau
, Case
No. 08-cv-1025-M.
The complaint names certain of our current and former officers
and directors as defendants. The factual allegations mirror
those in the purported class actions described above, and the
complaint asserts claims for breach of fiduciary duty, abuse of
control, gross mismanagement, waste of corporate assets, and
unjust enrichment. The complaint seeks disgorgement, costs,
expenses, and equitable
and/or
injunctive relief. On October 16, 2008, the court stayed
this case pending the courts ruling on any motions to
dismiss the class action claims. The Company intends to defend
vigorously against these claims.
State
Court Derivative Cases
Tim Bodeker, derivatively on behalf of nominal defendant
Quest Resource Corporation v. Jerry Cash, David E. Grose,
Bob G. Alexander, David C. Lawler, James B. Kite, John C.
Garrison, Jon H. Rateau and William H. Damon III,
Case
No. CJ-2008-9042,
in the District Court of Oklahoma County, State of Oklahoma,
filed October 8, 2008
William H. Jacobson, derivatively on behalf of nominal
defendant Quest Resource Corporation v. Jerry Cash, David
E. Grose, David C. Lawler, James B. Kite, Jon H. Rateau, Bob G.
Alexander, William H. Damon III, John C. Garrison, Murrell,
Hall, McIntosh & Co., LLP, and Eide Bailly, LLP,
Case
No. CJ-2008-9657
,
in the District Court of Oklahoma County, State of Oklahoma,
filed October 27, 2008
Amy Wulfert, derivatively on behalf of nominal defendant
Quest Resource Corporation, v. Jerry D. Cash, David C.
Lawler, Jon C. Garrison, John H. Rateau, James B. Kite Jr.,
William H. Damon III, David E. Grose, N. Malone Mitchell III,
and Bryan Simmons,
Case
No. CJ-2008-9042
consolidated December 30, 2008, in the District Court of
Oklahoma County, State of Oklahoma (Original Case
No. CJ-2008-9624,
filed October 24, 2008)
The factual allegations in these petitions mirror those in the
purported class actions discussed above. All three petitions
assert claims for breach of fiduciary duty, abuse of control,
gross mismanagement, and unjust enrichment. The
Jacobson
petition also asserts claims against the two auditing firms
named in that suit for professional negligence and aiding and
abetting the director defendants breaches of fiduciary
duties. The
Wulfert
petition also asserts a claim against
Mr. Bryan Simmons for aiding and abetting
Messrs. Cashs and Groses breaches of fiduciary
duties. The petitions seek damages, costs, expenses, and
equitable relief. On November 12, 2008, the parties to
these lawsuits filed a motion to consolidate the actions and
appoint lead counsel. The court has not yet ruled on this
motion. Under the proposed order, the defendants need not
respond to the individual petitions. Once the actions are
consolidated, the proposed order provides that counsel for the
parties shall meet and confer, within thirty days from the date
of the entry of the order, regarding the scheduling of the
filing of a consolidated derivative petition and the
defendants responses to that petition. The Company intends
to defend vigorously against plaintiffs claims.
72
Royalty
Owner Class Action
Hugo Spieker, et al. v. Quest Cherokee, LLC
Case
No. 07-1225-MLB
in the U.S. District Court, District of Kansas, filed
August 6, 2007
Quest Cherokee was named as a defendant in a class action
lawsuit filed by several royalty owners in the
U.S. District Court for the District of Kansas. 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.
Personal
Injury Litigation
Segundo Francisco Trigoso and Dana Jara De Trigoso v.
Quest Cherokee Oilfield Service, LLC,
CJ-2007-11079,
in the District Court of Oklahoma County, State of Oklahoma,
filed December 27, 2007
Quest Cherokee Oilfield Service, LLC (QCOS) has been
named in this lawsuit filed by plaintiffs Segundo Francisco
Trigoso and Dana Jara De Trigoso. Plaintiffs allege that Segundo
Francisco Trigoso was seriously injured while working for QCOS
on September 29, 2006 and that the conduct of QCOS was
substantially certain to cause injury to Segundo Francisco
Trigoso. Plaintiffs seek unspecified damages for physical
injuries, emotional injuries, loss of consortium and pain and
suffering. Plaintiffs also seek punitive damages. Various
motions for summary judgment have been filed and denied by the
court. It is expected that the court will set this matter for
trial in Fall 2009. QCOS intends to defend vigorously against
plaintiffs claims.
St. Paul Surplus Lines Insurance Company v. Quest
Cherokee Oilfield Service, LLC, et al,
CJ-2009-1078, in the
District Court of Tulsa County, State of Oklahoma, filed
February 11, 2009
QCOS has been named as a defendant in this declaratory action.
This action arises out of the
Trigoso
matter discussed
above. Plaintiff alleges that no coverage is owed QCOS under the
excess insurance policy issued by plaintiff. The contentions of
plaintiff primarily rest on their position that the allegations
made in
Trigoso
are intentional in nature and that the
excess insurance policy does not cover such claims. QCOS will
vigorously defend the declaratory action.
Billy Bob Willis, et al. v. Quest Resource Corporation, et
al.,
Case No. CJ-09-00063, District Court of Nowata
County, State of Oklahoma, filed April 28, 2009
Quest Resource Corporation,
et al.
have been named in the
above-referenced lawsuit. The lawsuit has not been served. At
this time and due to the recent filing of the lawsuit, the
Company is unable to provide further detail.
Larry Reitz, et al. v. Quest Resource Corporation, et
al.,
Case No. CJ-09-00076, District Court of Nowata
County, State of Oklahoma, filed May 15, 2009
Quest Resource Corporation,
et al.
have been named in the
above-referenced lawsuit. The lawsuit was served on May 22,
2009. Defendants have not answered and no discovery has taken
place. Plaintiffs allege that defendants have wrongfully
deducted costs from the royalties of plaintiffs and have engaged
in self-dealing contracts and agreements resulting in a less
than market price for production. Plaintiffs seek unspecified
actual and punitive damages. Defendants intend to defend
vigorously against this claim.
Berenice Urias v. Quest Cherokee, LLC, et al.
,
CV-2008-238C in the Fifth Judicial District, County of Lea,
State of New Mexico (Second Amended Complaint filed
September 24, 2008)
Quest Cherokee was named in this wrongful death lawsuit filed by
Berenice Urias. Plaintiff was the surviving fiancée of the
decedent Montano Moreno. The decedent was killed while working
for United Drilling, Inc. United Drilling was transporting a
drilling rig between locations when the decedent was
electrocuted. All claims against Quest Cherokee have been
dismissed with prejudice.
73
Litigation
Related to Oil and Gas Leases
Quest Cherokee has been named as a defendant or counterclaim
defendant in several lawsuits in which the plaintiff claims that
oil and gas leases owned and operated by Quest Cherokee have
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, Wilson, and Neosho
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. As of March 1, 2009, the total amount of acreage
covered by the leases at issue in these lawsuits was
approximately 4,808 acres. Discovery in those cases is
ongoing. Quest Cherokee intends to vigorously defend against
those claims. Following is a list of those cases:
Roger Dean Daniels v. Quest Cherokee, LLC,
Case
No. 06-CV-61,
in the District Court of Montgomery County, State of Kansas,
filed May 5, 2006
Carol R. Knisely, et al. v. Quest Cherokee, LLC,
Case
No. 07-CV-58-I,
in the District Court of Montgomery County, State of Kansas,
filed April 16, 2007
Quest Cherokee, LLC v. David W. Hinkle, et al.,
Case
No. 2006-CV-74,
in the District Court of Labette County, State of Kansas, filed
September 5, 2006
Scott Tomlinson, et al. v. Quest Cherokee, LLC,
Case
No. 2007-CV-45,
in the District Court of Wilson County, State of Kansas, filed
August 29, 2007
Ilene T. Bussman et al. v. Quest Cherokee, LLC,
Case
No. 07-CV-106-PA,
in the District Court of Labette County, State of Kansas, filed
November 26, 2007
Gary Dale Palmer, et al. v. Quest Cherokee, LLC,
Case
No. 07-CV-107-PA,
in the District Court of Labette County, State of Kansas, filed
November 26, 2007
Richard L. Bradford, et al. v. Quest Cherokee, LLC,
Case No. 2008-CV-67, in the District Court of Wilson County,
Kansas, filed September 18, 2008
Richard Winder v. Quest Cherokee, LLC,
Case Nos.
07-CV-141 and 08-CV-20, in the District Court of Wilson County,
Kansas, filed December 7, 2007, and February 27,
2008
Housel v. Quest Cherokee, LLC
, 06-CV-26-I, in the
District Court of Montgomery County, State of Kansas, filed
March 2, 2006
Quest Cherokee was named as a defendant in a lawsuit filed by
Charles Housel and Meredith Housel on March 2, 2006.
Plaintiffs allege that the primary term of the lease at issue
has expired and that based upon non-production, plaintiffs are
entitled to cancellation of said lease. A judgment was entered
against Quest Cherokee on May 15, 2006. Quest Cherokee,
however, was never properly served with this lawsuit and did not
learn of this lawsuit until on or about April 23, 2007.
Quest Cherokee filed a Motion to Set Aside Default Judgment and
the parties have since agreed to set aside the default judgment
that was entered. Quest Cherokee has answered the complaint. On
April 1, 2008, Quest Cherokee sought leave from the court
to bring a third party claim against Layne Energy Operating, LLC
(Layne) on the basis that it, among other things,
has committed a trespass and has converted the well and gas
and/or
proceeds at issue. Quest Cherokee was granted leave to file its
claim against Layne. Layne has moved to dismiss the Third Party
Petition and Quest Cherokee has objected. Quest Cherokee intends
to defend vigorously against plaintiffs claims and pursue
vigorously its claims against Layne.
Central Natural Resources, Inc. v. Quest Cherokee,
LLC, et al.,
Case
No. 04-C-100-PA
in the District Court of Labette County, State of Kansas, filed
on September 1, 2004
Quest Cherokee and Bluestem were named as defendants in a
lawsuit filed by Central Natural Resources, Inc. (Central
Natural Resources) 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
74
from these leases and that Quest Cherokee is a trespasser and
has damaged its coal through its drilling and production
operations. 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 gas were filed by Quest Cherokee and the plaintiff,
with summary judgment being awarded in Quest Cherokees
favor. Plaintiff appealed the summary judgment and the Kansas
Supreme Court has issued an opinion affirming the District
Courts decision and has remanded the case to the District
Court for further proceedings consistent with that decision.
Quest Cherokee and Bluestem intend to defend vigorously against
these claims.
Central Natural Resources, Inc. v. Quest Cherokee,
LLC, et al
., Case
No. CJ-06-07
in the District Court of Craig County, State of Oklahoma, filed
January 17, 2006
Quest Cherokee was named as a defendant in a lawsuit filed by
Central Natural Resources, Inc. on January 17, 2006, in the
District Court of Craig County, Oklahoma. 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 has been stayed
by agreement of the parties. Quest Cherokee intends to defend
vigorously against these claims.
Edward E. Birk, et ux., and Brian L. Birk, et ux., v.
Quest Cherokee, LLC, Case No. 09-CV-27, in the District
Court of Neosho County, State of Kansas, filed April 23,
2009
Quest Cherokee was named as a defendant in a lawsuit filed by
Edward E. Birk, et ux., and Brian L. Birk, et ux., on
April 23, 2009. In that case, the plaintiffs claim that
they are entitled to an overriding royalty interest
(1/16
th
in some leases, and
1/32
nd
in
some leases) in 14 oil and gas leases owned and operated by
Quest Cherokee. Plaintiffs contend that Quest Cherokee has
produced oil
and/or
gas
from wells located on or unitized with those leases, and that
Quest Cherokee has failed to pay plaintiffs their overriding
royalty interest in that production. Quest Cherokees
answer date is June 15, 2009. We are investigating the
factual and legal basis for these claims and intend to defend
against them vigorously based upon the results of the
investigation.
Robert C. Aker, et al. v. Quest Cherokee, LLC, et al.,
U.S. District Court for the Western District of
Pennsylvania, Case
No. 3-09CV101,
filed April 16, 2009
Quest Cherokee,
et al.
were named as defendants in this
action where plaintiffs seek a ruling invalidating certain oil
and gas leases. Quest Cherokee has not answered and no discovery
has taken place. Quest Cherokee is investigating whether it is a
proper party to this lawsuit and intends to vigorously defend
against this claim.
Other
Well Refined Drilling Co. v. Quest Cherokee, LLC,
Case
No. 2007-CV-91,
in the District Court of Neosho County, State of Kansas, filed
July 19, 2007; and
Well Refined Drilling
Co. v. Quest Cherokee, LLC,
Case
No. 2007-CV-46,
in the District Court of Wilson County, State of Kansas, filed
September 4, 2007
Quest Cherokee has been named as a defendant in two lawsuits
filed by Well Refined Drilling Company in the District Court of
Neosho County, Kansas (Case No. 2007 CV 91) and in the
District Court of Wilson County, Kansas (Case No. 2007 CV
46). In both cases, plaintiff contends that Quest Cherokee owes
certain sums for services provided by the plaintiff in
connection with drilling wells for Quest Cherokee. Plaintiff has
also filed mechanics liens against the oil and gas leases on
which those wells are located and also seeks foreclosure of
those liens. Quest
75
Cherokee has answered those petitions and has denied
plaintiffs claims. Discovery in those cases is ongoing.
Quest Cherokee intends to defend vigorously against these claims.
Barbara Cox v. Quest Cherokee, LLC
,
U.S. District Court for the District of New Mexico, Case
No. CIV-08-0546,
filed April 18, 2008
Quest Cherokee has been named in this lawsuit by Barbara Cox.
Plaintiff is a landowner in Hobbs, New Mexico and owns the
property where the Quest State 9-4 Well was drilled and plugged.
Plaintiff alleges that Quest Cherokee violated the New Mexico
Surface Owner Protection Act and has committed a trespass and
nuisance in the drilling and maintenance of the well. Quest
Cherokee denies the allegations of plaintiff. Plaintiff has not
articulated any firm damage numbers. Quest Cherokee intends to
defend vigorously against plaintiffs claims.
Juana Huerter v. Quest Cherokee Oilfield Services, LLC, et
al.,
Case No. 2008 CV-50, District Court of Neosho
County, State of Kansas, filed May 5, 2008
QCOS,
et al.
has been named in this personal injury
lawsuit arising out of an automobile collision. Initial written
discovery is being conducted. There is no pending trial date.
QCOS intends to defend vigorously against this claim.
Bradley Haviland, Jr., v. Quest Cherokee Oilfield
Services, LLC, et al.,
Case No. 2008 CV-78, District
Court of Neosho County, State of Kansas, filed July 25,
2008
QCOS,
et al.
has been named in this personal injury
lawsuit arising out of an automobile collision. There is no
pending trial date. QCOS intends to defend vigorously against
this claim.
|
|
ITEM 4.
|
SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS.
|
No matters were submitted to a vote of security holders during
the fourth quarter of 2008.
PART II
ITEM 5.
MARKET
FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES.
Market
Information
The Companys common stock trades on The NASDAQ Global
Market under the symbol QRCP. The table set forth
below lists the range of high and low prices of the
Companys common stock on NASDAQ for each quarter of the
last two years.
|
|
|
|
|
|
|
|
|
Fiscal Quarter and Period Ended
|
|
High Price
|
|
Low Price
|
|
December 31, 2008
|
|
$
|
2.84
|
|
|
$
|
0.23
|
|
September 30, 2008
|
|
$
|
10.86
|
|
|
$
|
2.15
|
|
June 30, 2008
|
|
$
|
13.45
|
|
|
$
|
6.96
|
|
March 31, 2008
|
|
$
|
8.10
|
|
|
$
|
6.35
|
|
December 31, 2007
|
|
$
|
10.82
|
|
|
$
|
6.66
|
|
September 30, 2007
|
|
$
|
11.96
|
|
|
$
|
9.00
|
|
June 30, 2007
|
|
$
|
12.08
|
|
|
$
|
8.50
|
|
March 31, 2007
|
|
$
|
9.70
|
|
|
$
|
7.50
|
|
The closing price for QRCP stock on May 15, 2009 was $0.49.
Record
Holders
As of May 15, 2009, there were 31,867,527 shares of
common stock outstanding held of record by approximately
646 stockholders.
76
Dividends
The payment of dividends on QRCPs common stock is within
the discretion of the board of directors and will depend on our
earnings, capital requirements, financial condition and other
relevant factors. We have not declared any cash dividends on
QRCPs common stock and do not anticipate paying any
dividends on QRCPs common stock in the foreseeable future.
Our ability to pay dividends on QRCPs common stock is
subject to restrictions contained in its credit agreement. See
Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations
Liquidity and Capital Resources Credit
Agreements for a discussion of these restrictions.
In addition, the partnership agreements for Quest Energy and
Quest Midstream restrict the ability of Quest Energy and Quest
Midstream to pay distributions on the subordinated units of such
partnerships that QRCP owns if the minimum quarterly
distribution has not been paid on all of the common units of
such partnerships. The credit agreements for Quest Energy and
Quest Midstream also restrict the ability of Quest Energy and
Quest Midstream to pay any distributions. See Item 7.
Managements Discussion and Analysis of Financial
Condition and Results of Operations Liquidity and
Capital Resources Credit Agreements. The third
and fourth quarter 2008 distributions for Quest Midstream were
not paid, the third quarter 2008 distribution on Quest
Energys subordinated units was not paid and the fourth
quarter 2008 distribution on all of Quest Energys units,
including common units, for Quest Energy was not paid. There can
be no assurance that minimum quarterly distributions on the
common units for those quarters will be paid or that any future
distributions will be paid.
Recent
Sales of Unregistered Securities
None.
Purchases
of Equity Securities
We have reacquired shares of stock from employees upon the
vesting of restricted stock that was granted under our 2005
Omnibus Stock Award Plan. These shares were surrendered by the
employees and reacquired by us to satisfy a portion of the
minimum statutory tax withholding obligations arising from the
lapse of restrictions on the shares. The following table
provides information with respect to these purchases during the
year ended December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum
|
|
|
|
|
|
|
Total Number of
|
|
Number (or
|
|
|
|
|
|
|
Shares
|
|
Approximate
|
|
|
|
|
|
|
Purchased as
|
|
Dollar Value) of
|
|
|
|
|
|
|
Part of Publicly
|
|
Shares that May
|
|
|
Total Number
|
|
Average Price
|
|
Announced
|
|
Yet Be Purchased
|
|
|
of Shares
|
|
Paid per
|
|
Plans or
|
|
Under the Plans
|
Period
|
|
Purchased
|
|
Share
|
|
Programs
|
|
or Programs
|
|
December 1 through December 31, 2008
|
|
|
21,955
|
|
|
$
|
0.32
|
|
|
|
|
|
|
|
|
|
77
STOCK
PRICE PERFORMANCE GRAPH
The following graph compares the performance of our common stock
to a published industry index (AMEX Natural Resources) and a
market index (Nasdaq Composite Index) for the past five years.
We have also included a peer group in our SIC code index that
was included in our Stock Price Performance Graph last year. The
peer group consists of the following companies: Abraxas
Petroleum Corporation; Credo Petroleum Corporation; Double Eagle
Petroleum Company; Dune Energy Inc; Edge Petroleum Corporation;
Evolution Petroleum Corporation; FX Energy Inc.; Georesources
Inc.; Houston American Energy Corporation; Kodiak
Oil & Gas Corporation; Meridian Resource Corporation;
Ngas Resources Inc.; Northern Oil & Gas Inc.; Pinnacle
Gas Resources Inc.; Platinum Energy Resources Inc.; Primeenergy
Corporation; South Texas Oil Company; Toreador Resources
Corporation; and Tri Valley Corporation.
The peer group was chosen last year to reflect a comparison of
companies closely aligned with our market capitalization value.
Beginning this year, we have decided to switch from a
self-selected peer group to a published industry index (AMEX
Natural Resources) because we believe the broader index provides
more meaningful stockholder return information.
The graph assumes the investment of $100 on December 31,
2003 and the reinvestment of all dividends. The graph shows the
value of the investment at the end of each year.
COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN
Among Quest Resource Corporation, AMEX Natural Resources,
Nasdaq Composite Index and a Peer Group
78
ITEM 6.
SELECTED
FINANCIAL DATA.
The following table sets forth selected financial information.
The data for the years ended December 31, 2008, 2007, 2006
and 2005 are derived from our audited and, for 2007, 2006 and
2005, restated consolidated financial statements included
elsewhere in this report. The data for the seven month
transition period ended December 31, 2004 and the fiscal
year ended May 31, 2004 are derived from unaudited
management accounts for such periods, not from our previously
filed audited financial statements, which have been restated.
See Note 18 Restatement to the consolidated
financial statements for a discussion of the restatements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7 Months
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ended
|
|
|
Fiscal Year
|
|
|
|
Year Ended December 31,
|
|
|
December 31,
|
|
|
Ended May 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2004
|
|
|
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
|
($ in thousands, except per share data)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
147,937
|
|
|
$
|
105,285
|
|
|
$
|
72,410
|
|
|
$
|
70,628
|
|
|
$
|
28,593
|
|
|
$
|
30,707
|
|
Gas pipeline revenue
|
|
|
28,176
|
|
|
|
9,853
|
|
|
|
5,014
|
|
|
|
3,939
|
|
|
|
1,918
|
|
|
|
2,707
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
176,113
|
|
|
|
115,138
|
|
|
|
77,424
|
|
|
|
74,567
|
|
|
|
30,511
|
|
|
|
33,414
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
44,111
|
|
|
|
36,295
|
|
|
|
25,338
|
|
|
|
18,532
|
|
|
|
5,181
|
|
|
|
6,835
|
|
Pipeline operating
|
|
|
29,742
|
|
|
|
21,098
|
|
|
|
13,151
|
|
|
|
7,703
|
|
|
|
4,451
|
|
|
|
3,506
|
|
General and administrative
|
|
|
28,269
|
|
|
|
21,023
|
|
|
|
8,655
|
|
|
|
6,218
|
|
|
|
2,765
|
|
|
|
2,925
|
|
Depreciation, depletion and amortization
|
|
|
70,445
|
|
|
|
39,782
|
|
|
|
27,011
|
|
|
|
22,244
|
|
|
|
7,933
|
|
|
|
5,488
|
|
Impairment of oil and gas properties
|
|
|
298,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from misappropriation of funds
|
|
|
|
|
|
|
2,000
|
|
|
|
6,000
|
|
|
|
2,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
471,428
|
|
|
|
120,198
|
|
|
|
80,155
|
|
|
|
56,697
|
|
|
|
20,330
|
|
|
|
18,754
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(295,315
|
)
|
|
|
(5,060
|
)
|
|
|
(2,731
|
)
|
|
|
17,870
|
|
|
|
10,181
|
|
|
|
14,660
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) from derivative financial instruments
|
|
|
80,707
|
|
|
|
1,961
|
|
|
|
52,690
|
|
|
|
(73,566
|
)
|
|
|
(6,085
|
)
|
|
|
(19,788
|
)
|
Gain (loss) on sale of assets
|
|
|
24
|
|
|
|
(322
|
)
|
|
|
3
|
|
|
|
12
|
|
|
|
|
|
|
|
(6
|
)
|
Loss on early extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,355
|
)
|
|
|
(1,834
|
)
|
|
|
|
|
Other income (expense)
|
|
|
305
|
|
|
|
(9
|
)
|
|
|
99
|
|
|
|
389
|
|
|
|
37
|
|
|
|
(843
|
)
|
Interest expense, net
|
|
|
(25,373
|
)
|
|
|
(43,628
|
)
|
|
|
(20,567
|
)
|
|
|
(28,225
|
)
|
|
|
(11,537
|
)
|
|
|
(8,388
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income and (expense)
|
|
|
55,663
|
|
|
|
(41,998
|
)
|
|
|
32,225
|
|
|
|
(113,745
|
)
|
|
|
(19,419
|
)
|
|
|
(29,025
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes and minority interests
|
|
|
(239,652
|
)
|
|
|
(47,058
|
)
|
|
|
29,494
|
|
|
|
(95,875
|
)
|
|
|
(9,238
|
)
|
|
|
(14,365
|
)
|
Income tax benefit (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
245
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) before minority interests
|
|
|
(239,652
|
)
|
|
|
(47,058
|
)
|
|
|
29,494
|
|
|
|
(95,875
|
)
|
|
|
(9,238
|
)
|
|
|
(14,120
|
)
|
Minority interests in continuing operations
|
|
|
72,268
|
|
|
|
2,904
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of accounting change, net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(28
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
(167,384
|
)
|
|
|
(44,154
|
)
|
|
|
29,508
|
|
|
|
(95,875
|
)
|
|
|
(9,238
|
)
|
|
|
(14,148
|
)
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10
|
)
|
|
|
(6
|
)
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common shareholders
|
|
$
|
(167,384
|
)
|
|
$
|
(44,154
|
)
|
|
$
|
29,508
|
|
|
$
|
(95,885
|
)
|
|
$
|
(9,244
|
)
|
|
$
|
(14,158
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
79
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7 Months
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ended
|
|
|
Fiscal Year
|
|
|
|
Year Ended December 31,
|
|
|
December 31,
|
|
|
Ended May 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2004
|
|
|
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
|
($ in thousands, except per share data)
|
|
|
Net income (loss) available to common shareholders per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(6.20
|
)
|
|
$
|
(1.97
|
)
|
|
$
|
1.33
|
|
|
$
|
(11.48
|
)
|
|
$
|
(1.63
|
)
|
|
$
|
(2.51
|
)
|
Diluted
|
|
$
|
(6.20
|
)
|
|
$
|
(1.97
|
)
|
|
$
|
1.33
|
|
|
$
|
(11.48
|
)
|
|
$
|
(1.63
|
)
|
|
$
|
(2.49
|
)
|
Weighted average common and common equivalent shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
27,010,690
|
|
|
|
22,379,479
|
|
|
|
22,119,497
|
|
|
|
8,351,945
|
|
|
|
5,661,096
|
|
|
|
5,645,077
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
27,010,690
|
|
|
|
22,379,479
|
|
|
|
22,198,799
|
|
|
|
8,351,945
|
|
|
|
5,661,096
|
|
|
|
5,675,077
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data (at end of period):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
650,176
|
|
|
$
|
672,537
|
|
|
$
|
467,936
|
|
|
$
|
274,768
|
|
|
$
|
245,996
|
|
|
$
|
190,184
|
|
Long-term debt, net of current maturities
|
|
$
|
343,094
|
|
|
$
|
233,046
|
|
|
$
|
225,245
|
|
|
$
|
100,581
|
|
|
$
|
134,609
|
|
|
$
|
105,379
|
|
Comparability of information in the above table between years is
affected by (1) changes in the annual average prices for
oil and gas, (2) increased production from drilling and
development activity, (3) significant acquisitions that
were made during the fiscal year ended May 31, 2004,
(4) the change in the fiscal year end on December 31,
2004, (5) formation of Quest Midstream in December 2006,
(6) the acquisition of KPC on November 1, 2007,
(7) Quest Energys initial public offering effective
November 15, 2007 and (8) the acquisition of PetroEdge
in July 2008. The table should be read in conjunction with
Managements Discussion and Analysis of Financial
Condition and Results of Operations and our consolidated
financial statements, including the notes, appearing in
Items 7 and 8 of this report, respectively.
|
|
ITEM 7.
|
MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
Restatement
As discussed in the Explanatory Note to this Annual Report on
Form 10-K
and in Note 18 Restatement to our consolidated
financial statements, we are restating the consolidated
financial statements included in this Annual Report on Form
10-K
as of
December 31, 2007 and 2006 and for the three years ended
December 31, 2007. We are also restating previously issued
Quarterly Financial Data for 2008 and 2007 presented in
Note 20 Supplemental Financial
Information Quarterly Financial Data (Unaudited) to
the consolidated financial statements. This Managements
Discussion and Analysis of Financial Condition and Results of
Operations for the years ended December 31, 2008, 2007,
2006 and 2005 reflects the restatements.
The following discussion should be read together with the
consolidated financial statements and the notes to consolidated
financial statements, which are included in Item 8 of this
Form 10-K,
and the Risk Factors, which are set forth in Item 1A.
Overview
of Our Company
Since QRCP controls the general partner interests in Quest
Energy and Quest Midstream, QRCP reflects its ownership interest
in these partnerships on a consolidated basis, which means that
our financial results are combined with Quest Energys and
Quest Midstreams financial results and the results of our
other subsidiaries. The interest owned by non-controlling
partners share of income is reflected as an expense in our
results of operations. Since the initial public offering of
Quest Energy in November 2007, QRCPs potential sources of
revenue and cash flows consist almost exclusively of
distributions on its partnership interests in Quest Energy and
Quest Midstream, because QRCPs Appalachian assets largely
consist of undeveloped acreage. Our consolidated results of
operations are derived from the results of operations of Quest
Energy and Quest Midstream and also include interest of non-
80
controlling partners in Quest Energys and Quest
Midstreams net income, interest income (expense) and
general and administrative expenses not reflected in Quest
Energys and Quest Midstreams results of operations.
Accordingly, the discussion of our financial position and
results of operations in this Managements Discussion
and Analysis of Financial Condition and Results of
Operations primarily reflects the operating activities and
results of operations of Quest Energy and Quest Midstream.
We are an integrated independent energy company involved in the
acquisition, development, transportation, exploration, and
production of natural gas, primarily from coal seams (coal bed
methane, or CBM), and oil. Our principal operations
and producing properties are located in the Cherokee Basin of
southeastern Kansas and northeastern Oklahoma; Seminole County,
Oklahoma; and West Virginia, New York and Pennsylvania in the
Appalachian Basin. We conduct substantially all of our
production operations through Quest Energy and our natural gas
transportation, gathering, treating and processing operations
through Quest Midstream. Our Cherokee Basin operations are
currently focused on developing CBM gas production through
Quest Energy, which is served by a gas gathering pipeline
network owned through Quest Midstream. Quest Midstream also owns
an interstate natural gas transmission pipeline. Our Appalachian
Basin operations are primarily focused on the development of the
Marcellus Shale through Quest Energy and
Quest Eastern.
Recent
Developments
The following is a discussion of some of the more significant
events that occurred during 2008 and the first part of 2009.
Please read Items 1. and 2. Business and
Properties Recent Developments for additional
information regarding these and other events that occurred
during the year.
PetroEdge
Acquisition
On July 11, 2008, QRCP acquired PetroEdge and
simultaneously transferred PetroEdges natural gas
producing wells to Quest Energy. Quest Energy funded its
purchase of the PetroEdge wellbores with borrowings under its
revolving credit facility, which was increased from
$160 million to $190 million as part of the
acquisition and the proceeds from the Second Lien Loan
Agreement. QRCP funded the balance of the PetroEdge acquisition
with proceeds from a public offering of 8,800,000 shares of
QRCP common stock at a price of $10.25 per share that closed on
July 8, 2008. QRCP received net proceeds from this offering
of approximately $84.2 million. Simultaneously with the
closing of the PetroEdge acquisition, QRCP converted its then
existing $50 million revolving credit facility to a
$35 million term loan with a maturity date of July 11,
2010. RBC required QRCP to use $13 million of the proceeds
from the equity offering to reduce the outstanding indebtedness
under the Credit Agreement from $48 million to
$35 million. The purpose of the PetroEdge acquisition was
to expand our operations to another geologic basin with less
basins differential, that had significant resource potential.
The acquisition closed during the peak month of natural gas
pricing in 2008.
Internal
Investigation; Restatements and Reaudits
On August 23, 2008, only six weeks after the PetroEdge
transaction closed, our then chief executive officer resigned
following the discovery of the Transfers. The Transfers were
brought to the attention of the boards of directors of each of
the Company, Quest Energy GP and Quest Midstream GP as a result
of an inquiry and investigation that had been initiated by the
Oklahoma Department of Securities. The Companys board of
directors, jointly with the boards of directors of Quest Energy
GP and Quest Midstream GP, formed a joint special committee to
investigate the matter and to consider the effect on our
consolidated financial statements. We also retained a new
independent registered public accounting firm to reaudit our
financial statements.
The investigation revealed that the Transfers resulted in a loss
of funds totaling approximately $10 million by the Company.
Further, it was determined that our former chief financial
officer directly participated
and/or
materially aided our former chief executive officer in
connection with the unauthorized Transfers. In addition, the
Oklahoma Department of Securities has filed a lawsuit alleging
that our former chief financial officer and our former
purchasing manager each received kickbacks of approximately
$0.9 million from several related suppliers over a two-year
period and that during the third quarter of 2008, they also
engaged in the direct theft of $1 million for their
personal benefit and use.
81
We experienced significant increased costs in the second half of
2008 and continue to experience such increased costs in the
first half of 2009 due to, among other things:
|
|
|
|
|
We had costs associated with the internal investigation and our
responding to inquiries from the Oklahoma Department of
Securities, the Federal Bureau of Investigation, the Department
of Justice, SEC and the IRS.
|
|
|
|
As a result of the termination of the former chief executive
officer and chief financial officer, we immediately retained
consultants to perform the accounting and finance functions and
to assist in the determination of the intercompany debt
discussed under Items 1. and 2. Business and
Properties Recent Developments
Intercompany Accounts.
|
|
|
|
We retained law firms to respond to the class action and
derivative suits that have been filed against QRCP and Quest
Energy GP and QELP and to pursue the claims against the former
employees.
|
|
|
|
We had costs associated with amending the credit agreements of
QRCP, QELP and QMLP and obtaining the necessary waivers from our
lenders thereunder as well as incremental increased interest
expense related thereto. See Liquidity and
Capital Resources.
|
|
|
|
We retained external auditors, who completed reaudits of the
restated consolidated financial statements for the years ended
December 31, 2007, 2006 and 2005.
|
|
|
|
Each of QRCP, QELP and QMLP retained financial advisors to
consider strategic options and each retained outside legal
counsel or increased the amount of work being performed by its
previously engaged outside legal counsel.
|
We estimate that the increased costs related to the foregoing
will be approximately $7.0 million to $8.0 million in
total.
Global
Financial Crisis and Impact on Capital Markets and Commodity
Prices
At about the same time as the Transfers were discovered, the
global economy experienced a significant downturn. The crisis
began over concerns related to the U.S. financial system
and quickly grew to impact a wide range of industries. There
were two significant ramifications to the exploration and
production industry as the economy continued to deteriorate. The
first was that capital markets essentially froze. Equity, debt
and credit markets shut down. Future growth opportunities have
been and are expected to continue to be constrained by the lack
of access to liquidity in the financial markets.
The second impact to the industry was that fear of global
recession resulted in a significant decline in oil and gas
prices. In addition to the decline in oil and gas prices, the
differential from NYMEX pricing to our sales point for our
Cherokee Basin gas production has widened and is still at
unprecedented levels of volatility.
Our operations and financial condition are significantly
impacted by these prices. During the year ended
December 31, 2008, the NYMEX monthly gas index price (last
day) ranged from a high of $13.58 per Mmbtu to a low of $5.29
per Mmbtu. Natural gas prices came under pressure in the second
half of the year as a result of lower domestic product demand
that was caused by the weakening economy and concerns over
excess supply of natural gas. In the Cherokee Basin, where we
produce and sell most of our gas, there has been a widening of
the historical discount of prices in the area to the NYMEX
pricing point at Henry Hub as a result of elevated levels of
natural gas drilling activity in the region and a lack of
pipeline takeaway capacity. During 2008, this discount (or basis
differential) in the Cherokee Basin ranged from $0.67 per Mmbtu
to $3.62 per Mmbtu.
The spot price for NYMEX crude oil in 2008 ranged from a high of
$145.29 per barrel in early July to a low of $33.87 per barrel
in late December. The volatility in oil prices during the year
was a result of the worldwide recession, geopolitical
activities, worldwide supply disruptions, actions taken by the
Organization of Petroleum Exporting Countries and the value of
the U.S. dollar in international currency markets as well
as domestic concerns about refinery utilization and petroleum
product inventories pushing prices up during the first half of
the year. Due to our relatively low level of oil production
relative to gas and our existing commodity hedge positions, the
volatility of oil prices had less of an effect on our operations.
82
Overall, as a result, our operating profitability was seriously
adversely affected during the second half of 2008 and is
expected to continue to be impaired during 2009. While our
existing commodity hedge position mitigates the impact of
commodity price declines, it does not eliminate the potential
effects of changing commodity prices. See Item 1A.
Risk Factors Risks Related to Our
Business The current financial crisis and
deteriorating economic conditions may have a material adverse
impact on our business and financial condition that we cannot
predict.
Credit
Agreement Amendments
In October and November 2008, QRCP, Quest Cherokee and Quest
Energy, and Quest Midstream and Bluestem entered into amendments
to their respective credit agreements that, among other things,
amended
and/or
waived certain of the representations and covenants contained in
each credit agreement in order to rectify any possible covenant
violations or non-compliance with the representations and
warranties as a result of (1) the questionable Transfers of
funds discussed above and (2) not timely settling certain
intercompany accounts among QRCP, Quest Energy and Quest
Midstream. The Quest Cherokee amendment also extended the
maturity date of the Second Lien Loan Agreement from
January 11, 2009 to September 30, 2009 due to our
inability to refinance the Second Lien Loan Agreement as a
result of a combination of the ongoing investigation and the
global financial crisis. The amendments also restricted the
ability of Quest Midstream and Quest Energy to pay distributions
to QRCP.
In May 2009, QRCP entered into an amendment to the Credit
Agreement to, among other things, waive certain events of
default related to its financial covenants and collateral
requirements, extend certain financial reporting deadlines and
permit the settlement agreements with Mr. Cash discussed
below.
See Liquidity and Capital
Resources Credit Agreements for additional
information regarding our credit agreements.
Suspension
of Distributions and Asset Sales
Distributions were suspended on Quest Energys subordinated
units beginning with the third quarter of 2008 and distributions
were suspended on all of Quest Energys units, including
its common units, beginning with the fourth quarter of 2008.
Since these distributions would have been substantially all of
QRCPs cash flows for 2009, the loss of the Quest Energy
distributions was material to QRCPs financial position.
In October 2008, we negotiated an additional $6 million
term loan under the Credit Agreement with a maturity date of
November 30, 2008. We agreed with our lenders that the
additional term loan would be repaid with the net proceeds from
asset sales by QRCP and that the first $4.5 million of net
proceeds in excess of any additional term loans that were
borrowed would be used to repay QRCPs $35 million
term loan.
On October 30, 2008, QRCP sold its interest in
approximately 22,600 net undeveloped acres and one well in
Somerset County, Pennsylvania to a private party for
approximately $6.8 million. On November 26, 2008, QRCP
sold its interest in the development rights and related purchase
option, which it had purchased on June 4, 2008 covering
approximately 28,700 acres in Potter County, Pennsylvania,
to an undisclosed party for approximately $3.2 million. On
February 13, 2009, QRCP sold its interest in approximately
23,076 net undeveloped acres in the Marcellus Shale and one
well in Lycoming County, Pennsylvania to a third party for
approximately $8.7 million.
Management decided that these undeveloped acres were good
candidates for disposition in the current environment given the
lack of gathering and transportation infrastructure in the
immediate area and the cost and time that would be involved in
establishing significant flow of natural gas.
In addition to these sales, on November 5, 2008, QRCP sold
a 50% interest in approximately 4,500 net undeveloped
acres, three wells in various stages of completion and existing
pipelines and facilities in Wetzel County, West Virginia to
another party for $6.1 million. QRCP will continue to
operate the Wetzel County property. All future development costs
will be split equally between QRCP and the other party. This
joint venture arrangement allows QRCP to retain a significant
interest in the Wetzel County property, which we believe is a
desirable asset due to established infrastructure, pipeline taps
and proved offset production in the area.
83
QRCP borrowed $2 million of the additional $6 million
term loan under its Credit Agreement in October 2008.
QRCPs portion of the proceeds from the asset sales were
used to repay the $2 million additional term loan and to
reduce QRCPs $35 million term loan to
$28.3 million as of May 15, 2009.
Decrease
in Year-End Reserves; Impairment
Due to the low price for natural gas as of December 31,
2008 as described above, revisions resulting from further
technical analysis (see Note 21 Supplemental
Information on Oil and Gas Producing Activities (Unaudited) to
the accompanying consolidated financial statements and
production during the year, proved reserves decreased 17.2% to
174.8 Bcfe at December 31, 2008 from 211.1 Bcfe
at December 31, 2007, and the standardized measure of our
proved reserves decreased 49.1% to $164.1 million as of
December 31, 2008 from $286.2 million as of
December 31, 2007. Proved reserves also decreased as a
result of our production during the year. Our proved reserves at
December 31, 2008 were calculated using a spot price of
$5.71 per Mmbtu (adjusted for basis differential, prices were
$5.93 per Mmbtu in the Appalachian Basin and $4.84 per Mmbtu in
the Cherokee Basin). As a result of this decrease, we recognized
a non-cash impairment of $298.9 million for the year ended
December 31, 2008.
As a result, the lenders under QELPs revolving credit
facility are likely to reduce QELPs borrowing base in the
near term. See Liquidity and Capital
Resources Sources of Liquidity in 2009 and
Capital Requirements Quest Energy.
Settlement
Agreements
As discussed above, we filed lawsuits against Mr. Cash, the
entity controlled by Mr. Cash that was used in connection
with the Transfers and two former officers, who are the other
owners of the controlled-entity, seeking, among other things, to
recover the funds that were transferred. On May 19, 2009,
QRCP, QELP and QMLP entered into settlement agreements with
Mr. Cash, the controlled-entity and the other owners to
settle this litigation. Under the terms of the settlement
agreements, QRCP received (1) approximately
$2.4 million in cash and (2) 60% of the
controlled-entitys interest in a gas well located in
Louisiana and a landfill gas development project located in
Texas. While QRCP estimates the value of these assets to be less
than the amount of the Transfers and cost of the internal
investigation, they represent the majority of the value of the
controlled-entity. We did not take Mr. Cashs stock in
QRCP, which he represented had been pledged to secure personal
loans with a principal balance far in excess of the current
market value of the stock. QELP received all of
Mr. Cashs equity interest in STP, which owns certain
oil producing properties in Oklahoma, and other assets as
reimbursement for all of the costs of the internal investigation
and the costs of the litigation against Mr. Cash that have
been paid by QELP.
Outlook
for 2009; Recombination
Given the liquidity challenges facing the Company, Quest
Midstream and Quest Energy, each entity has undertaken a
strategic review of its assets and may enter into one or more
transactions to dispose of assets in order to raise additional
funds for operations
and/or
to
repay indebtedness. In addition, in the current economic
environment we believe the complexity and added overhead costs
of our structure is negatively affecting our ability to
restructure our indebtedness and raise additional equity. See
Liquidity and Capital Resources. On
April 28, 2009, the Company, Quest Midstream and Quest
Energy entered into a non-binding letter of intent to enter into
the Recombination, pursuant to the terms of which all three
companies would form a new publicly traded holding company that
would wholly-own all three entities. The new company would
continue to develop the unconventional resources of the Cherokee
and Appalachian Basins with a clear focus on value creation
through efficient operations. The closing of the Recombination
is subject to the satisfaction of a number of conditions,
including the entry into a definitive merger agreement, the
negotiation of a new credit facility for the new company,
regulatory approval and the approval of the transaction by the
stockholders of the Company and the unitholders of Quest Energy
and Quest Midstream. There can be no assurance that the
definitive documentation will be agreed to or that the
Recombination will close.
84
Segment
Overview
After the acquisition of the KPC Pipeline in November 2007, we
began reporting our results of operations as two business
segments. These segments and the activities performed to provide
services to our customers and create value for our stockholders
are as follows:
|
|
|
|
|
Oil and gas production; and
|
|
|
|
Natural gas pipelines, including transporting, gathering,
treating and processing natural gas.
|
Previously reported amounts have been adjusted to reflect this
change, which did not impact our consolidated financial
statements. Operating segment data for the years ended
December 31, 2008, 2007, 2006, and 2005 follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
$
|
147,937
|
|
|
$
|
105,285
|
|
|
$
|
72,410
|
|
|
$
|
70,628
|
|
Natural gas pipelines
|
|
|
63,722
|
|
|
|
39,032
|
|
|
|
25,833
|
|
|
|
11,732
|
|
Elimination of inter-segment revenue
|
|
|
(35,546
|
)
|
|
|
(29,179
|
)
|
|
|
(20,819
|
)
|
|
|
(7,793
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas pipelines, net of inter-segment revenue
|
|
|
28,176
|
|
|
|
9,853
|
|
|
|
5,014
|
|
|
|
3,939
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment revenues
|
|
$
|
176,113
|
|
|
$
|
115,138
|
|
|
$
|
77,424
|
|
|
$
|
74,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production(a)
|
|
$
|
(284,244
|
)
|
|
$
|
5,999
|
|
|
$
|
1,861
|
|
|
$
|
23,508
|
|
Natural gas pipelines
|
|
|
17,198
|
|
|
|
11,964
|
|
|
|
10,063
|
|
|
|
2,580
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment operating profit (loss)
|
|
|
(267,046
|
)
|
|
|
17,963
|
|
|
|
11,924
|
|
|
|
26,088
|
|
General and administrative expenses
|
|
|
28,269
|
|
|
|
21,023
|
|
|
|
8,655
|
|
|
|
6,218
|
|
Misappropriation of funds
|
|
|
|
|
|
|
2,000
|
|
|
|
6,000
|
|
|
|
2,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating income (loss)
|
|
$
|
(295,315
|
)
|
|
$
|
(5,060
|
)
|
|
$
|
(2,731
|
)
|
|
$
|
17,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
2008 includes impairment of oil and gas properties of
$298.9 million in 2008.
|
Results
of Operations
The following discussion of financial condition and results of
operations should be read in conjunction with the consolidated
financial statements and the notes to the consolidated financial
statements, which are included elsewhere in this report.
85
Oil and
Gas Production Segment
Year
ended December 31, 2008 compared to the year ended
December 31, 2007
Overview.
The following discussion of results
of operations compares amounts for the year ended
December 31, 2008 to the amounts for the year ended
December 31, 2007, as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
Increase/
|
|
|
|
2008
|
|
|
2007
|
|
|
(Decrease)
|
|
|
|
($ in thousands)
|
|
|
Oil and gas sales
|
|
$
|
147,937
|
|
|
$
|
105,285
|
|
|
$
|
42,652
|
|
|
|
40.5
|
%
|
Oil and gas production costs
|
|
$
|
44,111
|
|
|
$
|
36,295
|
|
|
$
|
7,816
|
|
|
|
21.5
|
%
|
Transportation expense (intercompany)
|
|
$
|
35,546
|
|
|
$
|
29,179
|
|
|
$
|
6,367
|
|
|
|
21.8
|
%
|
Depreciation, depletion and amortization
|
|
$
|
53,663
|
|
|
$
|
33,812
|
|
|
$
|
19,851
|
|
|
|
58.7
|
%
|
Impairment charge
|
|
$
|
298,861
|
|
|
$
|
|
|
|
$
|
298,861
|
|
|
|
*
|
%
|
Production.
The following table presents the
primary components of revenues of our Oil and Gas Production
Segment (oil and gas production and average oil and gas prices),
as well as the average costs per Mcfe, for the fiscal years
ended December 31, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
Increase/
|
|
|
|
2008
|
|
|
2007
|
|
|
(Decrease)
|
|
|
Production Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production (Mmcfe)
|
|
|
21,748
|
|
|
|
17,017
|
|
|
|
4,731
|
|
|
|
27.8
|
%
|
Average daily production (Mmcfe/d)
|
|
|
59.4
|
|
|
|
46.6
|
|
|
|
12.8
|
|
|
|
27.5
|
%
|
Average Sales Price per Unit (Mcfe):
|
|
$
|
6.80
|
|
|
$
|
6.19
|
|
|
$
|
0.61
|
|
|
|
9.9
|
%
|
Average Unit Costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
$
|
2.03
|
|
|
$
|
2.13
|
|
|
$
|
(0.10
|
)
|
|
|
(4.7
|
)%
|
Transportation expense (intercompany)
|
|
$
|
1.63
|
|
|
$
|
1.71
|
|
|
$
|
(0.08
|
)
|
|
|
(4.7
|
)%
|
Depreciation, depletion and amortization
|
|
$
|
2.47
|
|
|
$
|
1.99
|
|
|
$
|
0.48
|
|
|
|
24.1
|
%
|
Oil and Gas Sales.
Oil and gas sales increased
$42.7 million, or 40.5%, to $147.9 million during the
year ended December 31, 2008. This increase was the result
of increased sales volumes and an increase in average realized
prices. Additional volumes of 4,731 Mmcfe accounted for
$32.2 million of the increase. The increased volumes
resulted from additional wells completed in 2008. The remaining
increase of $10.4 million was attributable to an increase
in the average product price in 2008. Our average product
prices, which exclude hedge settlements, on an equivalent basis
(Mcfe) increased to $6.80 per Mcfe for the 2008 period from
$6.19 per Mcfe for the 2007 period.
Oil and Gas Operating Expenses.
Oil and gas
operating expenses consist of oil and gas production costs,
which include lease operating expenses, severance taxes and ad
valorem taxes, and transportation expense. Oil and gas operating
expenses increased $14.2 million, or 21.7%, to
$79.7 million during the year ended December 31, 2008,
from $65.5 million during the year ended December 31,
2007.
Oil and gas production costs increased $7.8 million, or
21.5%, to $44.1 million during the year ended
December 31, 2008, from $36.3 million during the year
ended December 31, 2007. This increase was primarily due to
increased volumes in 2008. Production costs including gross
production taxes and ad valorem taxes were $2.03 per Mcfe for
the year ended December 31, 2008 as compared to $2.13 per
Mcfe for the year ended December 31, 2007. The decrease in
per unit cost was due to higher volumes over which to spread
fixed costs.
Transportation expense increased $6.4 million, or 21.8%, to
$35.5 million during the year ended December 31, 2008,
from $29.2 million during the year ended December 31,
2007. The increase was primarily due to increased volumes, which
resulted in additional expense of approximately
$7.6 million. This increase was offset by a decrease in
86
per unit cost of $0.08 per Mcfe. Transportation expense was
$1.63 per Mcfe for the year ended December 31, 2008 as
compared to $1.71 per Mcfe for the year ended December 31,
2007. This decrease in per unit cost was due to increased
volumes, over which to spread fixed costs.
Depreciation, Depletion and Amortization.
We
are subject to variances in our depletion rates from period to
period due to changes in our oil and gas reserve quantities,
production levels, product prices and changes in the depletable
cost basis of our oil and gas properties. Our depreciation,
depletion and amortization increased approximately
$19.9 million, or 58.7%, in 2008 to $53.7 million from
$33.8 million in 2007. On a per unit basis, we had an
increase of $0.48 per Mcfe to $2.47 per Mcfe in 2008 from $1.99
per Mcfe in 2007. This increase was primarily due to downward
revisions in our proved reserves, resulting in an increase in
the per unit rate. In addition, depreciation and amortization
increased approximately $5.5 million primarily due to
additional vehicles, equipment and facilities acquired in 2008.
Impairment of oil and gas properties.
We
recognized impairments of our oil and gas properties of
$298.9 million for the year ended December 31, 2008.
Under full cost method accounting, we are required to compute
the after-tax present value of our proved oil and gas properties
using spot market prices for oil and gas at our balance sheet
date. The base for our spot prices for gas is Henry Hub. On
December 31, 2008, the spot price for gas at Henry Hub was
$5.71 per Mcf and the spot oil price was $44.60 per Bbl compared
to $6.43 per Mcf and $92.01 per barrel, at December 31,
2007.
Year
ended December 31, 2007 compared to the year ended
December 31, 2006
Overview.
The following discussion of results
of operations compares amounts for the year ended
December 31, 2007 to the amounts for the year ended
December 31, 2006, as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Increase/
|
|
|
|
2007
|
|
|
2006
|
|
|
(Decrease)
|
|
|
|
($ in thousands)
|
|
|
Oil and gas sales
|
|
$
|
105,285
|
|
|
$
|
72,410
|
|
|
$
|
32,875
|
|
|
|
45.4
|
%
|
Oil and gas production costs
|
|
$
|
36,295
|
|
|
$
|
25,338
|
|
|
$
|
10,957
|
|
|
|
43.2
|
%
|
Transportation expense (intercompany)
|
|
$
|
29,179
|
|
|
$
|
20,819
|
|
|
$
|
8,360
|
|
|
|
40.1
|
%
|
Depreciation, depletion and amortization
|
|
$
|
33,812
|
|
|
$
|
24,392
|
|
|
$
|
9,420
|
|
|
|
38.6
|
%
|
Production.
The following table presents the
primary components of revenues of our Oil and Gas Production
Segment (oil and gas production and average oil and gas prices),
as well as the average costs per Mcfe, for the fiscal years
ended December 31, 2007 and 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Increase/
|
|
|
|
2007
|
|
|
2006
|
|
|
(Decrease)
|
|
|
Production Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production (Mmcfe)
|
|
|
17,017
|
|
|
|
12,364
|
|
|
|
4,653
|
|
|
|
37.6
|
%
|
Average daily production (Mmcfe/d)
|
|
|
46.6
|
|
|
|
33.9
|
|
|
|
12.7
|
|
|
|
37.5
|
%
|
Average Sales Price per Unit (Mcfe):
|
|
$
|
6.19
|
|
|
$
|
5.86
|
|
|
$
|
0.33
|
|
|
|
5.6
|
%
|
Average Unit Costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
$
|
2.13
|
|
|
$
|
2.05
|
|
|
$
|
0.08
|
|
|
|
3.9
|
%
|
Transportation expense (intercompany)
|
|
$
|
1.71
|
|
|
$
|
1.68
|
|
|
$
|
0.03
|
|
|
|
1.8
|
%
|
Depreciation, depletion and amortization
|
|
$
|
1.99
|
|
|
$
|
1.97
|
|
|
$
|
0.02
|
|
|
|
1.0
|
%
|
Oil and Gas Sales.
Oil and gas sales increased
$32.9 million, or 45.4%, to $105.3 million during the
year ended December 31, 2007, from $72.4 million
during the year ended December 31, 2006. This increase was
due to increased sales volumes. Higher volumes represented $28.8
million of the increase. The increase in production volumes was
due to additional wells completed during 2007. The additional
increase of $4.1 million was due to higher average sales
prices. Our average sales prices, which exclude hedge
settlements, on an equivalent basis (Mcfe) increased to $6.19
per Mcfe for 2007 from $5.86 per Mcfe for 2006.
87
Oil and Gas Operating Expenses.
Oil and gas
operating expenses consist of oil and gas production costs,
which include lease operating expenses, severance taxes and ad
valorem taxes, and transportation expense. Oil and gas operating
expenses increased $19.3 million, or 41.8%, to
$65.5 million during the year ended December 31, 2007,
from $46.2 million during the year ended December 31,
2006.
Oil and gas production costs increased $11.0 million, or
43.2%, to $36.3 million during the year ended
December 31, 2007, from $25.3 million during the year
ended December 31, 2006. This increase was a result of the
higher production volumes in 2007. Production costs including
gross production taxes and ad valorem taxes were $2.13 per Mcfe
for the year ended December 31, 2007 as compared to $2.05
per Mcfe for the year ended December 31, 2006. The increase
in per unit costs was due to an overall increase in the costs of
goods and services used in our operations partially offset by
higher volumes over which fixed costs were spread.
Transportation expense increased $8.4 million, or 40.1%, to
$29.2 million during the year ended December 31, 2007,
from $20.8 million during the year ended December 31,
2006. Transportation expense was $1.71 per Mcfe for the year
ended December 31, 2007 as compared to $1.68 per Mcfe for
the year ended December 31, 2006. This increase primarily
resulted from additional volumes as well as from the midstream
services agreement with Quest Midstream that became effective
December 1, 2006, which provided for a fixed transportation
fee that was higher than the fees in the prior year.
Depreciation, Depletion and Amortization.
We
are subject to variances in our depletion rates from period to
period due to changes in our oil and gas reserve quantities,
production levels, product prices and changes in the depletable
cost basis of our oil and gas properties. Our depreciation,
depletion and amortization increased approximately
$9.4 million, or 38.6%, in 2007 to $33.8 million from
$24.4 million in 2007. On a per unit basis, we had an
increase of $0.02 per Mcfe to $1.99 in 2007 from $1.97 per Mcfe
in 2006. This increase was primarily due to an increase in
depletion of $9.3 million. This increase was due to
additional production volumes in 2007.
Year
ended December 31, 2006 compared to the year ended
December 31, 2005
Overview.
The following discussion of results
of operations compares amounts for the year ended
December 31, 2006 to the amounts for the year ended
December 31, 2005, as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Increase/
|
|
|
|
2006
|
|
|
2005
|
|
|
(Decrease)
|
|
|
|
($ in thousands)
|
|
|
Oil and gas sales
|
|
$
|
72,410
|
|
|
$
|
70,628
|
|
|
$
|
1,782
|
|
|
|
2.5
|
%
|
Oil and gas production costs
|
|
$
|
25,338
|
|
|
$
|
18,532
|
|
|
$
|
6,806
|
|
|
|
36.7
|
%
|
Transportation expense (intercompany)
|
|
$
|
20,819
|
|
|
$
|
7,793
|
|
|
$
|
13,026
|
|
|
|
167.2
|
%
|
Depreciation, depletion and amortization
|
|
$
|
24,392
|
|
|
$
|
20,795
|
|
|
$
|
3,597
|
|
|
|
17.3
|
%
|
88
Production.
The following table presents the
primary components of revenues of the Oil and Gas Production
Segment (oil and gas production and average oil and gas prices),
as well as the average costs per Mcfe, for the fiscal years
ended December 31, 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Increase/
|
|
|
|
2006
|
|
|
2005
|
|
|
(Decrease)
|
|
|
Production Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production (Mmcfe)
|
|
|
12,364
|
|
|
|
9,629
|
|
|
|
2,735
|
|
|
|
28.4
|
%
|
Average daily production (Mmcfe/d)
|
|
|
33.9
|
|
|
|
26.4
|
|
|
|
7.5
|
|
|
|
28.4
|
%
|
Average Sales Price per Unit (Mcfe):
|
|
$
|
5.86
|
|
|
$
|
7.33
|
|
|
$
|
(1.47
|
)
|
|
|
(20.1
|
)%
|
Average Unit Costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
$
|
2.05
|
|
|
$
|
1.92
|
|
|
$
|
0.13
|
|
|
|
6.8
|
%
|
Transportation expense (intercompany)
|
|
$
|
1.68
|
|
|
$
|
0.81
|
|
|
$
|
0.87
|
|
|
|
107.4
|
%
|
Depreciation, depletion and amortization
|
|
$
|
1.97
|
|
|
$
|
2.16
|
|
|
$
|
(0.19
|
)
|
|
|
(8.8
|
)%
|
Oil and Gas Sales.
Oil and gas sales increased
$1.8 million, or 2.5%, to $72.4 million during the
year ended December 31, 2006, from $70.6 million
during the year ended December 31, 2005. Additional volumes
of 2,735 Mmcfe increased revenues by $16.0 million. The increase
in volumes resulted from the additional wells completed during
2006. This increase was offset by a decrease in average prices
of $1.47 per Mcfe, resulting in decreased revenues of
$14.2 million. Our average sales prices, which exclude
hedge settlements, on an equivalent basis (Mcfe) decreased to
$5.86 per Mcfe in 2006 from $7.33 per Mcfe in 2005.
Oil and Gas Operating Expenses.
Oil and gas
operating expenses consist of oil and gas production costs,
which include lease operating expenses, severance taxes and ad
valorem taxes, and transportation expense. Oil and gas
production expense increased $19.8 million, or 75.3%, to
$46.1 million during the year ended December 31, 2006,
from $26.3 million during the year ended December 31,
2005. This increase was due to increased sales volumes.
Oil and gas production costs increased $6.8 million, or
36.7%, to $25.3 million during the year ended
December 31, 2006, from $18.5 million during the year
ended December 31, 2005. Production expenses excluding
gross production and ad valorem taxes were $1.56 per Mcfe for
the year ended December 31, 2006 compared to $1.51 per Mcfe
for the year ended December 31, 2005. Production costs
including gross production taxes and ad valorem taxes were $2.05
per Mcfe for the year ended December 31, 2006 as compared
to $1.92 per Mcfe for the year ended December 31, 2005.
This increase was a result of a general increase in the costs of
goods and services used in our operations in 2006.
Transportation expense increased $13.0 million, or 167.2%,
to $20.8 million during the year ended December 31,
2006, from $7.8 million during the year ended
December 31, 2005. Transportation expense was $1.68 per
Mcfe for the year ended December 31, 2006 as compared to
$0.81 per Mcfe for the year ended December 31, 2005. The
increase primarily resulted from increases in volumes, as well
as from increases in compression rental and property taxes
assessed on pipelines and related equipment during 2006.
Depreciation, Depletion and Amortization.
We
are subject to variances in our depletion rates from period to
period due to changes in our oil and gas reserve quantities,
production levels, product prices and changes in the depletable
cost basis of our oil and gas properties. Our depreciation,
depletion and amortization increased approximately
$3.6 million, or 17.3%, in 2006 to $24.4 million from
$20.8 million in 2005. Depletion accounted for
$2.9 million of the increase, while the remaining increase
was due to depreciation and amortization. On a per unit basis,
we had a decrease of $0.19 per Mcfe to $1.97 in 2006 from $2.16
per Mcfe in 2005. This decrease was primarily due to a decrease
in our depletion rate per Mcfe of $0.20. This decreased rate was
attributable to an increase in our proved reserves.
89
Natural
Gas Pipelines Segment
Year
ended December 31, 2008 compared to year ended
December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Increase/(Decrease)
|
|
|
|
($ in thousands)
|
|
|
Natural Gas Pipeline Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas pipeline revenue Third Party
|
|
$
|
28,176
|
|
|
$
|
9,853
|
|
|
$
|
18,323
|
|
|
|
186.0
|
%
|
Gas pipeline revenue Intercompany
|
|
$
|
35,546
|
|
|
$
|
29,179
|
|
|
$
|
6,367
|
|
|
|
21.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total natural gas pipeline revenue
|
|
$
|
63,722
|
|
|
$
|
39,032
|
|
|
$
|
24,690
|
|
|
|
63.3
|
%
|
Pipeline operating expense
|
|
$
|
29,742
|
|
|
$
|
21,098
|
|
|
$
|
8,644
|
|
|
|
41.0
|
%
|
Depreciation and amortization expense
|
|
$
|
16,782
|
|
|
$
|
5,970
|
|
|
$
|
10,812
|
|
|
|
181.1
|
%
|
Throughput Data (Mmcf):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput Third Party
|
|
|
11,125
|
|
|
|
1,686
|
|
|
|
9,439
|
|
|
|
559.8
|
%
|
Throughput Intercompany
|
|
|
25,177
|
|
|
|
17,148
|
|
|
|
8,029
|
|
|
|
46.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total throughput (Mmcf)
|
|
|
36,302
|
|
|
|
18,834
|
|
|
|
17,468
|
|
|
|
92.7
|
%
|
Average Pipeline Operating Costs per Mmcf:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline operating expense
|
|
$
|
0.82
|
|
|
$
|
1.12
|
|
|
$
|
(0.30
|
)
|
|
|
(26.8
|
)%
|
Depreciation and amortization
|
|
$
|
0.46
|
|
|
$
|
0.32
|
|
|
$
|
0.14
|
|
|
|
43.8
|
%
|
Pipeline Revenue.
Total natural gas pipeline
revenue increased $24.6 million, or 63.3%, to
$63.7 million during the year ended December 31, 2008,
from $39.0 million during the year ended December 31,
2007.
Third party natural gas pipeline revenue increased
$18.3 million, or 186.0%, to $28.2 million during the
year ended December 31, 2008, from $9.9 million during
the year ended December 31, 2007. The increase was
primarily related to KPC, which was acquired November 1,
2007. During the year ended December 31, 2008, KPC had
revenues of $19.5 million compared to $3.2 million for
the period from November 1, 2007 through December 31,
2007. The remaining increase of $2.0 million was due to
additional third party volumes on our gathering system.
Intercompany natural gas pipeline revenue increased
$6.4 million, or 21.8%, to $35.5 million during the
year ended December 31, 2008, from $29.2 million
during the year ended December 31, 2007. The increase is
due to the 46.8% increase in throughput volumes from our
Cherokee Basin properties and the higher gathering and
compression fees resulting from the midstream services agreement
that became effective January 1, 2008.
Pipeline Operating Expense.
Pipeline operating
expense increased $8.6 million, or 41.0%, to
$29.7 million during the year ended December 31, 2008,
from $21.1 million during the year ended December 31,
2007. This increase is primarily the result of our KPC
acquisition in November 2007. Therefore, 2007 only had
two months of expenses versus 12 months in 2008.
During the year ended December 31, 2008, KPC had pipeline
operating costs of $7.7 million compared to operating costs
of $1.9 million during the period from November 1,
2007 through December 31, 2007. The remaining increase
of $1.7 million is due to increased throughput volumes
in 2008. Pipeline operating costs per unit decreased $0.30
per Mcf during 2008, from $1.12 per Mcf to $0.82 per Mcf.
The decrease in per unit cost was the result of higher volumes,
over which to spread fixed costs, as well as our cost-cutting
efforts implemented in the third quarter of 2008.
Depreciation and Amortization.
Depreciation
and amortization expense increased $10.8 million, or
181.1%, to $16.8 million during the year ended
December 31, 2008, from $6.0 million during the year
ended December 31, 2007. The increase is primarily due to
the amortization of our intangibles of $4.3 million
acquired in the KPC acquisition, as well as an increase in
depreciation on our pipelines of $1.7 million. During the
year ended December 31, 2008, KPC had depreciation and
amortization expense of $5.6 million compared to
$0.8 million for the period from November 1, 2007
through December 31, 2007. The remaining increase is due to
the additional natural gas gathering pipeline installed during
the year ended December 31, 2008.
90
Year
ended December 31, 2007 compared to year ended
December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Increase/(Decrease)
|
|
|
|
|
|
|
($ in thousands)
|
|
|
|
|
|
Natural Gas Pipeline Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas pipeline revenue Third Party
|
|
$
|
9,853
|
|
|
$
|
5,014
|
|
|
$
|
4,839
|
|
|
|
96.5
|
%
|
Gas pipeline revenue Intercompany
|
|
$
|
29,179
|
|
|
$
|
20,819
|
|
|
$
|
8,360
|
|
|
|
40.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total natural gas pipeline revenue
|
|
$
|
39,032
|
|
|
$
|
25,833
|
|
|
$
|
13,199
|
|
|
|
51.1
|
%
|
Pipeline operating expense
|
|
$
|
21,098
|
|
|
$
|
13,151
|
|
|
$
|
7,947
|
|
|
|
60.4
|
%
|
Depreciation and amortization expense
|
|
$
|
5,970
|
|
|
$
|
2,619
|
|
|
$
|
3,351
|
|
|
|
127.9
|
%
|
Throughput Data (Mmcf):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput Third Party
|
|
|
1,686
|
|
|
|
1,463
|
|
|
|
223
|
|
|
|
15.2
|
%
|
Throughput Intercompany
|
|
|
17,148
|
|
|
|
12,341
|
|
|
|
4,807
|
|
|
|
39.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total throughput (Mmcf)
|
|
|
18,834
|
|
|
|
13,804
|
|
|
|
5,030
|
|
|
|
36.4
|
%
|
Average Pipeline Operating Costs per Mmcf:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline operating expense
|
|
$
|
1.12
|
|
|
$
|
0.95
|
|
|
$
|
0.17
|
|
|
|
17.9
|
%
|
Depreciation and amortization
|
|
$
|
0.32
|
|
|
$
|
0.19
|
|
|
$
|
0.13
|
|
|
|
68.4
|
%
|
Pipeline Revenue.
Total natural gas pipeline
revenue increased $13.2 million, or 51.1%, to
$39.0 million during the year ended December 31, 2007,
from $25.8 million during the year ended December 31,
2006.
Third party natural gas pipeline revenue increased
$4.8 million, or 96.5%, to $9.9 million during the
year ended December 31, 2007, from $5.0 million during
the year ended December 31, 2006. KPC had revenues of
$3.2 million during the period from November 1, 2007
through December 31, 2007. The remaining increase of
$6.7 million was due to additional third party volumes on
our gathering system.
Intercompany natural gas pipeline revenue increased
$8.4 million, or 40.2%, to $29.2 million during the
year ended December 31, 2007, from $20.8 million
during the year ended December 31, 2006. The increase is
due to the 39.0% increase in throughput volumes from our
Cherokee Basin properties and the higher gathering and
compression fees resulting from the midstream services agreement
that became effective December 1, 2006.
Pipeline Operating Expense.
Pipeline operating
expense increased $7.9 million, or 60.4%, to
$21.1 million during the year ended December 31, 2007,
from $13.2 million during the year ended December 31,
2006. Pipeline operating costs per Mcf increased $0.17 per Mcf
during 2007, from $0.95 per Mcf during 2006 to $1.12 per Mcf
during 2007. During the period from November 1, 2007
through December 31, 2007, KPC had operating costs of
$1.9 million. The remaining increase was due to the
delivery of additional compressors in anticipation of increased
pipeline volumes, the number of wells completed and operated
during the year, the increased miles of pipeline in service and
the increase in property taxes.
Depreciation and Amortization.
Depreciation
and amortization expense increased $3.4 million, or 127.9%,
to $6.0 million during the year ended December 31,
2007, from $2.6 million during the year ended
December 31, 2006. During the period from
November 1, 2007 through December 31, 2007, KPC had
depreciation and amortization expense of $0.8 million. The
remaining increase is due to the additional natural gas
gathering pipeline installed during the year ended
December 31, 2007.
91
Year
ended December 31, 2006 compared to year ended
December 31, 2005
Overview.
The following discussion of pipeline
operations will compare amounts for the year ended
December 31, 2006 to the amounts for the year ended
December 31, 2005, as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Increase/(Decrease)
|
|
|
|
|
|
|
($ in thousands)
|
|
|
|
|
|
Natural Gas Pipeline Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas pipeline revenue Third Party
|
|
$
|
5,014
|
|
|
$
|
3,939
|
|
|
$
|
1,075
|
|
|
|
27.3
|
%
|
Gas pipeline revenue Intercompany
|
|
$
|
20,819
|
|
|
$
|
7,793
|
|
|
$
|
13,026
|
|
|
|
167.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total natural gas pipeline revenue
|
|
$
|
25,833
|
|
|
$
|
11,732
|
|
|
$
|
14,101
|
|
|
|
120.2
|
%
|
Pipeline operating expense
|
|
$
|
13,151
|
|
|
$
|
7,703
|
|
|
$
|
5,448
|
|
|
|
70.7
|
%
|
Depreciation and amortization expense
|
|
$
|
2,619
|
|
|
$
|
1,449
|
|
|
$
|
1,170
|
|
|
|
80.7
|
%
|
Throughput Data (Mmcf):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput Third Party
|
|
|
1,463
|
|
|
|
1,179
|
|
|
|
284
|
|
|
|
24.1
|
%
|
Throughput Intercompany
|
|
|
12,341
|
|
|
|
9,620
|
|
|
|
2,721
|
|
|
|
28.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total throughput (Mmcf)
|
|
|
13,804
|
|
|
|
10,799
|
|
|
|
3,005
|
|
|
|
27.8
|
%
|
Average Pipeline Operating Costs per Mmcf:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline operating expense
|
|
$
|
0.95
|
|
|
$
|
0.71
|
|
|
$
|
0.24
|
|
|
|
33.8
|
%
|
Depreciation and amortization
|
|
$
|
0.19
|
|
|
$
|
0.13
|
|
|
$
|
0.06
|
|
|
|
46.2
|
%
|
Pipeline Revenue.
Total natural gas pipeline
revenue increased $14.1 million, or 120.2%, to
$25.8 million during the year ended December 31, 2006,
from $11.7 million during the year ended December 31,
2005.
Third party natural gas pipeline revenue increased
$1.1 million, or 27.3%, to $5.0 million during the
year ended December 31, 2006, from $3.9 million during
the year ended December 31, 2005. This increase was
primarily due to an increase in third party wells connected to
our gathering system.
Intercompany natural gas pipeline revenue increased
$13.0 million, or 167.2%, to $20.8 million during the
year ended December 31, 2006, from $7.8 million during
the year ended December 31, 2005. The increase is due to
the 28.3% increase in throughput volumes from our Cherokee Basin
properties and higher gathering and compression fees charged.
Pipeline Operating Expense.
Pipeline operating
expense increased $5.4 million, or 70.7%, to
$13.1 million during the year ended December 31, 2006,
from $7.7 million during the year ended December 31,
2005. Pipeline operating costs per Mcf increased $0.24 per Mcf
during 2006, from $0.71 per Mcf during 2005 to $0.95 per Mcf
during 2006. The increase was due to the delivery of additional
compressors in anticipation of increased pipeline volumes, the
number of wells completed and operated during the year, the
increased miles of pipeline in service and the increase in
property taxes.
Depreciation and amortization.
Depreciation
and amortization expense increased $1.2 million, or 80.7%,
to $2.6 million during the year ended December 31,
2006, from $1.4 million during the year ended
December 31, 2005. The increase is due to the additional
natural gas gathering pipeline installed during the years ended
December 31, 2006 and 2005.
Unallocated
Items
The following discussion of results of operations will compare
amounts for the years ended December 31, 2008, 2007, 2006
and 2005.
General
and Administrative Expenses
General and administrative expenses increased $7.2 million,
or 34.5%, to $28.2 million during the year ended
December 31, 2008, from $21.0 million during the year
ended December 31, 2007. The increase is primarily due to
92
the internal investigation and restatements and reaudits
($4.7 million), increased rent in connection with
establishing a Houston Office and new corporate headquarters
($1.7 million), the inclusion of KPC for all of 2008
compared to two months in 2007 ($2.5 million), and
headcount (7%) and salary (10%) increases to support the growth
of the Company ($0.8 million). These amounts were partially
offset by lower stock compensation expense ($3.9 million)
in connection with the departure of our former chief executive
and financial officers. The remaining increase was the result of
the costs associated with Quest Energy being a separate publicly
traded company.
General and administrative expenses increased
$12.4 million, or 143.0%, to $21.0 million during the
year ended December 31, 2007, from $8.6 million during
the year ended December 31, 2006. The increase is mainly
due to stock compensation expense ($4.9 million), and
headcount (41%) and salary (10%) increases to support the growth
of the Company ($1.5 million). Other increases relate to
additional costs associated with Quest Energy becoming a
separate public entity and the acquisition of KPC in November
2007.
General and administrative expenses increased $2.4 million,
or 39.2%, to $8.6 million during the year ended
December 31, 2006, from $6.2 million during the year
ended December 31, 2005. The increase is mainly due to
headcount (39%) and salary (10%) increases to support the growth
of the Company ($0.9 million). The remaining increase was
associated with costs related to the formation of Quest
Midstream.
Loss
on Early Extinguishment of Debt
Loss on debt refinancing.
The loss on early
extinguishment of debt of $12.4 million for the year ended
December 31, 2005 relates to the refinancing of
subordinated debt entered into in connection with the creation
of Quest Cherokee in 2003.
Loss
from Misappropriation of Funds
Loss from misappropriation of funds.
As
disclosed previously, in connection with the Transfers, we have
recorded a loss from misappropriation of funds of
$2.0 million, $6.0 million and $2.0 million for
the years ended December 31, 2005, 2006 and 2007,
respectively.
Other
Income (Expense)
Gain (loss) from derivative financial
instruments.
Gain from derivative financial
instruments increased $78.7 million to $80.7 million
during the year ended December 31, 2008, from
$2.0 million during the year ended December 31, 2007.
Due to the decline in average natural gas and crude oil prices
during the second half of 2008, we recorded a $72.5 million
unrealized gain and $8.2 million realized gain on our
derivative contracts for the year ended December 31, 2008
compared to a $5.3 million unrealized loss and
$7.3 million realized gain for the year ended
December 31, 2007. Unrealized gains are attributable to
changes in natural gas prices and volumes hedged from one period
end to another.
Gain from derivative financial instruments decreased
$50.7 million to $2.0 million during the year ended
December 31, 2007, from $52.7 million during the year
ended December 31, 2006. We recorded a $5.3 million
unrealized loss and $7.3 million realized gain on our
derivative contracts for the year ended December 31, 2007
compared to a $70.4 million unrealized gain and
$17.7 million realized loss for the year ended
December 31, 2006.
We recorded a gain from derivative financial instruments of
$52.7 million for the year ended December 31, 2006 and
a loss from derivative financial instruments of
$73.6 million for the year ended December 31, 2005. We
recorded a $70.4 million unrealized gain and
$17.7 million realized loss on our derivative contracts for
the year ended December 31, 2006 compared to a
$46.6 million unrealized loss and $27.0 million
realized loss for the year ended December 31, 2005.
Interest
Expense
Interest expense, net.
Interest expense, net
decreased $18.3 million, or 41.8%, to $25.4 million
during the year ended December 31, 2008, from
$43.6 million during the year ended December 31, 2007.
The decreased interest expense for the year ended
December 31, 2008 relates to the write-off of
$9.9 million of deferred debt
93
issuance costs recorded in connection with the refinancing of
our credit facilities during 2007 and lower interest rates
during 2008.
Interest expense, net increased $23.1 million, or 112.1%,
to $43.6 million during the year ended December 31,
2007, from $20.6 million during the year ended
December 31, 2006. The increased interest expense for the
year ended December 31, 2007 relates to the write-off of
$9.9 million of debt issuance costs recorded in connection
with the refinancing of our credit facilities during 2007 and
higher average outstanding debt balances during 2007.
Interest expense, net decreased $7.7 million, or 27.1%, to
$20.6 million during the year ended December 31, 2006,
from $28.2 million during the year ended December 31,
2005. The decrease in interest expense for the year ended
December 31, 2006 is primarily due to the repayment of the
ArcLight subordinated notes in November 2005, which had higher
interest rates than the funds borrowed in 2006. In addition, we
wrote off the deferred financing costs of $0.8 million
associated with these notes in 2005. Additionally, we
capitalized approximately $0.9 million more interest in
2006.
Liquidity
and Capital Resources
Historical
Cash Flows and Liquidity
Cash Flows from Operating Activities.
Our
operating cash flows are driven by the quantities of our
production of oil and natural gas and the prices received from
the sale of this production and revenue generated from our
pipeline operating activities. Prices of oil and natural gas
have historically been very volatile and can significantly
impact the cash from the sale our oil and natural gas
production. Use of derivative financial instruments help
mitigate this price volatility. Cash expenses also impact our
operating cash flow and consist primarily of oil and natural gas
property operating costs, severance and ad valorem taxes,
interest on our indebtedness, general and administrative
expenses and taxes on income.
Cash flows from operations totaled $61.9 million for the
year ended December 31, 2008 as compared to cash flows from
operations of $28.8 million for the year ended
December 31, 2007. The increase is attributable primarily
to net cash from increased production and from higher average
oil and natural gas prices in 2008 (although 2008 prices began
to decline significantly in the third quarter of
2008) compared with average prices during 2007.
Cash Flows Used in Investing Activities.
Net
cash used in investing activities totaled $266.6 million
for the year ended December 31, 2008 as compared to
$272.5 million for the year ended December 31, 2007.
The following table sets forth our capital expenditures by major
categories in 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
Leasehold acquisition
|
|
$
|
18,945
|
|
|
$
|
15,847
|
|
Exploration
|
|
|
1,273
|
|
|
|
|
|
Development
|
|
|
58,070
|
|
|
|
67,586
|
|
Acquisition of PetroEdge
|
|
|
142,618
|
|
|
|
|
|
Acquisition of Seminole County, Oklahoma property
|
|
|
9,500
|
|
|
|
|
|
Acquisition of KPC
|
|
|
|
|
|
|
124,936
|
|
Pipelines
|
|
|
27,649
|
|
|
|
48,668
|
|
Other items (primarily capitalized overhead and interest)
|
|
|
9,061
|
|
|
|
7,832
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures
|
|
$
|
267,116
|
|
|
$
|
264,869
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities.
Net cash
provided by financing activities totaled $211.8 million for
the year ended December 31, 2008 as compared to
$216.5 million for the year ended December 31, 2007.
The cash provided from financing activities was primarily due to
an increase in borrowings of $169.4 million and proceeds
94
from issuance of common stock of $84.8 million, partially
offset by repayments of note borrowings of $15.0 million,
and $24.4 million of distributions to unitholders.
Working Capital Deficit.
At December 31,
2008, we had current assets of $97.8 million. Our working
capital (current assets minus current liabilities, excluding the
short-term derivative asset and liability of $43.0 million
and $12,000, respectively) was a deficit of $41.5 million
at December 31, 2008, compared to a working capital
(excluding the short-term derivative asset and liability of
$8.0 million and $8.1 million, respectively) deficit
of $12.4 million at December 31, 2007. Amounts in 2007
included a change in working capital due to the formation of
Quest Energy in November 2007 and the issuance of common units
in Quest Midstream to a group of investors for approximately
$75 million before expenses. Additionally, inventory,
accounts payable and accrued expenses balances increased in 2008
as we expanded our operations.
Credit
Agreements
Quest Resource.
On July 11, 2008, the
Company and Royal Bank of Canada (RBC) entered into
an Amended and Restated Credit Agreement (the Credit
Agreement) to convert the Companys then-existing
$50 million revolving credit facility to a $35 million
term loan, due and maturing on July 11, 2010 (the
Original Term Loan). On October 24, 2008, the
Company and RBC entered into a First Amendment to Amended and
Restated Credit Agreement (the First Amendment to Credit
Agreement), which, among other things, added a
$6 million term loan (the Additional Term Loan)
to the $35 million term loan under the Credit Agreement.
The maturity date for the Additional Term Loan was
November 30, 2008. On October 24, 2008, the Company
borrowed $2 million of the $6 million available under
the Additional Term Loan. On November 4, 2008, the Company
entered into a Second Amendment to Amended and Restated Credit
Agreement (the Second Amendment to Credit Agreement)
which clarified that the $6 million commitment under the
Additional Term Loan would be reduced dollar for dollar to the
extent the Company retained net cash proceeds from dispositions
in accordance with the terms of the Credit Agreement. On
January 30, 2009, the Company entered into a Third
Amendment to Amended and Restated Credit Agreement (the
Third Amendment to Credit Agreement) and on
May 29, 2009, the Company entered into a Fourth Amendment
to Amended and Restated Credit Agreement (the Fourth
Amendment to Credit Agreement).
Interest accrues on the Original Term Loan, and accrued on the
Additional Term Loan, at either LIBOR plus 10% (with a LIBOR
floor of 3.5%) or the base rate plus 9.0%. The base rate varies
daily and is generally the higher of the federal funds rate plus
0.50%, RBCs prime rate or LIBOR plus 2.5% (but without the
LIBOR floor). The Original Term Loan may be prepaid without any
premium or penalty, at any time.
The Original Term Loan is payable in quarterly installments of
$1.5 million on the last business day of each March, June,
September and December commencing on September 30, 2008,
with the remaining principal amount being payable in full on
July 11, 2010. As discussed in the next paragraph, the
Company has prepaid all of the quarterly principal payment
requirements of $1.5 million through June 30, 2009 and
therefore has no quarterly principal payments due until
September 30, 2009; however the Company does not anticipate
being able to make this payment. If the outstanding amount of
the Original Term Loan is at any time more than 50% of the
market value of the Companys partnership interests in
Quest Midstream and Quest Energy pledged to secure the loan plus
the value of the Companys Oil and Gas Properties (as
defined in the Credit Agreement) pledged to secure the loan, the
Company will be required to either repay the term loan by the
amount of such excess or pledge additional assets to secure the
term loan.
As part of the Second Amendment to Credit Agreement, the Company
agreed to apply any net cash proceeds from a sale of assets or a
sale of equity interests in certain subsidiaries as follows:
first, to repay any amounts borrowed under the Additional Term
Loan (this was done on October 30, 2008); second, to prepay
the next three quarterly principal payments due on the Original
Term Loan on the last business day of December 2008, March 2009
and June 2009 (this was done in October and November 2008);
third, subject to certain conditions being met and the net cash
proceeds being received by January 31, 2009, up to
$20 million for the Companys own use for working
capital and to make capital expenditures for the development of
its Oil and Gas Properties; and fourth, any excess net cash
proceeds to repay the Original Term Loan. The Third Amendment to
Credit Agreement provided that in connection with the sale of
the Companys Lycoming County, Pennsylvania acreage in
February 2009, the
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Company could retain all of the net proceeds from such sale in
excess of $750,000. The Company will be required to apply all of
the net cash proceeds from the issuance of any debt and 50% of
the net cash proceeds from the sale of any equity securities to
first repay the Original Term Loan and then to the Company.
The Second Amendment to Credit Agreement also amended
and/or
waived certain of the representations and covenants contained in
the Credit Agreement in order to rectify any possible covenant
violations or non-compliance with the representations and
warranties as a result of (1) the Transfers and
(2) not timely settling certain intercompany accounts among
QRCP, Quest Energy and Quest Midstream. The Fourth Amendment to
Credit Agreement, among other things, waived certain events of
default related to the financial covenants and collateral
requirements under the Credit Agreement, extended certain
financial reporting deadlines and permitted the settlement
agreements with Mr. Cash discussed elsewhere in this Annual
Report on
Form 10-K.
Quest Oil & Gas, LLC (QOG), Quest Energy
Service, LLC (QES), Quest Mergersub, Inc. and Quest
Eastern guarantee all of the Companys obligations under
the Credit Agreement. The Credit Agreement is secured by a first
priority lien on QRCPs ownership interests in Quest Energy
and Quest Midstream and their general partners and the Oil and
Gas Properties owned by Quest Eastern in the Appalachian Basin,
which are substantially all of QRCPs assets. The assets of
each of Quest Midstream GP, Quest Midstream and each of their
subsidiaries and Quest Energy GP, Quest Energy and each of their
subsidiaries (collectively the Excluded MLP
Entities) are not pledged to secure the Credit Agreement.
The Credit Agreement provides that all obligations arising under
the loan documents, including obligations under any hedging
agreement entered into with lenders or their affiliates, will be
secured
pari passu
by the liens granted under the loan
documents.
At December 31, 2008, $29 million was outstanding
under the Original Term Loan. The Additional Term Loan was
repaid on October 30, 2008.
The Company and its subsidiaries (excluding the Excluded MLP
Entities) are required to make certain representations and
warranties that are customary for a credit agreement of this
type. The agreement also contains affirmative and negative
covenants that are customary for credit agreements of this type,
including, without limitation, periodic delivery of financial
statements and other financial information, notice of defaults
and certain other matters; payment of obligations; preservation
of legal existence and good standing; maintenance of assets and
business; maintenance of insurance; compliance with laws and
contractual obligations; maintenance of books and records;
inspection rights; limitations on use of proceeds; execution of
guaranties by subsidiaries; perfecting security interests in
after-acquired property; maintenance of fiscal year; certain
limitations on liens, investments, hedging agreements,
indebtedness, lease obligations, fundamental changes,
dispositions of assets, restricted payments, distributions and
redemptions, nature of business, capital expenditures and risk
management, transactions with affiliates, and burdensome
agreements; and compliance with financial covenants.
The Credit Agreements financial covenants prohibit the
Company and any of its subsidiaries (excluding the Excluded MLP
Entities) from:
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permitting the interest coverage ratio (ratio of consolidated
EBITDA (or consolidated annualized EBITDA for periods ending on
or before December 31, 2008) to consolidated interest
charges (or consolidated annualized interest charges for periods
ending on or before December 31, 2008)) at any fiscal
quarter-end, commencing with the quarter-ended
September 30, 2008, to be less than 2.5 to 1.0 (calculated
based on the most recently delivered compliance
certificate); and
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permitting the leverage ratio (ratio of consolidated funded debt
to consolidated EBITDA (or consolidated annualized EBITDA for
periods ending on or before December 31, 2008)) at any
fiscal quarter-end, commencing with the quarter-ended
September 30, 2008, to be greater than 2.0 to 1.0
(calculated based on the most recently delivered compliance
certificate).
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Consolidated EBITDA is defined in the Credit Agreement to mean
for the Company and its subsidiaries (excluding the Excluded MLP
Entities) on a consolidated basis, an amount equal to the sum of
(i) consolidated net income, (ii) consolidated
interest charges, (iii) the amount of taxes, based on or
measured by income, used or included in the determination of
such consolidated net income, (iv) the amount of
depreciation, depletion and
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amortization expense deducted in determining such consolidated
net income, (v) merger and acquisition costs incurred by
the Company that are required to be expensed as a result of the
termination of the merger agreement with Pinnacle Gas Resources,
Inc., (vi) merger and acquisition costs required to be
expensed under FAS 141(R), (vii) fees and expenses of
the internal investigation relating to the Misappropriation
Transaction (as defined in the First Amendment to Credit
Agreement) and the related restructuring which were capped at
$1,500,000 for purposes of this definition and (viii) other
non-cash charges and expenses deducted in the determination of
such consolidated net income, including, without limitation,
non-cash charges and expenses relating to swap contracts or
resulting from accounting convention changes, of the Company and
its subsidiaries (excluding the Excluded MLP Entities) on a
consolidated basis, all determined in accordance with GAAP.
Consolidated annualized EBITDA means, for the Company and its
subsidiaries (excluding the Excluded MLP Entities) on a
consolidated basis, (i) for the fiscal quarter ended
September 30, 2008, consolidated EBITDA for the nine month
period ended September 30, 2008 multiplied by 1.33, and
(ii) for the fiscal quarter ended December 31, 2008,
consolidated EBITDA for the twelve month period ended
December 31, 2008.
Consolidated interest charges is defined to mean for the Company
and its subsidiaries (excluding the Excluded MLP Entities) on a
consolidated basis, the sum of (i) all interest, premium
payments, fees, charges and related expenses of the Company and
its subsidiaries (excluding the Excluded MLP Entities) in
connection with indebtedness (net of interest rate swap contract
settlements) (including capitalized interest), in each case to
the extent treated as interest in accordance with GAAP, and
(ii) the portion of rent expense of the Company and its
subsidiaries (excluding the Excluded MLP Entities) with respect
to any period under capital leases that is treated as interest
in accordance with GAAP.
Consolidated annualized interest charges means, for the Company
and its subsidiaries (excluding the Excluded MLP Entities) on a
consolidated basis, (i) for the fiscal quarter ended
September 30, 2008, consolidated interest charges for the
nine month period ended September 30, 2008 multiplied by
1.33, and (ii) for the fiscal quarter ended
December 31, 2008, consolidated interest charges for the
twelve month period ended December 31, 2008.
Consolidated funded debt means, for the Company and its
subsidiaries (excluding the Excluded MLP Entities) on a
consolidated basis, the sum of (i) the outstanding
principal amount of all obligations and liabilities, whether
current or long-term, for borrowed money (including obligations
under the Credit Agreement), (ii) all reimbursement
obligations relating to letters of credit that have been drawn
and remain unreimbursed, (iii) attributable indebtedness
pertaining to capital leases, (iv) attributable
indebtedness pertaining to synthetic lease obligations, and
(v) without duplication, all guaranty obligations with
respect to indebtedness of the type specified in
subsections (i) through (iv) above.
Events of default under the Credit Agreement are customary for
transactions of this type and include, without limitation,
non-payment of principal when due, non-payment of interest, fees
and other amounts for a period of three business days after the
due date, failure to perform or observe covenants and agreements
(subject to a
30-day
cure
period in certain cases), representations and warranties not
being correct in any material respect when made, cross-defaults
to other material indebtedness, certain acts of bankruptcy or
insolvency, and change of control. Under the Credit Agreement, a
change of control means the acquisition by any person, or two or
more persons acting in concert, of beneficial ownership (within
the meaning of
Rule 13d-3
of the SEC under the Securities Exchange Act of 1934) of
50% or more of the Companys outstanding shares of voting
stock; provided, however, that a merger of the Company into
another entity in which the other entity is the survivor will
not be deemed a change of control if the Companys
stockholders of record as constituted immediately prior to such
acquisition hold more than 50% of the outstanding shares of
voting stock of the surviving entity.
Quest Energy.
On November 15, 2007, Quest
Energy, as a guarantor, entered into an Amended and Restated
Credit Agreement (the Quest Cherokee Credit
Agreement) with the Company, as the initial co-borrower,
Quest Cherokee, as the borrower, RBC, as administrative agent
and collateral agent, KeyBank National Association, as
documentation agent and the lenders party thereto. Quest
Cherokee and the Company had previously been parties to the
following credit agreements with Guggenheim Corporate Funding,
LLC (Guggenheim): (i) Amended and Restated
Senior Credit Agreement, dated February 7, 2006, as
amended; (ii) Amended and Restated Second Lien Term Loan
Agreement, dated June 9, 2006, as amended; and
(iii) Third Lien Term Loan Agreement, dated June 9,
2006, as amended (collectively, the Prior Credit
Agreements). Guggenheim and the lenders under the Prior
Credit
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Agreements assigned all of their interests and rights (other
than certain excepted interests and rights) in the Prior Credit
Agreements to RBC and the new lenders under the Quest Cherokee
Credit Agreement pursuant to a Loan Transfer Agreement, dated
November 15, 2007, by and among the Company, Quest
Cherokee, QOG, QES, Quest Cherokee Oilfield Service, LLC
(QCOS), Guggenheim, Wells Fargo Foothill, Inc., the
lenders under the Prior Credit Agreements and RBC. The Quest
Cherokee Credit Agreement amended and restated the Prior Credit
Agreements in their entirety. In connection with the closing of
the initial public offering and the application of the net
proceeds thereof, the Company was released as a borrower under
the Quest Cherokee Credit Agreement. On April 15, 2008,
Quest Energy and Quest Cherokee entered into a First Amendment
to Amended and Restated Credit Agreement that, among other
things, amended the interest rate and maturity date pursuant to
the market flex rights contained in the commitment
papers related to the Quest Cherokee Credit Agreement.
The credit facility under the Quest Cherokee Credit Agreement,
as amended, consists of a three-year $250 million revolving
credit facility. Availability under the revolving credit
facility is tied to a borrowing base that will be redetermined
by RBC and the lenders every six months taking into account the
value of Quest Cherokees proved reserves. In addition,
Quest Cherokee and RBC each have the right to initiate a
redetermination of the borrowing base between each six-month
redetermination. As of December 31, 2008, the borrowing
base was $190 million, and the amount borrowed under the
Quest Cherokee Credit Agreement was $189 million. No
amounts were available for borrowing because the remaining
$1.0 million was supporting letters of credit issued under
the Quest Cherokee Credit Agreement.
Quest Cherokee will pay a quarterly revolving commitment fee
equal to 0.30% to 0.50% (depending on the utilization
percentage) of the actual daily amount by which the lesser of
the aggregate revolving commitment and the borrowing base
exceeds the sum of the outstanding balance of borrowings and
letters of credit under the revolving credit facility.
During the Transition Period (as defined in the Quest Cherokee
Credit Agreement, as amended), interest will accrue at either
LIBOR plus 4.0% or the base rate plus 3.0%. After the Transition
Period ends, interest will accrue at either LIBOR plus a margin
ranging from 2.75% to 3.375% (depending on the utilization
percentage) or the base rate plus a margin ranging from 1.75% to
2.375% (depending on the utilization percentage). The base rate
varies daily and is generally the higher of the federal funds
rate plus 0.50%, RBCs prime rate or LIBOR plus 1.25%. The
Transition Period will generally end once the repayment of the
Second Lien Loan Agreement (discussed below) has occurred.
On July 11, 2008, concurrent with Quest Energys
acquisition of 32.9 Bcfe of proved developed reserves in the
Appalachian Basin from the Company, Quest Energy and Quest
Cherokee entered into a Second Lien Senior Term Loan Agreement
(the Second Lien Loan Agreement, together with the
Quest Cherokee Credit Agreement, as amended, the Quest
Cherokee Agreements) for a six-month, $45 million
term loan. The Second Lien Loan Agreement is among Quest
Cherokee, as the borrower, Quest Energy as a guarantor, RBC, as
administrative agent and collateral agent, KeyBank National
Association, as syndication agent, Société
Générale, as documentation agent, and the lenders
party thereto.
On October 28, 2008, Quest Energy and Quest Cherokee
entered into a First Amendment to Second Lien Loan Agreement
(the First Amendment to Second Lien Loan Agreement)
to, among other things, extend the maturity date to
September 30, 2009 and to amend
and/or
waive
certain of the representations and covenants contained in the
Second Lien Loan Agreement in order to rectify any possible
covenant violations or non-compliance with the representations
and warranties as a result or (1) the Transfers and
(2) not timely settling certain intercompany accounts among
QRCP, Quest Energy and Quest Midstream. At the same time, a
Second Amendment to the Quest Cherokee Credit Agreement was
entered into to amend
and/or
waive
certain of the representations and covenants contained in the
Second Lien Loan Agreement in order to rectify any possible
covenant violations or non-compliance with the representations
and warranties as a result of (1) the Transfers and
(2) not timely settling certain intercompany accounts among
QRCP, Quest Energy and Quest Midstream.
The First Amendment to Second Lien Loan Agreement requires Quest
Cherokee to make repayments of principal in quarterly
installments of $3.8 million on the 15th day of each
February, May, August and November while amounts borrowed under
the Second Lien Loan Agreement are outstanding. As of
December 31, 2008, $41.2 million was outstanding under
the Second Lien Loan Agreement.
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Interest accrues on the term loan at either LIBOR plus 9.0%
(with a LIBOR floor of 3.5%) or the base rate plus 8.0%. The
base rate varies daily and is generally the higher of the
federal funds rate plus 0.5%, RBCs prime rate or LIBOR
plus 1.25%. The term loan may be prepaid without any premium or
penalty, at any time.
Subject to certain restrictions, Quest Cherokee and its
subsidiaries are required to apply all net cash proceeds from
sales of assets that yield gross proceeds of over
$5 million to repay the term loan. Under the terms of the
Second Lien Loan Agreement, Quest Energy is required by
June 30, 2009 to (i) complete a private placement of
its equity securities or debt, (ii) engage one or more
investment banks reasonably satisfactory to RBC Capital Markets
to publicly sell or privately place common equity securities or
debt of Quest Energy, which offering must close prior to
August 14, 2009 (the deadline for closing and funding the
securities offering may be extended up until September 30,
2009) or (iii) engage RBC Capital Markets to arrange
financing to refinance the term loan under the Second Lien Loan
Agreement on the prevailing terms in the credit market.
The Quest Cherokee Agreements restrict the amount of quarterly
distributions Quest Energy may declare and pay to its
unitholders to not exceed $0.40 per common unit per quarter as
long as the term loan has not been paid in full. Further, after
giving effect to each quarterly distribution, Quest Energy and
Quest Cherokee must be in compliance with a financial covenant
that prohibits each of Quest Cherokee, Quest Energy or any of
their respective subsidiaries from permitting Available
Liquidity (as defined in the Quest Cherokee Agreements) to be
less than $14 million at March 31, 2009 and to be less
than $20 million at June 30, 2009. The
$3.8 million quarterly principal payments discussed above
must also be paid before any distributions may be paid. Quest
Cherokees capital expenditures are limited to
$30 million for 2009.
Quest Energy and QCOS guarantee all of Quest Cherokees
obligations under the Quest Cherokee Agreements. The revolving
credit facility is secured by a first priority lien on
substantially all of the assets of Quest Energy, Quest Cherokee
and QCOS. The term loan is secured by a second priority lien on
substantially all of the assets of Quest Energy, Quest Cherokee
and QCOS.
The Quest Cherokee Agreements provide that all obligations
arising under the loan documents, including obligations under
any hedging agreement entered into with lenders or their
affiliates, will be secured
pari passu
by the liens
granted under the loan documents.
Quest Energy, Quest Cherokee, Quest Energy GP and their
subsidiaries are required to make certain representations and
warranties that are customary for credit agreements of these
types. The Quest Cherokee Agreements also contain affirmative
and negative covenants that are customary for credit agreements
of these types. The covenants in the Quest Cherokee Agreements
include, without limitation, periodic delivery of financial
statements and other financial information; notice of defaults
and certain other matters; payment of obligations; preservation
of legal existence and good standing; maintenance of assets and
business; maintenance of insurance; compliance with laws and
contractual obligations; maintenance of books and records;
inspection rights; limitations on use of proceeds; execution of
guaranties by subsidiaries; perfecting security interests in
after-acquired property; curing title defects; maintaining
material leases; operation of properties; notification of change
of purchasers of production; maintenance of fiscal year; certain
limitations on liens, investments, hedging agreements,
indebtedness, lease obligations, fundamental changes,
dispositions of assets, restricted payments, distributions and
redemptions, nature of business, capital expenditures and risk
management, transactions with affiliates, and burdensome
agreements; and compliance with financial covenants.
The Quest Cherokee Agreements financial covenants prohibit
Quest Cherokee, Quest Energy and any of their subsidiaries from:
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permitting the ratio (calculated based on the most recently
delivered compliance certificate) of Quest Energys
consolidated current assets (including the unused availability
under the revolving credit facility, but excluding non-cash
assets under FAS 133) to consolidated current
liabilities (excluding non-cash obligations under FAS 133,
asset and asset retirement obligations and current maturities of
indebtedness under the Quest Cherokee Credit Agreement) at any
fiscal quarter-end to be less than 1.0 to 1.0; provided,
however, that current assets and current liabilities will
exclude mark-to-market values of swap contracts, to the extent
such values are included in current assets and current
liabilities;
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permitting the interest coverage ratio (calculated on the most
recently delivered compliance certificate) of adjusted
consolidated EBITDA to consolidated interest charges at any
fiscal quarter-end to be less than 2.5 to 1.0 measured on a
rolling four quarter basis; and
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permitting the leverage ratio (calculated based on the most
recently delivered compliance certificate) of consolidated
funded debt to adjusted consolidated EBITDA at any fiscal
quarter-end to be greater than 3.5 to 1.0 measured on a rolling
four quarter basis.
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The Second Lien Loan Agreement contains an additional financial
covenant that prohibits Quest Cherokee, Quest Energy and any of
their subsidiaries from permitting the total reserve leverage
ratio (ratio of total proved reserves to consolidated funded
debt) at any fiscal quarter-end (calculated based on the most
recently delivered compliance certificate) to be less than 1.5
to 1.0.
Adjusted consolidated EBITDA is defined in the Quest Cherokee
Agreements to mean the sum of (i) consolidated EBITDA plus
(ii) the distribution equivalent amount (for each fiscal
quarter of Quest Energy, the amount of cash paid to the members
of Quest Energy GPs management group and non-management
directors with respect to restricted common units, bonus units
and/or
phantom units of Quest Energy that are required under GAAP to be
treated as compensation expense prior to vesting (and which,
upon vesting, are treated as limited partner distributions under
GAAP)).
Consolidated EBITDA is defined in the Quest Cherokee Agreements
to mean for Quest Energy and its subsidiaries on a consolidated
basis, an amount equal to the sum of (i) consolidated net
income, (ii) consolidated interest charges, (iii) the
amount of taxes, based on or measured by income, used or
included in the determination of such consolidated net income,
(iv) the amount of depreciation, depletion and amortization
expense deducted in determining such consolidated net income,
(v) acquisition costs required to be expensed under
FAS 141(R), (vi) fees and expenses of the internal
investigation relating to the Misappropriation Transaction and
the related restructuring (which shall be capped at $1,500,000
for purposes of this definition), and (vii) other non-cash
charges and expenses, including, without limitation, non-cash
charges and expenses relating to swap contracts or resulting
from accounting convention changes, of Quest Energy and its
subsidiaries on a consolidated basis, all determined in
accordance with GAAP.
Consolidated interests charges is defined to mean for Quest
Energy and its subsidiaries on a consolidated basis, the excess
of (i) the sum of (a) all interest, premium payments,
fees, charges and related expenses of Quest Energy and its
subsidiaries in connection with indebtedness (net of interest
rate swap contract settlements) (including capitalized
interest), in each case to the extent treated as interest in
accordance with GAAP, and (b) the portion of rent expense
of Quest Energy and its subsidiaries with respect to such period
under capital leases that is treated as interest in accordance
with GAAP over (ii) all interest income for such period.
Consolidated funded debt is defined to mean for Quest Energy and
its subsidiaries on a consolidated basis, the sum of
(i) the outstanding principal amount of all obligations and
liabilities, whether current or long-term, for borrowed money
(including obligations under the Quest Cherokee Agreements, but
excluding all reimbursement obligations relating to outstanding
but undrawn letters of credit), (ii) attributable
indebtedness pertaining to capital leases,
(iii) attributable indebtedness pertaining to synthetic
lease obligations, and (iv) without duplication, all
guaranty obligations with respect to indebtedness of the type
specified in subsections (i) through (iii) above.
Events of default under the Quest Cherokee Agreements are
customary for transactions of this type and include, without
limitation, non-payment of principal when due, non-payment of
interest, fees and other amounts for a period of three business
days after the due date, failure to perform or observe covenants
and agreements (subject to a
30-day
cure
period in certain cases), representations and warranties not
being correct in any material respect when made, certain acts of
bankruptcy or insolvency, cross defaults to other material
indebtedness, borrowing base deficiencies, and change of
control. Under the Quest Cherokee Agreements, a change of
control means (i) the Company fails to own or to have
voting control over at least 51% of the equity interest of Quest
Energy GP, (ii) any person acquires beneficial ownership of
51% or more of the equity interest in Quest Energy;
(iii) Quest Energy fails to own 100% of the equity
interests in Quest Cherokee, or (iv) the Company undergoes
a change in control (the acquisition by a person, or two or more
persons acting in concert, of beneficial ownership of 50% or
more of the Companys outstanding shares of voting stock,
except for a merger with and into another entity where
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the other entity is the survivor if the Companys
stockholders of record immediately preceding the merger hold
more than 50% of the outstanding shares of the surviving entity).
Quest Midstream.
Quest Midstream and its
wholly-owned subsidiary, Bluestem, have a separate
$135 million syndicated revolving credit facility. On
November 1, 2007, Quest Midstream and Bluestem entered into
an Amended and Restated Credit Agreement and First Amendment to
Amended and Restated Credit Agreement (together, the Quest
Midstream Credit Agreement) with RBC, as administrative
agent and collateral agent, and the lenders party thereto. On
October 28, 2008, Quest Midstream and Bluestem entered into
a Second Amendment to the Quest Midstream Credit Agreement (the
Quest Midstream Second Amendment). The Quest
Midstream Credit Agreement together with the Quest Midstream
Second Amendment are referred to collectively as the
Amended Quest Midstream Credit Agreement. As of
December 31, 2008, the amount borrowed under the Amended
Quest Midstream Credit Agreement was $128 million.
The Quest Midstream Second Amendment, among other things,
amended
and/or
waived certain of the representations and covenants contained in
the Quest Midstream Credit Agreement in order to rectify any
possible covenant violations or non-compliance with the
representations and warranties as a result of (1) the
Transfers and (2) not timely settling certain intercompany
accounts among QRCP, Quest Energy and Quest Midstream.
Quest Midstream and Bluestem may, from time to time, request an
increase in the $135 million commitment by an amount in the
aggregate not exceeding $75 million. However, the lenders
are under no obligation to increase the revolving credit
facility upon such request.
Quest Midstream and Bluestem will pay a quarterly revolving
commitment fee equal to 0.375% to 0.50% (depending on the total
leverage ratio) on the difference between $135 million and
the outstanding balance of borrowings and letters of credit
under the revolving credit facility.
During the Transition Period (as defined in the Amended Quest
Midstream Credit Agreement), interest will accrue on the
revolving credit facility at either LIBOR plus 4% or the base
rate plus 3.0%. After the Transition Period ends, interest will
accrue at either LIBOR plus a margin ranging from 2.0% to 3.50%
(depending on the total leverage ratio) or the base rate plus a
margin ranging from 1.0% to 2.5% (depending on the total
leverage ratio), at our option. The base rate is generally the
higher of the federal funds rate plus 0.50%, RBCs prime
rate or LIBOR plus 1.25%. The Transition Period ended on
March 31, 2009 when Quest Midstream audited financial
statements for 2008 were delivered to RBC.
If the total leverage ratio is greater than 4.5 to 1.0 for any
fiscal quarter ending on or after December 31, 2008, Quest
Midstream and Bluestem must prepay the revolving loans in an
amount equal to 75% of Excess Cash Flow (as defined in the
Amended Quest Midstream Credit Agreement) for such fiscal
quarter. Additionally, the lenders revolving commitment
will be temporarily reduced dollar for dollar by the amount of
any such prepayment. Once the total leverage ratio is less than
4.0 to 1.0 at the end of any fiscal quarter, any reductions in
the revolving commitments will be reinstated and no further
prepayments will be required.
The Amended Quest Midstream Credit Agreement places limitations
on capital expenditures for each of Quest Midstream and Bluestem
as follows: (i) $5 million for the fourth fiscal
quarter of 2008; (ii) $7 million for the first fiscal
quarter of 2009; (iii) $7 million for the second
fiscal quarter of 2009; (iv) $3 million for the third
fiscal quarter of 2009; and (v) $3 million for the
fourth fiscal quarter of 2009.
The Amended Quest Midstream Credit Agreement restricts Quest
Midstreams ability to make distributions on its units
unless the total leverage ratio is not greater than 4.0 to 1.0
after giving effect to the quarterly distribution.
Quest Kansas General Partner, Quest Kansas Pipeline, and Quest
KPC guarantee all of Quest Midstreams and Bluestems
obligations under the Amended Quest Midstream Credit Agreement.
The revolving credit facility is secured by a first priority
lien on substantially all of the assets of Quest Midstream and
Bluestem and their subsidiaries (including the KPC Pipeline).
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The Amended Quest Midstream Credit Agreement provides that all
obligations arising under the loan documents, including
obligations under any hedging agreement entered into with
lenders or their affiliates, will be secured
pari passu
by the liens granted under the loan documents.
Bluestem, Quest Midstream and their subsidiaries are required to
make certain representations and warranties that are customary
for credit agreements of this type. The Amended Quest Midstream
Credit Agreement also contains affirmative and negative
covenants that are customary for credit agreements of this type.
The covenants in the Amended Quest Midstream Credit Agreement
include, without limitation, delivery of financial statements
and other financial information; notice of defaults and certain
other matters; payment of obligations; preservation of legal
existence and good standing; maintenance of assets and business;
maintenance of insurance; compliance with laws and contractual
obligations; maintenance of books and records; permit inspection
rights; use of proceeds; execution of guaranties by
subsidiaries; perfecting security interests in after-acquired
property; maintenance of fiscal year; limitations on liens;
limitations on investments; limitation on hedging agreements;
limitations on indebtedness; limitations on lease obligations;
limitations on fundamental changes; limitations on dispositions
of assets; limitations on restricted payments, distributions and
redemptions; limitations on nature of business, capital
expenditures and risk management; limitations on transactions
with affiliates; limitations on burdensome agreements; and
compliance with financial covenants.
The Amended Quest Midstream Credit Agreements financial
covenants prohibit Bluestem, Quest Midstream and any of their
subsidiaries from:
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permitting the interest coverage ratio (ratio of adjusted
consolidated EBITDA to consolidated interest charges) on a
rolling four quarter basis (calculated based on the most
recently delivered compliance certificate), commencing with the
fiscal quarter ending December 31, 2007, to be less than
2.50 to 1.00 for any fiscal quarter ending on or prior to
December 31, 2008, increasing to 2.75 to 1.00 for each
fiscal quarter end thereafter; and
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permitting the total leverage ratio (ratio of adjusted
consolidated funded debt to adjusted consolidated EBITDA) on a
rolling four quarter basis (calculated based on the most
recently delivered compliance certificate), commencing with the
fiscal quarter ending December 31, 2007 and ending
December 31, 2008, to be greater than 5.00 to 1.00,
decreasing to 4.50 to 1.00 for each fiscal quarter end
thereafter.
|
Adjusted consolidated EBITDA is defined in the Amended Quest
Midstream Credit Agreement to mean the sum of
(i) consolidated EBITDA plus (ii) the distribution
equivalent amount (for each fiscal quarter of Quest Midstream,
the amount of cash paid to the members of Quest Midstream
GPs management group and non-management directors with
respect to restricted common units, bonus units
and/or
phantom units of Quest Midstream that are required under GAAP to
be treated as compensation expense prior to vesting (and which,
upon vesting, are treated as limited partner distributions under
GAAP)).
Consolidated EBITDA is defined in the Amended Quest Midstream
Credit Agreement for Quest Midstream and its subsidiaries on a
consolidated basis, an amount equal to the sum of
(i) consolidated net income, (ii) consolidated
interest charges, (iii) the amount of taxes, based on or
measured by income, used or included in the determination of
consolidated net income, (iv) the amount of depreciation,
depletion and amortization expense deducted in determining
consolidated net income, (v) merger and acquisition costs
required to be expensed under FAS 141(R), (vi) fees
and expenses of the internal investigation relating to the
Misappropriation Transaction and the related restructuring which
are capped at $1,500,000 for purposes of the definition of
Consolidated EBITDA and (vii) other non-cash charges and
expenses, including, without limitation, non-cash charges and
expenses related to swap contracts or resulting from accounting
convention changes, of Quest Midstream and its subsidiaries on a
consolidated basis, all determined in accordance with GAAP.
Consolidated interest charges is defined to mean for Quest
Midstream and its subsidiaries on a consolidated basis, the sum
of (i) all interest, premium payments, fees, charges and
related expenses of Quest Midstream and its subsidiaries in
connection with indebtedness (net of interest rate swap contract
settlements) (including capitalized interest and net of any
write-off of debt issuance costs), in each case to the extent
treated as interest in accordance with GAAP, and (ii) the
portion of rent expense of Quest Midstream and its subsidiaries
with respect to such period under capital leases that is treated
as interest in accordance with GAAP.
102
Consolidated net income is defined to mean for Quest Midstream
and its subsidiaries on a consolidated basis, the net income or
net loss of Quest Midstream and its subsidiaries from continuing
operations, excluding: (i) the income (or loss) of any
entity other than a subsidiary, except to the extent that any
such income has been actually received by Quest Midstream or
such subsidiary in the form of cash dividends or similar cash
distributions; (ii) extraordinary gains and losses;
(iii) any gains or losses attributable to non-cash
write-ups
or
write-downs of assets; (iv) proceeds of any insurance on
property, plant or equipment other than business interruption
insurance; (v) any gain or loss, net of taxes, on the sale,
retirement or other disposition of assets; and (vi) the
cumulative effect of a change in accounting principles.
Bluestem and Quest Midstream are required during each calendar
year to have at least 15 consecutive days during which there are
no revolving loans outstanding for the purpose of financing
working capital or funding quarterly distributions of Quest
Midstream.
Events of default under the Amended Quest Midstream Credit
Agreement are customary for transactions of this type and
include, without limitation, non-payment of principal when due,
non-payment of interest, fees and other amounts for a period of
three business days after the due date, failure to perform or
observe covenants and agreements (subject to a
30-day
cure
period in certain cases), representations and warranties not
being correct in any material respect when made, certain acts of
bankruptcy or insolvency, cross defaults to other material
indebtedness, and change of control. Under the Quest Midstream
Credit Agreement a change of control means (i) the Company
fails to own or to have voting control over, at least 51% of the
equity interest of Quest Midstream GP; (ii) any person
acquires beneficial ownership of 51% or more of the equity
interest in Quest Midstream; (iii) Quest Midstream fails to
own 100% of the equity interests in Bluestem or (iv) the
Company undergoes a change in control (the acquisition by a
person, or two or more persons acting in concert, of beneficial
ownership of 50% or more of the Companys outstanding
shares of voting stock, except for a merger with and into
another entity where the other entity is the survivor if the
Companys stockholders of record immediately preceding the
merger hold more than 50% of the outstanding shares of the
surviving entity).
Sources
of Liquidity in 2009 and Capital Requirements
Quest Resource.
Since the initial public
offering of Quest Energy in November 2007, QRCPs potential
sources of revenue and cash flows consist almost exclusively of
distributions on its partnership interests in Quest Energy and
Quest Midstream, because its Appalachian assets largely consist
of undeveloped acreage. While QRCP has historically been
successful in raising additional funds through issuing equity
securities and proceeds from borrowings, in the current capital
markets, we do not expect QRCP to be able to raise any funds
through the issuance of debt or equity under our current
organizational structure.
Quest Energy is required by its partnership agreement to
distribute all its cash on hand at the end of each quarter, less
reserves established by its general partner in its sole
discretion to provide for the proper conduct of Quest
Energys business or to provide for future distributions.
Through QRCPs ownership of Quest Energy GP, it also owns
the incentive distribution rights in Quest Energy, which would
entitle it to receive an increasing percentage of cash
distributed by Quest Energy as certain target distribution
levels are reached. Specifically, they entitle QRCP to receive
13.0% of all cash distributed in a quarter after each unit has
received $0.46 for that quarter, and 23.0% of all cash
distributed after each unit has received $0.50 for that quarter.
Quest Energy has not paid any quarterly distributions in excess
of the first target distribution level, and as a result, QRCP
has not received any incentive distributions.
Quest Energy paid quarterly distributions at or slightly above
the $0.40 per unit minimum quarterly distribution amount on all
of its units for the fourth quarter of 2007 (pro rated) and the
first and second quarters of 2008. It paid the $0.40 minimum
quarterly distribution amount on only its common units for the
third quarter of 2008 and has not paid any distributions on any
of its units for any subsequent periods.
Quest Energy suspended distributions on its subordinated units
beginning with the third quarter of 2008 as a result of the
amendments to the Quest Cherokee Agreements which required
quarterly payments under its Second Lien Loan Agreement equal to
$3.8 million (the amount of the minimum quarterly
distribution for its subordinated units). Quest Energy suspended
distributions on all of its units beginning with the fourth
quarter of 2008 as a result
103
of a decline in its cash flows from operations due to declines
in oil and natural gas prices during the last half of 2008, the
costs of the investigation and associated remedial actions,
including the reaudit and restatement of its consolidated
financial statements, and concerns about a potential borrowing
base redetermination in the second quarter of 2009 and the need
to repay or refinance the Second Lien Loan Agreement by
September 30, 2009.
The partnership agreement for Quest Midstream contains similar
provisions relating to the distribution of available cash.
However, most of QRCPs interest in Quest Midstream is in
the form of subordinated units and Quest Midstream generally has
not paid any distributions on its subordinated units. As a
result, QRCP has not received any material distributions from
Quest Midstream.
At this time, we are not able to estimate when Quest Midstream
and/or
Quest
Energy will resume the payment of distributions.
In addition, QRCP also receives reimbursements by Quest Energy
and Quest Midstream for general and administrative expenses
incurred by it on their behalf and allocated to them. However,
these reimbursements do not cover all of QRCPs general and
administrative expenses.
In response to the recent developments, QRCP has adjusted its
business strategy for 2009 to focus on negotiating documentation
and other activities necessary to complete the Recombination
while still maintaining a stable asset base, improving the
profitability of its assets by increasing their utilization
while controlling costs and reducing capital expenditures as
discussed elsewhere in this Annual Report on
Form 10-K,
renegotiating with its lenders and possibly raising equity
capital. For 2009, QRCP has budgeted approximately
$2.4 million of net expenditures to drill one gross
vertical well, complete three gross wells and connect four gross
wells in the Appalachian Basin. This one new well will be
drilled on a location that is classified as containing proved
reserves in our December 31, 2008 reserve report. However,
QRCP intends to fund these capital expenditures only to the
extent that it has available cash after taking into account its
debt service and other obligations. We can give no assurance
that any such funds will be available.
As discussed above under Credit
Agreements Quest Resource, QRCP is required to
maintain as of the end of each quarter, an Interest Coverage
Ratio of not less than 2.5 to 1.0 and a Leverage Ratio of no
more than 2.0 to 1.0. As a result of the suspension of the
distributions to QRCP from Quest Energy and Quest Midstream
discussed above, QRCP was not in compliance with these financial
covenants as of December 31, 2008 and March 31, 2009
and QRCP does not anticipate that it will be in compliance at
any time in the foreseeable future. On May 29, 2009, QRCP
obtained a waiver of these defaults from its lenders for the
quarters ended December 31, 2008 and March 31, 2009
and is currently negotiating with its lender to obtain a waiver
of these requirements for future periods. There can be no
assurance that QRCP will be able to obtain such waivers.
Under the terms of the Credit Agreement, QRCP is required to
make quarterly principal payments of $1.5 million. QRCP has
prepaid the quarterly principal payments through and including
June 30, 2009 and its next quarterly principal payment is
due September 30, 2009. QRCP currently does anticipate
being able to make this payment and is negotiating with its
lenders to obtain a waiver. There can be no assurance that QRCP
will be able to obtain such waiver.
Under the terms of the Credit Agreement, the outstanding
principal amount of borrowings may not exceed the sum of
(i) the value of QRCPs oil and gas properties in the
Appalachian Basin (as determined by the administrative agent
under the Credit Agreement in its reasonable discretion) and
(ii) 50% of the market value of QRCPs interests in
Quest Energy and Quest Midstream (such excess is referred to as
a Collateral Deficiency). QRCP is required to make a
mandatory prepayment equal to any such Collateral Deficiency. On
May 29, 2009, QRCP obtained a waiver of this mandatory
prepayment for the quarters ended December 31, 2008,
March 31, 2009 and June 30, 2009. If a Collateral
Deficiency exists after June 30, 2009 that is not waived by
QRCPs lender, QRCP will be required to sell assets, issue
additional equity securities or refinance the Credit Agreement
in order to cure such deficiency. There can be no assurance that
QRCP will be successful in raising sufficient funds to cure such
deficiency in the future. QRCP is currently negotiating with its
lenders to obtain a waiver of this requirement for future
periods. There can be no assurance that QRCP will be able to
obtain such a waiver.
In addition, QRCP failed to timely deliver its 2008 audited
financial statements to its lender. QRCP has received an
extension of this deadline to June 30, 2009.
104
As of December 31, 2008, QRCP had cash and cash equivalents
of $4.0 million and no ability to borrow under the terms of
the Credit Agreement. QRCP currently estimates that it will not
have enough cash to pay its expenses, including capital
expenditures and debt service requirements after August 31,
2009. This date could be extended if QRCP is able to restructure
its debt obligations, issue equity securities
and/or
sell
additional assets. Our independent registered public accounting
firm has expressed doubt about our ability to continue as a
going concern. See Item 1A. Risk Factors
Our independent registered public accounting firm has expressed
substantial doubt about our ability to continue as a going
concern. If QRCP is not successful in obtaining sufficient
additional funds, there is a significant risk that QRCP will be
forced to file for bankruptcy protection.
Quest Energy.
Historically, Quest Energy has
been successful in accessing capital from financial institutions
to fund the growth of its operations and in generating
sufficient cash flow from its operations to satisfy its debt
service requirements, operating expenses, maintenance capital
expenditures and distributions to its unitholders. However, due
to the lack of liquidity in the financial and equity markets
coupled with the significant decline in oil and natural gas
prices in the second half of 2008 and the uncertainties
associated with Quest Energys financial condition as a
result of the matters relating to the internal investigation and
the restatement of our consolidated financial statements, Quest
Energys access to capital has been, and is expected to
continue to be, severely limited in 2009. As a result, Quest
Energy has significantly reduced its growth plans during 2009 in
order to maximize the amount of cash flow from operations that
is available to repay indebtedness.
For 2009, QELP has budgeted approximately $3.8 million to
drill seven new gross wells, connect and complete 49 existing
gross wells, and connect and complete three existing salt water
disposal wells in the Cherokee Basin. All of these wells will be
drilled on locations that are classified as containing proved
reserves in our December 31, 2008 reserve report. In 2009,
QELP plans to recomplete an estimated 10 gross wells, and
has budgeted another $1.9 million for equipment, vehicle
replacement, and other capital purchases. In addition, QELP has
budgeted $2.4 million related to lease renewals and
extensions for Cherokee Basin acreage that is expiring in 2009.
Additionally, QELP has budgeted for 2009 $1.4 million for
artificial lift equipment, vehicle replacement and purchases and
salt water disposal activities in the Appalachian Basin.
However, QELP intends to fund these capital expenditures only to
the extent that QELP has available cash from operations after
taking into account its debt service obligations. We can give no
assurance that any such funds will be available. As discussed
above under Quest Resource, Quest Energy
has suspended distributions on its common and subordinated units
and does not intend to resume distributions until after it has
repaid its Second Lien Loan Agreement, at the earliest.
As discussed above under Credit
Agreements Quest Energy, Quest Energy is
required to be in compliance as of the end of each quarter with
certain financial ratios. As of December 31, 2008, Quest
Energy was in compliance with all of its financial covenants.
Quest Energy is expected to be in compliance with the Total
Reserve Leverage Ratio as of March 31, 2009. However, there
can be no assurance that Quest Energy will be able to remain in
compliance with this ratio in future periods in light of the
significantly reduced capital expenditures program and low
natural gas prices.
In addition, Quest Energy is required to have Available
Liquidity of $14 million and $20 million as of
March 31, 2009 and June 30, 2009, respectively.
Available Liquidity is generally defined in the Quest Cherokee
Agreements as cash and cash equivalents, plus any availability
under its revolving credit facility, plus any reductions in the
principal amount of its Second Lien Loan Agreement in excess of
the $3.8 million required per quarter. Quest Energy is not
anticipated to be in compliance with this covenant as of
June 30, 2009. Quest Energy is currently negotiating with
its lenders to obtain a waiver of this covenant.
As discussed above under Credit
Agreements Quest Energy, the amount available
under the Quest Cherokee Credit Agreement may not exceed a
borrowing base, which is subject to redetermination on a
semi-annual basis. The price of oil and gas has significantly
decreased since the borrowing base was last redetermined. The
lead agent for QELPs credit agreement initially proposed
that QELPs borrowing base be reduced, as part of the
redetermination being made in connection with the delivery of
its year-end reserve report to its lenders, by approximately
$50 million to $140 million. However, the actual
borrowing base may be more or less than this amount. Under the
terms of the Quest Cherokee Credit Agreement, Quest Energy is
required to reduce the amount outstanding under the Quest
Cherokee Credit Agreement by the amount that the outstanding
borrowings exceed the amount of the new borrowing base (which is
referred to as a Borrowing Base Deficiency). Quest
Energy will be
105
required to repay the amount of the Borrowing Base Deficiency in
four equal monthly installments after such amount has been
determined. Quest Energy is currently pursuing various
alternatives, including entering into additional derivative
contracts
and/or
repricing existing derivative contracts in order to reduce the
borrowing base deficiency. There can be no assurance that such
efforts will be successful or that Quest Energy will be able to
repay any remaining amount of the Borrowing Base Deficiency in
accordance with the terms of the Quest Cherokee Credit
Agreement. See Risk Factors Risks Related to
Our Business The QELP borrowing base under its first
lien credit agreement could be redetermined to an amount that
creates a deficiency that QELP does not have the ability to
pay.
Under the terms of Quest Energys Second Lien Loan
Agreement, Quest Energy is required to make quarterly principal
payments of $3.8 million. The next payment is due
August 15, 2009. The balance remaining after such payments
of $29.8 million is due on September 30, 2009. Due to
the likely principal payments required to be made under the
Quest Cherokee Credit Agreement in connection with the Borrowing
Base Deficiency, Quest Energy is currently seeking to
restructure the required principal payments under its Second
Lien Loan Agreement; however, there can be no assurance that
Quest Energy will be successful in restructuring such principal
payments.
Quest Energy is actively pursuing lawsuits against the former
chief financial officer and purchasing manager and others
related to the matters arising out of the investigation. There
can be no assurance that it will be successful in collecting any
amounts in settlement of such claims.
As of May 15, 2009, Quest Energy had $14.6 million of
cash and cash equivalents. Based on our current estimates of
Quest Energys operating and administrative expenses and
budgeted capital expenditures, we anticipate that Quest Energy
would have sufficient resources to satisfy these expenditures
for the foreseeable future, if it can restructure its debt
service obligations discussed above.
Quest Midstream.
Historically, Quest Midstream
has been successful in accessing capital from both the equity
market and financial institutions to fund the growth of its
operations and in generating sufficient cash flow from its
operations to satisfy its debt service requirements, operating
expenses, maintenance capital expenditures and distributions to
its unitholders. However, due to the lack of liquidity in the
financial and equity markets coupled with the leveling off of
production by Quest Energy and the uncertainties associated with
Quest Midstreams financial condition as a result of the
matters relating to the internal investigation and the
restatement of our financial statements, Quest Midstreams
access to capital has been, and is expected to continue to be,
severely limited in 2009. As a result, Quest Midstream has
significantly reduced its growth plans during 2009 in order to
maximize the amount of cash flow from operations that is
available to repay indebtedness. We estimate that our cost for
pipeline infrastructure to connect a Cherokee Basin well will be
approximately $61,000 per well for 2009. If commodity prices
improve, we expect to connect 56 wells in the Cherokee
Basin in 2009.
As discussed above under Quest Resource,
Quest Midstream is restricted from paying distributions on its
common and subordinated units until its leverage ratio is less
than or equal to 4.0 to 1.0. At this time, we are unable to
estimate when Quest Midstream will satisfy this requirement.
As discussed above under Credit
Agreements Quest Midstream, Quest Midstream is
required to be in compliance as of the end of each quarter, with
certain financial ratios. As of December 31, 2008, Quest
Midstream was in compliance with all of its financial covenants.
As of May 15, 2009, Quest Midstream had $3.7 million
of cash and cash equivalents. Based on our current estimates of
Quest Midstreams operating and administrative expenses and
budgeted capital expenditures, we anticipate that Quest
Midstream would have sufficient resources to satisfy its
obligations for the foreseeable future.
Recombination.
In connection with the proposed
Recombination, we intend to enter into a credit facility that
would refinance all of our existing credit agreements. There can
be no assurance that we will be able to obtain such a credit
facility on terms favorable to us, if at all. The lenders for
any such new credit facility may require us to obtain additional
equity capital as a condition to such a new credit facility.
There can be no assurance that we will be able to obtain any
additional equity capital on terms favorable to us, if at all.
106
Contractual
Obligations
We have numerous contractual commitments in the ordinary course
of business, debt service requirements and operating lease
commitments. The following table summarizes these commitments at
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
Less Than
|
|
|
1-3
|
|
|
4-5
|
|
|
More Than
|
|
|
|
Total
|
|
|
1 Year
|
|
|
Years
|
|
|
Years
|
|
|
5 Years
|
|
|
|
(In thousands)
|
|
|
Term Loan Quest Resource
|
|
|
29,000
|
|
|
|
3,000
|
|
|
|
26,000
|
|
|
|
|
|
|
|
|
|
Revolving Credit Facility Quest Energy
|
|
|
189,000
|
|
|
|
|
|
|
|
189,000
|
|
|
|
|
|
|
|
|
|
Term Loan Quest Energy
|
|
|
41,200
|
|
|
|
41,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revolving Credit Facility Quest Midstream
|
|
|
128,000
|
|
|
|
|
|
|
|
|
|
|
|
128,000
|
|
|
|
|
|
Other Note obligations
|
|
|
906
|
|
|
|
813
|
|
|
|
79
|
|
|
|
13
|
|
|
|
1
|
|
Interest expense on bank credit facilities(1)
|
|
|
52,411
|
|
|
|
21,647
|
|
|
|
24,355
|
|
|
|
6,409
|
|
|
|
|
|
Operating lease obligations
|
|
|
14,549
|
|
|
|
4,922
|
|
|
|
3,934
|
|
|
|
3,003
|
|
|
|
2,690
|
|
Financial advisor contracts
|
|
|
2,675
|
|
|
|
675
|
|
|
|
2,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total commitments
|
|
$
|
457,741
|
|
|
$
|
72,257
|
|
|
$
|
245,368
|
|
|
$
|
137,425
|
|
|
$
|
2,691
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The interest payment obligation was computed using the LIBOR
interest rate as of December 31, 2008. Assumes no reduction
in the outstanding principal amount borrowed under the revolving
credit facilities prior to maturity.
|
Off-balance
Sheet Arrangements
At December 31, 2008, 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.
Critical
Accounting Policies
The preparation of our consolidated financial statements
requires us to make assumptions and estimates that affect the
reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the dates of the
consolidated the financial statements and the reported amounts
of revenues and expenses during the reporting periods. We base
our estimates on historical experiences and various other
assumptions that we believe are reasonable; however, actual
results may differ. Our significant accounting policies are
described in Note 2 Summary of Significant
Accounting Policies to our consolidated financial statements
included elsewhere in this Annual Report on
Form 10-K.
We believe the following critical accounting policies affect our
more significant judgments and estimates used in the preparation
of our consolidated financial statements.
Oil and Gas Reserves
Our most significant financial estimates are based on estimates
of proved oil and gas reserves. Proved reserves represent
estimated quantities of oil and gas that geological and
engineering data demonstrate, with reasonable certainty, to be
recoverable in future years from known reservoirs under economic
and operating conditions existing at the time the estimates were
made. There are numerous uncertainties inherent in estimating
quantities of proved reserves and in projecting future revenues,
rates of production, and timing of development expenditures,
including many factors beyond our control. The estimation
process relies on assumptions and interpretations of available
geologic, geophysical, engineering, and production data and, the
accuracy of reserves estimates is a function of the quality and
quantity of available data, engineering and geologic
interpretation, and judgment. In addition, as a result of
changing market conditions, commodity prices and future
development costs will change from year to year, causing
estimates of proved reserves to also change. Estimates of proved
reserves are key components of our most significant financial
estimates involving our unevaluated properties, our rate for
recording depreciation, depletion
107
and amortization and our full cost ceiling limitation. Our
reserves are estimated on an annual basis by independent
petroleum engineers.
In December 2008, the SEC released the final rule for the
Modernization of Oil and Gas Reporting. The
rules disclosure requirements will permit reporting of oil
and gas reserves using an average price based upon the prior
12-month
period rather than year-end prices and the use of new
technologies to determine proved reserves, if those technologies
have been demonstrated to result in reliable conclusions about
reserves volumes. Companies will also be allowed to disclose
probable and possible reserves in SEC filed documents. In
addition, companies will be required to report the independence
and qualifications of its reserves preparer or auditor and file
reports when a third party is relied upon to prepare reserves
estimates or conduct a reserves audit. The rules
disclosure requirements become effective for our Annual Report
on
Form 10-K
for the year ended December 31, 2009. The SEC is
coordinating with the FASB to obtain the revisions necessary to
provide consistency with the new rules. In the event that
consistency is not achieved in time for companies to comply with
the new rules, the SEC will consider delaying the compliance
date. The calculation of reserves using an average price is a
significant change that should reduce the volatility of our
reserve calculation and could impact any potential future
impairments arising from our ceiling test.
Oil and Gas Properties
The method of accounting for oil and natural gas properties
determines what costs are capitalized and how these cost are
ultimately matched with revenues and expenses. We use the full
cost method of accounting for oil and natural gas and oil
properties. Under the full cost method, all direct costs and
certain indirect costs associated with the acquisition,
exploration, and development of our oil and gas properties are
capitalized.
Oil and gas properties are depleted using the
units-of-production method. The depletion expense is
significantly affected by the unamortized historical and future
development costs and the estimated proved oil and gas reserves.
Estimation of proved oil and gas reserves relies on professional
judgment and use of factors that cannot be precisely determined.
Holding all other factors constant, if proved oil and gas
reserves were revised upward or downward, earnings would
increase or decrease, respectively. Subsequent proved reserve
estimates materially different from those reported would change
the depletion expense recognized during the future reporting
period. No gains or losses are recognized upon the sale or
disposition of oil and gas properties unless the sale or
disposition represents a significant quantity of reserves, which
would have a significant impact on the depreciation, depletion,
and amortization rate.
Under the full cost accounting rules, total capitalized costs
are limited to a ceiling equal to the present value of future
net revenues, discounted at 10% per annum, plus the lower of
cost or fair value of unevaluated properties less income tax
effects (the ceiling limitation). We perform a
quarterly ceiling test to evaluate whether the net book value of
our full cost pool exceeds the ceiling limitation. If
capitalized costs (net of accumulated depreciation, depletion,
and amortization) less related deferred taxes are greater than
the discounted future net revenues or ceiling limitation, a
write-down or impairment of the full cost pool is required. A
write-down of the carrying value of our full cost pool is a
non-cash charge that reduces earnings and impacts
stockholders equity in the period of occurrence and
typically results in lower depreciation, depletion, and
amortization expense in future periods. Once incurred, a
write-down is not reversible at a later date. The risk that we
will be required to write down the carrying value of our oil and
gas properties increases when gas prices are depressed, even if
low prices are temporary. In addition, a write-down may occur if
estimates of proved reserves are substantially reduced or
estimates of future development costs increase significantly.
The ceiling test is calculated using natural gas prices in
effect as of the balance sheet date and adjusted for
basis or location differential, held constant over
the life of the reserves. In addition, subsequent to the
adoption of SFAS 143,
Accounting for Asset Retirement
Obligations
, the future cash outflows associated with
settling asset retirement obligations are not included in the
computation of the discounted present value of future net
revenues for the purpose of the ceiling test calculation.
Unevaluated Properties
The costs directly associated with unevaluated properties and
properties under development are not initially included in the
amortization base and relate to unproved leasehold acreage,
seismic data, wells and production
108
facilities in progress and wells pending determination together
with interest costs capitalized for these projects. Unevaluated
leasehold costs are transferred to the amortization base once
determination has been made or upon expiration of a lease.
Geological and geophysical costs associated with a specific
unevaluated property are transferred to the amortization base
with the associated leasehold costs on a specific project basis.
Costs associated with wells in progress and wells pending
determination are transferred to the amortization base once a
determination is made whether or not proved reserves can be
assigned to the property. All items included in our unevaluated
property balance are assessed on a quarterly basis for possible
impairment or reduction in value. Any impairment to unevaluated
properties is transferred to the amortization base. See
Note 21 Supplemental Information on Oil and Gas
Producing Activities (Unaudited) in the notes to the
consolidated financial statements for a summary by year of
unevaluated costs.
Future Abandonment Costs
We have significant legal obligations to plug, abandon and
dismantle existing wells and facilities that we have acquired,
constructed, or developed. Liabilities for asset retirement
obligations are recorded at fair value in the period incurred.
Upon initial recognition of the asset retirement liability, the
asset retirement cost is capitalized by increasing the carrying
amount of the long-lived asset by the same amount as the
liability. Asset retirement costs included in the carrying
amount of the related asset are subsequently allocated to
expense as part of our depletion calculation. Additionally,
increases in the discounted asset retirement liability resulting
from the passage of time are recorded as lease operating expense.
Estimating the future asset retirement liability requires us to
make estimates and judgments regarding timing, existence of a
liability, as well as what constitutes adequate restoration. We
use the present value of estimated cash flows related to our
asset retirement obligations to determine the fair value.
Present value calculations inherently incorporate numerous
assumptions and judgments. These include the ultimate retirement
and restoration costs, inflation factors, credit adjusted
discount rates, timing of settlement, and changes in the legal,
regulatory, environmental and political environments. To the
extent future revisions to these assumptions impact the present
value of the existing assets retirement liability, a
corresponding adjustment will be made to the carrying cost of
the related asset.
We have not recorded any asset retirement obligations relating
to our gathering systems as of December 31, 2008, 2007 and
2006 because we do not have any legal or constructive
obligations relative to asset retirements of the gathering
systems. We have recorded asset retirement obligations relating
to the abandonment of our interstate pipeline assets (see
discussion in Note 9 Asset Retirement
Obligations to the consolidated financial statements).
Derivative Instruments
Due to the historical volatility of oil and natural gas prices,
we have implemented a hedging strategy aimed at reducing the
variability of prices we receive for our production. Currently,
we use collars, fixed-price swaps and fixed price sales
contracts as our mechanism for hedging commodity prices. Our
current derivative instruments are not accounted for as hedges
for accounting purposes in accordance with
SFAS No. 133,
Derivative Instruments and Hedging
Activities
. As a result, we account for our derivative
instruments on a mark-to-market basis, and changes in the fair
value of derivative instruments are recognized as gains and
losses which are included in other income and expense in the
period of change. While we believe that the stabilization of
prices and production afforded us by providing a revenue floor
for our production is beneficial, this strategy may result in
lower revenues than we would have if we were not a party to
derivative instruments in times of rising natural gas prices. As
a result of rising commodity prices, we may recognize additional
charges to future periods; however, for the year ended
December 31, 2008 prices decreased, and we recognized a
total gain on derivative financial instruments in the amount of
$80.7 million, consisting of a $7.3 million realized
gain and a $73.4 million unrealized gain. Our estimates of
fair value are determined by the use of an option-pricing model
that is based on various assumptions and factors including the
time value of options, volatility, and closing NYMEX market
indices.
Revenue Recognition
We derive revenue from our oil and natural gas operations from
the sale of produced oil and natural gas. We use the sales
method of accounting for the recognition of oil and gas revenue.
Because there is a ready market for oil and natural gas, we sell
our oil and natural gas shortly after production at various
pipeline receipt points at which time
109
title and risk of loss transfers to the buyer. Revenue is
recorded when title and risk of loss is transferred based on our
net revenue interests. Oil and gas sold in production operations
is not significantly different from our share of production
based on our interest in the properties.
Settlement of oil and gas sales occur after the month in which
the oil and gas was produced. We estimate and accrue for the
value of these sales using information available at the time the
financial statements are generated. Differences are reflected in
the accounting period that payments are received from the
purchaser.
Revenue from our pipeline operations is recognized at the time
the natural gas is gathered or transported through the system
and delivered to a third party.
Income Taxes
We record our income taxes using an asset and liability approach
in accordance with the provisions of the Statement of Financial
Accounting Standards No. 109,
Accounting for Income
Taxes
(SFAS No. 109). This results in the
recognition of deferred tax assets and liabilities for the
expected future tax consequences of temporary differences
(primarily intangible drilling costs and the net operating loss
carry forward) between the book carrying amounts and the tax
bases of assets and liabilities using enacted tax rates at the
end of the period. Under SFAS No. 109, the effect of a
change in tax rates of deferred tax assets and liabilities is
recognized in the year of the enacted change. Deferred tax
assets are reduced by a valuation allowance when, in the opinion
of management, it is more likely than not that some portion or
all of the deferred tax assets will not be realized.
Estimating the amount of valuation allowance is dependent on
estimates of future taxable income, alternative minimum tax
income, and changes in stockholder ownership that could trigger
limits on use of net operating losses under Internal Revenue
Code section 382. We have a significant deferred tax asset
associated with net operating loss carry-forward (NOLs).
Recent
Accounting Pronouncements
In February 2008, the FASB issued Staff Position
FAS 157-2,
Effective Date of FASB Statement No. 157
(FSP 157-2).
FSP 157-2
delays the effective date of SFAS No. 157 to fiscal
years beginning after November 15, 2008 for all
nonfinancial assets and nonfinancial liabilities, except those
recognized or disclosed at fair value in the financial
statements on a recurring basis, at least annually. We
implemented this standard on January 1, 2009. The adoption
of
FSP 157-2
is not expected to have a material impact on our financial
condition, operations or cash flows.
Effective upon issuance, the FASB issued Staff Position
FAS 157-3,
Determining the Fair Value of a Financial Asset When the
Market for That Asset is Not Active
,
(FSP 157-3)
in October 2008.
FSP 157-3
clarifies the application of SFAS No. 157 in
determining the fair value of a financial asset when the market
for that financial asset is not active. As of December 31,
2008, we had no financial assets with a market that was not
active. Accordingly,
FSP 157-3
is not expect to have an impact on our consolidated financial
statements.
In September 2006, the SEC issued Staff Accounting
Bulletin No. 108 (SAB No. 108).
SAB No. 108 addresses how the effects of prior year
uncorrected misstatements should be considered when quantifying
misstatements in current year financial statements.
SAB No. 108 requires companies to quantify
misstatements using a balance sheet and income statement
approach and to evaluate whether either approach results in
quantifying an error that is material in light of relevant
quantitative and qualitative factors. When the effect of initial
adoption is material, companies will record the effect as a
cumulative effect adjustment to beginning of year retained
earnings and disclose the nature and amount of each individual
error being corrected in the cumulative adjustment.
SAB No. 108 became effective beginning January 1,
2007 and applies to our restatements included in this filing but
its adoption did not have a material impact on our financial
position, results of operations, or cash flows.
In December 2007, FASB issued SFAS No. 141(R),
Business Combinations
, which replaces
SFAS No. 141. SFAS No. 141(R) establishes
principles and requirements for how the acquirer in a business
combination recognizes and measures in its financial statements
the identifiable assets acquired, the liabilities assumed, and
any non-controlling interest in the acquiree. In addition,
SFAS No. 141(R) recognizes and measures the goodwill
acquired in the business combination or a gain from a bargain
purchase. SFAS No. 141(R) also establishes disclosure
requirements to enable users to evaluate the nature and
financial effects of the business combination.
110
SFAS No. 141(R) is effective as of the beginning of an
entitys fiscal year that begins after December 15,
2008, with early adoption prohibited. We are currently assessing
the impact this standard might have on our results of
operations, cash flows and financial position.
In December 2007, the FASB issued SFAS No. 160,
Non-controlling Interests in Consolidated Financial
Statements An Amendment of ARB No. 51.
SFAS No. 160 establishes accounting and reporting
standards for ownership interests in subsidiaries held by
parties other than the parent, the amount of consolidated net
income attributable to the parent and to the non-controlling
interest, and changes in a parents ownership interest
while the parent retains its controlling financial interest in
its subsidiary. In addition, SFAS No. 160 establishes
principles for valuation of retained non-controlling equity
investments and measurement of gain or loss when a subsidiary is
deconsolidated. SFAS No. 160 also establishes
disclosure requirements to clearly identify and distinguish
between interests of the parent and the interests of the
non-controlling owners. SFAS No. 160 is effective for
fiscal years and interim periods beginning after
December 15, 2008, with early adoption prohibited. We are
currently assessing the impact this standard will have on our
results of operations, cash flows and financial position.
In March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging
Activities-an amendment of FASB Statement No. 133
(SFAS 161). This statement does not change the
accounting for derivatives but will require enhanced disclosures
about derivative strategies and accounting practices.
SFAS 161 is effective for fiscal years beginning after
January 15, 2008, and we will comply with any necessary
disclosure requirements beginning with the interim financial
statements for the three months ended March 31, 2009.
On December 31, 2008, the SEC issued Release
No. 33-8995,
Modernization of Oil and Gas Reporting
, which revises
disclosure requirements for oil and gas companies. In addition
to changing the definition and disclosure requirements for oil
and gas reserves, the new rules change the requirements for
determining oil and gas reserve quantities. These rules permit
the use of new technologies to determine proved reserves under
certain criteria and allow companies to disclose their probable
and possible reserves. The new rules also require companies to
report the independence and qualifications of their reserves
preparer or auditor and file reports when a third party is
relied upon to prepare reserves estimates or conducts a reserves
audit. The new rules also require that oil and gas reserves be
reported and the full cost ceiling limitation be calculated
using a twelve-month average price rather than period-end
prices. The use of a twelve-month average price could have had
an effect on our 2009 depletion rates for our natural gas and
crude oil properties and the amount of the impairment recognized
as of December 31, 2008 had the new rules been effective
for the period. The new rules are effective for annual reports
on
Form 10-K
for fiscal years ending on or after December 31, 2009,
pending the potential alignment of certain accounting standards
by the FASB with the new rule. We plan to implement the new
requirements in our Annual Report on
Form 10-K
for the year ended December 31, 2009. We are currently
evaluating the impact of the new rules on our consolidated
financial statements.
Forward-Looking
Statements
Various statements in this report, including those that express
a belief, expectation, or intention, as well as those that are
not statements of historical fact, are forward-looking
statements within the meaning of the Private Securities
Litigation Reform Act of 1995. These include such matters as
projections and estimates concerning the timing and success of
specific projects; financial position; business strategy;
budgets; amount, nature and timing of capital expenditures;
drilling of wells and construction of pipeline infrastructure;
acquisition and development of oil and natural gas properties
and related pipeline infrastructure; timing and amount of future
production of oil and gas; operating costs and other expenses;
estimated future net revenues from oil and natural gas 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 factors impacting these risks
and uncertainties include, but are not limited to:
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current financial instability and deteriorating economic
conditions;
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our current financial instability;
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111
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volatility of oil and gas prices;
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completion of the Recombination;
|
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|
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increases in the cost of drilling, completion and gas gathering
or other costs of developing and producing our reserves;
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our restrictive debt covenants;
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results of our hedging activities;
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drilling, operational and environmental risks; and
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regulatory changes and litigation risks.
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You should consider carefully the statements in Item 1A.
Risk Factors and other sections of this report,
which describe factors that could cause our actual results to
differ from those set forth in the forward-looking statements.
We have based these forward-looking statements on our current
expectations and assumptions about future events. 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. Readers are urged to carefully
review and consider the various disclosures made by us in our
reports filed with the SEC, which attempt to advise interested
parties of the risks and factors that may affect our business,
financial condition, results of operation and cash flows. If one
or more of these risks or uncertainties materialize, or if the
underlying assumptions prove incorrect, our actual results may
vary materially from those expected or projected.
ITEM 7A.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Quantitative
and Qualitative Disclosures about Market Risk
The discussion in this section provides information about the
financial instruments we use to manage commodity price and
interest rate volatility. All contracts are financial contracts,
which are settled in cash and do not require the actual delivery
of a commodity quantity to satisfy settlement.
Commodity
Price Risk
Our most significant market risk relates to the prices we
receive for our oil and natural gas production. For example,
NYMEX-WTI oil prices have declined from a record high of $147.55
per barrel in July 2008 to approximately $33.87 per barrel in
December 2008. Meanwhile, near month NYMEX natural gas futures
prices during 2008 ranged from as high as $13.58 per Mmbtu in
July 2008 to as low as $5.29 per Mmbtu in December 2008. In
light of the historical volatility of these commodities, we
periodically have entered into, and expect in the future to
enter into, derivative arrangements aimed at reducing the
variability of oil and natural gas prices we receive for our
production. From time to time, we enter into commodity pricing
derivative contracts for a portion of our anticipated production
volumes to provide certainty on future sales price and reduce
revenue volatility.
We use, and may continue to use, a variety of commodity-based
derivative financial instruments, including collars, fixed-price
swaps and basis protection swaps. Our fixed price swap and
collar transactions are settled based upon either NYMEX prices
or index prices at our main delivery points, and our basis
protection swap transactions are settled based upon the index
price of natural gas at our main delivery points. Settlement for
our natural gas derivative contracts typically occurs in advance
of our purchaser receipts.
While we believe that the oil and natural gas price derivative
arrangements we enter into are important to our program to
manage price variability for our production, we have not
designated any of our derivative contracts as hedges for
accounting purposes. We record all derivative contracts on the
balance sheet at fair value, which reflects changes in oil and
natural gas prices. We establish fair value of our derivative
contracts by price quotations obtained from counterparties to
the derivative contracts. Changes in fair values of our
derivative contracts are recognized in current period earnings.
As a result, our current period earnings may be significantly
affected by changes in fair
112
value of our commodities derivative contracts. Changes in fair
value are principally measured based on period-end prices
compared to the contract price.
At December 31, 2008, 2007 and 2006, QELP was party to
derivative financial instruments in order to manage commodity
price risk associated with a portion of its expected future
sales of its oil and gas production. None of these derivative
instruments have been designated as hedges. Accordingly, we
record all derivative instruments in the consolidated balance
sheet at fair value with changes in fair value recognized in
earnings as they occur. Both realized and unrealized gains and
losses associated with derivative financial instruments are
currently recognized in other income (expense) as they occur.
Gains and losses associated with derivative financial
instruments related to gas and oil production were as follows
for the years ended December 31, 2008, 2007 and 2006
(in thousands):
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2008
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|
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2007
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|
|
2006
|
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Realized gains (losses)
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$
|
8,174
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|
|
$
|
7,279
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|
$
|
(17,712
|
)
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Unrealized gains (losses)
|
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72,533
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|
(5,318
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)
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70,402
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|
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Total
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$
|
80,707
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|
|
$
|
1,961
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|
|
$
|
52,690
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The following table summarizes the estimated volumes, fixed
prices and fair value attributable to oil and gas derivative
contracts as of December 31, 2008:
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Year Ending December 31,
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2009
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2010
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2011
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Thereafter
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Total
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($ in thousands, except Mmbtu and per Mmbtu data)
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Natural Gas Swaps:
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Contract volumes (Mmbtu)
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14,629,200
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12,499,060
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2,000,004
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2,000,004
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31,128,268
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Weighted-average fixed price per Mmbtu(1)
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$
|
7.78
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$
|
7.42
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$
|
8.00
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|
$
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8.11
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$
|
7.67
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Fair value, net
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$
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38,107
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$
|
14,071
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$
|
2,441
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$
|
2,335
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$
|
56,954
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Natural Gas Collars:
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Contract volumes (Mmbtu):
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Floor
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750,000
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630,000
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3,549,996
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3,000,000
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7,929,996
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Ceiling
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750,000
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630,000
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3,549,996
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3,000,000
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|
7,929,996
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Weighted-average fixed price per Mmbtu(1):
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Floor
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$
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11.00
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$
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10.00
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$
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7.39
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$
|
7.03
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$
|
7.79
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Ceiling
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$
|
15.00
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$
|
13.11
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$
|
9.88
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$
|
7.39
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$
|
9.52
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Fair value, net
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$
|
3,630
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|
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$
|
1,875
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$
|
3,144
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$
|
2,074
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$
|
10,723
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Total Natural Gas Contracts:
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Contract volumes (Mmbtu)
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15,379,200
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13,129,060
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5,550,000
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5,000,004
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39,058,264
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Weighted-average fixed price per Mmbtu(1)
|
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$
|
7.94
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|
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$
|
7.55
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|
$
|
7.61
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|
|
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7.44
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|
|
$
|
7.70
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Fair value, net
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$
|
41,737
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|
|
$
|
15,946
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|
|
$
|
5,585
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|
|
|
4,409
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|
|
$
|
67,677
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Crude Oil Swaps:
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|
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Contract volumes (Bbl)
|
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36,000
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|
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30,000
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|
|
|
|
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|
|
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66,000
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Weighted-average fixed per Bbl(1)
|
|
$
|
90.07
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|
|
$
|
87.50
|
|
|
|
|
|
|
|
|
|
|
$
|
88.90
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Fair value, net
|
|
$
|
1,246
|
|
|
$
|
666
|
|
|
|
|
|
|
|
|
|
|
$
|
1,912
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|
113
Interest
Rate Risk
The Company has entered into interest rate derivatives to
mitigate its exposure to fluctuations in interest rates on
variable rate debt. These instruments have not been designated
as hedges and, therefore are recorded in the consolidated
balance sheet at fair value with changes in fair value
recognized in earnings as they occur.
As of December 31, 2008, we had outstanding
$388.1 million of variable-rate debt. A 1% increase in our
interest rates would increase gross interest expense
approximately $3.9 million per year. As of
December 31, 2008, we did not have any interest hedging
activities. The last of our interest rate cap agreements expired
September 2007.
114
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ITEM 8.
|
FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA.
|
Please see the accompanying consolidated financial statements
attached hereto beginning on
page F-1.
|
|
ITEM 9.
|
CHANGES
IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
|
None.
|
|
ITEM 9A.
|
CONTROLS
AND PROCEDURES
|
Conclusion
Regarding the Effectiveness of Disclosure Controls and
Procedures
Disclosure controls and procedures (as defined in
Rules 13a-15(e)
and
15d-15(e)
under the Exchange Act) are designed to ensure that information
required to be disclosed in reports filed or submitted under the
Exchange Act is recorded, processed, summarized, and reported
within the time periods specified in SEC rules and forms and
that such information is accumulated and communicated to
management, including the principal executive officer and the
principal financial officer, to allow timely decisions regarding
required disclosures. There are inherent limitations to the
effectiveness of any system of disclosure controls and
procedures, including the possibility of human error and the
circumvention or overriding of the controls and procedures.
Accordingly, even effective disclosure controls and procedures
can only provide reasonable assurance of the achieving their
control objectives.
In connection with the preparation of this Annual Report on
Form 10-K,
our management, under the supervision and with the participation
of the current principal executive officer and current principal
financial officer, conducted an evaluation of the effectiveness
of the design and operation of our disclosure controls and
procedures as of December 31, 2008. Based on that
evaluation, our principal executive officer and principal
financial officer have concluded that our disclosure controls
and procedures were not effective as of December 31, 2008.
Notwithstanding this determination, our management believes that
the consolidated financial statements in this Annual Report on
Form 10-K
fairly present, in all material respects, our financial position
and results of operations and cash flows as of the dates and for
the periods presented, in conformity with GAAP.
Managements
Annual Report on Internal Control Over Financial
Reporting
Management, under the supervision of the principal executive
officer and the principal financial officer, is responsible for
establishing and maintaining adequate internal control over
financial reporting. Internal control over financial reporting
(as defined in
Rules 13a-15(f)
and
15d-15(f)
under the Exchange Act) is a process designed to provide
reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for
external purposes in accordance with GAAP. Internal control over
financial reporting includes those policies and procedures which
(a) pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect the
transactions and dispositions of assets, (b) provide
reasonable assurance that transactions are recorded as necessary
to permit preparation of financial statements in accordance with
GAAP, (c) provide reasonable assurance that receipts and
expenditures are being made only in accordance with appropriate
authorization of management and the board of directors, and
(d) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use or disposition
of assets that could have a material effect on the financial
statements. A material weakness is a deficiency, or a
combination of deficiencies, in internal control over financial
reporting such that there is a reasonable possibility that a
material misstatement of the annual or interim financial
statements will not be prevented or detected on a timely basis.
In connection with the preparation of this Annual Report on
Form 10-K,
our management, under the supervision and with the participation
of the current principal executive officer and current principal
financial officer, conducted an evaluation of the effectiveness
of our internal control over financial reporting as of
December 31, 2008 based on the framework and criteria
established in Internal Control Integrated Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). As a result of that
115
evaluation, management identified the following control
deficiencies that constituted material weaknesses as of
December 31, 2008:
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(1)
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Control environment
We did not maintain an
effective control environment. The control environment, which is
the responsibility of senior management, sets the tone of the
organization, influences the control consciousness of its
people, and is the foundation for all other components of
internal control over financial reporting. Each of these control
environment material weaknesses contributed to the material
weaknesses discussed in items (2) through (8) below.
We did not maintain an effective control environment because of
the following material weaknesses:
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(a)
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We did not maintain a tone and control consciousness that
consistently emphasized adherence to accurate financial
reporting and enforcement of Company policies and procedures.
This control deficiency fostered a lack of sufficient
appreciation for internal controls over financial reporting,
allowed for management override of internal controls in certain
circumstances and resulted in an ineffective process for
monitoring the adherence of the Companys policies and
procedures.
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(b)
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In addition, we did not maintain a sufficient complement of
personnel with an appropriate level of accounting knowledge,
experience, and training in the application of GAAP commensurate
with our financial reporting requirements and business
environment.
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(c)
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We did not maintain an effective anti-fraud program designed to
detect and prevent fraud relating to (i) an effective
whistle-blower program, (ii) consistent background checks
of personnel in positions of responsibility, and (iii) an
ongoing program to manage identified fraud risks.
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The control environment material weaknesses described above
contributed to the material weaknesses related to the transfers
that were the subject of the internal investigation and to our
internal control over financial reporting, period end financial
close and reporting, accounting for derivative instruments,
stock compensation costs, depreciation, depletion and
amortization, impairment of oil and gas properties and cash
management described in items (2) to (8) below.
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(2)
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Internal control over financial reporting
We
did not maintain effective monitoring controls to determine the
adequacy of our internal control over financial reporting and
related policies and procedures because of the following
material weaknesses:
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(a)
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Our policies and procedures with respect to the review,
supervision and monitoring of our accounting operations
throughout the organization were either not designed and in
place or not operating effectively.
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(b)
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We did not maintain an effective internal control monitoring
function. Specifically, there were insufficient policies and
procedures to effectively determine the adequacy of our internal
control over financial reporting and monitoring the ongoing
effectiveness thereof.
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Each of these material weaknesses relating to the monitoring of
our internal control over financial reporting contributed to the
material weaknesses described in items (3) through
(8) below.
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(3)
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Period end financial close and reporting
We
did not establish and maintain effective controls over certain
of our period-end financial close and reporting processes
because of the following material weaknesses:
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(a)
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We did not maintain effective controls over the preparation and
review of the interim and annual consolidated financial
statements and to ensure that we identified and accumulated all
required supporting information to ensure the completeness and
accuracy of the consolidated financial statements and that
balances and disclosures reported in the consolidated financial
statements reconciled to the underlying supporting schedules and
accounting records.
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(b)
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We did not maintain effective controls to ensure that we
identified and accumulated all required supporting information
to ensure the completeness and accuracy of the accounting
records.
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(c)
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We did not maintain effective controls over the preparation,
review and approval of account reconciliations. Specifically, we
did not have effective controls over the completeness and
accuracy of supporting schedules for substantially all financial
statement account reconciliations.
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(d)
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We did not maintain effective controls over the complete and
accurate recording and monitoring of intercompany accounts.
Specifically, effective controls were not designed and in place
to ensure that intercompany balances were completely and
accurately classified and reported in our underlying accounting
records and to ensure proper elimination as part of the
consolidation process.
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(e)
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We did not maintain effective controls over the recording of
journal entries, both recurring and non-recurring. Specifically,
effective controls were not designed and in place to ensure that
journal entries were properly prepared with sufficient support
or documentation or were reviewed and approved to ensure the
accuracy and completeness of the journal entries recorded.
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(4)
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Derivative instruments
We did not establish
and maintain effective controls to ensure the correct
application of GAAP related to derivative instruments.
Specifically, we did not adequately document the criteria for
measuring hedge effectiveness at the inception of certain
derivative transactions and did not subsequently value those
derivatives appropriately.
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(5)
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Stock compensation cost
We did not establish
and maintain effective controls to ensure completeness and
accuracy of stock compensation costs. Specifically, effective
controls were not designed and in place to ensure that
documentation of the terms of the awards were reviewed in order
to be recorded accurately.
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(6)
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Depreciation, depletion and amortization
We
did not establish and maintain effective controls to ensure
completeness and accuracy of depreciation, depletion and
amortization expense. Specifically, effective controls were not
designed and in place to calculate and review the depletion of
oil and gas properties.
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(7)
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Impairment of oil and gas properties
We did
not establish and maintain effective controls to ensure the
accuracy and application of GAAP related to the capitalization
of costs related to oil and gas properties and the required
evaluation of impairment of such costs. Specifically, effective
controls were not designed and in place to determine, review and
record the nature of items recorded to oil and gas properties
and the calculation of oil and gas property impairments.
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(8)
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Cash management
We did not establish and
maintain effective controls to adequately segregate the duties
over cash management. Specifically, effective controls were not
designed to prevent the misappropriation of cash.
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Additionally, each of the control deficiencies described in
items (1) through (8) above could result in a
misstatement of the aforementioned account balances or
disclosures that would result in a material misstatement to the
annual or interim consolidated financial statements that would
not be prevented or detected. These material weaknesses resulted
in the misstatement of our annual and interim consolidated
financial statements as of and for the years ended
December 31, 2007, 2006 and 2005 (including the interim
periods within those years) and as of and for the three months
ended March 31, 2008 and as of and for the three and six
months ended June 30, 2008.
Based on managements evaluation, because of the material
weaknesses described above, management has concluded that our
internal control over financial reporting was not effective as
of December 31, 2008. Our independent registered public
accounting firm, UHY LLP, has audited the effectiveness of our
internal control over financial reporting as of
December 31, 2008, and that report appears in this Annual
Report on
Form 10-K.
Remediation
Plan
Our management, under new leadership as described below, has
been actively engaged in the planning for, and implementation
of, remediation efforts to address the material weaknesses, as
well as other identified areas of risk. These remediation
efforts, outlined below, are intended both to address the
identified material weaknesses and to enhance our overall
financial control environment. In August 2008, Mr. David
Lawler was appointed President (and
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in May 2009 was appointed as our Chief Executive Officer)
(our principal executive officer) and in September 2008,
Mr. Jack Collins was appointed Chief Compliance Officer. In
January 2009, Mr. Eddie LeBlanc was appointed Chief
Financial Officer (our principal financial and accounting
officer). The design and implementation of these and other
remediation efforts are the commitment and responsibility of
this new leadership team.
In addition, Mr. Rateau, one of our independent directors,
was elected as Chairman of the Board, and Mr. McMichael,
who has significant prior public company audit committee
experience, was added to our Board of Directors and Audit
Committee.
Our new leadership team, together with other senior executives,
is committed to achieving and maintaining a strong control
environment, high ethical standards, and financial reporting
integrity. This commitment will be communicated to and
reinforced with every employee and to external stakeholders.
This commitment is accompanied by a renewed management focus on
processes that are intended to achieve accurate and reliable
financial reporting.
As a result of the initiatives already underway to address the
control deficiencies described above, we have effected personnel
changes in our accounting and financial reporting functions. We
have taken remedial actions, which included termination, with
respect to all employees who were identified as being involved
with the inappropriate transfers of funds. In addition, we have
implemented additional training
and/or
increased supervision and established segregation of duties
regarding the initiation, approval and reconciliation of cash
transactions, including wire transfers.
The Board of Directors has directed management to develop a
detailed plan and timetable for the implementation of the
foregoing remedial measures (to the extent not already
completed) and will monitor their implementation. In addition,
under the direction of the Board of Directors, management will
continue to review and make necessary changes to the overall
design of our internal control environment, as well as policies
and procedures to improve the overall effectiveness of internal
control over financial reporting.
We believe the measures described above will enhance the
remediation of the control deficiencies we have identified and
strengthen our internal control over financial reporting. We are
committed to continuing to improve our internal control
processes and will continue to diligently and vigorously review
our financial reporting controls and procedures. As we continue
to evaluate and work to improve our internal control over
financial reporting, we may determine to take additional
measures to address control deficiencies or determine to modify,
or in appropriate circumstances not to complete, certain of the
remediation measures described above.
Changes
in Internal Control Over Financial Reporting
During the fourth quarter, and subsequent to December 31,
2008, we have begun the implementation of some of the remedial
measures described above, including communication, both
internally and externally, of our commitment to a strong control
environment, high ethical standards, and financial reporting
integrity and certain personnel actions.
ITEM 9B.
OTHER
INFORMATION.
None.
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PART III
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ITEM 10.
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DIRECTORS,
EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE
GOVERNANCE.
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Directors
and Executive Officers
Our Directors and Executive Officers are as follows:
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Name
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Age
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Positions Held
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Term of Office Since
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David C. Lawler
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Chief Executive Officer, President and Director
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2007
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Eddie M. LeBlanc, III
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Chief Financial Officer
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2009
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James B. Kite, Jr.
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57
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Director
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2002
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William H. Damon III
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Director
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2007
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John C. Garrison
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Director
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1998
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Jon H. Rateau
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Chairman of the Board and Director
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2005
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Greg L. McMichael
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Director
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2008
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Richard Marlin
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Executive Vice President, Engineering
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2004
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David W. Bolton
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Executive Vice President, Land
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2006
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Jack Collins
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Executive Vice President, Finance/Corporate Development
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2007
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Thomas A. Lopus
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Executive Vice President, Appalachia
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2008
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Mr. Lawler joined us in May 2007 as our Chief Operating
Officer and served as Chief Operating Officer until May 2009,
then became our President in August 2008 and our Chief Executive
Officer in May 2009. He has worked in the oil and gas
industry for more than 18 years in various management and
engineering positions. Prior to joining us, Mr. Lawler was
employed by Shell Exploration & Production Company
from May 1997 to May 2007 in roles of increasing responsibility
most recently as Engineering and Operations Manager for multiple
assets along the U.S. Gulf Coast. Mr. Lawler graduated
from the Colorado School of Mines in 1990 with a bachelors
of science degree in petroleum engineering and earned his
Masters in Business Administration from Tulane University in
2003.
Mr. LeBlanc joined us in January 2009 as our Chief
Financial Officer. He served as Executive Vice President and
Chief Financial Officer of Ascent Energy Company, an
independent, private oil and gas company, from July 2003 until
it was sold to RAM Energy Resources in November 2007, after
which time, Mr. LeBlanc went into retirement. Prior to
that, Mr. LeBlanc was Senior Vice President and Chief
Financial Officer of Range Resources Corporation, an NYSE-listed
independent oil and gas company, from January 2000 to July 2003.
Previously, Mr. LeBlanc was a founder of Interstate Natural
Gas Company, which merged into Coho Energy in 1994. At Coho, he
served as Senior Vice President and Chief Financial Officer
until 1999. Mr. LeBlancs 35 years of experience
include assignments in Celeron Corporation and the energy
related subsidiaries of Goodyear Tire and Rubber. Prior to
entering the oil and gas industry, Mr. LeBlanc was with a
national accounting firm. He is a certified public accountant
and a chartered financial analyst, and he received a B.S. in
Business Administration from University of Southwestern
Louisiana.
Mr. Kite is the Chief Executive Officer of Boothbay Royalty
Company, an independent investment company with its primary
concentration in the field of oil and gas exploration and
production based in Oklahoma City, Oklahoma, which he founded in
1977. He has served as its Chief Executive Officer, President
and Treasurer since its inception. Mr. Kite spent several
years in the commercial banking industry with an emphasis in
credit and loan review prior to his involvement in the oil and
gas industry. Mr. Kite presently is a director of The All
Souls Anglican Foundation. Mr. Kite earned a
bachelors of business administration in finance from the
University of Oklahoma.
Mr. Damon has over 30 years of professional experience
specializing in engineering design and development of power
generation projects and consulting services. Since January 2008,
he has served as Senior Vice President and National Director of
Power Consulting for HDR, Inc., which recently purchased the
engineering-consulting
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firm, Cummins & Barnard, Inc., which was focused on
power generation development and engineering projects for
electric utilities, independent power producers, large
industrial and institutional clients throughout the United
States. Mr. Damon served as the Chief Executive Officer of
Cummins & Barnard and had been its principal and
co-owner from 1990 to January 2008. He currently leads
HDRs project development and strategic consulting business
for coal, natural gas and renewable energy projects. He
previously worked for Consumers Power Company,
Gilbert-Commonwealth, Inc. and Alternative Energy Ventures. He
also held board seats on a minerals and wind turbine company,
MKBY, and a
start-up
construction company that was recently sold to Aker Kvaerner
Songer in which he was also a founding member. Mr. Damon
graduated from Michigan State University with a B.S. in
Mechanical Engineering and continued graduate studies at both
Michigan State University and the University of Michigan.
Mr. Garrison brings expertise in public company activities
and issues. Mr. Garrison served as our Treasurer from 1998
to September 2001. Mr. Garrison has been a self-employed
Certified Public Accountant in public practice providing
financial management and accounting services to a variety of
businesses for over thirty years. From August 2007 to March
2008, and again from August 2008 to the present, he has served
as the Chief Financial Officer of Empire Energy Corporation
International. From July 2004 to June 2007, Mr. Garrison
was the Chief Financial Officer of ICOP Digital, Inc. He has
also been a director of Empire Energy since 1999.
Mr. Garrison holds a bachelors degree in Accounting
from Kansas State University.
Mr. Rateau is currently the Vice President of New Energy,
Global Primary Products Growth, Alcoa, Inc., where he is
responsible for developing and acquiring energy positions/assets
worldwide in support of Alcoas smelting and refining
activities, and has been at Alcoa, Inc. since 1996.
Mr. Rateau has served in his present capacity at Alcoa
since September 2007. Prior to that, he was Vice President of
Business Development, Primary Metals from March 2001 to
September 2007 and Vice President of Energy
Management & Services, Primary Metals from November
1997 to March 2001. Before joining Alcoa, Mr. Rateau held a
number of managerial positions with National Steel Corporation
from 1981 to 1996. He brings expertise in business acquisitions
and divestitures, capital budgets and project management, energy
contracting, and applied research of complex technology and
processes. Mr. Rateau holds an M.B.A. from Michigan State
University and received a B.S. in Industrial Engineering from
West Virginia University.
Mr. McMichael has over 30 years of oil and gas
experience, including 13 years working directly in the
exploration and production (E&P) sector, 16 years as
an equity analyst following the E&P sector and over four
years as a director of both private and public oil and gas
companies. Mr. McMichael has served as a Director of
Denbury Resources, Inc. since 2004, a publicly held E&P
company based in Plano, Texas, where he currently chairs
Denburys Compensation Committee. Concurrent with being a
director at Denbury, he served for four years as a director of
Matador Resources Company, a privately held E&P company
where he served on the Audit Committee. Mr. McMichael was
employed by A.G. Edwards Inc. for eight years (1998
2004) as Vice President and Group Leader of Energy Research,
where he managed that firms global energy equity research
effort. He earned a Bachelors degree in Political Science
and Economics from Schiller International University in London,
England in 1973.
Mr. Marlin has served as Executive Vice
President Engineering since September 2004. He also
was our Chief Operations Officer from February 2005 through July
2006. He was our engineering manager from November 2002 to
September 2004. Prior to that, he was the engineering manager
for STP from 1999 until our acquisition of STP in November 2002.
Prior to that, he was employed by Parker and Parsley Petroleum
as the Mid-Continent Operations Manager for 12 years.
Mr. Marlin has more than 32 years industry experience
involving all phases of drilling and production in more than
14 states. His experience also involved primary and
secondary operations along with the design and oversight of
gathering systems that move as much as
175 Mmcf/d.
He is a registered Professional Engineer holding licenses in
Oklahoma and Colorado. Mr. Marlin earned a B.S. in
Industrial Engineering and Management from Oklahoma State
University in 1974. Mr. Marlin was a Director of the
Mid-Continent Coal Bed Methane Forum from 2003 to 2005.
Mr. Bolton has served as Executive Vice
President Land since May 2006. Prior to that, he was
a Land Manager for Continental Land Resources, LLC, an Oklahoma
based oil and gas lease broker from May 2004 to May 2006. Prior
to that, Mr. Bolton was a landman for Continental Land
Resources from April 2001 to May 2004. He was an independent
landman from 1995 to April 2001. Mr. Bolton is a Certified
Professional Landman with over
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18 years of experience in various aspects of the oil and
gas industry, and has worked extensively throughout Oklahoma,
Texas, and Kansas. Mr. Bolton holds a Bachelor of Liberal
Studies degree from the University of Oklahoma, attended the
Oklahoma City University School of Law, and is a member of
American Association of Petroleum Landmen, Oklahoma City
Association of Petroleum Landmen, the American Bar Association,
and the Energy Bar Association.
Mr. Collins joined the Company in December 2007 as
Executive Vice President Investor Relations. From
September 2008 to January 2009, he served as the Companys
Interim Chief Financial Officer, and since January 2009, he has
served as the Companys Executive Vice
President Finance/Corporate Development.
Mr. Collins has more than 11 years of experience
providing analysis and advice to oil and gas industry investors.
Prior to joining us, he worked for A.G. Edwards &
Sons, Inc., a national, full-service brokerage firm, from 1999
to 2007 in various positions, most recently as a Securities
Analyst, where he was responsible for initiating the firms
coverage of the high yield U.S. energy stock sector
(E&P partnerships and U.S. royalty trusts). As an
Associate Analyst (2001 to 2005) and Research Associate
(1999 to 2001) at A.G. Edwards, he assisted senior analysts
in coverage of the independent E&P and oilfield service
sectors of the energy industry. Mr. Collins holds a
Bachelors degree in Economics with a Business Emphasis from the
University of Colorado at Boulder.
Mr. Lopus has served as Executive Vice
President Appalachia since July 2008. Mr. Lopus
has more than 27 years of experience in the oil and gas
industry. Prior to joining us, Mr. Lopus served as Senior
Vice President of Eastern Operations for Linn Energy, LLC from
April 2006 to July 2008 where he was responsible for all Eastern
United States oil and natural gas activity. From April 2005 to
March 2006, he was an independent consultant for a variety of
oil and gas related businesses. From February 2002 to March
2005, Mr. Lopus held senior management positions at
Equitable Resources, Inc., where he was responsible for all oil
and natural gas operations. Prior to that, he worked at FINA,
Inc. for 20 years, where he was in charge of all oil and
natural gas operations in the United States. Mr. Lopus is a
registered petroleum engineer and received a Bachelor of Science
degree from The Pennsylvania State University in Petroleum and
Natural Gas Engineering. He has held leadership positions with
numerous industry and civic organizations, including the
Independent Petroleum Association of America, Society of
Petroleum Engineers, American Petroleum Institute, United Way,
and March of Dimes.
Board of
Directors
Our Board of Directors is currently divided among three classes
as follows:
Class I John C. Garrison and Jon H. Rateau;
Class II David C. Lawler and William H. Damon
III; and
Class III Greg L. McMichael and James B.
Kite, Jr.
The term of each class of directors expires at each annual
meeting of stockholders, with the terms of
Messrs. McMichael and Kite expiring in 2009, the terms of
Messrs. Garrison and Rateau expiring in 2010 and the terms
of Messrs. Lawler and Damon expiring in 2011.
Corporate
Governance
Audit
Committee
The Board of Directors has established a separately designated
standing Audit Committee in accordance with
Section 3(a)(58)(A) of the Exchange Act. The purposes of
the Audit Committee are to oversee and review (i) the
integrity of all financial information provided to any
governmental body or the public and (ii) the integrity and
adequacy of the our auditing, accounting and financial reporting
processes and systems of internal control for financial
reporting and disclosure controls and procedures.
The following three directors are members of the Audit
Committee: John Garrison, Chair, Greg McMichael and William H.
Damon III. The Board of Directors has determined that each of
the Audit Committee members are independent, as that term is
defined under the enhanced independence standards for audit
committee members in the Securities Exchange Act of 1934 and
rules thereunder, as amended, as incorporated into the listing
standards of the
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NASDAQ Global Market. The Board of Directors has determined that
Mr. Garrison is an audit committee financial
expert, as that term is defined in the rules promulgated
by the SEC pursuant to the Sarbanes-Oxley Act of 2002.
The Audit Committee performs its functions and responsibilities
pursuant to a written charter adopted by our Board of Directors,
which is published on our Internet website at
www.questresourcecorp.com under the heading Corporate Governance.
Code
of Ethics
We have adopted a Code of Business Conduct and Ethics for
Directors, Officers and Employees (Code of Ethics),
which addresses conflicts of interests, that is applicable to
our principal executive officer, principal financial officer and
principal accounting officer. The Code of Ethics describes the
types of transactions that may be subject to the review,
approval or ratification of the Audit Committee or the chief
compliance officer. Any waiver of any provision of our Code of
Ethics for a member of our Board of Directors, an executive
officer, or a senior financial or accounting officer must be
approved by our Audit Committee, and any such waiver will be
promptly disclosed as required by law or NASDAQ rule.
A copy of our Code of Ethics is available on our internet
website at www.questresourcecorp.com under the heading Corporate
Governance. We will also provide a copy of the Code of Ethics,
without charge, to any stockholder who requests it. Requests
should be addressed in writing to: Corporate Secretary at Quest
Resource Corporation, 210 Park Avenue, Suite 2750, Oklahoma
City, OK 73102. We intend to post any amendment to or waiver
from the Code of Ethics that applies to executive officers or
directors on our website.
Section 16(a)
Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our directors
and executive officers, and persons who own more than 10% of a
registered class of our equity securities (Section 16
Insiders), to file with the SEC initial reports of
ownership and reports of changes in ownership of our equity
securities. Directors, executive officers and greater than 10%
stockholders are required by SEC regulations to furnish us with
copies of all Section 16(a) forms they file.
To our knowledge, based solely on a review of Forms 3, 4, 5
and amendments thereto furnished to us and written
representations that no other reports were required, during and
for the fiscal year ended December 31, 2008, all
Section 16(a) filing requirements applicable to our
directors, executive officers and greater than 10% beneficial
owners were complied with in a timely manner, except for the
following:
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Messrs. Rateau, Garrison, Damon and Kite each did not timely
report his acquisition of 5,000 shares of common stock
pursuant to a bonus shares award agreement.
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Richard Marlin did not timely report his disposition of
8,434 shares held in Mr. Marlins retirement
account.
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Bob Alexander, a former director of the Company who resigned on
August 22, 2008, did not timely report his achievement of
the status of Section 16 Insider. In addition,
Mr. Alexander did not timely report his acquisition of a
pecuniary interest in 10,000 shares pursuant to a bonus
shares award agreement. These shares were not issued to
Mr. Alexander and he relinquished any right to receive
these shares as part of his resignation from our Board of
Directors.
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ITEM 11.
EXECUTIVE
COMPENSATION.
Compensation
Discussion and Analysis
Compensation
Philosophy
Our compensation philosophy is to manage Named Executive Officer
(defined below) total compensation at the median level (50th
percentile) relative to companies with which we compete for
talent (which are primarily peer group companies). The
Compensation Committee of our Board of Directors (the
Committee) compares compensation levels with a
selected cross-industry group of other oil and natural gas
exploration and production companies of similar size to
establish a competitive compensation package.
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Role
of the Compensation Committee
The Committee is responsible for reviewing and approving all
aspects of compensation for the Named Executive
Officers listed in the Summary Compensation Table (the
Named Executive Officers). The Committee is also
responsible for approving the compensation policies of Quest
Energy GP, some of whose officers are our Named Executive
Officers.
In meeting these responsibilities, the Committees policy
is to ensure that Named Executive Officer compensation is
designed to achieve three primary objectives:
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attract and retain well-qualified executives who will lead us
and achieve superior performance;
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tie annual incentives to achievement of specific, measurable
short-term corporate goals; and
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align the interests of management with those of the stockholders
to encourage achievement of increases in stockholder value.
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The Committee retained the independent compensation consulting
firm of Towers Perrin (T-P) in February 2008 to:
(i) assist the Committee in formulating our compensation
policies for 2008 and future years; (ii) provide advice to
the Committee concerning specific compensation packages and
appropriate levels of Named Executive Officers
compensation; (iii) provide advice about competitive levels
of compensation and marketplace trends in the oil and gas
industry; and (iv) review and recommend changes in our
compensation system and programs. As described below, T-P
compiled competitive salary data for seven of our peer group
companies and eight of Quest Energys peer group companies
and assisted the Committee in its benchmarking efforts, among
other things. T-P had a conference call with the Committee in
order to gather information about us and our business.
Additionally, in September 2008, the Committee subscribed to a
service provided by Equilar, Inc. (Equilar) to
create reports concerning compensation data (including base
salary, bonus compensation and equity awards) to assist the
Committee in analyzing the compensation received by our Named
Executive Officers and directors in comparison to
publicly-traded benchmarked companies as described below.
In connection with the adoption of a Long Term Incentive Plan
(LTIP) and amendments made to our 2005 Omnibus Stock
Award Plan (the Omnibus Plan) and Management Annual
Incentive Plan (the QRC Bonus Plan) in May 2008, the
Committee retained RiskMetrics Group, formerly Institutional
Shareholder Services (RiskMetrics), to advise it
with respect to corporate governance matters.
The Committee separately considered the elements of
(i) base salary, (ii) base salary plus target bonus,
and (iii) long-term equity incentive value, comparing our
compensation for such elements to the median level
(50th percentile) of our peer group for 2008. The Committee
believed the metric of actual total cash compensation (base
salary, as well as base salary plus bonus) was key to retaining
well-qualified executives and to providing annual incentives and
therefore gave it a heavier weighting than our peer group. The
Committee made adjustments to attempt to align the actual total
annual cash compensation between the 50th to
75th percentiles of our market peer group, while taking
into account differences in job titles and duties, as well as
individual performance. The Committee believes that total
compensation packages (taking into account long term equity
compensation) were between the 25th and 50th percentiles of
our market peer group. Initially, equity awards were granted as
part of the Named Executive Officers employment agreements
in a lump sum that vested over a three-year period. As discussed
below, the Committee adopted the LTIP in 2008 in order to
provide the Named Executive Officers with annual grants of
equity incentive compensation. However, this program was
cancelled at the end of 2008 due to our low stock price.
Role
of Management in Compensation Process
Each year the Committee asks our principal executive officer
(which prior to August 22, 2008, was Jerry Cash, our Chief
Executive Officer, and after that date was David Lawler, our
President) and principal financial officer to present a proposed
compensation plan for the fiscal year beginning January 1 and
ending December 31 (each, a Plan Year), along with
supporting and competitive market data. For 2008, T-P assisted
our management in providing this competitive market data,
primarily through published and private salary surveys. The
compensation amounts presented to the Committee for the 2008
Plan Year were determined based upon Mr. Cashs
negotiations
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with the Named Executive Officers (taking into account the T-P
competitive data). The Committee then met with Mr. Cash to
review the proposal and establish the compensation plan, with
members of T-P participating by telephone.
The Committee monitors the performance of our Named Executive
Officers throughout the Plan Year against the targets set for
each performance measure. At the end of the Plan Year, the
Committee meets with the principal executive officer and
principal financial officer to review the final results compared
to the established performance goals before determining the
Named Executive Officers compensation levels for the Plan
Year. During these meetings, the Committee also establishes the
Named Executive Officer compensation plan for the upcoming Plan
Year, based on the principal executive officers
recommendations. In general, the plan must be established within
the first 90 days of a Plan Year.
During 2008, we hired Thomas Lopus, who was one of the
Named Executive Officers for 2008. The compensation package for
Mr. Lopus was negotiated between Mr. Cash and Mr. Lopus
(taking into account the T-P competitive data). The Committee
then met with Mr. Cash to review and approve the proposed
compensation package.
In connection with David Lawlers change of executive
officer position in October 2008, Mr. Lawler and the Committee
renegotiated his compensation package after taking into account
the T-P and Equilar competitive data.
Mr. Lawler was actively involved in the renegotiation of
Mr. Collins employment agreement in October 2008 and
made the determination of the amount of the discretionary
bonuses awarded to the other Named Executive Officers in January
2009 under the Supplemental Bonus Program discussed below.
Performance
Peer Groups
In 2008, the Committee retained T-P as its independent
compensation consultant to advise the Committee on matters
related to the Named Executive Officers compensation
program. To assist the Committee in its benchmarking efforts,
T-P provided a compensation analysis and survey data for peer
groups of companies that are similar in scale and scope to us
and Quest Energy. With the assistance of T-P, the Committee
selected (i) a peer group for us consisting of the
following seven publicly traded U.S. exploration and
production companies which had annual revenues ranging from
$4 million to $106 million: American Oil &
Gas Inc., Aurora Oil & Gas Corp., Brigham Exploration
Co., Double Eagle Petroleum Co., Kodiak Oil & Gas
Corp., Rex Energy Corp. and Warren Resources Inc.; and
(ii) a peer group for Quest Energy consisting of the
following eight publicly traded U.S. limited partnerships
and limited liability companies: Atlas Energy Resources, LLC,
Linn Energy, LLC, BreitBurn Energy Partners, L.P., Legacy
Reserves, L.P. , EV Energy Partners, L.P., Constellation Energy
Partners, LLC, Encore Energy Partners, L.P. and Vanguard Natural
Resources, LLC.
Additionally, the Committee utilized Equilar in 2008 to collect
market data concerning total compensation for director and Named
Executive Officer positions at comparable peer group companies.
The peer group used for the Equilar benchmarking service
includes: ATP Oil & Gas Corporation, Brigham Exploration
Co., Carrizo Oil & Gas, Inc., Edge Petroleum Corporation,
Gastar Exploration Ltd., GMX Resources Inc., Goodrich Petroleum
Corporation, Linn Energy, LLC, McMoRan Exploration Co., Parallel
Petroleum Corporation, Toreador Resources Corporation, and
Warren Resources Inc.
Elements
of Executive Compensation Program
Our compensation program for Named Executive Officers consists
of the following components:
Base Salary:
The base salary element of our
compensation program serves as the foundation for other
compensation components and addresses the first compensation
objective stated above, which is to attract and retain
well-qualified executives. Base salaries for all Named Executive
Officers are established based on their scope of
responsibilities, taking into account competitive market
compensation paid by other companies in our peer group. The
Committee considers the median salary range for each Named
Executive Officers counterpart, but makes adjustments to
reflect differences in job descriptions and scope of
responsibilities for each Named Executive Officer and to reflect
the Committees philosophy that each Named Executive
Officers total compensation should be at the median level
(50th percentile) relative to our peer group. The Committee
annually reviews base salaries for Named
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Executive Officers and makes adjustments from time to time to
realign their salaries, after taking into account individual
performance, responsibilities, experience, autonomy, strategic
perspectives and marketability, as well as the recommendations
of the principal executive officer.
In August 2008, David Lawlers and Jack Collinss
executive officer positions changed and their duties and
responsibilities increased. Accordingly, in October 2008, their
base salaries were increased and they were granted stock options
after the Committee took into account their individual
performance, increased responsibilities and experience and
competitive data provided by
T-P
and
Equilar.
The Committee allocated approximately 4% of all base salaries of
the Named Executive Officers to a pool to be used as a cost of
living adjustment. The Committee approved a 4% increase for
Mr. Cash and gave Mr. Cash the authority to divide the
remaining pool among the Named Executive Officers (other than
Mr. Cash).
Management Annual Incentive Plan:
In 2006, the
Committee established the QRC Bonus Plan. The QRC Bonus Plan is
intended to recognize value creation by providing competitive
incentives for meeting and exceeding annual financial and
operating performance measurement targets related to our
exploration and production operations.
By providing market-competitive bonus awards, the Committee
believes the QRC Bonus Plan supports the compensation objective
of attracting and retaining Named Executive Officer talent
critical to achieving superior performance and support the
compensation objective of tying annual incentives to the
achievement of specific short-term performance goals during the
year, which creates a direct connection between the
executives pay and our financial performance.
For 2008, awards under the QRC Bonus Plan were paid solely in
cash. The Committee anticipates that future annual bonus awards
will also be paid only in the form of cash awards, except that a
portion of Mr. Lawlers award may be paid in the form
of QRCP common stock.
Each year the Committee establishes goals during the first
quarter of the calendar year. The 2008 performance goals for the
QRC Bonus Plan are described below. The amount of the bonus
payable to each participant varies based on the percentage of
the performance goals achieved and the employees position
with us. More senior ranking management personnel are entitled
to bonuses that are potentially a higher percentage of their
base salaries, reflecting the Committees philosophy that
higher ranking employees should have a greater percentage of
their overall compensation at risk.
Each executive officer and key employee that participates in the
QRC Bonus Plan has a target bonus percentage expressed as a
percentage of base salary based on his or her level of
responsibility. The performance criteria for 2008 includes
minimum performance thresholds required to earn any incentive
compensation, as well as maximum payouts geared towards
rewarding extraordinary performance, thus, actual awards can
range from 0% (if performance is below 60% of target) to 99% of
base salary for our most senior executives (if performance is
150% of target). For 2008, the potential bonus amounts for each
of Messrs. Cash, Grose, Lawler, and Collins were as
follows: If we achieved an average of our financial goals of
60%, their incentive awards would be 22% of base salary. If we
achieved an average of our financial goals of 100%, their
incentive awards would be 42% of base salary. If we achieved an
average of our financial goals of 150%, their incentive awards
would be 99% of base salary. For 2008, the potential bonus
amounts for each of the other Named Executive Officers were as
follows: If we achieved an average of our financial goals of
60%, their incentive awards would be 7% of base salary. If we
achieved an average of our financial goals of 100%, their
incentive awards would be 27% of base salary. If we achieved an
average of our financial goals of 150%, their incentive awards
would be 73.5% of base salary.
After the end of the Plan Year, the Committee determines to what
extent we and the participants have achieved the performance
measurement goals. The Committee calculates and certifies in
writing the amount of each participants bonus based upon
the actual achievements and computation formula set forth in the
QRC Bonus Plan. The Committee has no discretion to increase the
amount of any Named Executive Officers bonus as so
determined, but may reduce the amount of or totally eliminate
such bonus, if it determines, in its absolute and sole
discretion that such reduction or elimination is appropriate in
order to reflect the Named Executive Officers performance
or unanticipated factors. The performance period
(Incentive Period) with respect to which target
awards and
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bonuses may be payable under the QRC Bonus Plan will generally
be the fiscal year beginning on January 1 and ending on
December 31, but the Committee has the authority to
designate different Incentive Periods.
The Committee increased certain 2008 performance targets for the
QRC Bonus Plan from the 2007 levels. Since our drilling program
for 2008 concentrated mainly on drilling new wells located on
our proved undeveloped reserves, the Committee eliminated the
increase in year end proved reserves as a performance measure in
2008. The Committee added a health, safety and
environment target in order to reflect our commitment to
improving the environment, increasing worker safety and reducing
costs. The Committee established the 2008 performance targets
and percentages of goals achieved for each of the five corporate
goals described below:
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Percentage of Goal Achieved
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50%
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100%
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150%
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Performance Measure and % Weight
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Cost reduction in savings health, safety and
environment (20% in the aggregate)
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Number of OSHA recordable injuries (5%)
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33
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30
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26
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Number of vehicle incidents > $1,000 (5%)
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20
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18
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15
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Salt water spills (Bbls) (5%)
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14,760
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13,120
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11,480
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Number of spills (5%)
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338
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301
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263
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EBITDA (earnings before interest, taxes, depreciation and
amortization) (20%)
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$
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69,300,000
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$
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72,400,000
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$
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78,800,000
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Lease operating expense (excluding gross production taxes and ad
valorem taxes) (20%)
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$
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28,246,660
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$
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25,700,000
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$
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23,153,000
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Finding and development cost (20%)
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$
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1.52/Mcf
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$
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1.39/Mcf
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$
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1.25/Mcf
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Production (20%)
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22.5 Bcfe
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23.1 Bcfe
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24.5 Bcfe
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Each of the five corporate goals were equally weighted. The
amount of the incentive bonus varies depending upon the average
percentage of the goals achieved. For amounts between 50% and
100% and between 100% and 150%, linear interpolation is used to
determine the Percentage of Goal Achieved. For
amounts below 50%, the Percentage of Goal Achieved
is determined using the same scale as between 50% and 100%. For
amounts in excess of 150%, the Percentage of Goal
Achieved is determined using the same scale as between
100% and 150%. For 2008, no incentive awards would have been
payable under the QRC Bonus Plan if the average percentage of
the goals achieved was less than 60%. Additionally, no
additional incentive awards were payable if the average
percentage of the goals achieved exceeded 150%. For 2008, the
average percentage of the goals achieved under the QRC Bonus
Plan was 60.9%. We made a dramatic improvement in our health,
safety and environment performance for 2008 compared to 2007.
Without this strong health, safety and environment performance
our average percentage of goals achieved would have been below
60% and no bonuses would have been payable under the QRC Bonus
Plan. We believe that we realized a number of benefits from
improving our health, safety and environment performance,
including improving the environment where our wells are located,
reducing worker injuries and reducing costs. In addition, we
should be able to significantly lower our insurance costs if we
are able to maintain our 2008 level of performance.
Additionally, with respect to the 2008 awards, and any future
awards under the QRC Bonus Plan, if our overall performance
under the QRC Bonus Plan equals or exceeds 100%, Mr. Lawler
will be granted a number of performance shares and restricted
shares (valued based on the closing price of the Companys
common stock at year end) under the Companys Omnibus Plan,
each having a value equal to 50% of the payment Mr. Lawler
would have been paid under the QRC Bonus Plan if our overall
performance under the QRC Bonus Plan was 100%. The performance
shares will be immediately vested and the restricted shares will
vest on the first anniversary of the date of grant. The
Companys overall performance under the QRC Bonus Plan for
2008 was less than 100%, so no additional equity award was
payable to Mr. Lawler for 2008.
Mr. Lopus commenced employment as our EVP
Appalachia in July 2008, and Mr. Lopus received a pro rata
portion of the bonus for 2008 under the QRC Bonus Plan.
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Discretionary Bonuses:
In October 2008, our
Board of Directors adopted a 2008 Supplemental Bonus Plan (the
Supplemental Bonus Plan) for certain key employees,
excluding Mr. Lawler. The Supplemental Bonus Plan provided
additional incentive and bonus opportunities to supplement the
bonus opportunities available to employees under the QRC Bonus
Plan for 2008 and additional key employees. The determination as
to whether a bonus payment was made under the Supplemental Bonus
Plan and the amount of that payment was solely within the
discretion of Mr. Lawler, who took into account both our
performance during 2008 and the respective employees
individual performance during 2008. The maximum amount that an
employee was eligible to receive under the Supplemental Bonus
Plan was dependent upon the employees classification under
the QRC Bonus Plan less the actual amount such individual
received under the QRC Bonus Plan, if any, for 2008. The maximum
aggregate amount of bonuses available under the Supplemental
Bonus Plan was capped at $2 million. Employees were to
receive their supplemental bonuses in quarterly payments in
2009. To the extent an employees payment under the QRC
Bonus Plan, if any, was greater than or less than originally
anticipated at the time the amount of the employees
supplemental bonus was established, any quarterly payment made
after the payment under the QRC Bonus Plan were to be
appropriately adjusted. Mr. Lawler awarded quarterly
discretionary bonuses in January 2009, which were related to
2008 performance. The Compensation Committee subsequently
terminated the Supplemental Bonus Program.
In connection with the amendment to Mr. Lawlers
employment agreement in October 2008 and in lieu of
participating in the Supplemental Bonus Plan, the Committee
authorized the payment of a $232,000 bonus to Mr. Lawler in
November 2008 and payment of an amount equal to $164,000 minus
the amount, if any, Mr. Lawler is paid under the QRC Bonus
Plan in 2009 for his 2008 performance, which was payable at the
same time as the awards under the QRC Bonus Plan for 2008 were
payable in March 2009.
Certain of our executive officers had entered into 10b(5)-1(c)
trading plans with the company and a designated broker that
provided that upon vesting of restricted stock our chief
financial officer would notify the designated broker of the
number of shares that needed to be sold in order to generate
sufficient funds to satisfy the executive officers tax
withholding obligations (which would have been about 30% of the
shares that vested). During 2008, several of the executive
officers had restricted shares that vested in March and April at
a time when QRCPs stock price was generally between $6.50
and $7.00 per share. Our former chief financial officer did not
perform his obligations under the trading plans, but the
executive officers still incurred a tax liability based on the
stock price on the date of vesting. Subsequent to the disclosure
of the Transfers, our stock price dropped significantly to under
one dollar. At that time, it came to the attention of our Board
of Directors that our former chief financial officer had not
complied with the trading plans. The Board of Directors decided
to make the executive officers whole due to our former chief
financial officers inaction. The Board of Directors agreed
to pay the affected executive officers a bonus equal to the
value of approximately 30% of each executive officers
stock on the date of vesting in exchange for approximately 30%
of the vested shares (the approximate number of shares that
would have been sold under the trading plans). The Board of
Directors also agreed to pay the affected executive officers a
tax gross-up payment on this bonus, since the bonus was
additional taxable income that the executive officers would not
have had if our former chief financial officer had complied with
the trading plans.
Productivity Gain Sharing Payments:
For part
of 2008, we made productivity sharing payments, which were
comprised of a one-time cash payment equal to 10% of an
individuals monthly base salary earned during each month
that our CBM production rate increased by 1,000 Mcf/day
over the prior record. All of our employees were eligible to
receive productivity gain sharing payments. The purpose of these
payments was to incentivize all employees, including Named
Executive Officers, to continually and immediately focus on
production. The Named Executive Officers received payments equal
to less than one month of base salary as a result of this plan.
Equity Awards:
The Committee believes that the
long-term performance of our executive officers is enhanced
through ownership of stock-based awards, such as stock options
and restricted stock, which expose executive officers to the
risks of downside stock prices and provide an incentive for
executive officers to build shareholder value.
Omnibus Stock Award Plan.
Our Omnibus
Plan provides for grants of non-qualified stock options,
restricted shares, bonus shares, deferred shares, stock
appreciation rights, performance units and performance shares.
Currently, the total number of shares that may be issued under
the Omnibus Plan is 2,700,000. The Omnibus
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Plan also permits the grant of incentive stock options. The
objectives of the Omnibus Plan are to strengthen key
employees and non-employee directors commitment to
our success, to stimulate key employees and non-employee
directors efforts on our behalf and to help us attract new
employees with the education, skills and experience we need and
retain existing key employees. All of our equity awards
consisting of our common stock are issued under the Omnibus Plan.
In connection with the adoption of the LTIP and amendments made
to the Omnibus Plan and QRC Bonus Plan in May 2008, the
Committee received guidance from RiskMetrics with respect to
corporate governance matters. As a result of the
Committees discussions with RiskMetrics, the Committee
adopted a burn rate policy. This policy provides
that for the years ended December 31, 2008, 2009 and 2010,
our prospective three-year average burn rate with respect to our
equity awards will not exceed the mean and one standard
deviation of our Global Industry Classification Standards Peer
Group (1010 Energy) of 4.43%. For purposes of
calculating the three-year average burn rate under this burn
rate policy, each restricted stock (unit), bonus share or stock
award or any forms of full-value awards granted under our equity
plans will be counted as 1.5 award shares and will be calculated
as (i) the number of equity awards granted in each fiscal
year by the Committee to employees and directors, excluding
awards granted to replace securities assumed in connection with
a business combination transaction, divided by (ii) the
weighted average basic shares outstanding.
As a result of the termination of Messrs. Cash and Grose
and other employees related to the internal investigation and
related matters, a significant percentage of our prior unvested
equity awards were forfeited during 2008. However, under the
burn rate policy, awards that are forfeited during the year are
not taken into account in calculating the burn rate.
In order to attract a new chief financial officer and to
compensate Messrs. Lawler and Collins for their increased
roles at the Company, the Committee determined that it was
necessary under the circumstances to grant new equity awards
during 2008 that exceeded the burn rate policy. However, we are
significantly below the burn rate policy if the forfeiture of
previously granted awards is taken into consideration.
Long-Term Incentive Plan.
In May 2008,
the Committee adopted the LTIP. Under the LTIP, our principal
executive officer would have received awards of restricted stock
under the Omnibus Plan if the adjusted average share price for a
calendar year exceeded both the initial value ($9.74
for 2007) and the adjusted average share price for
the prior year. The adjusted average share price is
the adjusted average of the fair market values for each trading
day during a calendar year, taking into account the trading
volume of our shares on each day. Any restricted stock awards
granted to our principal executive officer under the LTIP would
have vested ratably over a three-year period. The LTIP also
provided for awards of restricted stock to the other
participants (including the Named Executive Officers) based upon
(1) a pool of 3% of our consolidated income before
depreciation, depletion, amortization and taxes and ignoring
changes in income attributable to non-cash changes in derivative
fair value and (2) the stock price as of the day awards
were made under the Omnibus Plan. Any restricted stock awards
under the LTIP to the other participants would have vested over
a two-year period.
The LTIP was intended to encourage participants to focus on our
long-term performance, align the interests of management with
those of our stockholders, and provide an opportunity for our
executive officers to increase their stake in us through grants
of restricted stock pursuant to the terms of the Omnibus Plan.
The Committee designed the long-term incentive plan to:
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enhance the link between the creation of stockholder value and
long-term incentive compensation;
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provide an opportunity for increased equity ownership by
executive officers; and
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maintain a competitive level of total compensation.
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However, for 2008, the Committee elected to not make any awards,
and effective January 1, 2009, the LTIP was terminated due
to (1) the large number of shares that would have been
required to be issued due to our low stock price and
(2) the establishment of the Supplemental Bonus Plan
discussed above.
Quest Energy Partners Long Term Incentive
Plan.
In July 2007, we formed Quest Energy to
own and operate our Cherokee Basin assets and to acquire,
exploit and develop oil and natural gas properties in the
Cherokee Basin. On November 14, 2007, Quest Energys
general partner, Quest Energy GP adopted the Quest Energy
Partners, L.P.
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Long-Term Incentive Plan for employees, consultants and
directors of Quest Energy GP and any of its affiliates who
perform services for Quest Energy. The long-term incentive plan
consists of the following securities of Quest Energy: options,
restricted units, phantom units, unit appreciation rights,
distribution equivalent rights, other unit-based awards and unit
awards. The purpose of awards under the long-term incentive plan
is to provide additional incentive compensation to employees
providing services to Quest Energy, and to align the economic
interests of such employees with the interests of Quest
Energys unitholders. The total number of common units
available to be awarded under the long-term incentive plan is
2,115,950. Common units cancelled, forfeited or withheld to
satisfy exercise prices or tax withholding obligations will be
available for delivery pursuant to other awards. The plan is
administered by the Committee, provided that administration may
be delegated to such other committee as appointed by Quest
Energy GPs board of directors. To date, no awards have
been made under this plan other than to the independent
directors of Quest Energy GP.
Benefits
Our employees, including the Named Executive Officers, who meet
minimum service requirements are entitled to receive medical,
dental, life and disability insurance benefits for themselves
(and beginning the first of the following month after
90 days of employment, 50% coverage for their dependents).
Our Named Executive Officers also participate along with other
employees in our 401(k) plan and other standard benefits. Our
401(k) plan provides for matching contributions by us and
permits discretionary contributions by us of up to 10% of a
participants eligible compensation. Such benefits are
provided equally to all employees, other than where benefits are
provided pro rata based on the respective Named Executive
Officers salary (such as the level of disability insurance
coverage).
Perquisites
We believe our executive compensation program described above is
generally sufficient for attracting talented executives and that
providing large perquisites is neither necessary nor in the
stockholders best interests. Certain perquisites are
provided to provide job satisfaction and enhance productivity.
For example, we provide an automobile for
Messrs. Lawler, Marlin and Lopus and provided an
automobile for Mr. Cash. On occasion, family members and
acquaintances accompanied Mr. Cash on business trips made
on private charter flights. The Named Executive Officers also
are eligible to receive gym and social club memberships and
subsidized parking. Messrs. Lawler and Collins received
reimbursements of certain relocation and temporary living
expenses in connection with their move to Oklahoma City,
Oklahoma in 2007 and 2008, respectively.
Ownership
Guidelines (Stock Ownership Policy)
Our Board of Directors, upon the Committees
recommendation, adopted a Stock Ownership Policy for our
corporate officers and directors (Guideline Owners)
to ensure that they have a meaningful economic stake in us. The
guidelines are designed to satisfy an individual Guideline
Owners need for portfolio diversification, while
maintaining management stock ownership at levels high enough to
assure our stockholders of managements commitment to value
creation.
The Committee annually reviews each Guideline Owners
compensation and stock ownership levels to confirm if
appropriate or make adjustments. The Committee requires that the
Guideline Owners have direct ownership of our common stock in at
least the following amounts:
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CEO
five times base salary
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Directors
four times cash compensation
(including committee fees)
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Direct CEO Reports
two and one-half
times base salary
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Corporate Officers (vice president or higher and
controller)
one and one-half times base
salary.
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A corporate officer has five years to comply with the ownership
requirement from the later of: (a) February 1, 2007 or
(b) the date the individual was appointed to a position
noted above. A director has five years to comply with the
ownership requirement from the later of:
(a) January 1, 2008 or (b) the date the
individual was appointed to be a
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director. If a corporate officer is promoted to a position with
a higher stock ownership salary multiple, the corporate officer
will have five years from the date of the change in position to
reach the higher expected stock ownership salary multiple, but
still must meet the prior expected stock ownership salary
multiple within the original five years of the date first
appointed to such prior position or February 1, 2007,
whichever is later.
Until a Guideline Owner achieves the applicable stock ownership
salary multiple, the following applies:
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Restricted Stock/Bonus Share Awards.
Upon
vesting of a restricted stock or bonus share award, the
Guideline Owner is required to hold the net profit shares until
the applicable Stock Ownership Guideline is met.
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Exercise of Options.
Upon exercise of a stock
option, the Guideline Owner is required to hold net profit
shares (less any shares used to pay the exercise price for the
shares) until the applicable Stock Ownership Guideline is met.
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Reporting of Taxes upon Vesting/Exercise.
The
Guideline Owner must report to the Corporate Secretary the
number of shares required by such Guideline Owner to pay the
applicable taxes upon the vesting of restricted stock or bonus
share awards or exercise of stock options in excess of the
minimum statutory taxes and any shares used to pay the exercise
price of any options.
|
Notwithstanding the foregoing, corporate officers are not
required to hold bonus shares that were originally granted prior
to January 1, 2007 or any bonus shares awarded pursuant to
the 2006 management annual incentive plan.
Required Ownership Shares.
Upon reaching the
required stock ownership salary multiple, the Guideline Owner
must certify to the Corporate Secretary that the ownership
requirements have been met and the Corporate Secretary must
confirm such representation and record the number of shares
required to be held by the Guideline Owner based on the closing
price of the shares and the corporate officers current
salary level or the directors current compensation level
on the day prior to certification by the Guideline Owner (the
Required Ownership Shares).
The Guideline Owner is not be required to accumulate any shares
in excess of the Required Ownership Shares so long as the
Required Ownership Shares are held by the Guideline Owner,
regardless of changes in the price of the shares. However, the
Guideline Owner may only sell shares held prior to certification
if, after the sale of shares, the Guideline Owner will
(a) still own a number of shares equal to at least the
Required Ownership Shares or (b) still be in compliance
with the stock ownership salary multiple as of the day the
shares are sold based on current share price and salary level.
Annual Review.
The Committee reviews all
Required Ownership Shares levels of the Guideline Owners covered
by the Policy on an annual basis. Deviations from the Stock
Ownership Policy can only be approved the Committee and then
only because of a personal hardship.
Policy
Regarding Hedging Stock Ownership
In April 2007, the Board of Directors, upon the Committees
recommendation, adopted a policy to prohibit directors,
executive officers and employees from speculating in our stock,
including, but not limited to, the following: short selling
(profiting if the market price of the stock decreases); buying
or selling publicly traded options, including writing covered
calls; taking out margin loans against stock options; and
hedging or any other type of derivative arrangement that has a
similar economic effect without the full risk or benefit of
ownership. In March 2009, the Board of Directors amended the
policy to also prohibit directors, executive officers and
employees from pledging any of our stock and taking out margin
loans against shares of our stock.
Compensation
Recovery Policies
The Board maintains a policy that it will evaluate in
appropriate circumstances whether to seek recovery of certain
compensation awards paid to our executive officers and any
profits realized from their sale of our securities if we are
required to prepare an accounting restatement due to our
material noncompliance, as a result of misconduct, with any
financial reporting requirement under the securities laws. This
policy ensures that if
130
circumstances warrant, we may seek to claw back appropriate
portions of our executive officers compensation for the
relevant period, as provided by law. This supplements the
SECs ability, under Section 304 of the Sarbanes-Oxley
Act of 2002, to claw back appropriate portions of the Chief
Executive Officers and Chief Financial Officers
compensation under the same circumstances.
Tax
and Accounting Considerations
U.S. federal tax laws (Section 162(m) of the Internal
Revenue Code of 1986, as amended) impose a limitation on our
U.S. income tax deductibility of Named Executive Officer
compensation, unless it is performance-based under
the tax rules. The Committee is concerned about the tax aspects
of restricted stock and bonus share grants because they are not
currently performance-based awards. The Committee will evaluate
and consider possible performance elements for future awards.
The Committee, however, does not believe the failure of Named
Executive Officers equity awards to qualify as performance based
awards to have a material impact on the Company at this time.
Executive
Compensation and Other Information
The table below sets forth information concerning the annual and
long-term compensation paid to or earned by Jerry Cash and David
Lawler, who each served as our principal executive officer
during 2008; David Grose and Jack Collins, who each served as
our principal financial officer during 2008; and the three other
most highly compensated executive officers who were serving as
executive officers as of December 31, 2008 (the Named
Executive Officers). The positions of the Named Executive
Officers listed in the table below are those positions held in
2008.
Summary
Compensation Table
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Non-Equity
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All
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Stock
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Option
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Incentive Plan
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Other
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Name and Principal Position
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Year
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Salary
|
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Bonus (1)
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Awards (2)
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Awards (3)
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Compensation (4)
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Compensation (5)
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Total
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Jerry D. Cash
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2008
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$
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349,731
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$
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100
|
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$
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(637,113
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)
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$
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22,225
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$
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11,534
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$
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(253,523
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)
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Chairman of the Board,
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2007
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$
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491,346
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$
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1,200
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$
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2,048,169
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|
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|
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$
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289,667
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$
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11,300
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$
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2,841,682
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President and Chief
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2006
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$
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400,000
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$
|
1,300
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|
|
$
|
14,000
|
|
|
|
|
|
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$
|
165,333
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$
|
11,054
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|
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$
|
591,687
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Executive Officer
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David Lawler(6)
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2008
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$
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344,616
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$
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390,244
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$
|
280,735
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$
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48,000
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|
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$
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104,917
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$
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50,205
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$
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1,218,717
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President, Chief Operating
Officer and Director
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2007
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$
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180,692
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$
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1,200
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|
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$
|
515,264
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|
|
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|
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$
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107,672
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$
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96,040
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$
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900,868
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|
|
|
|
|
|
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|
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|
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|
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David E. Grose
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2008
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$
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275,154
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$
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100
|
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$
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(140,993
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)
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$
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17,850
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$
|
11,538
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$
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163,649
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Chief Financial Officer
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2007
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$
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329,808
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$
|
1,200
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$
|
1,129,900
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|
|
|
|
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$
|
193,458
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|
|
$
|
11,300
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|
|
$
|
1,665,666
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|
|
|
|
2006
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|
|
$
|
270,240
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|
|
$
|
1,200
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|
|
$
|
203,890
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|
|
|
|
|
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$
|
113,667
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|
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$
|
11,054
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|
|
$
|
600,051
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|
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|
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Jack Collins(7)
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2008
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$
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152,500
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$
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28,600
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|
|
$
|
289,363
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|
|
$
|
19,619
|
|
|
$
|
52,042
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|
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$
|
49,994
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(8)
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$
|
592,118
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Interim Chief Financial
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Officer and Executive VP
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Finance/Corporate
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Development
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Richard Marlin
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2008
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$
|
254,486
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|
$
|
17,990
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$
|
154,302
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|
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|
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$
|
32,851
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|
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$
|
11,550
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|
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$
|
471,179
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Executive VP Engineering
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2007
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$
|
247,865
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|
|
$
|
1,500
|
|
|
$
|
270,421
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|
|
|
|
|
|
$
|
102,073
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|
|
$
|
11,300
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|
|
$
|
633,159
|
|
|
|
|
2006
|
|
|
$
|
247,500
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|
|
$
|
1,000
|
|
|
$
|
195,066
|
|
|
|
|
|
|
$
|
77,550
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|
|
$
|
11,054
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|
|
$
|
532,170
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
David Bolton
|
|
|
2008
|
|
|
$
|
230,885
|
|
|
$
|
57,848
|
|
|
$
|
196,108
|
|
|
|
|
|
|
$
|
29,805
|
|
|
$
|
24,542
|
|
|
$
|
539,188
|
|
Executive VP Land
|
|
|
2007
|
|
|
$
|
228,461
|
|
|
$
|
1,200
|
|
|
$
|
414,205
|
|
|
|
|
|
|
$
|
92,625
|
|
|
$
|
11,300
|
|
|
$
|
747,791
|
|
|
|
|
2006
|
|
|
$
|
100,961
|
|
|
$
|
1,000
|
|
|
$
|
65,856
|
|
|
|
|
|
|
$
|
39,588
|
|
|
$
|
2,746
|
|
|
$
|
210,151
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thomas Lopus (9)
|
|
|
2008
|
|
|
$
|
95,192
|
|
|
$
|
26,156
|
|
|
$
|
126,131
|
|
|
|
|
|
|
$
|
10,313
|
|
|
$
|
8
|
|
|
$
|
257,800
|
|
Executive Vice President
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
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|
|
|
|
|
|
Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
131
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(1)
|
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See Compensation Discussion and Analysis
Elements of Executive Compensation Program
Discretionary Bonuses, exclusive of the portion
constituting a tax
gross-up.
Also includes other miscellaneous bonuses available to all
employees totaling less than $1,500 per named executive officer.
|
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(2)
|
|
Includes expense related to bonus shares and restricted stock
granted under employment agreements. Expense for the bonus
shares and restricted stock is computed in accordance with the
provisions of Statement of Financial Accounting Standards
No. 123 (Revised) (SFAS No. 123R) and
represents the grant date fair value, which for our common stock
was determined by utilizing the closing stock price on the date
of grant, with expense being recognized ratably over the
requisite service period. Also includes equity portion of the
QRC Bonus Plan award earned for 2006. Twenty-five percent of the
bonus shares vested in March 2007 at the time the Committee
determined the amount of the awards based upon 2006 performance,
twenty-five percent of the bonus shares vested in March 2008 and
the remaining portion vests and will be paid in March of each of
the next two years. Amounts for Messrs. Cash and Grose in
2008 are negative due to forfeiture of unvested equity awards in
connection with the termination of their employment during
the year.
|
|
(3)
|
|
Includes expense related to stock options granted to
Mr. Lawler and Mr. Collins during 2008. Expense for
the stock options is computed in accordance with the provisions
of Statement of Financial Accounting Standards No. 123
(Revised) (SFAS No. 123R) and represents
the grant date fair value, which is calculated using the
Black-Scholes Option Pricing Model, with expense being
recognized ratably over the requisite service period. For a
discussion of valuation assumptions, see
Note 10 Stockholders Equity
Stock Awards of the notes to the consolidated
financial statements included in this
Form 10-K.
|
|
(4)
|
|
Represents the QRC Bonus Plan awards earned for 2007 and 2008
and paid in 2008 and 2009, as applicable, the cash portion of
the QRC Bonus Plan awards earned for 2006 and paid in 2007 and
productivity gain sharing bonus payments earned and paid in
2006, 2007 and 2008.
|
|
(5)
|
|
Company matching contribution under the 401(k) savings plan,
life insurance premiums, perquisites and personal benefits if
$10,000 or more for the year and, for Messrs. Lawler and
Bolton, tax withholding
gross-ups
related to discretionary bonuses paid in 2008 relating to the
failure of our former chief financial officer to execute on
10b-5(1)(c)
trading plans. See Compensation Discussion and
Analysis Elements of Executive Compensation
Program Discretionary Bonuses. Salary shown
above has not been reduced by pre-tax contributions to the
company-sponsored 401(k) savings plan. For 2008, Company
matching contributions were as follows:
Mr. Cash $11,500, Mr. Lawler
$10,193, Mr. Grose $11,500,
Mr. Collins $6,245, Mr. Marlin
$11,500, Mr. Bolton $9,437 and
Mr. Lopus $0. Tax withholding gross-up in
2008 for Mr. Lawler was $39,962 and for Mr. Bolton was $15,055.
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(6)
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|
Mr. Lawlers employment as our chief operating officer
commenced on April 10, 2007 and as our president effective
as of August 23, 2008.
|
|
(7)
|
|
Mr. Collinss employment as our executive vice
president of investor relations commenced on December 3,
2007 and as our interim chief financial officer and executive
vice president of finance/corporate development effective as of
August 23, 2008.
|
|
(8)
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|
Perquisites and personal benefits for 2008 consist of expenses
related to relocation expenses ($40,782), benefits for gym
services, parking and social club membership.
|
|
(9)
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|
Mr. Lopuss employment as our Executive Vice President
Appalachia commenced on July 16, 2008.
|
132
Grants
of Plan-Based Awards in 2008
This table discloses the actual number of stock options and
restricted stock awards granted during the last fiscal year, the
grant date fair value of these awards and the estimated payouts
under non-equity incentive plan awards.
Grants of
Plan-Based Awards in 2008
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|
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|
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|
|
|
|
|
|
|
|
|
|
Estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
future
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
payouts
|
|
All other
|
|
All other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
under
|
|
stock
|
|
option
|
|
|
|
Grant date
|
|
|
|
|
|
|
|
|
|
|
|
|
equity
|
|
awards:
|
|
awards:
|
|
Exercise
|
|
fair value
|
|
|
|
|
|
|
Estimated future payouts under
|
|
incentive
|
|
Number of
|
|
Number of
|
|
or base
|
|
of stock
|
|
|
|
|
|
|
non-equity incentive plan awards
|
|
plan awards
|
|
shares of
|
|
securities
|
|
price of
|
|
and
|
|
|
Approval
|
|
Grant
|
|
Threshold
|
|
Target
|
|
Maximum
|
|
Target
|
|
stock or
|
|
underlying
|
|
option
|
|
option
|
Name
|
|
Date
|
|
Date
|
|
($)
|
|
($)
|
|
($)
|
|
($)
|
|
units (#)
|
|
options (#)
|
|
awards ($/Sh)
|
|
awards(1)
|
|
Jerry Cash
|
|
|
|
|
|
|
(2
|
)
|
|
$
|
115,500
|
|
|
$
|
220,500
|
|
|
$
|
519,750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5/19/08
|
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
$
|
22,225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
David Lawler
|
|
|
|
|
|
|
(2
|
)
|
|
$
|
75,816
|
|
|
$
|
144,739
|
|
|
$
|
341,170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5/19/08
|
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
24,166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
$
|
16,917
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10/20/08
|
|
|
|
10/20/08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
200,000
|
(5)
|
|
$
|
0.71
|
|
|
$
|
122,000
|
|
David Grose
|
|
|
|
|
|
|
(2
|
)
|
|
$
|
77,000
|
|
|
$
|
147,000
|
|
|
$
|
346,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5/19/08
|
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
25,133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
$
|
17,850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jack Collins
|
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5/19/08
|
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
8,976
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
$
|
8,042
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10/20/08
|
|
|
|
10/23/08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100,000
|
(6)
|
|
$
|
0.48
|
|
|
$
|
41,000
|
|
Richard Marlin
|
|
|
|
|
|
|
(2
|
)
|
|
$
|
17,814
|
|
|
$
|
68,711
|
|
|
$
|
187,047
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5/19/08
|
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
17,808
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
$
|
14,797
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
David Bolton
|
|
|
|
|
|
|
(2
|
)
|
|
$
|
16,162
|
|
|
$
|
62,339
|
|
|
$
|
169,700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5/19/08
|
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
16,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
$
|
13,425
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thomas Lopus
|
|
|
|
|
|
|
(2
|
)
|
|
$
|
6,663
|
|
|
$
|
25,696
|
|
|
$
|
69,937
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
$
|
3,750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6/30/08
|
|
|
|
7/14/08
|
(7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45,000
|
|
|
|
|
|
|
|
|
|
|
$
|
441,450
|
|
|
|
|
(1)
|
|
The amounts included in the Grant date fair value of stock
and option awards column represents the grant date fair
value of the awards made to Named Executive Officers in 2008
computed in accordance with SFAS No. 123(R). The value
ultimately realized by the executive upon the actual vesting of
the award(s) or the exercise of the stock option(s) may or may
not be equal to the SFAS No. 123(R) determined value. For a
discussion of valuation assumptions, see
Note 10 Stockholders Equity
Stock Awards of the notes to the consolidated financial
statements included in this Form 10-K.
|
|
(2)
|
|
Represents an award under the QRC Bonus Plan for 2008. On
March 26, 2009, the Committee determined the amount of the
award payable for 2008 based upon 2008 performance. The amounts
for Messrs. Lawler, Collins, Marlin, Bolton and Lopus are
based upon their actual base salary paid during the year. The
amounts for Messrs. Cash and Grose represents the amounts
they would have been entitled to receive if they had remained
employed with the Company for the entire year at the salaries
provided for in their employment agreements. See
Compensation Discussion and Analysis Elements
of Executive Compensation Program Management Annual
Incentive Plan for a discussion of the performance
criteria applicable to these awards.
|
|
(3)
|
|
Represents amounts payable under the LTIP adopted by the Board
of Directors on May 19, 2008. The award for Mr. Cash
was an indeterminate number of shares based on the increase in
our adjusted average share price for 2008 over $9.74. As such, a
target amount for the award was not determinable. The amount of
Mr. Cashs award was capped at $3.0 million. For
the other Named Executive Officers, a bonus pool equal to three
percent of our consolidated income before income taxes, adjusted
to (1) add back depreciation, depletion and amortization
expenses and (2) exclude the effect of non-cash derivative
fair value gains or losses, for the applicable calendar year or
period (Measured Income) was to be divided among
plan participants based on their relative base
|
133
|
|
|
|
|
salaries. Each individual would then be issued that number of
shares equal to the dollar amount of their award divided by the
stock price as of the day the Compensation Committee finalized
the awards. For purposes of this table, the target amount is
based on the base salaries of all participants as of
May 19, 2008 and assumes QRCPs Measured Income was
equal to the budgeted amount. The LTIP program for 2008 was
terminated in January 2009 and no awards were paid to the Named
Executive Officers for 2008.
|
|
(4)
|
|
Represents amount payable under our productivity gain sharing
bonus program.
|
|
(5)
|
|
100,000 shares subject to the stock option were immediately
vested.
|
|
(6)
|
|
50,000 shares subject to the stock option were immediately
vested.
|
|
(7)
|
|
Represents an equity award granted in connection with the
execution of Mr. Lopuss employment agreement in 2008.
Grant date is the date the employment agreement was executed.
One-third of the award vests on July 16, 2009, 2010 and
2011.
|
134
Equity
Awards Outstanding at Fiscal Year-End 2008
The following table shows unvested stock awards and stock
options outstanding for the Named Executive Officers as of
December 31, 2008. Market value is based on the closing
market price of our common stock on December 31, 2008
($0.44 a share).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option Awards
|
|
Stock Awards
|
|
|
Number of
|
|
Number of
|
|
|
|
|
|
|
|
Market value
|
|
|
Securities
|
|
Securities
|
|
|
|
|
|
Number of
|
|
of shares or
|
|
|
Underlying
|
|
Underlying
|
|
|
|
|
|
shares or
|
|
units of stock
|
|
|
Unexercised
|
|
Unexercised
|
|
Option
|
|
Option
|
|
units that
|
|
that
|
|
|
Options
|
|
Options (#)
|
|
Exercise
|
|
Expiration
|
|
have not
|
|
have not
|
|
|
(#) Exercisable
|
|
Unexercisable
|
|
Price ($)
|
|
Date
|
|
vested
|
|
vested
|
|
Jerry Cash(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
David Lawler
|
|
|
100,000
|
|
|
|
100,000
|
(2)
|
|
$
|
0.71
|
|
|
|
10/20/18
|
|
|
|
60,000
|
(3)
|
|
$
|
26,400
|
|
David Grose(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jack Collins
|
|
|
50,000
|
|
|
|
50,000
|
(5)
|
|
$
|
0.48
|
|
|
|
10/23/18
|
|
|
|
40,000
|
(6)
|
|
$
|
17,600
|
|
Richard Marlin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31,376
|
(7)
|
|
$
|
13,805
|
|
Dave Bolton
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30,740
|
(8)
|
|
$
|
13,526
|
|
Thomas Lopus
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45,000
|
(9)
|
|
$
|
19,800
|
|
|
|
|
(1)
|
|
Mr. Cash forfeited all of his unvested stock awards when he
resigned all of his positions with us on August 23, 2008.
|
|
(2)
|
|
Option vests on October 20, 2009.
|
|
(3)
|
|
30,000 shares vest on each of May 1, 2009 and 2010.
|
|
(4)
|
|
All of Mr. Groses unvested stock awards were
forfeited in connection with the termination of his employment
on September 13, 2008.
|
|
(5)
|
|
Option vests on October 23, 2009.
|
|
(6)
|
|
20,000 shares vest on each of December 3, 2009 and
2010.
|
|
(7)
|
|
15,688 shares vest on each of March 16, 2009 and 2010.
|
|
(8)
|
|
15,370 shares vest on each of March 16, 2009 and 2010.
|
|
(9)
|
|
15,000 shares vest on each of July 16, 2009, 2010 and
2011.
|
Stock
Vested in 2008
The following table sets forth certain information regarding
stock awards vested during 2008 for the Named Executive
Officers.
|
|
|
|
|
|
|
|
|
|
|
Stock Awards
|
|
|
|
|
Number of shares of
|
|
|
|
|
common stock acquired
|
|
Value realized on
|
Name
|
|
on vesting (#)
|
|
vesting ($)
|
|
Jerry Cash
|
|
|
166,088
|
|
|
$
|
1,077,625
|
|
David Lawler
|
|
|
30,000
|
|
|
$
|
266,400
|
|
David Grose
|
|
|
36,188
|
|
|
$
|
231,544
|
|
Jack Collins
|
|
|
20,000
|
|
|
$
|
7,200
|
|
Richard Marlin
|
|
|
27,688
|
|
|
$
|
129,924
|
|
David Bolton
|
|
|
35,370
|
|
|
$
|
149,282
|
|
Thomas Lopus
|
|
|
|
|
|
|
|
|
For purposes of the above table, the amount realized upon
vesting is determined by multiplying the number of shares of
stock or units by the market value of the shares or units on the
date the shares vested.
135
Director
Compensation for 2008
The following table discloses the cash, equity awards and other
compensation earned, paid or awarded, as the case may be, to
each of our directors during the fiscal year ended
December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fees earned or
|
|
Stock Awards
|
|
|
Name
|
|
paid in cash ($)
|
|
($)(1)
|
|
Total ($)
|
|
James Kite
|
|
$
|
44,434
|
|
|
$
|
113,012(2
|
)
|
|
$
|
157,446
|
|
Jon Rateau
|
|
$
|
63,125
|
|
|
$
|
113,012(2
|
)
|
|
$
|
176,137
|
|
John Garrison
|
|
$
|
57,500
|
|
|
$
|
113,012(2
|
)
|
|
$
|
170,512
|
|
Malone Mitchell
|
|
$
|
13,750
|
|
|
|
(3
|
)
|
|
$
|
13,750
|
|
William Damon
|
|
$
|
51,585
|
|
|
$
|
192,372(4
|
)
|
|
$
|
243,957
|
|
Bob Alexander
|
|
$
|
21,586
|
|
|
|
|
|
|
$
|
21,586
|
|
Greg McMichael
|
|
$
|
444
|
|
|
|
|
|
|
$
|
444
|
|
|
|
|
(1)
|
|
Represents the dollar amount recognized for financial statement
reporting purposes for 2008 in accordance with FAS 123R.
|
|
(2)
|
|
In October 2005, Messrs. Kite, Rateau, and Garrison each
received a grant of an option for 50,000 shares of common
stock. Each option has a term of 10 years and an exercise
price of $10.00 per share. The FAS 123R grant date fair
value of each option award was $370,000. Options for
10,000 shares were immediately vested and the options for
the remaining 40,000 shares were to vest 10,000 per year
over the next four years; provided that the director was still
serving on the board of directors at the time of the vesting of
the stock options. However, as described below, in March 2008,
Messrs. Kite, Rateau, and Garrison each exchanged their 20,000
unvested stock options for 10,000 bonus shares of common
stock of the Company; 5,000 of these shares vested in October
2008 and 5,000 of these shares will vest in October 2009. The
incremental fair value of this exchange, computed in accordance
with FAS 123R, as of the exchange date was $51,600. On
June 19, 2008, Messrs. Kite, Rateau, and Garrison each
received a grant of 5,000 shares of common stock. The
FAS 123R grant date fair value of these shares was $36,000.
|
|
(3)
|
|
In August 2007, Mr. Mitchell received a grant of an option for
50,000 shares of common stock. The option had a term of
10 years and an exercise price of $10.05 per share. The
FAS 123R grant date fair value of the option award was
$398,000. Options for 10,000 shares were immediately vested
and the options for the remaining 40,000 shares were to
vest 10,000 per year over the next four years; provided that
Mr. Mitchell was still serving on the board of directors at
the time of the vesting of the stock options. However, as
described below, in March 2008, Mr. Mitchell exchanged his
40,000 unvested stock options for 20,000 bonus shares of common
stock of the Company. The incremental fair value of this
exchange, computed in accordance with FAS 123R, as of the
exchange date was $38,400. Mr. Mitchell resigned from the
board of directors on May 7, 2008, and forfeited all
20,000 bonus shares, so no compensation cost was recorded
in 2008.
|
|
(4)
|
|
In August 2007, Mr. Damon received a grant of an option for
50,000 shares of common stock. The option had a term of
10 years and an exercise price of $10.05 per share. The
FAS 123R grant date fair value of the option award was
$398,000. Options for 10,000 shares were immediately vested
and the options for the remaining 40,000 shares were to
vest 10,000 per year over the next four years; provided that
Mr. Damon was still serving on the board of directors at
the time of the vesting of the stock options. However, as
described below, in March 2008, Mr. Damon exchanged
his 40,000 unvested stock options for 20,000 bonus shares
of common stock of the Company; 5,000 of these shares vested in
August 2008 and 5,000 of these shares will vest in August of
2009, 2010 and 2011. The incremental fair value of this
exchange, computed in accordance with FAS 123R, as of the
exchange date was $38,400. On June 19, 2008, Mr. Damon
received a grant of 5,000 shares of common stock. The
FAS 123R grant date fair value of these shares was $36,000.
|
In addition to the stock and option awards described above, for
the fiscal year ended December 31, 2008, all of our
non-employee directors received an annual director fee of
$50,000 (the fees for Messrs. Mitchell, Alexander and
McMichael were pro rated for 2008 based on their length of
service). The chairman of the Audit Committee received an
additional $7,500 and the chairmen of the Compensation and
Nominating Committees each received an
136
additional $5,000. Additionally, Mr. Rateau was appointed
Chairman of the Board in September 2008 and received a $30,000
pro rated fee based on his length of service.
In March 2008, the Board of Directors approved the exchange of
each unvested stock option for one-half of a bonus share of
common stock of the Company, with the same vesting schedule as
their unvested options. The directors made the decision to
exchange the stock options for bonus shares in order to more
closely align the interests of the directors with those of the
stockholders. The directors also believed that the recent trend
in director compensation was to grant awards of bonus shares
rather than stock options. The exchange ratio was determined
based on market data provided by T-P. As a result of the
exchange, Messrs. Kite, Rateau and Garrison each received
10,000 bonus shares of our common stock and Messrs. Damon
and Mitchell each received 20,000 bonus shares of our common
stock. 5,000 of these shares vested in 2008 and 5,000 will vest
in 2009 for Messrs. Kite, Rateau and Garrison. 5,000 of
these shares will vest over each of the next three years for
Mr. Damon. Mr. Mitchell forfeited his shares when he
resigned in May 2008. Additionally, each of Messrs. Kite,
Rateau, Garrison and Damon was awarded 5,000 shares of
common stock following the 2008 annual meeting of our
stockholders. Mr. Mitchell resigned as a director in May
2008 and therefore did not receive an equity grant for 2008.
Mr. Alexander resigned in August 2008 before the shares
were issued to him and he relinquished any right to the shares
at that time.
In March 2009, the Board of Directors approved a change to the
structure of the non-employee directors fees, based on the
recommendation of the Committee. Under the new fee structure,
the annual retainer was increased to $125,000 effective as of
January 1, 2009. The Chairman of the Board will receive an
additional $30,000 per year, the chair of the Audit Committee
will receive an additional $10,000 per year and the chairs of
the other committees will receive $5,000 per year. No equity
awards will be paid to the non-employee directors for 2009 due
to the current low stock price and the large number of shares
that would need to be issued in connection with any significant
equity component.
Employment
Contracts
Each of the Named Executive Officers has or had an employment
agreement with us. Mr. Cash resigned all of his positions
with us in August 2008 and the employment agreement of
Mr. Grose was terminated in September 2008. Except as
described below, the employment agreements for each of the Named
Executive Officers are substantially similar.
Each of these agreements has an initial term of three years (the
Initial Term). In October 2008, the Initial Term of
the employment agreements for Messrs. Lawler and Collins
were extended until August 2011. Upon expiration of the Initial
Term, each agreement will automatically continue for successive
one-year terms, unless earlier terminated in accordance with the
terms of the agreement. The positions, base salary, number of
restricted
137
shares of our common stock, and shares for purchase pursuant to
stock options granted under each of the employment agreements is
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
Number of Shares
|
|
|
|
|
Expiration of
|
|
|
|
Shares of
|
|
for Purchase
|
|
|
|
|
Initial
|
|
|
|
Restricted
|
|
Pursuant to
|
Name
|
|
Position
|
|
Term
|
|
Base Salary
|
|
Stock
|
|
Stock Options
|
|
Jerry Cash
|
|
Chief Executive Officer
|
|
(1)
|
|
$
|
525,000
|
|
|
|
493,080
|
(2)
|
|
|
|
|
David Lawler
|
|
Chief Operating Officer and
|
|
August 2011
|
|
$
|
400,000
|
|
|
|
90,000
|
|
|
|
200,000
|
|
|
|
President
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
David Grose
|
|
Chief Financial Officer
|
|
(1)
|
|
$
|
350,000
|
|
|
|
105,000
|
(3)
|
|
|
|
|
Jack Collins
|
|
Interim Chief Financial
|
|
August 2011
|
|
$
|
200,000
|
|
|
|
60,000
|
|
|
|
100,000
|
|
|
|
Officer and Executive Vice President Finance/
Corporate Development
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
David Bolton
|
|
Executive Vice President
|
|
March 2010
|
|
$
|
225,000
|
|
|
|
45,000
|
|
|
|
|
|
|
|
Land
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Richard Marlin
|
|
Executive Vice
|
|
March 2010
|
|
$
|
248,000
|
|
|
|
45,000
|
|
|
|
|
|
|
|
President Engineering
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thomas Lopus
|
|
Executive Vice President
|
|
July 2011
|
|
$
|
225,000
|
|
|
|
45,000
|
|
|
|
|
|
|
|
Appalachia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Agreement has been terminated.
|
|
(2)
|
|
328,720 of these shares were forfeited at the time the agreement
was terminated.
|
|
(3)
|
|
All of these shares were cancelled at the time the agreement was
terminated.
|
One-third of the restricted shares vest on each of the first
three anniversary dates of each employment agreement. In
addition, Mr. Grose and Mr. Lawler received 70,000 and
15,000 unrestricted shares, respectively, of our common stock in
connection with the execution of their employment agreements.
In connection with the amendments to the employment agreements
of Messrs. Lawler and Collins in October 2008,
Mr. Lawler received a nonqualified stock option to purchase
200,000 shares of the Companys common stock at an
exercise price of $0.71 per share and Mr. Collins received
a non-qualified stock option to purchase 100,000 shares of
the Companys common stock at an exercise price of $0.48
per share. One-half of these options were immediately vested and
the other half will vest on the first anniversary date of the
applicable amendment. These options are included in the table
above.
Each executive is eligible to participate in all of our
incentive bonus plans that are established for our executive
officers. If we terminate an executives employment without
cause (as defined below) or if an executive
terminates his employment agreement for Good Reason (as defined
below), in each case after notice and cure periods
|
|
|
|
|
the executive will receive his base salary for the remainder of
the term,
|
|
|
|
we will pay the executives health insurance premium
payments for the duration of the COBRA continuation period
(18 months) or until he becomes eligible for health
insurance with a different employer,
|
|
|
|
the executive will receive his pro rata portion of any annual
bonus and other incentive compensation to which he would have
been entitled; and
|
|
|
|
his unvested shares of restricted stock will vest (which vesting
may be deferred for six months if necessary to comply with
Section 409A of the Internal Revenue Code).
|
Under each of the employment agreements, Good Reason means:
|
|
|
|
|
our failure to pay the executives salary or annual bonus
in accordance with the terms of the agreement (unless the
payment is not material and is being contested by us in good
faith);
|
138
|
|
|
|
|
if we require the executive to be based anywhere other than
Oklahoma City, Oklahoma (or, in the case of Mr. Lopus,
Pittsburgh, Pennsylvania);
|
|
|
|
a substantial or material reduction in the executives
duties or responsibilities; or
|
|
|
|
the executive no longer has the title specified above (though
this does not apply to Mr. Lopus and in the case of
Mr. Collins, Good Reason does not apply in the situation
where he no longer holds the interim chief financial officer
position as long as he continues to have a title, position and
duties not materially less than those of executive vice
president finance/corporate development).
|
For purposes of the employment agreements, cause
includes the following:
|
|
|
|
|
any act or omission by the executive that constitutes gross
negligence or willful misconduct;
|
|
|
|
theft, dishonest acts or breach of fiduciary duty that
materially enrich the executive or materially damage us or
conviction of a felony,
|
|
|
|
any conflict of interest, except those consented to in writing
by us;
|
|
|
|
any material failure by the executive to observe our work rules,
policies or procedures;
|
|
|
|
failure or refusal by the executive to perform his duties and
responsibilities required under the employment agreements, or to
carry out reasonable instruction, to our satisfaction;
|
|
|
|
any conduct that is materially detrimental to our operations,
financial condition or reputation; or
|
|
|
|
any material breach of the employment agreement by the executive.
|
The following summarizes potential maximum payments that an
executive could receive upon a termination of employment without
cause or for Good Reason, actual amounts are likely to be less.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unvested Equity
|
|
|
|
|
|
|
Name
|
|
Base Salary(1)
|
|
Compensation(2)
|
|
Bonus(3)
|
|
Benefits(4)
|
|
Total
|
|
David Lawler
|
|
$
|
1,057,534
|
|
|
$
|
53,400
|
|
|
$
|
336,000
|
|
|
$
|
21,522
|
|
|
$
|
1,468,456
|
|
Jack Collins
|
|
$
|
528,767
|
|
|
$
|
19,600
|
|
|
$
|
84,000
|
|
|
$
|
25,461
|
|
|
$
|
657,828
|
|
Richard Marlin
|
|
$
|
302,356
|
|
|
$
|
13,805
|
|
|
$
|
66,960
|
|
|
$
|
9,703
|
|
|
$
|
392,824
|
|
David Bolton
|
|
$
|
265,685
|
|
|
$
|
13,526
|
|
|
$
|
60,750
|
|
|
$
|
17,582
|
|
|
$
|
357,543
|
|
Thomas Lopus
|
|
$
|
570,205
|
|
|
$
|
19,800
|
|
|
$
|
60,750
|
|
|
$
|
17,582
|
|
|
$
|
668,337
|
|
|
|
|
(1)
|
|
Assumes full amount of remaining base salary payable under the
agreement as of December 31, 2008 is paid (with no renewal
of the term of the agreement). Actual amounts may be less.
|
|
(2)
|
|
For purposes of this table, we have used the number of unvested
stock awards and stock options as of December 31, 2008 and
the closing price of our common stock on that date ($0.44).
Assumes all such equity awards remain unvested on the date of
termination. No value was assigned to unvested stock options
since the exercise price exceeded the stock price on
December 31, 2008.
|
|
(3)
|
|
Represents target amounts payable under the QRC Bonus Plan for
2009. Assumes a full years bonus (i.e., if employment were
terminated on December 31 of a year). Actual payment would be
pro-rated based on the number of days in the year during which
the executive was employed. For Mr. Lawler, also assumes he will
be granted (i) a number of performance shares under the Omnibus
Plan having a value equal to 50% of the payment he would have
been paid under the QRC Bonus Plan and (ii) a number of
restricted shares under the Omnibus Plan having a value equal to
50% of the payment he would have been paid under the QRC Bonus
Plan.
|
|
(4)
|
|
Represents 18 months of insurance premiums at current rates.
|
On August 23, 2008, Jerry Cash resigned as our Chairman of
the Board, Chief Executive Officer and President. He was paid
his base salary through his last day of work, was not entitled
to receive any additional compensation pursuant to his
employment agreement and forfeited his rights in his unvested
equity awards. On September 13, 2008, David Groses
employment was terminated, and he was paid his base salary
through his last day of work, was
139
not entitled to receive any additional compensation pursuant to
his employment agreement and all of his equity awards granted
under his employment agreement were cancelled.
In general, base salary payments will be paid to the executive
in equal installments on our regular payroll dates, with the
installments commencing six months after the executives
termination of employment (at which time the executive will
receive a lump sum amount equal to the monthly payments that
would have been paid during such six month period). However, the
payments may be commenced immediately if an exemption under
Internal Revenue Code § 409A is available.
If the executives employment is terminated without cause
within two years after a change in control (as defined below),
then the base salary payments will be paid in a lump sum six
months after termination of employment.
Under the employment agreements, a change in control
is generally defined as:
|
|
|
|
|
the acquisition by any person or group of our common stock that,
together with shares of common stock held by such person or
group, constitutes more than 50% of the total voting power of
our common stock;
|
|
|
|
any person or group acquires (or has acquired during the
12-month
period ending on the date of the most recent acquisition by such
person or group) ownership of our common stock possessing 35% or
more of the total voting power of our common stock;
|
|
|
|
a majority of members of our board of directors being replaced
during any
12-month
period by directors whose appointment or election is not
endorsed by a majority of the members of our board of directors
prior to the date of the appointment or election; or
|
|
|
|
any person or group acquires (or has acquired during the
12-month
period ending on the date of the most recent acquisition by such
person or group) assets from us that have a total gross fair
market value equal to or more than 40% of the total gross fair
market value of all of our assets immediately prior to the
acquisition or acquisitions.
|
The pro rata portion of any annual bonus or other compensation
to which the executive would have been entitled for the year
during which the termination occurred will generally be paid at
the time bonuses are paid to all employees, but in no event
later than March 15th of the calendar year following the
calendar year the executive separates from service. However,
unless no exception to Internal Revenue Code § 409A
applies, payment will be made six months after the
executives termination of employment, if later.
If the executive is unable to render services as a result of
physical or mental disability, we may terminate his employment,
and he will receive a lump-sum payment equal to one years
base salary and all compensation and benefits that were accrued
and vested as of the date of termination. If necessary to comply
with Internal Revenue Code § 409A, the payment may be
deferred for six months.
Each of the employment agreements also provides for one-year
restrictive covenants of non-solicitation in the event the
executive terminates his own employment or is terminated by us
for cause. Our obligation to make severance payments is
conditioned upon the executive not competing with us during the
term that severance payments are being made.
Compensation
Committee Interlocks and Insider Participation
None of the persons who served on our Compensation Committee
during the last completed fiscal year (Jon H. Rateau, John C.
Garrison, James B. Kite, Jr., William H. Damon III and
Greg McMichael) (i) was an officer or employee of the
Company during the last fiscal year or (ii) had any
relationship requiring disclosure under Item 404 of
Regulation S-K.
Except for Mr. Garrison, who previously served as our
Treasurer from 1998 to 2001, none of the persons who served on
our Compensation Committee during the last completed fiscal year
was formerly an officer of the Company.
None of our executive officers, during the last completed fiscal
year, served as a (i) member of the compensation committee
of another entity, one of whose executive officers served on our
Compensation Committee; (ii) director of another entity,
one of whose executive officers served on our Compensation
Committee; or (iii) member of the compensation committee of
another entity, one of whose executive officers served as our
director.
140
Compensation
Committee Report
The Compensation Committee has reviewed and discussed the
Compensation Discussion and Analysis set forth above with
management, and based on such review and discussions, the
Compensation Committee has recommended to the Board of Directors
of the Company that such Compensation Discussion and Analysis be
included in the Companys Annual Report on
Form 10-K
and the Companys Proxy Statement.
Greg McMichael, Chairman
William H. Damon III
James B. Kite, Jr.
Jon H. Rateau
John C. Garrison
Note: Mr. Rateau served on the Compensation Committee and
was its chairman until September 4, 2008. Mr. Damon
served on the Compensation Committee for all of 2008 and was its
chairman from September 4, 2008 until December 29,
2008. Mr. Garrison served on the Compensation Committee
from September 4, 2008 until December 29, 2008.
Mr. McMichael joined the board of directors on
December 29, 2008, at which time he was appointed chairman
of the Compensation Committee. As such, Messrs. McMichael
and Garrison had only limited involvement in the compensation
decisions related to 2008.
|
|
ITEM 12.
|
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS.
|
The following table sets forth information as of May 15,
2009 concerning the shares of our common stock beneficially
owned by (i) each person known by us, solely by reason of
our examination of Schedule 13D and 13G filings made with
the SEC and by information voluntarily provided to us by certain
stockholders, to be the beneficial owner of 5% or more of our
outstanding common stock, (ii) each of our directors,
(iii) each of the executive officers named in the summary
compensation table and (iv) all current directors and
executive officers as a group. If a person or entity listed in
the following table is the beneficial owner of less than one
percent of the securities outstanding, this fact is indicated by
an asterisk in the table.
|
|
|
|
|
|
|
|
|
|
|
Number of Shares of
|
|
|
|
|
Quest Resource
|
|
|
|
|
Corporation Common
|
|
Percent
|
|
|
Stock
|
|
of Class of Quest
|
|
|
Beneficially
|
|
Resource Corporation
|
Name and Address of Beneficial Owner
|
|
Owned(1)
|
|
Common Stock
|
|
Advisory Research, Inc.(2)
180 North Stetson, Suite 5500
Chicago, IL 60601
|
|
|
2,889,400
|
|
|
|
9.1
|
%
|
Jerry D. Cash(3)
|
|
|
1,463,270
|
|
|
|
4.6
|
%
|
James B. Kite, Jr.(4)(5)
|
|
|
956,157
|
|
|
|
3.0
|
%
|
David C. Lawler(6)
|
|
|
183,415
|
|
|
|
|
*
|
Jack T. Collins(7)
|
|
|
113,000
|
|
|
|
|
*
|
John C. Garrison(4)(8)
|
|
|
106,053
|
|
|
|
|
*
|
Richard Marlin(9)
|
|
|
61,012
|
|
|
|
|
*
|
David Grose(10)
|
|
|
56,080
|
|
|
|
|
*
|
David W. Bolton(11)
|
|
|
47,776
|
|
|
|
|
*
|
Thomas A. Lopus(12)
|
|
|
45,000
|
|
|
|
|
*
|
Jon H. Rateau(4)(13)
|
|
|
40,000
|
|
|
|
|
*
|
William H. Damon III(14)
|
|
|
20,000
|
|
|
|
|
*
|
Greg McMichael
|
|
|
|
|
|
|
|
|
All Current Directors and Executive Officers as a Group
(11 Persons)
|
|
|
1,572,413
|
|
|
|
4.9
|
%
|
141
|
|
|
(1)
|
|
The number of securities beneficially owned by the persons or
entities above is determined under rules promulgated by the SEC
and the information is not necessarily indicative of beneficial
ownership for any other purpose. Under such rules, beneficial
ownership includes any securities as to which the person or
entity has sole or shared voting power or investment power and
also any securities that the person or entity has the right to
acquire within 60 days through the exercise of any option
or other right. The inclusion herein of such securities,
however, does not constitute an admission that the named
equityholder is a direct or indirect beneficial owner of such
securities. Unless otherwise indicated, each person or entity
named in the table has sole voting power and investment power
(or shares such power with his or her spouse) with respect to
all securities listed as owned by such person or entity.
|
|
(2)
|
|
Advisory Research, Inc. (ARI) is the general partner
and investment manager of Advisory Research Micro Cap Value
Fund, L.P. (Advisory Micro Cap) (which owns
1,503,421 shares of our common stock) and Advisory Research
Energy Fund, L.P. (Advisory Energy) (which owns
533,874 shares of our common stock) and is registered under
the Investment Advisers Act of 1940. By virtue of investment
management agreements with each of Advisory Micro Cap, Advisory
Energy, and other discretionary client funds, ARI is deemed to
have beneficial ownership over the 2,889,400 shares.
|
|
(3)
|
|
Includes (i) 1,200 shares of our common stock owned by
Mr. Cashs wife, Sherry J. Cash and
(ii) 7,678 shares held in Mr. Cashs
retirement account (Mr. Cash does not have voting rights
with respect to the shares held in his profit sharing retirement
account). Mr. Cash disclaims beneficial ownership of the
shares owned by Sherry J. Cash. Mr. Cash did not respond to
our request to confirm the exact beneficial ownership
information and, as a result, it is based on his most recent
Form 4 adjusted for forfeitures; however, he has advised us
that all of the shares of our common stock beneficially owned by
him have been pledged to secure a personal loan.
|
|
(4)
|
|
Includes options to acquire 30,000 shares of our common
stock that are immediately exercisable.
|
|
(5)
|
|
Includes 916,157 shares of our common stock owned by McKown
Point LP, a Texas Limited Partnership. Easterly Family
Investments LLC is the sole general partner of McKown Point LP.
Easterly Family Investments LLC is wholly owned by the Virginia
V. Kite GST Exempt Trust for James B. Kite, Jr. Mr. Kite
and Bank of Texas, N.A. are the trustees of the Virginia V. Kite
GST Exempt Trust for James B. Kite, Jr. Easterly Family
Investments LLC, the Virginia V. Kite GST Exempt Trust for James
B. Kite, Jr. and James B. Kite, Jr. may be deemed to have
beneficial ownership of the shares owned by McKown Point LP. In
addition, Mr. Kite is entitled to receive 5,000 bonus
shares upon satisfaction of certain vesting requirements.
Mr. Kite does not have the ability to vote these bonus
shares.
|
|
(6)
|
|
Includes 30,000 restricted shares, which are subject to vesting,
and options to acquire 100,000 shares of our common stock
that are immediately exercisable.
|
|
(7)
|
|
Includes 40,000 restricted shares, which are subject to vesting,
and options to acquire 50,000 shares of our common stock
that are immediately exercisable.
|
|
(8)
|
|
Mr. Garrison is also entitled to receive 5,000 bonus shares
upon satisfaction of certain vesting requirements.
Mr. Garrison does not have the ability to vote these bonus
shares.
|
|
(9)
|
|
Includes 15,000 restricted shares, which are subject to vesting.
In addition, Mr. Marlin is entitled to receive 688 bonus
shares upon satisfaction of certain vesting requirements.
Mr. Marlin does not have the ability to vote these bonus
shares.
|
|
(10)
|
|
Includes 3,281 shares of our common stock held in
Mr. Groses retirement account (Mr. Grose does
not have voting rights with respect to these shares).
Mr. Grose did not respond to our request to confirm the
exact beneficial ownership information and, as a result it is
based on his most recent Form 4 adjusted for shares
cancelled in connection with the termination of his employment.
|
|
(11)
|
|
Includes 15,000 restricted shares, which are subject to vesting.
In addition, Mr. Bolton is entitled to receive 370 bonus
shares upon satisfaction of certain vesting requirements.
Mr. Bolton does not have the ability to vote these bonus
shares.
|
|
(12)
|
|
Consists of 45,000 restricted shares, which are subject to
vesting.
|
|
(13)
|
|
Mr. Rateau is also entitled to receive 5,000 bonus shares
upon satisfaction of certain vesting requirements.
Mr. Rateau does not have the ability to vote these bonus
shares.
|
142
|
|
|
(14)
|
|
Includes options to acquire 10,000 shares of our common
stock that are immediately exercisable. In addition,
Mr. Damon is entitled to receive 5,000 bonus shares upon
satisfaction of certain vesting requirements. Mr. Damon
does not have the ability to vote these bonus shares.
|
Equity
Compensation Plans
The table below sets forth information concerning compensation
plans under which equity securities are authorized for issuance
as of the fiscal year ended December 31, 2008.
Equity
Compensation Plan Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of securities
|
|
|
|
Number of securities to
|
|
|
Weighted-average
|
|
|
remaining available for
|
|
|
|
be issued upon exercise
|
|
|
exercise price of
|
|
|
future issuance under
|
|
|
|
of outstanding options,
|
|
|
outstanding options,
|
|
|
equity compensation
|
|
Plan category
|
|
warrants and rights
|
|
|
warrants and rights
|
|
|
plans
|
|
|
Equity compensation plans approved by security holders(1)
|
|
|
310,000
|
|
|
$
|
0.94
|
|
|
|
1,349,859(3
|
)
|
Equity compensation plans not approved by security holders(2)
|
|
|
90,000
|
|
|
$
|
10.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
400,000
|
|
|
$
|
2.98
|
|
|
|
1,349,859
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Consists of (a) 10,000 immediately vested
10-year
options issued to one of our non-employee directors
(Mr. Damon) in August 2007 with an exercise price of $10.05
per share; (b) 200,000
10-year
options issued to Mr. Lawler in October 2008, one-half of which
were immediately vested and one-half of which will vest on the
first anniversary of the date of grant, with an exercise price
of $0.71; and (c) 100,000
10-year
options issued to Mr. Collins in October 2008, one-half of
which were immediately vested and one-half of which will vest on
the first anniversary of the date of grant, with an exercise
price of $0.48.
|
|
(2)
|
|
Consists of 30,000 options issued to each of our non-employee
directors (Messrs. Kite, Garrison and Rateau) in October
2005. For each director, 10,000 of the options were immediately
vested and 10,000 of the remaining options vested on the first
two anniversaries of the date of grant. The options have a term
of 10 years and an exercise price of $10.00 per share.
|
|
(3)
|
|
Excludes securities to be issued upon exercise of outstanding
options, warrants and rights. Amount includes 78,669 unvested
and unissued shares awarded under our management incentive plan
that are subject to forfeiture.
|
|
|
ITEM 13.
|
CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE.
|
Related
Transactions
No director, executive officer or stockholder who is known to us
to own of record or beneficially own more than five percent of
our common stock, or any member of the immediate family of such
director, executive officer or stockholder, had a direct or
indirect material interest in any transaction since the
beginning of the year ended December 31, 2008, or any
currently proposed transaction, in which we or one of our
subsidiaries is a party and the amount involved exceeds $120,000.
See Note 15 Related Party Transactions to the
accompanying consolidated financial statements for descriptions
of certain unauthorized transactions made by our former chief
executive officer and two former officers.
Policy
Regarding Transactions with Related Persons
We do not have a formal, written policy for the review, approval
or ratification of transactions between us and any director or
executive officer, nominee for director, 5% stockholder or
member of the immediate family of any
143
such person that are required to be disclosed under
Item 404(a) of
Regulation S-K.
However, our policy is that any activities, investments or
associations of a director or officer that create, or would
appear to create, a conflict between the personal interests of
such person and our interests must be assessed by our Chief
Financial Officer or the Audit Committee.
Director
Independence
Our Board of Directors has determined that each of our
directors, except Mr. Lawler, is an independent director,
as defined in the applicable rules and regulations of The NASDAQ
Global Market, including Rule 5605(a)(2) of the Marketplace
Rules of the NASDAQ Stock Market LLC.
ITEM 14.
PRINCIPAL
ACCOUNTING FEES AND SERVICES.
Audit and
Non-Audit Fees
On August 1, 2008, MHM resigned as our independent
registered public accounting firm as a result of its operations
having been acquired by Eide Bailly. We engaged Eide Bailly on
that date as our independent registered public accounting firm.
On September 25, 2008, Eide Bailly notified us that it was
resigning as our independent registered accounting firm
effective upon the earlier of the date of the filing of the
Companys
Form 10-Q
for the period ended September 30, 2008, or
November 10, 2008. On October 23, 2008, our Board of
Directors approved the recommendation of the Audit Committee to
appoint UHY as our independent registered public accounting firm.
The following table lists fees billed by MHM, Eide Bailly and
UHY for services rendered during the years ended
December 31, 2007 and 2008.
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Audit Fees(1)
|
|
$
|
514,593
|
|
|
$
|
354,738
|
|
Audit-Related Fees(2)
|
|
|
316,561
|
|
|
|
3,100
|
|
Tax Fees(3)
|
|
|
174,195
|
|
|
|
117,891
|
|
All Other Fees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fees
|
|
$
|
1,005,349
|
|
|
$
|
475,729
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.
|
Audit Fees include fees billed for services performed to comply
with Generally Accepted Auditing Standards (GAAS), including the
recurring audit of our consolidated financial statements for
such period included in the Annual Report on
Form 10-K
and for the reviews of the consolidated quarterly financial
statements included in the Quarterly Reports on
Form 10-Q
filed with the SEC. This category also includes fees for audits
provided in connection with statutory filings or procedures
related to the audit of income tax provisions and related
reserves, consents and assistance with and review of documents
filed with the SEC. During 2008, UHY billed us $215,327 for
audit fees.
|
|
|
2.
|
Audit-Related Fees include fees for services associated with
assurance and reasonably related to the performance of the audit
or review of our financial statements. This category includes
fees related to assistance in financial due diligence related to
mergers and acquisitions, consultations regarding GAAP, reviews
and evaluations of the impact of new regulatory pronouncements,
general assistance with implementation of Sarbanes-Oxley Act of
2002 requirements and audit services not required by statute or
regulation. This category also includes audits of pension and
other employee benefit plans, as well as the review of
information systems and general internal controls unrelated to
the audit of the financial statements. During 2008, UHY did not
bill us any amount for audit-related fees.
|
|
|
3.
|
Tax fees consist of fees related to the preparation and review
of our federal and state income tax returns and tax consulting
services. During 2008, UHY did not bill us any amount for tax
fees.
|
The Audit Committee has concluded the provision of the non-audit
services listed above as Audit-Related Fees and
Tax Fees is compatible with maintaining the
auditors independence and has approved all of the fees
discussed above.
144
All services to be performed by the independent public
accountants must be pre-approved by the Audit Committee, which
has chosen not to adopt any pre-approval policies for enumerated
services and situations, but instead has retained the sole
authority for such approvals.
PART IV
ITEM 15.
EXHIBITS,
FINANCIAL STATEMENT SCHEDULES.
(a)(1) and (2)
Financial
Statements.
See Index to Financial
Statements set forth on page F-1 of this
Form 10-K.
(a)(3)
Index to Exhibits.
Exhibits
requiring attachment pursuant to Item 601 of
Regulation S-K
are listed in the Index to Exhibits beginning on page 147
of this
Form 10-K
that is incorporated herein by reference.
145
QUEST
RESOURCE CORPORATION
Index To Financial Statements
|
|
|
|
|
|
|
|
F-2
|
|
|
|
|
F-3
|
|
|
|
|
F-6
|
|
|
|
|
F-7
|
|
|
|
|
F-8
|
|
|
|
|
F-9
|
|
|
|
|
F-10
|
|
F-1
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Quest Resource
Corporation:
We have audited the accompanying consolidated balance sheets of
Quest Resource Corporation and subsidiaries (the Company) as of
December 31, 2008, 2007 and 2006, and the related
consolidated statements of operations, cash flows and
stockholders (deficit) equity for each of the four years
in the period ended December 31, 2008. These financial
statements are the responsibility of the Companys
management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of
Quest Resource Corporation and subsidiaries at December 31,
2008, 2007 and 2006, and the results of their operations and
their cash flows for each of the four years in the period ended
December 31, 2008, in conformity with accounting principles
generally accepted in the United States of America.
The accompanying consolidated financial statements for the year
ended December 31, 2008, have been prepared assuming that
the Company will continue as a going concern. As discussed in
Note 1 to the consolidated financial statements, the
Companys recurring losses from operations, accumulated
deficit, and inability to generate sufficient cash flow to meet
its obligations and sustain its operations raise substantial
doubt about its ability to continue as a going concern.
Managements plans concerning these matters are also
discussed in Note 1 to the consolidated financial
statements. The consolidated financial statements do not include
any adjustments that might result from the outcome of this
uncertainty.
As discussed in Notes 1 and 18 to the consolidated
financial statements, the Company has restated its previously
issued consolidated financial statements as of December 31,
2007, 2006 and for the years ended December 31, 2007, 2006
and 2005, which were audited by other auditors.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
Companys internal control over financial reporting as of
December 31, 2008, based on the criteria established in
Internal Control Integrated Framework
issued
by the Committee of Sponsoring Organizations of the Treadway
Commission and our report dated June 2, 2009 expressed an
adverse opinion on the Companys internal control over
financial reporting.
/s/ UHY LLP
Houston, Texas
June 2, 2009
F-2
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Quest Resource
Corporation:
We have audited Quest Resource Corporation and
subsidiaries (the Company) internal control over financial
reporting as of December 31, 2008, based on criteria
established by the Committee of Sponsoring Organizations of the
Treadway Commission. Quest Resource Corporations
management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting,
included in the accompanying Managements Annual Report on
Internal Control over Financial Reporting. Our responsibility is
to express an opinion on the Companys internal control
over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk
that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on
that risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit
provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a
process designed by, or under the supervision of, the
companys principal executive and principal financial
officers, or persons performing similar functions, and effected
by the companys board of directors, management, and other
personnel to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles (GAAP). A
companys internal control over financial reporting
includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions
of the assets of the company; (2) provide reasonable
assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance
with authorizations of management and directors of the company;
and (3) provide reasonable assurance regarding prevention
or timely detection of unauthorized acquisition, use, or
disposition of the companys assets that could have a
material effect on the financial statements.
Because of the inherent limitations of internal control over
financial reporting, including the possibility of collusion or
improper management override of controls, material misstatements
due to error or fraud may not be prevented or detected on a
timely basis. Also, projections of any evaluation of the
effectiveness of the internal control over financial reporting
to future periods are subject to the risk that the controls may
become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may
deteriorate.
Material weaknesses related to ineffective controls over the
period-end financial reporting process have been identified and
included in managements assessment. These material
weaknesses were considered in determining the nature, timing,
and extent of audit tests applied in our audit of the
consolidated financial statements as of and for the year ended
December 31, 2008. This report does not affect our report
on such financial statements. A material weakness is a control
deficiency, or combination of control deficiencies, that results
in more than a remote likelihood that a material misstatement of
the annual or interim financial statements will not be prevented
or detected. The following material weaknesses have been
identified and included in managements assessment as of
December 31, 2008:
(1)
Control environment
The Company did
not maintain an effective control environment. The control
environment which is the responsibility of senior management,
sets the tone of the organization, influences the control
consciousness of its people, and is the foundation for all other
components of internal control over financial reporting. Each of
these control environment material weaknesses contributed to the
material weaknesses discussed in items (2) through
(8) below. The Company did not maintain an effective
control environment because of the following material weaknesses:
(a) The Company did not maintain a tone and control
consciousness that consistently emphasized adherence to accurate
financial reporting and enforcement of Company policies and
procedures. This
F-3
control deficiency fostered a lack of sufficient appreciation
for internal controls over financial reporting, allowed for
management override of internal controls in certain
circumstances and resulted in an ineffective process for
monitoring the adherence of the Companys policies and
procedures.
(b) The Company did not maintain a sufficient complement of
personnel with an appropriate level of accounting knowledge,
experience, and training in the application of GAAP commensurate
with its financial reporting requirements and business
environment.
(c) The Company did not maintain an effective anti-fraud
program designed to detect and prevent fraud relating to
(i) an effective whistle-blower program,
(ii) consistent background checks of personnel in positions
of responsibility, and (iii) an ongoing program to manage
identified fraud risks.
The control environment material weaknesses described above
contributed to the material weaknesses related to the transfers
that were the subject of the internal investigation and to its
internal control over financial reporting, period end financial
close and reporting, accounting for derivative instruments,
stock compensation costs, depreciation, depletion and
amortization, impairment of oil and gas properties and cash
management described in items (2) to (8) below.
(2)
Internal control over financial reporting
The Company did not maintain effective
monitoring controls to determine the adequacy of its internal
control over financial reporting and related policies and
procedures because of the following material weaknesses:
(a) The Companys policies and procedures with respect
to the review, supervision and monitoring of its accounting
operations throughout the organization were either not designed
and in place or not operating effectively.
(b) The Company did not maintain an effective internal
control monitoring function. Specifically, there were
insufficient policies and procedures to effectively determine
the adequacy of the Companys internal control over
financial reporting and monitoring the ongoing effectiveness
thereof.
Each of these material weaknesses relating to the monitoring of
the Companys internal control over financial reporting
contributed to the material weaknesses described in items
(3) through (8) below.
(3)
Period end financial close and reporting
The Company did not establish and maintain
effective controls over certain of its period-end financial
close and reporting processes because of the following material
weaknesses:
(a) The Company did not maintain effective controls over
the preparation and review of the interim and annual
consolidated financial statements and to ensure that it
identified and accumulated all required supporting information
to ensure the completeness and accuracy of the consolidated
financial statements and that balances and disclosures reported
in the consolidated financial statements reconciled to the
underlying supporting schedules and accounting records.
(b) Company did not maintain effective controls to ensure
that it identified and accumulated all required supporting
information to ensure the completeness and accuracy of the
accounting records.
(c) The Company did not maintain effective controls over
the preparation, review and approval of account reconciliations.
Specifically, the Company did not have effective controls over
the completeness and accuracy of supporting schedules for
substantially all financial statement account reconciliations.
(d) The Company did not maintain effective controls over
the complete and accurate recording and monitoring of
intercompany accounts. Specifically, effective controls were not
designed and in place to ensure that intercompany balances were
completely and accurately classified and reported in the
Companys underlying accounting records and to ensure
proper elimination as part of the consolidation process.
(e) The Company did not maintain effective controls over
the recording of journal entries, both recurring and
non-recurring. Specifically, effective controls were not
designed and in place to ensure that
F-4
journal entries were properly prepared with sufficient support
or documentation or were reviewed and approved to ensure the
accuracy and completeness of the journal entries recorded.
(4)
Derivative instruments
The Company
did not establish and maintain effective controls to ensure the
correct application of GAAP related to derivative instruments.
Specifically, the Company did not adequately document the
criteria for measuring hedge effectiveness at the inception of
certain derivative transactions and did not subsequently value
those derivatives appropriately.
(5)
Stock compensation cost
The Company
did not establish and maintain effective controls to ensure
completeness and accuracy of stock compensation costs.
Specifically, effective controls were not designed and in place
to ensure that documentation of the terms of the awards were
reviewed in order to be recorded accurately.
(6)
Depreciation, depletion and amortization
The Company did not establish and maintain
effective controls to ensure completeness and accuracy of
depreciation, depletion and amortization expense. Specifically,
effective controls were not designed and in place to calculate
and review the depletion of oil and gas properties.
(7)
Impairment of oil and gas properties
The Company did not establish and maintain
effective controls to ensure the accuracy and application of
GAAP related to the capitalization of costs related to oil and
gas properties and the required evaluation of impairment of such
costs. Specifically, effective controls were not designed and in
place to determine, review and record the nature of items
recorded to oil and gas properties and the calculation of oil
and gas property impairments.
(8)
Cash management
The Company did not
establish and maintain effective controls to adequately
segregate the duties over cash management. Specifically,
effective controls were not designed to prevent the
misappropriation of cash.
Additionally, each of the control deficiencies described in
items (1) through (8) above could result in a
misstatement of the aforementioned account balances or
disclosures that would result in a material misstatement to the
annual or interim consolidated financial statements that would
not be prevented or detected. Management has determined that
each of the control deficiencies in items (1) through
(8) above constitutes a material weakness. These material
weaknesses were considered in determining the nature, timing,
and extent of audit tests applied in our audit of the 2008
consolidated financial statements, and our opinion regarding the
effectiveness of the Companys internal control over
financial reporting does not affect our opinion on those
consolidated financial statements.
In our opinion, because of the effect of the material weaknesses
identified above on the achievement of the objectives of the
control criteria, the Company has not maintained effective
internal control over financial reporting as of
December 31, 2008, based on the criteria established in
Internal Control Integrated Framework
issued
by the Committee of Sponsoring Organizations of the Treadway
Commission.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets and the related consolidated
statements of operations, cash flows, and stockholders
(deficit) equity of the Company as of December 31, 2006,
2007 and 2008 and for the years ended December 31, 2008.
Our report dated June 2, 2009 expressed an unqualified
opinion on those financial statements and included (1) an
explanatory paragraph expressing substantial doubt about the
Companys ability to continue as a going concern and
(2) an explanatory paragraph related to the Companys
restatement of the 2007, 2006, and 2005 financial statements.
/s/ UHY LLP
Houston, Texas
June 2, 2009
F-5
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
($ in thousands, except share and per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
13,785
|
|
|
$
|
6,680
|
|
|
$
|
33,820
|
|
Restricted cash
|
|
|
559
|
|
|
|
1,236
|
|
|
|
1,150
|
|
Accounts receivable trade, net
|
|
|
16,715
|
|
|
|
15,557
|
|
|
|
9,651
|
|
Other receivables
|
|
|
9,434
|
|
|
|
1,480
|
|
|
|
235
|
|
Other current assets
|
|
|
2,858
|
|
|
|
3,962
|
|
|
|
1,076
|
|
Inventory
|
|
|
11,420
|
|
|
|
6,622
|
|
|
|
5,632
|
|
Current derivative financial instrument assets
|
|
|
42,995
|
|
|
|
8,008
|
|
|
|
14,109
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
97,766
|
|
|
|
43,545
|
|
|
|
65,673
|
|
Oil and gas properties under full cost method of accounting, net
|
|
|
172,537
|
|
|
|
300,953
|
|
|
|
241,278
|
|
Pipeline assets, net
|
|
|
310,439
|
|
|
|
294,526
|
|
|
|
126,654
|
|
Other property and equipment, net
|
|
|
23,863
|
|
|
|
21,505
|
|
|
|
16,680
|
|
Other assets, net
|
|
|
14,735
|
|
|
|
8,541
|
|
|
|
9,629
|
|
Long-term derivative financial instrument assets
|
|
|
30,836
|
|
|
|
3,467
|
|
|
|
8,022
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
650,176
|
|
|
$
|
672,537
|
|
|
$
|
467,936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
35,804
|
|
|
$
|
31,202
|
|
|
$
|
16,411
|
|
Revenue payable
|
|
|
8,309
|
|
|
|
7,725
|
|
|
|
4,989
|
|
Accrued expenses
|
|
|
7,138
|
|
|
|
8,387
|
|
|
|
786
|
|
Current portion of notes payable
|
|
|
45,013
|
|
|
|
666
|
|
|
|
324
|
|
Current derivative financial instrument liabilities
|
|
|
12
|
|
|
|
8,108
|
|
|
|
8,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
96,276
|
|
|
|
56,088
|
|
|
|
31,389
|
|
Non-current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term derivative financial instrument liabilities
|
|
|
4,230
|
|
|
|
6,311
|
|
|
|
10,878
|
|
Asset retirement obligations
|
|
|
5,922
|
|
|
|
2,938
|
|
|
|
1,410
|
|
Notes payable
|
|
|
343,094
|
|
|
|
233,046
|
|
|
|
225,245
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
353,246
|
|
|
|
242,295
|
|
|
|
237,533
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority interests
|
|
|
204,536
|
|
|
|
297,385
|
|
|
|
84,173
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock, $0.001 par value; authorized shares
50,000,000; none issued and outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock, $0.001 par value; authorized shares
200,000,000; issued 32,224,643, 23,553,230 and
22,365,883 at December 31, 2008, 2007 and 2006;
outstanding 31,720,312, 22,471,355, and 22,248,883
at December 31, 2008, 2007 and 2006, respectively
|
|
|
33
|
|
|
|
24
|
|
|
|
22
|
|
Additional paid-in capital
|
|
|
298,583
|
|
|
|
211,852
|
|
|
|
205,772
|
|
Treasury stock at cost
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
Accumulated deficit
|
|
|
(302,491
|
)
|
|
|
(135,107
|
)
|
|
|
(90,953
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders (deficit) equity
|
|
|
(3,882
|
)
|
|
|
76,769
|
|
|
|
114,841
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders (deficit) equity
|
|
$
|
650,176
|
|
|
$
|
672,537
|
|
|
$
|
467,936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-6
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
($ in thousands, except share and per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
147,937
|
|
|
$
|
105,285
|
|
|
$
|
72,410
|
|
|
$
|
70,628
|
|
Gas pipeline revenue
|
|
|
28,176
|
|
|
|
9,853
|
|
|
|
5,014
|
|
|
|
3,939
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
176,113
|
|
|
|
115,138
|
|
|
|
77,424
|
|
|
|
74,567
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
44,111
|
|
|
|
36,295
|
|
|
|
25,338
|
|
|
|
18,532
|
|
Pipeline operating
|
|
|
29,742
|
|
|
|
21,098
|
|
|
|
13,151
|
|
|
|
7,703
|
|
General and administrative expenses
|
|
|
28,269
|
|
|
|
21,023
|
|
|
|
8,655
|
|
|
|
6,218
|
|
Depreciation, depletion and amortization
|
|
|
70,445
|
|
|
|
39,782
|
|
|
|
27,011
|
|
|
|
22,244
|
|
Impairment of oil and gas properties
|
|
|
298,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Misappropriation of funds
|
|
|
|
|
|
|
2,000
|
|
|
|
6,000
|
|
|
|
2,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
471,428
|
|
|
|
120,198
|
|
|
|
80,155
|
|
|
|
56,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(295,315
|
)
|
|
|
(5,060
|
)
|
|
|
(2,731
|
)
|
|
|
17,870
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) from derivative financial instruments
|
|
|
80,707
|
|
|
|
1,961
|
|
|
|
52,690
|
|
|
|
(73,566
|
)
|
Gain (loss) on sale of assets
|
|
|
24
|
|
|
|
(322
|
)
|
|
|
3
|
|
|
|
12
|
|
Loss on early extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,355
|
)
|
Other income (expense)
|
|
|
305
|
|
|
|
(9
|
)
|
|
|
99
|
|
|
|
389
|
|
Interest expense
|
|
|
(25,609
|
)
|
|
|
(44,044
|
)
|
|
|
(20,957
|
)
|
|
|
(28,271
|
)
|
Interest income
|
|
|
236
|
|
|
|
416
|
|
|
|
390
|
|
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
55,663
|
|
|
|
(41,998
|
)
|
|
|
32,225
|
|
|
|
(113,745
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes and minority interests
|
|
|
(239,652
|
)
|
|
|
(47,058
|
)
|
|
|
29,494
|
|
|
|
(95,875
|
)
|
Income tax benefit (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss before minority interest
|
|
|
(239,652
|
)
|
|
|
(47,058
|
)
|
|
|
29,494
|
|
|
|
(95,875
|
)
|
Minority interest
|
|
|
72,268
|
|
|
|
2,904
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
(167,384
|
)
|
|
|
(44,154
|
)
|
|
|
29,508
|
|
|
|
(95,875
|
)
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common shareholders
|
|
$
|
(167,384
|
)
|
|
$
|
(44,154
|
)
|
|
$
|
29,508
|
|
|
$
|
(95,885
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common shareholders per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(6.20
|
)
|
|
$
|
(1.97
|
)
|
|
$
|
1.33
|
|
|
$
|
(11.48
|
)
|
Diluted
|
|
$
|
(6.20
|
)
|
|
$
|
(1.97
|
)
|
|
$
|
1.33
|
|
|
$
|
(11.48
|
)
|
Weighted average common and common equivalent shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
27,010,690
|
|
|
|
22,379,479
|
|
|
|
22,119,497
|
|
|
|
8,351,945
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
27,010,690
|
|
|
|
22,379,479
|
|
|
|
22,129,607
|
|
|
|
8,351,945
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-7
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
($ in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(167,384
|
)
|
|
$
|
(44,154
|
)
|
|
$
|
29,508
|
|
|
$
|
(95,875
|
)
|
Adjustments to reconcile net income (loss) to cash provided by
(used in) operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
70,445
|
|
|
|
39,782
|
|
|
|
27,011
|
|
|
|
22,244
|
|
Impairment of oil and gas properties
|
|
|
298,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of debt discount
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,478
|
|
Stock-based compensation
|
|
|
1,939
|
|
|
|
6,081
|
|
|
|
1,037
|
|
|
|
1,217
|
|
Stock-based compensation minority interests
|
|
|
486
|
|
|
|
1,137
|
|
|
|
|
|
|
|
|
|
Stock issued for services and retirement plan
|
|
|
|
|
|
|
|
|
|
|
904
|
|
|
|
559
|
|
Amortization of deferred loan costs
|
|
|
2,100
|
|
|
|
11,220
|
|
|
|
2,069
|
|
|
|
4,497
|
|
Change in fair value of derivative financial instruments
|
|
|
(72,533
|
)
|
|
|
5,318
|
|
|
|
(70,402
|
)
|
|
|
46,602
|
|
Bad debt expense
|
|
|
|
|
|
|
22
|
|
|
|
85
|
|
|
|
302
|
|
Minority interest
|
|
|
(72,268
|
)
|
|
|
(2,904
|
)
|
|
|
(14
|
)
|
|
|
|
|
Loss on early extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,355
|
|
Loss on disposal of property and equipment
|
|
|
|
|
|
|
1,363
|
|
|
|
|
|
|
|
|
|
Change in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(1,158
|
)
|
|
|
(5,928
|
)
|
|
|
604
|
|
|
|
(4,469
|
)
|
Other receivables
|
|
|
(7,954
|
)
|
|
|
(1,245
|
)
|
|
|
108
|
|
|
|
181
|
|
Other current assets
|
|
|
4,173
|
|
|
|
(2,827
|
)
|
|
|
860
|
|
|
|
(1,693
|
)
|
Other assets
|
|
|
318
|
|
|
|
15
|
|
|
|
(819
|
)
|
|
|
788
|
|
Accounts payable
|
|
|
5,233
|
|
|
|
14,347
|
|
|
|
2,550
|
|
|
|
(14,867
|
)
|
Revenue payable
|
|
|
584
|
|
|
|
2,736
|
|
|
|
(256
|
)
|
|
|
1,518
|
|
Accrued expenses
|
|
|
(1,187
|
)
|
|
|
4,001
|
|
|
|
137
|
|
|
|
61
|
|
Other long-term liabilities
|
|
|
404
|
|
|
|
220
|
|
|
|
167
|
|
|
|
210
|
|
Other
|
|
|
(159
|
)
|
|
|
(388
|
)
|
|
|
1,053
|
|
|
|
116
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
61,900
|
|
|
|
28,796
|
|
|
|
(5,398
|
)
|
|
|
(14,776
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
677
|
|
|
|
(86
|
)
|
|
|
3,168
|
|
|
|
(4,318
|
)
|
Acquisition of business PetroEdge
|
|
|
(141,777
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of business KPC
|
|
|
|
|
|
|
(133,725
|
)
|
|
|
|
|
|
|
|
|
Acquisition of minority interest ArcLight
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(26,100
|
)
|
Equipment, development, leasehold and pipeline
|
|
|
(141,553
|
)
|
|
|
(138,657
|
)
|
|
|
(168,315
|
)
|
|
|
(35,312
|
)
|
Proceeds from sale of oil and gas properties
|
|
|
16,100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(266,553
|
)
|
|
|
(272,468
|
)
|
|
|
(165,147
|
)
|
|
|
(65,730
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from bank borrowings
|
|
|
86,195
|
|
|
|
44,580
|
|
|
|
125,170
|
|
|
|
100,103
|
|
Repayments of note borrowings
|
|
|
(59,800
|
)
|
|
|
(225,441
|
)
|
|
|
(589
|
)
|
|
|
(135,565
|
)
|
Proceeds from revolver note
|
|
|
128,000
|
|
|
|
224,000
|
|
|
|
75,000
|
|
|
|
|
|
Repayment of revolver note
|
|
|
|
|
|
|
(35,000
|
)
|
|
|
(75,000
|
)
|
|
|
|
|
Proceeds from Quest Energy
|
|
|
|
|
|
|
163,800
|
|
|
|
|
|
|
|
|
|
Proceeds from Quest Midstream
|
|
|
|
|
|
|
75,230
|
|
|
|
84,187
|
|
|
|
|
|
Syndication costs
|
|
|
|
|
|
|
(14,618
|
)
|
|
|
|
|
|
|
|
|
Distributions to unitholders
|
|
|
(24,413
|
)
|
|
|
(5,872
|
)
|
|
|
|
|
|
|
|
|
Proceeds from subordinated debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,000
|
|
Repayment of subordinated debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(83,912
|
)
|
Refinancing costs
|
|
|
(3,018
|
)
|
|
|
(10,147
|
)
|
|
|
(4,569
|
)
|
|
|
(6,281
|
)
|
Equity offering costs
|
|
|
|
|
|
|
|
|
|
|
(393
|
)
|
|
|
|
|
Dividends paid
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10
|
)
|
Repurchase of restricted stock
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of common stock
|
|
|
84,801
|
|
|
|
|
|
|
|
|
|
|
|
185,272
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
211,758
|
|
|
|
216,532
|
|
|
|
203,806
|
|
|
|
74,607
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash
|
|
|
7,105
|
|
|
|
(27,140
|
)
|
|
|
33,261
|
|
|
|
(5,899
|
)
|
Cash and cash equivalents beginning of period
|
|
|
6,680
|
|
|
|
33,820
|
|
|
|
559
|
|
|
|
6,458
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents end of period
|
|
$
|
13,785
|
|
|
$
|
6,680
|
|
|
$
|
33,820
|
|
|
$
|
559
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
|
|
|
Common
|
|
|
Common
|
|
|
Additional
|
|
|
Shares of
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
|
|
|
Stock
|
|
|
Shares
|
|
|
Stock
|
|
|
Paid-in
|
|
|
Treasury
|
|
|
Treasury
|
|
|
Accumulated
|
|
|
|
|
|
|
Shares
|
|
|
Par Value
|
|
|
Issued
|
|
|
Par Value
|
|
|
Capital
|
|
|
Stock
|
|
|
Stock
|
|
|
Deficit
|
|
|
Total
|
|
|
Balance, December 31, 2004
|
|
|
10,000
|
|
|
$
|
|
|
|
|
5,699,877
|
|
|
$
|
6
|
|
|
$
|
17,192
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(24,576
|
)
|
|
$
|
(7,378
|
)
|
Proceeds from stock offering
|
|
|
|
|
|
|
|
|
|
|
15,258,164
|
|
|
|
15
|
|
|
|
183,257
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
183,272
|
|
Conversion of preferred stock
|
|
|
(10,000
|
)
|
|
|
|
|
|
|
16,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends on preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10
|
)
|
|
|
(10
|
)
|
Stock issued for warrants exercised
|
|
|
|
|
|
|
|
|
|
|
639,840
|
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock issued for services
|
|
|
|
|
|
|
|
|
|
|
8,660
|
|
|
|
|
|
|
|
64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
64
|
|
Stock sold for cash
|
|
|
|
|
|
|
|
|
|
|
400,000
|
|
|
|
|
|
|
|
2,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,000
|
|
Stock issued to retirement plan
|
|
|
|
|
|
|
|
|
|
|
49,842
|
|
|
|
|
|
|
|
495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
495
|
|
Stock based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,217
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,217
|
|
Restricted stock grants, net of forfeitures
|
|
|
|
|
|
|
|
|
|
|
140,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(95,875
|
)
|
|
|
(95,875
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
22,212,383
|
|
|
|
22
|
|
|
|
204,224
|
|
|
|
|
|
|
|
|
|
|
|
(120,461
|
)
|
|
|
83,785
|
|
Equity offering costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(393
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(393
|
)
|
Stock issued to refinance debt
|
|
|
|
|
|
|
|
|
|
|
82,500
|
|
|
|
|
|
|
|
904
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
904
|
|
Stock based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,037
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,037
|
|
Restricted stock grants, net of forfeitures
|
|
|
|
|
|
|
|
|
|
|
71,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,508
|
|
|
|
29,508
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
22,365,883
|
|
|
|
22
|
|
|
|
205,772
|
|
|
|
|
|
|
|
|
|
|
|
(90,953
|
)
|
|
|
114,841
|
|
Stock based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,081
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,081
|
|
Restricted stock grants, net of forfeitures
|
|
|
|
|
|
|
|
|
|
|
1,187,347
|
|
|
|
2
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(44,154
|
)
|
|
|
(44,154
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
23,553,230
|
|
|
|
24
|
|
|
|
211,852
|
|
|
|
|
|
|
|
|
|
|
|
(135,107
|
)
|
|
|
76,769
|
|
Proceeds from stock offering
|
|
|
|
|
|
|
|
|
|
|
8,800,000
|
|
|
|
9
|
|
|
|
84,692
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84,701
|
|
Stock based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,939
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,939
|
|
Restricted stock grants, net of forfeitures
|
|
|
|
|
|
|
|
|
|
|
(138,587
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of stock options
|
|
|
|
|
|
|
|
|
|
|
10,000
|
|
|
|
|
|
|
|
100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100
|
|
Repurchase of common stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21,955
|
)
|
|
|
(7
|
)
|
|
|
|
|
|
|
(7
|
)
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(167,384
|
)
|
|
|
(167,384
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
|
|
|
|
$
|
|
|
|
|
32,224,643
|
|
|
$
|
33
|
|
|
$
|
298,583
|
|
|
|
(21,955
|
)
|
|
$
|
(7
|
)
|
|
$
|
(302,491
|
)
|
|
$
|
(3,882
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-9
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
Note 1
Organization, Going Concern, Misappropriation, Reaudit and
Restatement and Business
Organization
Quest Resource Corporation (Quest or
QRCP) is a Nevada corporation. Unless the context
clearly requires otherwise, references to we,
us, our or the Company are
intended to mean Quest Resource Corporation and its consolidated
subsidiaries.
We are an integrated independent energy company involved in the
acquisition, development, gathering, transportation,
exploration, and production of oil and natural gas. Our
principal operations and producing properties are located in the
Cherokee Basin of southeastern Kansas and northeastern Oklahoma
and the Appalachian Basin in West Virginia and New York. We
conduct substantially all of our production operations through
Quest Energy Partners, L.P. (Nasdaq: QELP) (Quest
Energy or QELP) and our natural gas
transportation and gathering operations through Quest Midstream
Partners, L.P. (Quest Midstream or
QMLP). Our Appalachian Basin operations are
primarily focused on the development of the Marcellus Shale
through Quest Eastern Resource LLC (Quest Eastern)
and Quest Energy. Our Cherokee Basin operations are currently
focused on developing CBM gas production through Quest Energy,
which is served by a gas gathering pipeline network owned
through Quest Midstream. Quest Midstream also owns an interstate
natural gas transmission pipeline.
Misappropriation,
Reaudit and Restatement
These consolidated financial statements include restated and
reaudited financial statements for QRCP as of December 31,
2007 and 2006 and for the periods ended December 31, 2007,
2006 and 2005 and are included in our
Form 10-K
for the year ended December 31, 2008. QRCP will
subsequently file (i) an amended Quarterly Report on
Form 10-Q
for the quarter ended March 31, 2008 including restated
unaudited condensed financial statements as of March 31,
2008 and for the three month periods ended March 31, 2008
and 2007; (ii) an amended Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2008 including restated
unaudited condensed financial statements as of June 30,
2008 and for the three and six month periods ended June 30,
2008 and 2007; and (iii) a Quarterly Report on
Form 10-Q
including restated unaudited condensed financial statements as
of September 30, 2008 and for the three and nine month
periods ended September 30, 2008 and 2007.
Investigation
On August 22, 2008, in
connection with an inquiry from the Oklahoma Department of
Securities, the boards of directors of QRCP, Quest Energy GP,
LLC (Quest Energy GP), the general partner of QELP,
and Quest Midstream GP, LLC (Quest Midstream GP),
the general partner of QMLP, held a joint working session to
address certain unauthorized transfers, repayments and
re-transfers of funds (the Transfers) to entities
controlled by their former chief executive officer,
Mr. Jerry D. Cash. These transfers totaled approximately
$10 million between 2005 and 2008.
A joint special committee comprised of one member designated by
each of the boards of directors of QRCP, Quest Energy GP, and
Quest Midstream GP, was immediately appointed to oversee an
independent internal investigation of the Transfers. In
connection with this investigation, other errors were identified
in prior year financial statements and management and the board
of directors concluded that the Company had material weaknesses
in its internal control over financial reporting. As of
December 31, 2008, these material weaknesses continued to
exist.
As reported on a Current Report on
Form 8-K
filed on January 2, 2009, on December 31, 2008, the
board of directors of QRCP determined that the audited
consolidated financial statements of QRCP as of and for the
years ended December 31, 2007, 2006 and 2005 and
QRCPs unaudited consolidated financial statements as of
and for the three months ended March 31, 2008 and 2007 and
as of and for the three and six months ended June 30, 2008
and 2007 should no longer be relied upon.
In October 2008, QRCPs audit committee engaged a new
independent registered public accounting firm to audit the
Companys consolidated financial statements for 2008 and,
in January 2009, engaged them to reaudit the
F-10
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Companys consolidated financial statements as of
December 31, 2007 and 2006 and for the years ended
December 31, 2007, 2006 and 2005.
The restated consolidated financial statements to which these
Notes apply also correct errors in a majority of the financial
statement line items found in the previously issued consolidated
financial statements for all periods presented. See
Note 18 Restatement.
Going
Concern
The accompanying consolidated financial statements have been
prepared assuming that the Company will continue as a going
concern, which contemplates the realization of assets and the
liquidation of liabilities in the normal course of business,
though such an assumption may not be true. The Company has
incurred significant losses from 2003 through 2008, mainly
attributable to operations, legal restructurings, financings,
the current legal and operational structure and, to a lesser
degree, the cash expenditures resulting from the investigation
related to the Transfers. We have determined that there is
substantial doubt about our ability to continue as a going
concern.
QRCP is almost exclusively dependent upon distributions from its
partnership interests in Quest Energy and Quest Midstream for
revenue and cash flow. Quest Midstream did not pay any
distributions on any of its units for the third or fourth
quarters of 2008, and Quest Energy suspended its distributions
on its subordinated units for the third quarter of 2008 and all
units starting with the fourth quarter of 2008. QRCP does not
expect to receive any distributions from Quest Energy or Quest
Midstream in 2009 and is unable to estimate at this time when
such distributions may be resumed.
Although QRCP is not currently receiving distributions from
Quest Energy or Quest Midstream, it continues to require cash to
fund general and administrative expenses, debt service
requirements, capital expenditures to develop and maintain its
undeveloped acreage, drilling commitments and payments to
landowners necessary to maintain its oil and gas leases.
Given the liquidity challenges facing the Company, Quest
Midstream and Quest Energy, each entity has undertaken a
strategic review of its assets and is currently evaluating one
or more transactions to dispose of assets in order to raise
additional funds for operations
and/or
to
repay indebtedness. On April 28, 2009, QRCP, Quest
Midstream and Quest Energy entered into a non-binding letter of
intent which contemplates a transaction in which all three
companies would form a new publicly traded holding company that
would wholly-own all three entities (the
Recombination). The closing of the Recombination is
subject to the satisfaction of a number of conditions, including
the entry into a definitive merger agreement, the negotiation of
a new credit facility for the new company, regulatory approval
and the approval of the transaction by the stockholders of QRCP
and the common unit holders of Quest Energy and Quest Midstream.
As of December 31, 2008, QRCP, excluding QELP and QMLP, had
cash and cash equivalents of $4.0 million and no ability to
borrow under the terms of its existing credit agreement. QRCP
currently estimates that it will not have enough cash to pay its
expenses, including capital expenditures and debt service
requirements, after August 31, 2009. This date could be
extended if QRCP is able to restructure its debt obligations,
issue equity securities and/or sell additional assets. The
accompanying financial statements do not include any adjustments
that might result from the outcome of this uncertainty.
Business
We conduct our business through two reportable business
segments. These segments and the activities performed to provide
services to our customers and create value for our stockholders
are as follows:
|
|
|
|
|
Oil and gas production, and
|
|
|
|
Natural gas pipelines, including transporting, gathering,
treating and processing natural gas.
|
F-11
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Oil
and Gas Production Operations
On November 15, 2007, Quest Energy completed an initial
public offering of 9,100,000 common units at $18.00 per unit, or
$16.83 per unit after payment of the underwriting discount
(excluding a structuring fee). On November 9, 2007, Quest
Energys common units began trading on the NASDAQ Global
Market under the symbol QELP. Total proceeds from
the sale of the common units in the initial public offering were
$163.8 million, before underwriting discounts, a
structuring fee and offering costs, of approximately
$10.6 million, $0.4 million and $1.5 million,
respectively. Quest Energy used the net proceeds of
$151.3 million to repay a portion of the indebtedness of
the Company.
Additionally, on November 15, 2007:
(a) Quest Energy, Quest Energy GP, the Company and certain
of the Companys subsidiaries entered into a Contribution,
Conveyance and Assumption Agreement (the Contribution
Agreement). At the closing of the offering, the following
transactions, among others, occurred pursuant to the
Contribution Agreement:
|
|
|
|
|
the contribution of Quest Cherokee, LLC (Quest
Cherokee) and its subsidiary, Quest Oilfield Service, LLC
(QCOS), to Quest Energy. Quest Cherokee owns all of
the Companys oil and gas leases in the Cherokee Basin;
|
|
|
|
the issuance of 431,827 General Partner Units and the incentive
distribution rights to Quest Energy GP, LLC (Quest Energy
GP) and the continuation of its 2.0% general partner
interest in Quest Energy;
|
|
|
|
the issuance of 3,201,521 common units and 8,857,981
subordinated units to the Company; and
|
|
|
|
the Company and its affiliates on the one hand, and Quest
Cherokee and Quest Energy on the other, agreed to indemnify the
other parties from and against all losses suffered or incurred
by reason of or arising out of certain existing legal
proceedings.
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(b) Quest Energy, Quest Energy GP and the Company entered
into an Omnibus Agreement, which governs Quest Energys
relationship with the Company and its affiliates regarding the
following matters:
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reimbursement of certain insurance, operating and general and
administrative expenses incurred on behalf of Quest Energy;
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indemnification for certain environmental liabilities, tax
liabilities, title defects and other losses in connection with
assets;
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a license for the use of the Quest name and mark; and
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Quest Energys right to purchase from the Company and its
affiliates certain assets that the Company and its affiliates
acquire within the Cherokee Basin.
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(c) Quest Energy, Quest Energy GP and Quest Energy Service,
LLC (QES) entered into a Management Services
Agreement, under which QES will perform acquisition services and
general and administrative services, such as accounting,
finance, tax, property management, risk management, land,
marketing, legal and engineering to Quest Energy, as directed by
Quest Energy GP, for which Quest Energy will reimburse QES on a
monthly basis for the reasonable costs of the services provided.
(d) Quest Energy entered into an Assignment and Assumption
Agreement (the Assignment) with Bluestem Pipeline,
LLC (Bluestem) and the Company, whereby the Company
assigned all of its rights in that certain Midstream Services
and Gas Dedication Agreement, dated as of December 22,
2006, but effective as of December 1, 2006, as amended (the
Midstream Services Agreement), to Quest Energy, and
Quest Energy assumed all of the Companys liabilities and
obligations arising under the Midstream Services Agreement from
and after the assignment. Bluestem will gather and provide
certain midstream services, including
F-12
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
dehydration, treating and compression, to Quest Energy for all
gas produced from Quest Energys wells in the Cherokee
Basin that are connected to Bluestems gathering system.
(e) Quest Energy signed an Acknowledgement and Consent and
therefore became subject to that certain Omnibus Agreement (the
Midstream Omnibus Agreement), dated
December 22, 2006, among the Company, Quest Midstream GP,
LLC, Bluestem and Quest Midstream. As long as Quest Energy is an
affiliate of the Company and the Company or any of its
affiliates control Quest Midstream, Quest Energy will be bound
by the Midstream Omnibus Agreement. The Quest Midstream
Agreement restricts Quest Energy from engaging in the following
businesses, subject to certain exceptions:
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the gathering, treating, processing and transporting of gas in
North America;
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the transporting and fractionating of gas liquids in North
America;
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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 Internal Revenue
Code of 1986, as amended, 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.
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(f) Quest Energy GP adopted the Quest Energy Partners, L.P.
Long-Term Incentive Plan (the Plan) for employees,
consultants and directors of Quest Energy GP and its affiliates,
including Quest Energy, who perform services for Quest Energy.
The Plan provides for the grant of unit awards, restricted
units, phantom units, unit options, unit appreciation rights,
distribution equivalent rights and other unit-based awards.
Subject to adjustment for certain events, an aggregate of
2,115,950 common units may be delivered pursuant to awards under
the Plan.
Natural
Gas Pipeline Operations
Our natural gas gathering pipeline network is owned by Bluestem.
Bluestem was a wholly-owned subsidiary of Quest Cherokee until
the formation and contribution of our midstream assets to Quest
Midstream on December 22, 2006. On this date, we
contributed Bluestem assets to Quest Midstream in exchange for
4.9 million class B subordinated units, 35,134
class A subordinated units and an 85% interest in the
general partner of Quest Midstream (see discussion below). Also
on December 22, 2006, Quest Midstream sold 4,864,866 common
units, representing an approximate 48.64% limited partner
interest in Quest Midstream, for $18.50 per common unit, or
approximately $90 million ($84.2 million after
offering costs), pursuant to a purchase agreement dated
December 22, 2006, to a group of institutional investors
led by Alerian Capital Management, LLC (Alerian),
and co-led by Swank Capital, LLC (Swank).
Quest Midstream GP, LLC (Quest Midstream GP), the
sole general partner of Quest Midstream, was formed on
December 13, 2006 by the Company. As of December 31,
2008, Quest Midstream GP owns 276,531 general partner units
representing a 2% general partner interest in Quest Midstream.
The Company owns 850 member interests representing an 85%
ownership interest in Quest Midstream GP, Alerian owns 75 member
interests representing a 7.5% ownership interest in Quest
Midstream GP and Swank owns 75 member interests representing a
7.5% ownership interest in Quest Midstream GP. Quest Midstream
GPs sole business activity is to act as the general
partner of Quest Midstream.
On November 1, 2007, Quest Midstream completed the purchase
of an interstate gas pipeline running from Oklahoma to Missouri
(the KPC Pipeline) pursuant to a Purchase and Sale
Agreement, dated as of October 9, 2007, by and among Quest
Midstream, Enbridge Midcoast Energy, L.P. and Midcoast Holdings
No. One, L.L.C.,
F-13
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
whereby Quest Midstream purchased all of the membership
interests in the two general partners of Enbridge Pipelines
(KPC), the owner of the KPC Pipeline, for a purchase price of
approximately $134 million including transaction costs and
assumed liabilities of approximately $1.2 million. In
connection with this acquisition, Quest Midstream issued
3,750,000 common units for $20.00 per common unit, or
approximately $75 million of gross proceeds
($73.6 million after offering costs) to fund a portion of
the purchase price and borrowed the remainder of the purchase
price under its credit facility.
Note 2
Summary of Significant Accounting Policies
Principles of Consolidation
These
consolidated financial statements include the accounts of the
Company and its subsidiaries. Subsidiaries in which the Company
directly or indirectly owns more than 50% of the outstanding
voting securities or those in which the Company has effective
control over are generally accounted for under the consolidation
method of accounting. Under this method, a subsidiaries
balance sheet and results of operations are reflected within the
Companys consolidated financial statements. The equity of
the minority interests in its majority-owned or effectively
controlled subsidiaries are shown in the consolidated financial
statements as minority interest. Minority interest
adjusts the Companys consolidated results of operations to
reflect only the Companys share of the earnings or losses
of the consolidated subsidiary company. Upon dilution of control
below 50% or the loss of effective control, the accounting
method is adjusted to the equity or cost method of accounting,
as appropriate, for subsequent periods. All significant
intercompany accounts and transactions have been eliminated.
Use of Estimates in the Preparation of Financial
Statements
The preparation of financial
statements in conformity with accounting principles generally
accepted in the United States of America (GAAP)
requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and
disclosures of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues
and expenses during the reporting period. Our most significant
estimates are based on remaining proved oil and gas reserves.
Estimates of proved reserves are key components of our depletion
rate for oil and natural gas properties and our full cost
ceiling test limitation. In addition, estimates are used in
computing taxes, asset retirement obligations, fair value of
derivative contracts and other items. Actual results could
differ from these estimates.
Revenue Recognition
We derive revenue from
our oil and gas operations from the sale of produced oil and
natural gas. We use the sales method of accounting for the
recognition of oil and gas revenue. Because there is a ready
market for oil and natural gas, we sell our oil and natural gas
shortly after production at various pipeline receipt points at
which time title and risk of loss transfers to the buyer.
Revenue is recorded when title and risk of loss is transferred
based on our net revenue interests.
Gathering revenue from our pipeline operations is recognized at
the time the natural gas is gathered or transported through the
system and delivered to a third party. Transportation revenue
from our interstate pipeline operations is primarily from
services pursuant to firm transportation agreements. These
agreements provide for a demand charge based on the volume of
contracted capacity and a commodity charge based on the volume
of gas delivered, both at rates specified in our FERC tariffs.
We recognize revenues from demand charges ratably over the
contract period regardless of the volume of natural gas that is
transported or stored. Revenues for commodity charges are
recognized when natural gas is scheduled to be delivered at the
agreed upon delivery point.
Cash and Cash Equivalents
The Company
considers all highly liquid investments purchased with an
original maturity of three months or less to be cash
equivalents. The Company maintains its cash balances at several
financial institutions that are insured by the Federal Deposit
Insurance Corporation. The Companys cash balances
typically are in excess of the insured amount; however no losses
have been recognized as a result of this circumstance.
Restricted Cash represents cash pledged to support reimbursement
obligations under outstanding letters of credit.
F-14
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Accounts Receivable
The Company conducts the
majority of its operations in the States of Kansas and Oklahoma
and operates exclusively in the oil and gas industry. The
Companys receivables are generally unsecured; however, the
Company has not experienced any significant losses to date.
Receivables are recorded at the estimate of amounts due based
upon the terms of the related agreements. Management
periodically assesses the Companys accounts receivable and
establishes an allowance for estimated uncollectible amounts.
Accounts determined to be uncollectible are charged to
operations in the period determined to be uncollectible. The
allowance for doubtful accounts was approximately $0.2 million
as of December 31, 2008, 2007 and 2006.
Inventory
Inventory includes tubular goods
and other lease and well equipment which we plan to utilize in
our ongoing exploration and development activities and is
carried at the lower of cost or market using the specific
identification method.
Oil and Gas Properties
We use the full cost
method of accounting for oil and gas properties. Under the full
cost method, all direct costs and certain indirect costs
associated with the acquisition, exploration, and development of
our oil and gas properties are capitalized.
Oil and gas properties are depleted using the
units-of-production method. The depletion expense is
significantly affected by the unamortized historical and future
development costs and the estimated proved oil and gas reserves.
Estimation of proved oil and gas reserves relies on professional
judgment and use of factors that cannot be precisely determined.
Holding all other factors constant, if proved oil and gas
reserve quantities were revised upward or downward, earnings
would increase or decrease, respectively. Subsequent proved
reserve estimates materially different from those reported would
change the depletion expense recognized during the future
reporting period. No gains or losses are recognized upon the
sale or disposition of oil and gas properties unless the sale or
disposition represents a significant quantity of proved
reserves, which would have a significant impact on the
depreciation, depletion, and amortization rate.
Under the full cost accounting rules, total capitalized costs
are limited to a ceiling equal to the present value of future
net revenues, discounted at 10% per annum, plus the lower of
cost or fair value of unevaluated properties less income tax
effects (the ceiling limitation). We perform a
quarterly ceiling test to evaluate whether the net book value of
our full cost pool exceeds the ceiling limitation. If
capitalized costs (net of accumulated depreciation, depletion,
and amortization) less related deferred taxes are greater than
the discounted future net revenues or ceiling limitation, a
write-down or impairment of the full cost pool is required. A
write-down of the carrying value of our full cost pool is a
non-cash charge that reduces earnings and impacts
stockholders (deficit) equity in the period of occurrence
and typically results in lower depreciation, depletion, and
amortization expense in future periods. Once incurred, a
write-down is not reversible at a later date. The risk that we
will be required to write down the carrying value of our oil and
gas properties increases when oil and gas prices are depressed,
even if low prices are temporary. In addition, a write-down may
occur if estimates of proved reserves are substantially reduced
or estimates of future development costs increase significantly.
See Note 5 Property.
Unevaluated Properties
The costs directly
associated with unevaluated oil and gas properties and
properties under development are not initially included in the
amortization base and relate to unproved leasehold acreage,
seismic data, wells and production facilities in progress and
wells pending determination together with interest costs
capitalized for these projects. Unevaluated leasehold costs are
transferred to the amortization base once determination has been
made or upon expiration of a lease. Geological and geophysical
costs associated with a specific unevaluated property are
transferred to the amortization base with the associated
leasehold costs on a specific project basis. Costs associated
with wells in progress and wells pending determination are
transferred to the amortization base once a determination is
made whether or not proved reserves can be assigned to the
property. All items included in our unevaluated property balance
are assessed on a quarterly basis for possible impairment or
reduction in value. Any impairments to unevaluated properties
are transferred to the amortization base.
Capitalized General and Administrative
Expenses
Under the full cost method of
accounting, a portion of general and administrative expenses
that are directly attributable to our acquisition, exploration,
and development
F-15
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
activities are capitalized to our full cost pool. The
capitalized costs include salaries, related fringe benefits,
cost of consulting services and other costs directly associated
with those activities. We capitalized general and administrative
costs related to our acquisition, exploration and development
activities, during the years ended December 31, 2008, 2007,
2006 and 2005 of $3.0 million, $2.3 million,
$1.4 million and $0.8 million, respectively.
Capitalized Interest Costs
The Company
capitalizes interest based on the cost of major development
projects. For the years ended December 31, 2008, 2007, 2006
and 2005, the Company capitalized $0.6 million,
$0.4 million, $1.1 million and $0.2 million of
interest, respectively.
Other Property and Equipment
The cost of
other property and equipment is depreciated over the estimated
useful lives of the related assets. The cost of leasehold
improvements is depreciated over the lesser of the length of the
related leases or the estimated useful lives of the assets.
Upon disposition or retirement of property and equipment, other
than oil and gas properties, the cost and related accumulated
depreciation are removed from the accounts and the gain or loss
thereon, if any, is recognized in the income statement in the
period of sale or disposition.
Impairment
Long-lived assets, such as
property, and equipment, and finite-lived intangibles subject to
amortization, are reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount of
such assets may not be recoverable. Recoverability of assets to
be held and used is measured by a comparison of the carrying
amount of such assets to estimated undiscounted future cash
flows expected to be generated by the assets. If the carrying
amount of such assets exceeds their undiscounted estimated
future cash flows, an impairment charge is recognized in the
amount by which the carrying amount of such assets exceeds the
fair value of the assets.
Other Assets
Other assets include deferred
financing costs associated with bank credit facilities and are
amortized over the term of the credit facility into interest
expense. Also included in other assets are contractual rights
obtained in connection with the KPC Pipeline acquisition. These
intangible assets are amortized over their estimated useful
lives and are reviewed for impairment whenever impairment
indicators are present.
Asset Retirement Obligations
Asset retirement
obligations associated with the retirement of a tangible
long-lived asset are recognized as a liability in the period
incurred or when it becomes determinable, with an associated
increase in the carrying amount of the related long-lived asset.
The cost of the tangible asset, including the asset retirement
cost, is depreciated over the useful life of the asset. The
asset retirement obligation is recorded at its estimated fair
value, measured by reference to the expected future cash
outflows required to satisfy the retirement obligation
discounted at our credit-adjusted risk-free interest rate.
Accretion expense is recognized over time as the discounted
liability is accreted to its expected settlement value. If the
estimated future cost of the asset retirement obligation
changes, an adjustment is recorded to both the asset retirement
obligation and the long-lived asset. Revisions to estimated
asset retirement obligations can result from changes in
retirement cost estimates, revisions to estimated inflation
rates and changes in the estimated timing of abandonment.
We own oil and gas properties that require expenditures to plug
and abandon the wells when the oil and gas reserves in the wells
are depleted. These expenditures are recorded in the period in
which the liability is incurred (at the time the wells are
drilled or acquired). Asset retirement obligations are recorded
as a liability at their estimated present value at the
assets inception, with the offsetting increase to property
cost. Periodic accretion expense of the estimated liability is
recorded in the consolidated statements of operations. We have
recorded asset retirement obligations relative to the
abandonment of our interstate pipeline assets because we believe
we have a legal or constructive obligation relative to asset
retirements of the interstate pipeline system. We have not
recorded an asset retirement obligation relating to our
gathering system because we do not have any legal or
constructive obligations relative to asset retirements of the
gathering system.
Derivative Instruments
We utilize derivative
instruments in conjunction with our marketing and trading
activities and to manage price risk attributable to our
forecasted sales of oil and gas production.
F-16
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
We elect Normal Purchases Normal Sales
(NPNS) accounting for derivative contracts that
provide for the purchase or sale of a physical commodity that
will be delivered in quantities expected to be used or sold over
a reasonable period in the normal course of business.
Derivatives that are designated as NPNS are accounted for under
the accrual method accounting.
Under accrual accounting, we record revenues in the period when
we deliver energy commodities or products, render services, or
settle contracts. Once we elect NPNS classification for a given
contract, we do not subsequently change the election and treat
the contract as a derivative using mark-to-market or hedge
accounting. However, if we were to determine that a transaction
designated as NPNS no longer qualified for the NPNS election, we
would have to record the fair value of that contract on the
balance sheet at that time and immediately recognize that amount
in earnings.
For those derivatives that do not meet the requirements for NPNS
designation nor qualify for hedge accounting, we believe that
they are still effective as economic hedges of our commodity
price exposure. These contracts are accounted for using the
mark-to-market accounting method. Using this method, the
contracts are carried at their fair value on our consolidated
balance sheets under the captions Derivative financial
instrument assets and Derivative financial
instrument liabilities. We recognize all unrealized and
realized gains and losses related to these contracts on our
consolidated statements of operations under the caption
Gain (loss) from derivative financial instruments,
which is a component of other income (expense).
We have exposure to credit risk to the extent a counterparty to
a derivative instrument is unable to meet its settlement
commitment. We actively monitor the creditworthiness of each
counterparty and assesses the impact, if any, on our derivative
positions. We do not apply hedge accounting to our derivative
instruments. As a result, both realized and unrealized gains and
losses on derivative instruments are recognized in the income
statement as they occur.
Legal
We are subject to legal proceedings,
claims and liabilities which arise in the ordinary course of our
business. We accrue for losses associated with legal claims when
such losses are probable and can be reasonably estimated. These
estimates are adjusted as additional information becomes
available or circumstances change. See Note 12
Commitments and Contingencies.
Environmental Costs
Environmental
expenditures are expensed or capitalized, as appropriate,
depending on future economic benefit. Expenditures that relate
to an existing condition caused by past operations and that have
no future economic benefit are expensed. Liabilities related to
future costs are recorded on an undiscounted basis when
environmental assessments
and/or
remediation activities are probable and costs can be reasonably
estimated. We have no environmental costs accrued for all
periods presented.
Stock-Based Compensation
The Company grants
various types of stock-based awards (including stock options and
restricted stock) and accounts for stock-based compensation at
fair value. The fair value of stock option awards is determined
using a Black-Scholes pricing model. The fair value of
restricted stock awards are valued using the market price of the
Companys common stock on the grant date. Stock-based
compensation expense is recognized over the requisite service
period net of estimated forfeitures.
The Company accounts for stock-based compensation in accordance
with Statement of Financial Accounting Standards
(SFAS) No. 123(R),
Share-Based Payment
(SFAS 123(R)), which requires that compensation
related to all stock-based awards, including stock options, be
recognized in the financial statements based on their estimated
grant-date fair value. The Company utilized the modified
retrospective method of adopting SFAS 123(R), whereby
compensation cost and the related tax effect have been
recognized in the consolidated financial statements for all
relevant periods.
Income Taxes
We record our income taxes using
an asset and liability approach in accordance with the
provisions of the SFAS No. 109,
Accounting for
Income Taxes
(SFAS 109). This results in the
recognition of deferred tax assets and liabilities for the
expected future tax consequences of temporary differences
(primarily
F-17
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
intangible drilling costs and the net operating loss carry
forward) between the book carrying amounts and the tax bases of
assets and liabilities using enacted tax rates at the end of the
period. Under SFAS 109, the effect of a change in tax rates
of deferred tax assets and liabilities is recognized in the year
of the enacted change. Deferred tax assets are reduced by a
valuation allowance when, in the opinion of management, it is
more likely than not that some portion or all of the deferred
tax assets will not be realized. As of December 31, 2008,
2007 and 2006, a full valuation allowance was recorded against
our deferred tax assets.
On January 1, 2007, the Company adopted Financial
Accounting Standards Board (FASB) Interpretation
No. 48,
Accounting for Uncertainty in Income Taxes
(FIN 48), which defines the criteria an
individual tax position must meet in order to be recognized in
the financial statements. FIN 48 also provides guidance on
the measurement of the income tax benefit associated with
uncertain tax positions, derecognition, classification, interest
and penalties and financial statement disclosure. We regularly
analyze tax positions taken or expected to be taken in a tax
return based on the threshold condition prescribed under
FIN 48. Tax positions that do not meet or exceed this
threshold condition are considered uncertain tax positions. We
accrue interest related to these uncertain tax positions which
is recognized in interest expense. Penalties, if any, related to
uncertain tax positions would be recorded in other expenses. The
adoption of FIN 48 did not have a material impact on our
financial position or results of operations.
Net Income (Loss) per Common Share
Basic
earnings (loss) per share is calculated by dividing net income
(loss) by the weighted average number of shares of common stock
outstanding during the period. Diluted earnings (loss) per share
assumes the conversion of all potentially dilutive securities
(stock options and restricted stock awards) and is calculated by
dividing net income (loss) by the sum of the weighted average
number of shares of common stock outstanding plus potentially
dilutive securities under the treasury stock method. See
Note 10 Stockholders Equity
Earnings (Loss) Per Share.
Concentrations of Market Risk
Our future
results will be affected by the market price of oil and natural
gas. The availability of a ready market for oil and gas will
depend on numerous factors beyond our control, including
weather, production of oil and gas, imports, marketing,
competitive fuels, proximity of oil and gas pipelines and other
transportation facilities, any oversupply or undersupply of oil
and gas, the regulatory environment, and other regional and
political events, none of which can be predicted with certainty.
Concentration of Credit Risk
Financial
instruments, which subject us to concentrations of credit risk,
consist primarily of cash and accounts receivable. We place our
cash investments with highly qualified financial institutions.
Risk with respect to receivables as of December 31, 2008,
2007 and 2006 arise substantially from the sales of oil and gas
and transportation revenue from our pipeline system.
ONEOK Energy Marketing and Trading Company (ONEOK),
accounted for substantially all of our oil and gas revenue for
the year ended December 31, 2008. Natural gas sales to
ONEOK accounted for more than 71% of total revenue for the year
ended December 31, 2007, and more than 91% for the years
ended December 31, 2006 and 2005.
Fair Value
Effective January 1, 2008, we
adopted SFAS 157,
Fair Value Measurements
(SFAS 157), for financial assets and
liabilities measured on a recurring basis. SFAS 157 defines
fair value, establishes a framework for measuring fair value and
requires certain disclosures about fair value measurements for
assets and liabilities measured on a recurring basis. In
February 2008, the FASB issued
FSP 157-2,
which delayed the effective date of SFAS 157 by one year
for non-financial assets and liabilities, except for items that
are recognized or disclosed at fair value in the financial
statements on a recurring basis (at least annually). We have
elected to utilize this deferral and have only partially applied
SFAS 157 (to financial assets and liabilities measured at
fair value on a recurring basis, as described above).
Accordingly, we will apply SFAS 157 to our nonfinancial
assets and liabilities for which we disclose or recognize at
fair value on a nonrecurring basis, such as asset retirement
obligations and other assets and liabilities in the first
quarter of 2009. Fair value is the exit price that we would
receive to sell an asset or pay to transfer a liability in an
orderly transaction between market participants at the
measurement date.
F-18
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
SFAS 157 also establishes a hierarchy that prioritizes the
inputs used to measure fair value. The three levels of the fair
value hierarchy are as follows:
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Level 1 Quoted prices available in active
markets for identical assets or liabilities as of the reporting
date.
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Level 2 Pricing inputs other than quoted prices
in active markets included in Level 1 which are either
directly or indirectly observable as of the reporting date.
Level 2 consists primarily of non-exchange traded commodity
derivatives.
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Level 3 Pricing inputs include significant
inputs that are generally less observable from objective sources.
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We classify assets and liabilities within the fair value
hierarchy based on the lowest level of input that is significant
to the fair value measurement of each individual asset and
liability taken as a whole. Certain of our derivatives are
classified as Level 3 because observable market data is not
available for all of the time periods for which we have
derivative instruments. As observable market data becomes
available for all of the time periods, these derivative
positions will be reclassified as Level 2. The income
valuation approach, which involves discounting estimated cash
flows, is primarily used to determine recurring fair value
measurements of our derivative instruments classified as
Level 2 or Level 3. We prioritize the use of the
highest level inputs available in determining fair value.
The Companys assessment of the significance of a
particular input to the fair value measurement requires judgment
and may affect the classification of assets and liabilities
within the fair value hierarchy. Because of the long-term nature
of certain assets and liabilities measured at fair value as well
as differences in the availability of market prices and market
liquidity over their terms, inputs for some assets and
liabilities may fall into any one of the three levels in the
fair value hierarchy. While SFAS 157 requires us to
classify these assets and liabilities in the lowest level in the
hierarchy for which inputs are significant to the fair value
measurement, a portion of that measurement may be determined
using inputs from a higher level in the hierarchy.
Recently
Adopted Accounting Principles
We adopted SFAS 157 as of January 1, 2008.
SFAS 157 does not require any additional fair value
measurements. Rather, the pronouncement defines fair value,
establishes a framework for measuring fair value under existing
accounting pronouncements that require fair value measurements,
and expands disclosures about fair value measurements. We
elected to implement SFAS 157 with the one-year deferral
FASB Staff Position (FSP)
FAS No. 157-2
for nonfinancial assets and nonfinancial liabilities, except
those nonfinancial items recognized or disclosed at fair value
on a recurring basis (at least annually). Effective upon
issuance, the FASB issued FSP
FAS 157-3,
Determining the Fair Value of a Financial Asset When the
Market for That Asset is Not Active
(FSP FAS 157-3),
in October 2008.
FSP FAS 157-3
clarifies the application of SFAS 157 in determining the
fair value of a financial asset when the market for that
financial asset is not active. As of December 31, 2008, we
had no financial assets with a market that was not active.
In September 2006, the SEC issued Staff Accounting
Bulletin (SAB) No. 108
(SAB 108). SAB 108 addresses how the
effects of prior year uncorrected misstatements should be
considered when quantifying misstatements in current year
financial statements. SAB 108 requires companies to
quantify misstatements using a balance sheet and income
statement approach and to evaluate whether either approach
results in quantifying an error that is material in light of
relevant quantitative and qualitative factors. When the effect
of initial adoption is material, companies will record the
effect as a cumulative effect adjustment to beginning of year
retained earnings and disclose the nature and amount of each
individual error being corrected in the cumulative adjustment.
SAB 108 became effective beginning January 1, 2007 and
applies to our restatement adjustments recorded in the restated
financial statements presented herein.
In December 2004, the FASB issued SFAS 153,
Exchanges of
Nonmonetary Assets
(SFAS 153). SFAS 153 requires
the use of fair value measurement for exchanges of nonmonetary
assets. Because SFAS 153 is applied
F-19
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
retrospectively, the statement was effective for us in 2005. The
adoption of SFAS 153 did not have a material impact on our
financial statements.
In September 2005, the Emerging Issues Task Force
(EITF) concluded in Issue
No. 04-13,
Accounting for Purchases and Sales of Inventory with the Same
Counterparty
(EITF
04-13),
that purchases and sales of inventory with the same party in the
same line of business should be accounted for as nonmonetary
exchanges, if entered into in contemplation of one another. We
present purchase and sale activities related to our marketing
and trading activities on a net basis in the income statement.
The conclusion reached on EITF
04-13
did
not have an impact on our consolidated financial statements.
Recent
Accounting Pronouncements
In April 2007, the FASB issued FSP FIN
39-1,
Amendment of FASB Interpretation No. 39
(FSP
FIN
39-1),
which amends FIN 39,
Offsetting of Amounts Related to
Certain Contracts
. FSP
FIN 39-1
permits netting fair values of derivative assets and liabilities
for financial reporting purposes, if such assets and liabilities
are with the same counterparty and subject to a master netting
arrangement. FSP
FIN 39-1
also requires that the net presentation of derivative assets and
liabilities include amounts attributable to the fair value of
the right to reclaim collateral assets held by counterparties or
the obligation to return cash collateral received from
counterparties. We did not elect to adopt FSP FIN 39-1.
In December 2007, the FASB issued SFAS No. 141(R),
Business Combinations
(SFAS 141(R)),
which replaces SFAS 141. SFAS 141(R) establishes
principles and requirements for how the acquirer in a business
combination recognizes and measures in its financial statements
the identifiable assets acquired, the liabilities assumed, and
any non-controlling interest in the acquiree. In addition,
SFAS 141(R) recognizes and measures the goodwill acquired
in the business combination or a gain from a bargain purchase.
SFAS 141(R) also establishes disclosure requirements to
enable users to evaluate the nature and financial effects of the
business combination. SFAS 141(R) is effective as of the
beginning of an entitys fiscal year that begins after
December 15, 2008, with early adoption prohibited.
Effective January 1, 2009, we will apply this statement to
any business combinations, including the contemplated
Recombination previously discussed. The adoption of
SFAS 141(R) did not have a material effect on our results
of operations, cash flows and financial position as of
January 1, 2009, the date of adoption.
In February 2007, the FASB issued SFAS 159,
The Fair
Value Option for Financial Assets and Financial Liabilities
(SFAS 159), including an amendment to
SFAS 115. Under SFAS 159, entities may elect to
measure specified financial instruments and warranty and
insurance contracts at fair value on a
contract-by-contract
basis, with changes in fair value recognized in earnings each
reporting period. The election, called the fair value option,
enables entities to achieve an offset accounting effect for
changes in fair value of certain related assets and liabilities
without having to apply complex hedge accounting provisions.
SFAS 159 is expected to expand the use of fair value
measurement consistent with the FASBs long-term objectives
for financial instruments. SFAS 159 is effective for fiscal
years beginning after November 15, 2007. We have assessed
the provisions of SFAS 159 and we have elected not to apply
fair value accounting to our existing eligible financial
instruments. As a result, the adoption of SFAS 159 did not
have an impact on our financial statements.
In December 2007, the FASB issued SFAS No. 160,
Non-controlling Interests in Consolidated Financial
Statements An Amendment of ARB No. 51
(SFAS 160). SFAS 160 establishes accounting and
reporting standards for ownership interests in subsidiaries held
by parties other than the parent, the amount of consolidated net
income attributable to the parent and to the non-controlling
interest, and changes in a parents ownership interest
while the parent retains its controlling financial interest in
its subsidiary. In addition, SFAS 160 establishes
principles for valuation of retained non-controlling equity
investments and measurement of gain or loss when a subsidiary is
deconsolidated. SFAS 160 also establishes disclosure
requirements to clearly identify and distinguish between
interests of the parent and the interests of the non-controlling
owners. SFAS 160 is effective for fiscal years and interim
periods beginning after December 15, 2008, with early
adoption prohibited. After adopting SFAS 160 in
F-20
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
2009, we will apply provisions of this standard to
noncontrolling interests created or acquired in future periods.
Upon adoption, we will reclassify our minority interests to
stockholders equity.
In March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging
Activities an amendment of FASB Statement
No. 133
(SFAS 161). SFAS 161 does not
change the accounting for derivatives, but requires enhanced
disclosures about how and why we use derivative instruments, how
derivative instruments and related hedged items (if any) are
accounted for, and how they affect our financial position,
financial performance and cash flows. SFAS 161 is effective
for us beginning with the first quarter of 2009.
In June 2008, the FASB issued FSP EITF
No. 03-6-1,
Determining Whether Instruments Granted in Share-Based
Payment Transactions Are Participating Securities
(FSP
EITF
03-6-1).
FSP EITF
03-6-1
addresses whether instruments granted in share-based payment
transactions are participating securities prior to vesting and
are therefore required to be included in the earnings allocation
in calculating earnings per share under the two-class method
described in SFAS No. 128,
Earnings per Share.
FSP EITF
03-6-1
requires companies to treat unvested share-based payment awards
that have non-forfeitable rights to dividend or dividend
equivalents as a separate class of securities in calculating
earnings per share. FSP EITF
03-6-1
is
effective for fiscal years beginning after December 15,
2008. We adopted FSP EITF
03-6-1
effective January 1, 2009. FSP EITF
03-6-1
did
not have an effect on the presentation of earnings per share.
On December 31, 2008, the SEC issued Release
No. 33-8995,
Modernization of Oil and Gas Reporting
, which revises
disclosure requirements for oil and gas companies. In addition
to changing the definition and disclosure requirements for oil
and gas reserves, the new rules change the requirements for
determining oil and gas reserve quantities. These rules permit
the use of new technologies to determine proved reserves under
certain criteria and allow companies to disclose their probable
and possible reserves. The new rules also require companies to
report the independence and qualifications of their reserves
preparer or auditor and file reports when a third party is
relied upon to prepare reserves estimates or conducts a reserves
audit. The new rules also require that oil and gas reserves be
reported and the full cost ceiling limitation be calculated
using a twelve-month average price rather than period-end
prices. The use of a twelve-month average price may have had an
effect on our 2008 depletion rates for our oil and gas
properties and the amount of impairment recognized as of
December 31, 2008 had the new rules been effective for the
period. The new rules are effective for annual reports on
Form 10-K
for fiscal years ending on or after December 31, 2009,
pending the potential alignment of certain accounting standards
by the FASB with the new rule. We plan to implement the new
requirements in our Annual Report on
Form 10-K
for the year ended December 31, 2009. We are currently
assessing the impact the rules will have on our consolidated
financial statements.
Note 3
Acquisitions and Divestitures
Acquisitions
PetroEdge
On July 11, 2008, QRCP
completed the acquisition of privately held PetroEdge Resources
(WV) LLC (PetroEdge) in an all cash purchase for
approximately $142 million in cash including transaction
costs, subject to certain adjustments for working capital and
certain other activity between May 1, 2008 and the closing
date. The assets acquired were approximately 78,000 net
acres of oil and natural gas producing properties in the
Appalachian Basin with estimated net proved reserves of
99.6 Bcfe as of May 1, 2008 and net production of
approximately 3.3 million cubic feet equivalent per day
(Mmcfe/d). The transaction was recorded within the
Companys oil and gas production segment and was funded
using the proceeds from the sale of the PetroEdge producing
wellbores to Quest Cherokee discussed below and the proceeds of
its July 8, 2008 public offering of 8,800,000 shares
of common stock.
At closing, QRCP sold the producing well bores to Quest Cherokee
for approximately $71.2 million. The proved undeveloped
reserves, unproved and undrilled acreage related to the
wellbores (generally all acreage other than established spacing
related to the producing well bores) and a gathering system were
retained by PetroEdge
F-21
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
and its name was changed to Quest Eastern Resource LLC. Quest
Eastern is designated as operator of the wellbores purchased by
Quest Cherokee and conducts drilling and other operations for
our affiliates and third parties on the PetroEdge acreage. Quest
Cherokee funded its purchase of the PetroEdge wellbores with
borrowings under its revolving credit facility and the proceeds
of a $45 million, six-month term loan. See
Note 4 Long-Term Debt.
We accounted for this acquisition in accordance with
SFAS 141,
Business Combinations.
The
purchase price was allocated to assets acquired and liabilities
assumed based on estimated fair values of the respective assets
and liabilities at the time of closing. The following table
summarizes the allocation of the purchase price (in thousands):
|
|
|
|
|
Current assets
|
|
$
|
3,069
|
|
Oil and gas properties
|
|
|
142,618
|
(a)
|
Gathering facilities
|
|
|
1,820
|
|
Current liabilities
|
|
|
(3,537
|
)
|
Asset retirement obligations
|
|
|
(2,193
|
)(a)
|
|
|
|
|
|
Purchase price
|
|
$
|
141,777
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Net assets acquired by Quest Cherokee consisted of
$73.4 million of proved oil and gas properties and
$2.2 million of asset retirement obligations.
|
KPC Pipeline
On November 1, 2007, Quest
Midstream completed the purchase of the KPC Pipeline for
approximately $133.7 million, including transaction costs.
The acquisition expanded Quest Midstreams pipeline
operations and was recorded in the Companys natural gas
pipelines segment. The KPC Pipeline is a 1,120 mile
interstate gas pipeline, which transports natural gas from
Oklahoma and western Kansas to the metropolitan Wichita and
Kansas City markets and is one of only three pipeline systems
capable of delivering gas into the Kansas City metropolitan
market. The KPC system includes three compressor stations with a
total of 14,680 horsepower and has a capacity of approximately
160 MMcf/d. The KPC Pipeline has supply interconnections
with pipelines owned and/or operated by Enogex, Inc., Panhandle
Eastern Pipeline Company and ANR Pipeline Company, allowing
Quest Midstream to transport natural gas sourced from the
Anadarko and Arkoma basins, as well as the western Kansas and
Oklahoma panhandle producing regions. The acquisition was funded
through the issuance of 3,750,000 common units of Quest
Midstream for $20.00 per common unit and borrowings of
$58 million under Quest Midstreams credit facility.
The total cost of the acquisition was allocated to the assets
acquired and liabilities assumed based on their estimated fair
values on the acquisition date. The preliminary allocation was
recorded during 2007 before valuation work was completed on
contract-based intangibles. After completing valuation work on
the acquired intangibles, a final purchase price allocation was
recorded in 2008. The following table summarizes the allocation
of the purchase price (in thousands):
|
|
|
|
|
Pipeline assets
|
|
$
|
124,936
|
|
Contract-related intangible assets (See Note 13)
|
|
|
9,934
|
|
Liabilities assumed
|
|
|
(1,145
|
)
|
|
|
|
|
|
Purchase price
|
|
$
|
133,725
|
|
|
|
|
|
|
F-22
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Pro Forma
Summary Data related to acquisitions (unaudited)
The following unaudited pro forma information summarizes the
results of operations for the years ended December 31,
2008, 2007 and 2006 as if the PetroEdge acquisition had occurred
on January 1, 2008 and 2007 and as if the KPC Pipeline
acquisition had occurred on January 1, 2007 and 2006 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Pro forma revenue
|
|
$
|
182,813
|
|
|
$
|
143,913
|
|
|
$
|
96,200
|
|
Pro forma net income (loss)
|
|
$
|
(246,175
|
)
|
|
$
|
(60,677
|
)
|
|
$
|
30,768
|
|
Pro forma net income (loss) per share basic
|
|
$
|
(7.79
|
)
|
|
$
|
(1.95
|
)
|
|
$
|
1.39
|
|
Pro forma net income (loss) per share diluted
|
|
$
|
(7.79
|
)
|
|
$
|
(1.95
|
)
|
|
$
|
1.39
|
|
The pro forma information is presented for illustration purposes
only, in accordance with the assumptions set forth below. The
pro forma information does not reflect any cost savings or other
synergies anticipated as a result of the acquisitions or any
future acquisition-related expenses. The pro forma adjustments
are based on estimates and assumptions. Management believes the
estimates and assumptions are reasonable, and that the
significant effects of the transactions are properly reflected.
The pro forma information is a result of combining the income
statement of the Company with the pre-acquisition results of KPC
and PetroEdge adjusted for 1) recording pro forma interest
expense on debt incurred to acquire KPC and PetroEdge;
2) DD&A expense calculated based on the adjusted basis
of the properties and intangibles acquired using the purchase
method of accounting; and 3) any related income tax effects
of these adjustments based on the applicable statutory tax rates.
Other Transactions
On October 15, 2007,
QRCP, Quest MergerSub, Inc., QRCPs wholly-owned subsidiary
(MergerSub), and Pinnacle Gas Resources, Inc.
(Pinnacle) entered into an Agreement and Plan of
Merger, pursuant to which MergerSub would merge (the
Merger) with and into Pinnacle, with Pinnacle
continuing as the surviving corporation and as QRCPs
wholly-owned subsidiary. On May 16, 2008, the Merger
Agreement was terminated. Pursuant to the terms of the Merger
Agreement, either QRCP or Pinnacle had the right to terminate
the Merger Agreement if the proposed Merger was not completed by
May 16, 2008. No termination fee was payable by QRCP or
Pinnacle as a result of the termination of the Merger Agreement.
Divestitures
On June 4, 2008, we acquired the right to develop, and the
option to purchase, certain drilling and other rights in and
below the Marcellus Shale covering approximately 28,700 net
acres in Potter County, Pennsylvania for $4.0 million. On
November 26, 2008, we divested of these rights to a private
party for approximately $3.2 million.
On October 30, 2008, we divested of approximately
22,600 net undeveloped acres and one well in Somerset
County, Pennsylvania to a private party for approximately
$6.8 million.
On November 5, 2008, we divested of 50% of our interest in
approximately 4,500 net undeveloped acres in Wetzel County,
West Virginia to a private party for $6.1 million. Included
in the sale were three wells in various stages of completion and
existing pipelines and facilities. QRCP will continue to operate
the property included in this joint venture. All future
development costs will be split equally between us and the
private party.
On February 13, 2009, we divested of approximately
23,000 net undeveloped acres and one well in Lycoming
County, Pennsylvania to a private party for approximately
$8.7 million.
The proceeds from these divestitures were credited to the full
cost pool.
F-23
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 4
Long-Term Debt
The following is a summary of the Companys long-term debt
at December 31, 2008, 2007 and 2006 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Borrowings under bank senior credit facilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Quest
|
|
$
|
29,000
|
|
|
$
|
44,000
|
|
|
$
|
225,000
|
|
Quest Energy:
|
|
|
|
|
|
|
|
|
|
|
|
|
Revolving credit facility
|
|
|
189,000
|
|
|
|
94,000
|
|
|
|
|
|
Term loan
|
|
|
41,200
|
|
|
|
|
|
|
|
|
|
Quest Midstream
|
|
|
128,000
|
|
|
|
95,000
|
|
|
|
|
|
Notes payable to banks and finance companies, secured by
equipment and vehicles, due in installments through October 2013
with interest ranging from 2.9% to 9.8% per annum
|
|
|
907
|
|
|
|
712
|
|
|
|
569
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt
|
|
|
388,107
|
|
|
|
233,712
|
|
|
|
225,569
|
|
Less current maturities included in current liabilities
|
|
|
45,013
|
|
|
|
666
|
|
|
|
324
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
$
|
343,094
|
|
|
$
|
233,046
|
|
|
$
|
225,245
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate maturities of long-term debt during the next five
years at December 31, 2008 are as follows (in thousands):
|
|
|
|
|
2009
|
|
$
|
45,013
|
|
2010
|
|
|
215,053
|
|
2011
|
|
|
26
|
|
2012
|
|
|
128,007
|
|
2013 and thereafter
|
|
|
8
|
|
|
|
|
|
|
Total
|
|
$
|
388,107
|
|
|
|
|
|
|
Other
Long-Term Indebtedness
Approximately $0.9 million of notes payable to banks and
finance companies were outstanding at December 31, 2008 and
are secured by equipment and vehicles, with payments due in
monthly installments through October 2013 with interest ranging
from 2.9% to 9.8% per annum.
Credit
Facilities
Quest
.
On July 11, 2008, QRCP and
Royal Bank of Canada (RBC) entered into an Amended
and Restated Credit Agreement (the Credit Agreement)
to convert QRCPs then-existing $50 million revolving
credit facility to a $35 million term loan, due and
maturing on July 11, 2010 (the Original Term
Loan). On October 24, 2008, QRCP and RBC entered into
a First Amendment to Amended and Restated Credit Agreement,
which, among other things, added a $6 million term loan
(the Additional Term Loan) to the $35 million
term loan under the Credit Agreement. The maturity date for the
Additional Term Loan was November 30, 2008. On
October 24, 2008, QRCP borrowed $2 million of the
$6 million available under the Additional Term Loan. On
November 4, 2008, QRCP entered into a Second Amendment to
Amended and Restated Credit Agreement (the Second
Amendment to Credit Agreement) which clarified that the
$6 million commitment under the Additional Term Loan would
be reduced dollar for dollar to the extent QRCP retained net
cash proceeds from dispositions in accordance with the terms of
the Credit Agreement. On January 30, 2009, QRCP entered
into a Third Amendment to Amended and Restated Credit
F-24
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Agreement (the Third Amendment to Credit Agreement)
and on May 29, 2009, QRCP entered into a Fourth Amendment
to Amended and Restated Credit Agreement (the Fourth
Amendment to Credit Agreement).
Interest accrues on the Original Term Loan, and accrued on the
Additional Term Loan, at either LIBOR plus 10% (with a LIBOR
floor of 3.5%) or the base rate plus 9.0%. The base rate varies
daily and is generally the higher of the federal funds rate plus
0.50%, RBCs prime rate or LIBOR plus 2.5% (but without the
LIBOR floor). The Original Term Loan may be prepaid without any
premium or penalty, at any time.
The Original Term Loan is payable in quarterly installments of
$1.5 million on the last business day of each March, June,
September and December commencing on September 30, 2008,
with the remaining principal amount being payable in full on
July 11, 2010. As discussed in the next paragraph, QRCP
has prepaid all of the quarterly principal payment requirements
of $1.5 million through June 30, 2009 and therefore
has no quarterly principal payments due until September 30,
2009. If the outstanding amount of the Original Term Loan is at
any time more than 50% of the market value of QRCPs
partnership interests in Quest Midstream and Quest Energy
pledged to secure the loan plus the value of QRCPs oil and
gas properties (as defined in the Credit Agreement) pledged to
secure the loan, QRCP will be required to either repay the term
loan by the amount of such excess or pledge additional assets to
secure the term loan.
As part of the Second Amendment to Credit Agreement, QRCP agreed
to apply any net cash proceeds from a sale of assets or a sale
of equity interests in certain subsidiaries as follows: first,
to repay any amounts borrowed under the Additional Term Loan
(this was done on October 30, 2008); second, to prepay the
next three quarterly principal payments due on the Original Term
Loan on the last business day of December 2008, March 2009 and
June 2009 (this was done in October and November 2008); third,
subject to certain conditions being met and the net cash
proceeds being received by January 31, 2009, up to
$20 million for QRCPs own use for working capital and
to make capital expenditures for the development of its oil and
gas properties; and fourth, any excess net cash proceeds to
repay the Original Term Loan. The Third Amendment to Credit
Agreement provided that in connection with the sale of
QRCPs Lycoming County, Pennsylvania acreage in February
2009, QRCP could retain all of the net proceeds from such sale
in excess of $750,000. QRCP will be required to apply all of the
net cash proceeds from the issuance of any debt and 50% of the
net cash proceeds from the sale of any equity securities to
first repay the Original Term Loan and then to QRCP.
The Second Amendment to Credit Agreement also amended
and/or
waived certain of the representations and covenants contained in
the Credit Agreement in order to rectify any possible covenant
violations or non-compliance with the representations and
warranties as a result of (1) the Transfers and
(2) not timely settling certain intercompany accounts among
QRCP, Quest Energy and Quest Midstream. The Fourth Amendment to
Credit Agreement, among other things, waived certain events of
default related to the financial covenants and collateral
requirements under the Credit Agreement, extended certain
financial reporting deadlines and permitted the settlement
agreements with Mr. Cash discussed elsewhere in the Annual
Report on
Form 10-K.
Quest Oil & Gas, LLC (QOG), Quest Energy
Service, LLC (QES), Quest Mergersub and Quest
Eastern guarantee all of QRCPs obligations under the
Credit Agreement. The Credit Agreement is secured by a first
priority lien on QRCPs ownership interests in Quest Energy
and Quest Midstream and their general partners and the oil and
gas properties owned by Quest Eastern in the Appalachian Basin,
which are substantially all of QRCPs assets. The assets of
each of Quest Midstream GP, Quest Midstream and each of their
subsidiaries and Quest Energy GP, Quest Energy and each of their
subsidiaries (collectively the Excluded MLP
Entities) are not pledged to secure the Credit Agreement.
The Credit Agreement provides that all obligations arising under
the loan documents, including obligations under any hedging
agreement entered into with lenders or their affiliates, will be
secured
pari passu
by the liens granted under the loan
documents.
At December 31, 2008, $29 million was outstanding
under the Original Term Loan. The Additional Term Loan was
repaid on October 30, 2008.
F-25
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
QRCP and its subsidiaries (excluding the Excluded MLP Entities)
are required to make certain representations and warranties that
are customary for a credit agreement of this type. The agreement
also contains affirmative and negative covenants that are
customary for credit agreements of this type, including, without
limitation, periodic delivery of financial statements and other
financial information, notice of defaults and certain other
matters; payment of obligations; preservation of legal existence
and good standing; maintenance of assets and business;
maintenance of insurance; compliance with laws and contractual
obligations; maintenance of books and records; inspection
rights; limitations on use of proceeds; execution of guaranties
by subsidiaries; perfecting security interests in after-acquired
property; maintenance of fiscal year; certain limitations on
liens, investments, hedging agreements, indebtedness, lease
obligations, fundamental changes, dispositions of assets,
restricted payments, distributions and redemptions, nature of
business, capital expenditures and risk management, transactions
with affiliates, and burdensome agreements; and compliance with
financial covenants.
The Credit Agreements financial covenants prohibit QRCP
and any of its subsidiaries (excluding the Excluded MLP
Entities) from:
|
|
|
|
|
permitting the interest coverage ratio (ratio of consolidated
EBITDA (or consolidated annualized EBITDA for periods ending on
or before December 31, 2008) to consolidated interest
charges (or consolidated annualized interest charges for periods
ending on or before December 31, 2008)) at any fiscal
quarter-end, commencing with the quarter-ended
September 30, 2008, to be less than 2.5 to 1.0 (calculated
based on the most recently delivered compliance
certificate); and
|
|
|
|
permitting the leverage ratio (ratio of consolidated funded debt
to consolidated EBITDA (or consolidated annualized EBITDA for
periods ending on or before December 31, 2008)) at any
fiscal quarter-end, commencing with the quarter-ended
September 30, 2008, to be greater than 2.0 to 1.0
(calculated based on the most recently delivered compliance
certificate).
|
Consolidated EBITDA is defined in the Credit Agreement to mean
for QRCP and its subsidiaries (excluding the Excluded MLP
Entities) on a consolidated basis, an amount equal to the sum of
(i) consolidated net income, (ii) consolidated
interest charges, (iii) the amount of taxes, based on or
measured by income, used or included in the determination of
such consolidated net income, (iv) the amount of
depreciation, depletion and amortization expense deducted in
determining such consolidated net income, (v) merger and
acquisition costs incurred by QRCP that are required to be
expensed as a result of the termination of the merger agreement
with Pinnacle Gas Resources, Inc., (vi) merger and
acquisition costs required to be expensed under FAS 141(R),
(vii) fees and expenses of the internal investigation
relating to the Misappropriation Transaction (as defined in the
First Amendment to Credit Agreement) and the related
restructuring which were capped at $1,500,000 for purposes of
this definition and (viii) other non-cash charges and
expenses deducted in the determination of such consolidated net
income, including, without limitation, non-cash charges and
expenses relating to swap contracts or resulting from accounting
convention changes, of QRCP and its subsidiaries (excluding the
Excluded MLP Entities) on a consolidated basis, all determined
in accordance with GAAP.
Consolidated annualized EBITDA means, for QRCP and its
subsidiaries (excluding the Excluded MLP Entities) on a
consolidated basis, (i) for the fiscal quarter ended
September 30, 2008, consolidated EBITDA for the nine month
period ended September 30, 2008 multiplied by 1.33, and
(ii) for the fiscal quarter ended December 31, 2008,
consolidated EBITDA for the twelve month period ended
December 31, 2008.
Consolidated interest charges are defined to mean for QRCP and
its subsidiaries (excluding the Excluded MLP Entities) on a
consolidated basis, the sum of (i) all interest, premium
payments, fees, charges and related expenses of QRCP and its
subsidiaries (excluding the Excluded MLP Entities) in connection
with indebtedness (net of interest rate swap contract
settlements) (including capitalized interest), in each case to
the extent treated as interest in accordance with GAAP, and
(ii) the portion of rent expense of QRCP and its
subsidiaries (excluding the Excluded MLP Entities) with respect
to any period under capital leases that is treated as interest
in accordance with GAAP.
F-26
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Consolidated annualized interest charges means, for QRCP and its
subsidiaries (excluding the Excluded MLP Entities) on a
consolidated basis, (i) for the fiscal quarter ended
September 30, 2008, consolidated interest charges for the
nine month period ended September 30, 2008 multiplied by
1.33, and (ii) for the fiscal quarter ended
December 31, 2008, consolidated interest charges for the
twelve month period ended December 31, 2008.
Consolidated funded debt means, for QRCP and its subsidiaries
(excluding the Excluded MLP Entities) on a consolidated basis,
the sum of (i) the outstanding principal amount of all
obligations and liabilities, whether current or long-term, for
borrowed money (including obligations under the Credit
Agreement), (ii) all reimbursement obligations relating to
letters of credit that have been drawn and remain unreimbursed,
(iii) attributable indebtedness pertaining to capital
leases, (iv) attributable indebtedness pertaining to
synthetic lease obligations, and (v) without duplication,
all guaranty obligations with respect to indebtedness of the
type specified in subsections (i) through (iv) above.
Events of default under the Credit Agreement are customary for
transactions of this type and include, without limitation,
non-payment of principal when due, non-payment of interest, fees
and other amounts for a period of three business days after the
due date, failure to perform or observe covenants and agreements
(subject to a
30-day
cure
period in certain cases), representations and warranties not
being correct in any material respect when made, cross-defaults
to other material indebtedness, certain acts of bankruptcy or
insolvency, and change of control. Under the Credit Agreement, a
change of control means the acquisition by any person, or two or
more persons acting in concert, of beneficial ownership (within
the meaning of
Rule 13d-3
of the SEC under the Securities Exchange Act of 1934) of
50% or more of QRCPs outstanding shares of voting stock;
provided, however, that a merger of QRCP into another entity in
which the other entity is the survivor will not be deemed a
change of control if QRCPs stockholders of record as
constituted immediately prior to such acquisition hold more than
50% of the outstanding shares of voting stock of the surviving
entity.
QRCP was not in compliance with all of its financial covenants
as of December 31, 2008 and March 31, 2009 and QRCP
does not anticipate that it will be in compliance at any time in
the foreseeable future. On May 29, 2009, QRCP obtained a
waiver of these defaults from its lenders for the quarters ended
December 31, 2008 and March 31, 2009 and is
negotiating with its lender to obtain a waiver of these
requirements for future periods.
Quest Energy.
On November 15,
2007, Quest Energy, as a guarantor, entered into an Amended and
Restated Credit Agreement (the Quest Cherokee Credit
Agreement) with QRCP, as the initial co-borrower, Quest
Cherokee, as the borrower, RBC, as administrative agent and
collateral agent, KeyBank National Association, as documentation
agent and the lenders party thereto. Quest Cherokee and QRCP had
previously been parties to the following credit agreements with
Guggenheim Corporate Funding, LLC (Guggenheim):
(i) Amended and Restated Senior Credit Agreement, dated
February 7, 2006, as amended; (ii) Amended and
Restated Second Lien Term Loan Agreement, dated June 9,
2006, as amended; and (iii) Third Lien Term Loan Agreement,
dated June 9, 2006, as amended (collectively, the
Prior Credit Agreements). Guggenheim and the lenders
under the Prior Credit Agreements assigned all of their
interests and rights (other than certain excepted interests and
rights) in the Prior Credit Agreements to RBC and the new
lenders under the Quest Cherokee Credit Agreement pursuant to a
Loan Transfer Agreement, dated November 15, 2007, by and
among QRCP, Quest Cherokee, QOG, QES, Quest Cherokee Oilfield
Service, LLC (QCOS), Guggenheim, Wells Fargo
Foothill, Inc., the lenders under the Prior Credit Agreements
and RBC. The Quest Cherokee Credit Agreement amended and
restated the Prior Credit Agreements in their entirety. In
connection with the closing of the initial public offering and
the application of the net proceeds thereof, QRCP was released
as a borrower under the Quest Cherokee Credit Agreement. On
April 15, 2008, Quest Energy and Quest Cherokee entered
into a First Amendment to Amended and Restated Credit Agreement
that, among other things, amended the interest rate and maturity
date pursuant to the market flex rights contained in
the commitment papers related to the Quest Cherokee Credit
Agreement.
The credit facility under the Quest Cherokee Credit Agreement,
as amended, consists of a three-year $250 million revolving
credit facility. Availability under the revolving credit
facility is tied to a borrowing base that will be redetermined
by RBC and the lenders every six months taking into account the
value of Quest
F-27
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Cherokees proved reserves. In addition, Quest Cherokee and
RBC each have the right to initiate a redetermination of the
borrowing base between each six-month redetermination. As of
December 31, 2008, the borrowing base was
$190 million, and the amount borrowed under the Quest
Cherokee Credit Agreement was $189 million. No amounts were
available for borrowing because the remaining $1.0 million
was supporting letters of credit issued under the Quest Cherokee
Credit Agreement.
Quest Cherokee will pay a quarterly revolving commitment fee
equal to 0.30% to 0.50% (depending on the utilization
percentage) of the actual daily amount by which the lesser of
the aggregate revolving commitment and the borrowing base
exceeds the sum of the outstanding balance of borrowings and
letters of credit under the revolving credit facility.
During the Transition Period (as defined in the Quest Cherokee
Credit Agreement, as amended), interest will accrue at either
LIBOR plus 4.0% or the base rate plus 3.0%. After the Transition
Period ends, interest will accrue at either LIBOR plus a margin
ranging from 2.75% to 3.375% (depending on the utilization
percentage) or the base rate plus a margin ranging from 1.75% to
2.375% (depending on the utilization percentage). The base rate
varies daily and is generally the higher of the federal funds
rate plus 0.50%, RBCs prime rate or LIBOR plus 1.25%. The
Transition Period will generally end once the repayment of the
Second Lien Loan Agreement (discussed below) has occurred.
On July 11, 2008, concurrent with Quest Energys
acquisition of 32.9 Bcfe of proved developed reserves in the
Appalachian Basin from QRCP, Quest Energy and Quest Cherokee
entered into a Second Lien Senior Term Loan Agreement (the
Second Lien Loan Agreement, together with the Quest
Cherokee Credit Agreement, as amended, the Quest Cherokee
Agreements) for a six-month, $45 million term loan.
The Second Lien Loan Agreement is among Quest Cherokee, as the
borrower, Quest Energy as a guarantor, RBC, as administrative
agent and collateral agent, KeyBank National Association, as
syndication agent, Société Générale, as
documentation agent, and the lenders party thereto. On
October 28, 2008, Quest Energy and Quest Cherokee entered
into a First Amendment to Second Lien Loan Agreement (the
First Amendment to Second Lien Loan Agreement) to,
among other things, extend the maturity date to
September 30, 2009 and to amend and/or waive certain of the
representations and covenants contained in the Second Lien Loan
Agreement in order to rectify any possible covenant violations
or non-compliance with the representations and warranties as a
result or (1) the Transfers and (2) not timely
settling certain intercompany accounts among QRCP, Quest Energy
and Quest Midstream. At the same time, a Second Amendment to the
Quest Cherokee Credit Agreement was entered into to amend and/or
waive certain of the representations and covenants contained in
the Second Lien Loan Agreement in order to rectify any possible
covenant violations or non-compliance with the representations
and warranties as a result of (1) the Transfers and
(2) not timely settling certain intercompany accounts among
QRCP, Quest Energy and Quest Midstream.
The First Amendment to Second Lien Loan Agreement requires Quest
Cherokee to make repayments of principal in quarterly
installments of $3.8 million on the 15th day of each
February, May, August and November while amounts borrowed under
the Second Lien Loan Agreement are outstanding. As of
December 31, 2008, $41.2 million was outstanding under
the Second Lien Loan Agreement.
Interest accrues on the term loan at either LIBOR plus 9.0%
(with a LIBOR floor of 3.5%) or the base rate plus 8.0%. The
base rate varies daily and is generally the higher of the
federal funds rate plus 0.5%, RBCs prime rate or LIBOR
plus 1.25%. The term loan may be prepaid without any premium or
penalty, at any time.
Subject to certain restrictions, Quest Cherokee and its
subsidiaries are required to apply all net cash proceeds from
sales of assets that yield gross proceeds of over
$5 million to repay the term loan. Under the terms of the
Second Lien Loan Agreement, Quest Energy is required by
June 30, 2009 to (i) complete a private placement of
its equity securities or debt, (ii) engage one or more
investment banks reasonably satisfactory to RBC Capital Markets
to publicly sell or privately place common equity securities or
debt of Quest Energy, which offering must close prior to
August 14, 2009 (the deadline for closing and funding the
securities offering may be extended up until
F-28
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
September 30, 2009) or (iii) engage RBC Capital
Markets to arrange financing to refinance the term loan under
the Second Lien Loan Agreement on the prevailing terms in the
credit market.
The Quest Cherokee Agreements restrict the amount of quarterly
distributions Quest Energy may declare and pay to its
unitholders to not exceed $0.40 per common unit per quarter as
long as the term loan has not been paid in full. Further, after
giving effect to each quarterly distribution, Quest Energy and
Quest Cherokee must be in compliance with a financial covenant
that prohibits each of Quest Cherokee, Quest Energy or any of
their respective subsidiaries from permitting Available
Liquidity (as defined in the Quest Cherokee Agreements) to be
less than $14 million at March 31, 2009 and to be less
than $20 million at June 30, 2009. The
$3.8 million quarterly principal payments discussed above
must also be paid before any distributions may be paid. Quest
Cherokees capital expenditures are limited to
$30 million for 2009.
Quest Energy and QCOS guarantee all of Quest Cherokees
obligations under the Quest Cherokee Agreements. The revolving
credit facility is secured by a first priority lien on
substantially all of the assets of Quest Energy, Quest Cherokee
and QCOS. The term loan is secured by a second priority lien on
substantially all of the assets of Quest Energy, Quest Cherokee
and QCOS.
The Quest Cherokee Agreements provide that all obligations
arising under the loan documents, including obligations under
any hedging agreement entered into with lenders or their
affiliates, will be secured
pari passu
by the liens
granted under the loan documents.
Quest Energy, Quest Cherokee, Quest Energy GP and their
subsidiaries are required to make certain representations and
warranties that are customary for credit agreements of these
types. The Quest Cherokee Agreements also contain affirmative
and negative covenants that are customary for credit agreements
of these types. The covenants in the Quest Cherokee Agreements
include, without limitation, periodic delivery of financial
statements and other financial information; notice of defaults
and certain other matters; payment of obligations; preservation
of legal existence and good standing; maintenance of assets and
business; maintenance of insurance; compliance with laws and
contractual obligations; maintenance of books and records;
inspection rights; limitations on use of proceeds; execution of
guaranties by subsidiaries; perfecting security interests in
after-acquired property; curing title defects; maintaining
material leases; operation of properties; notification of change
of purchasers of production; maintenance of fiscal year; certain
limitations on liens, investments, hedging agreements,
indebtedness, lease obligations, fundamental changes,
dispositions of assets, restricted payments, distributions and
redemptions, nature of business, capital expenditures and risk
management, transactions with affiliates, and burdensome
agreements; and compliance with financial covenants.
The Quest Cherokee Agreements financial covenants prohibit
Quest Cherokee, Quest Energy and any of their subsidiaries from:
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permitting the ratio (calculated based on the most recently
delivered compliance certificate) of Quest Energys
consolidated current assets (including the unused availability
under the revolving credit facility, but excluding non-cash
assets under FAS 133) to consolidated current
liabilities (excluding non-cash obligations under FAS 133,
asset and asset retirement obligations and current maturities of
indebtedness under the Quest Cherokee Credit Agreement) at any
fiscal quarter-end to be less than 1.0 to 1.0; provided,
however, that current assets and current liabilities will
exclude mark-to-market values of swap contracts, to the extent
such values are included in current assets and current
liabilities;
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permitting the interest coverage ratio (calculated on the most
recently delivered compliance certificate) of adjusted
consolidated EBITDA to consolidated interest charges at any
fiscal quarter-end to be less than 2.5 to 1.0 measured on a
rolling four quarter basis; and
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permitting the leverage ratio (calculated based on the most
recently delivered compliance certificate) of consolidated
funded debt to adjusted consolidated EBITDA at any fiscal
quarter-end to be greater than 3.5 to 1.0 measured on a rolling
four quarter basis.
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F-29
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Second Lien Loan Agreement contains an additional financial
covenant that prohibits Quest Cherokee, Quest Energy and any of
their subsidiaries from permitting the total reserve leverage
ratio (ratio of total proved reserves to consolidated funded
debt) at any fiscal quarter-end (calculated based on the most
recently delivered compliance certificate) to be less than 1.5
to 1.0.
Adjusted consolidated EBITDA is defined in the Quest Cherokee
Agreements to mean the sum of (i) consolidated EBITDA plus
(ii) the distribution equivalent amount (for each fiscal
quarter of Quest Energy, the amount of cash paid to the members
of Quest Energy GPs management group and non-management
directors with respect to restricted common units, bonus units
and/or
phantom units of Quest Energy that are required under GAAP to be
treated as compensation expense prior to vesting (and which,
upon vesting, are treated as limited partner distributions under
GAAP)).
Consolidated EBITDA is defined in the Quest Cherokee Agreements
to mean for Quest Energy and its subsidiaries on a consolidated
basis, an amount equal to the sum of (i) consolidated net
income, (ii) consolidated interest charges, (iii) the
amount of taxes, based on or measured by income, used or
included in the determination of such consolidated net income,
(iv) the amount of depreciation, depletion and amortization
expense deducted in determining such consolidated net income,
(v) acquisition costs required to be expensed under
FAS 141(R), (vi) fees and expenses of the internal
investigation relating to the Misappropriation Transaction and
the related restructuring (which shall be capped at $1,500,000
for purposes of this definition), and (vii) other non-cash
charges and expenses, including, without limitation, non-cash
charges and expenses relating to swap contracts or resulting
from accounting convention changes, of Quest Energy and its
subsidiaries on a consolidated basis, all determined in
accordance with GAAP.
Consolidated interests charges is defined to mean for Quest
Energy and its subsidiaries on a consolidated basis, the excess
of (i) the sum of (a) all interest, premium payments,
fees, charges and related expenses of Quest Energy and its
subsidiaries in connection with indebtedness (net of interest
rate swap contract settlements) (including capitalized
interest), in each case to the extent treated as interest in
accordance with GAAP, and (b) the portion of rent expense
of Quest Energy and its subsidiaries with respect to such period
under capital leases that is treated as interest in accordance
with GAAP over (ii) all interest income for such period.
Consolidated funded debt is defined to mean for Quest Energy and
its subsidiaries on a consolidated basis, the sum of
(i) the outstanding principal amount of all obligations and
liabilities, whether current or long-term, for borrowed money
(including obligations under the Quest Cherokee Agreements, but
excluding all reimbursement obligations relating to outstanding
but undrawn letters of credit), (ii) attributable
indebtedness pertaining to capital leases,
(iii) attributable indebtedness pertaining to synthetic
lease obligations, and (iv) without duplication, all
guaranty obligations with respect to indebtedness of the type
specified in subsections (i) through (iii) above.
Events of default under the Quest Cherokee Agreements are
customary for transactions of this type and include, without
limitation, non-payment of principal when due, non-payment of
interest, fees and other amounts for a period of three business
days after the due date, failure to perform or observe covenants
and agreements (subject to a
30-day
cure
period in certain cases), representations and warranties not
being correct in any material respect when made, certain acts of
bankruptcy or insolvency, cross defaults to other material
indebtedness, borrowing base deficiencies, and change of
control. Under the Quest Cherokee Agreements, a change of
control means (i) QRCP fails to own or to have voting
control over at least 51% of the equity interest of Quest Energy
GP, (ii) any person acquires beneficial ownership of 51% or
more of the equity interest in Quest Energy; (iii) Quest
Energy fails to own 100% of the equity interests in Quest
Cherokee, or (iv) QRCP undergoes a change in control (the
acquisition by a person, or two or more persons acting in
concert, of beneficial ownership of 50% or more of QRCPs
outstanding shares of voting stock, except for a merger with and
into another entity where the other entity is the survivor if
QRCPs stockholders of record immediately preceding the
merger hold more than 50% of the outstanding shares of the
surviving entity).
Quest Energy was in compliance with all of its covenants as of
December 31, 2008.
F-30
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Quest Midstream.
Quest Midstream and
its wholly-owned subsidiary, Bluestem, have a separate
$135 million syndicated revolving credit facility. On
November 1, 2007, Quest Midstream and Bluestem entered into
an Amended and Restated Credit Agreement and First Amendment to
Amended and Restated Credit Agreement (together, the Quest
Midstream Credit Agreement) with RBC, as administrative
agent and collateral agent, and the lenders party thereto. On
October 28, 2008, Quest Midstream and Bluestem entered into
a Second Amendment to the Quest Midstream Credit Agreement (the
Quest Midstream Second Amendment). The Quest
Midstream Credit Agreement together with the Quest Midstream
Second Amendment are referred to collectively as the
Amended Quest Midstream Credit Agreement. As of
December 31, 2008, the amount borrowed under the Amended
Quest Midstream Credit Agreement was $128 million.
The Quest Midstream Second Amendment, among other things,
amended
and/or
waived certain of the representations and covenants contained in
the Quest Midstream Credit Agreement in order to rectify any
possible covenant violations or non-compliance with the
representations and warranties as a result of (1) the
Transfers and (2) not timely settling certain intercompany
accounts among QRCP, Quest Energy and Quest Midstream.
Quest Midstream and Bluestem may, from time to time, request an
increase in the $135 million commitment by an amount in the
aggregate not exceeding $75 million. However, the lenders
are under no obligation to increase the revolving credit
facility upon such request.
Quest Midstream and Bluestem will pay a quarterly revolving
commitment fee equal to 0.375% to 0.50% (depending on the total
leverage ratio) on the difference between $135 million and
the outstanding balance of borrowings and letters of credit
under the revolving credit facility.
During the Transition Period (as defined in the Amended Quest
Midstream Credit Agreement), interest will accrue on the
revolving credit facility at either LIBOR plus 4% or the base
rate plus 3.0%. After the Transition Period ends, interest will
accrue at either LIBOR plus a margin ranging from 2.0% to 3.50%
(depending on the total leverage ratio) or the base rate plus a
margin ranging from 1.0% to 2.5% (depending on the total
leverage ratio), at our option. The base rate is generally the
higher of the federal funds rate plus 0.50%, RBCs prime
rate or LIBOR plus 1.25%. The Transition Period ended on
March 31, 2009 when Quest Midstreams audited
financial statements for 2008 were delivered to RBC.
If the total leverage ratio is greater than 4.5 to 1.0 for any
fiscal quarter ending on or after December 31, 2008, Quest
Midstream and Bluestem must prepay the revolving loans in an
amount equal to 75% of Excess Cash Flow (as defined in the
Amended Quest Midstream Credit Agreement) for such fiscal
quarter. Additionally, the lenders revolving commitment
will be temporarily reduced dollar for dollar by the amount of
any such prepayment. Once the total leverage ratio is less than
4.0 to 1.0 at the end of any fiscal quarter, any reductions in
the revolving commitments will be reinstated and no further
prepayments will be required.
The Amended Quest Midstream Credit Agreement places limitations
on capital expenditures for each of Quest Midstream and Bluestem
as follows: (i) $5 million for the fourth fiscal
quarter of 2008; (ii) $7 million for the first fiscal
quarter of 2009; (iii) $7 million for the second
fiscal quarter of 2009; (iv) $3 million for the third
fiscal quarter of 2009; and (v) $3 million for the
fourth fiscal quarter of 2009.
The Amended Quest Midstream Credit Agreement restricts Quest
Midstreams ability to make distributions on its units
unless the total leverage ratio is not greater than 4.0 to 1.0
after giving effect to the quarterly distribution.
Quest Kansas General Partner, Quest Kansas Pipeline, and KPC
guarantee all of Quest Midstreams and Bluestems
obligations under the Amended Quest Midstream Credit Agreement.
The revolving credit facility is secured by a first priority
lien on substantially all of the assets of Quest Midstream and
Bluestem and their subsidiaries (including the KPC Pipeline).
The Amended Quest Midstream Credit Agreement provides that all
obligations arising under the loan documents, including
obligations under any hedging agreement entered into with
lenders or their affiliates, will be secured
pari passu
by the liens granted under the loan documents.
F-31
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Bluestem, Quest Midstream and their subsidiaries are required to
make certain representations and warranties that are customary
for credit agreements of this type. The Amended Quest Midstream
Credit Agreement also contains affirmative and negative
covenants that are customary for credit agreements of this type.
The covenants in the Amended Quest Midstream Credit Agreement
include, without limitation, delivery of financial statements
and other financial information; notice of defaults and certain
other matters; payment of obligations; preservation of legal
existence and good standing; maintenance of assets and business;
maintenance of insurance; compliance with laws and contractual
obligations; maintenance of books and records; permit inspection
rights; use of proceeds; execution of guaranties by
subsidiaries; perfecting security interests in after-acquired
property; maintenance of fiscal year; limitations on liens;
limitations on investments; limitation on hedging agreements;
limitations on indebtedness; limitations on lease obligations;
limitations on fundamental changes; limitations on dispositions
of assets; limitations on restricted payments, distributions and
redemptions; limitations on nature of business, capital
expenditures and risk management; limitations on transactions
with affiliates; limitations on burdensome agreements; and
compliance with financial covenants.
The Amended Quest Midstream Credit Agreements financial
covenants prohibit Bluestem, Quest Midstream and any of their
subsidiaries from:
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permitting the interest coverage ratio (ratio of adjusted
consolidated EBITDA to consolidated interest charges) on a
rolling four quarter basis (calculated based on the most
recently delivered compliance certificate), commencing with the
fiscal quarter ending December 31, 2007, to be less than
2.50 to 1.00 for any fiscal quarter ending on or prior to
December 31, 2008, increasing to 2.75 to 1.00 for each
fiscal quarter end thereafter; and
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permitting the total leverage ratio (ratio of adjusted
consolidated funded debt to adjusted consolidated EBITDA) on a
rolling four quarter basis (calculated based on the most
recently delivered compliance certificate), commencing with the
fiscal quarter ending December 31, 2007 and ending
December 31, 2008, to be greater than 5.00 to 1.00,
decreasing to 4.50 to 1.00 for each fiscal quarter end
thereafter.
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Adjusted consolidated EBITDA is defined in the Amended Quest
Midstream Credit Agreement to mean the sum of
(i) consolidated EBITDA plus (ii) the distribution
equivalent amount (for each fiscal quarter of Quest Midstream,
the amount of cash paid to the members of Quest Midstream
GPs management group and non-management directors with
respect to restricted common units, bonus units
and/or
phantom units of Quest Midstream that are required under GAAP to
be treated as compensation expense prior to vesting (and which,
upon vesting, are treated as limited partner distributions under
GAAP)).
Consolidated EBITDA is defined in the Amended Quest Midstream
Credit Agreement for Quest Midstream and its subsidiaries on a
consolidated basis, an amount equal to the sum of
(i) consolidated net income, (ii) consolidated
interest charges, (iii) the amount of taxes, based on or
measured by income, used or included in the determination of
consolidated net income, (iv) the amount of depreciation,
depletion and amortization expense deducted in determining
consolidated net income, (v) merger and acquisition costs
required to be expensed under FAS 141(R), (vi) fees
and expenses of the internal investigation relating to the
Misappropriation Transaction and the related restructuring which
are capped at $1,500,000 for purposes of the definition of
Consolidated EBITDA and (vii) other non-cash charges and
expenses, including, without limitation, non-cash charges and
expenses related to swap contracts or resulting from accounting
convention changes, of Quest Midstream and its subsidiaries on a
consolidated basis, all determined in accordance with GAAP.
Consolidated interest charges is defined to mean for Quest
Midstream and its subsidiaries on a consolidated basis, the sum
of (i) all interest, premium payments, fees, charges and
related expenses of Quest Midstream and its subsidiaries in
connection with indebtedness (net of interest rate swap contract
settlements) (including capitalized interest and net of any
write-off of debt issuance costs), in each case to the extent
treated as interest in accordance with GAAP, and (ii) the
portion of rent expense of Quest Midstream and its subsidiaries
with respect to such period under capital leases that is treated
as interest in accordance with GAAP.
F-32
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Consolidated net income is defined to mean for Quest Midstream
and its subsidiaries on a consolidated basis, the net income or
net loss of Quest Midstream and its subsidiaries from continuing
operations, excluding: (i) the income (or loss) of any
entity other than a subsidiary, except to the extent that any
such income has been actually received by Quest Midstream or
such subsidiary in the form of cash dividends or similar cash
distributions; (ii) extraordinary gains and losses;
(iii) any gains or losses attributable to non-cash
write-ups
or
write-downs of assets; (iv) proceeds of any insurance on
property, plant or equipment other than business interruption
insurance; (v) any gain or loss, net of taxes, on the sale,
retirement or other disposition of assets; and (vi) the
cumulative effect of a change in accounting principles.
Bluestem and Quest Midstream are required during each calendar
year to have at least 15 consecutive days during which there are
no revolving loans outstanding for the purpose of financing
working capital or funding quarterly distributions of Quest
Midstream.
Events of default under the Amended Quest Midstream Credit
Agreement are customary for transactions of this type and
include, without limitation, non-payment of principal when due,
non-payment of interest, fees and other amounts for a period of
three business days after the due date, failure to perform or
observe covenants and agreements (subject to a
30-day
cure
period in certain cases), representations and warranties not
being correct in any material respect when made, certain acts of
bankruptcy or insolvency, cross defaults to other material
indebtedness, and change of control. Under the Quest Midstream
Credit Agreement a change of control means (i) QRCP fails
to own or to have voting control over, at least 51% of the
equity interest of Quest Midstream GP; (ii) any person
acquires beneficial ownership of 51% or more of the equity
interest in Quest Midstream; (iii) Quest Midstream fails to
own 100% of the equity interests in Bluestem or (iv) QRCP
undergoes a change in control (the acquisition by a person, or
two or more persons acting in concert, of beneficial ownership
of 50% or more of QRCPs outstanding shares of voting
stock, except for a merger with and into another entity where
the other entity is the survivor if QRCPs stockholders of
record immediately preceding the merger hold more than 50% of
the outstanding shares of the surviving entity).
Quest Midstream was in compliance with all of its covenants as
of December 31, 2008.
Subordinated Notes
In December 2003, we
issued a five-year $51 million junior subordinated
promissory note (the Original Note) to ArcLight
Energy Partners Fund I, L.P. (ArcLight)
pursuant to the terms of a note purchase agreement. The Original
Note bore interest at 15% per annum and was subordinate and
junior in right of payment to the prior payment in full of
superior debts. In connection with the purchase of the Original
Note, the original limited liability company agreement for Quest
Cherokee was amended and restated to, among other things,
provide for Class A units and Class B units of
membership interest, and ArcLight acquired all of the
Class A units of Quest Cherokee in exchange for $100. The
existing membership interests in Quest Cherokee owned by our
subsidiaries were converted into all of the Class B units.
To appropriately determine the fair value of the Class A
units, we imputed a discount on the Original Note of
approximately $15.4 million. Accordingly, the initial
carrying value of the Original Note was $35.6 million. The
$15.4 million value allocated to the Class A units was
recorded as minority interest in Quest Cherokee in our
consolidated financial statements.
During 2005, Quest Cherokee and ArcLight amended and restated
the note purchase agreement to provide for the issuance to
ArcLight of up to $15 million of additional 15% junior
subordinated promissory notes (the Additional Notes
and together with the Original Notes, the Subordinated
Notes) pursuant to the terms of an amended and restated
note purchase agreement and issued $15 million of
Additional Notes to ArcLight.
In November 2005, we paid approximately $84 million to
repurchase the Subordinated Notes and accrued interest and
$26.1 million to repurchase the Class A units of Quest
Cherokee. In connection with this transaction, a loss on
extinguishment of debt of approximately $12.4 million was
recognized representing the remaining debt discount on the
Subordinated Notes as of the date of the repurchase. The excess
of the amount paid to repurchase the Class A units of Quest
Cherokee over the minority interest (approximately
$10.7 million) was allocated to oil and
F-33
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
gas properties and pipeline assets under the provisions of
SFAS 141. Additionally, the Company wrote-off
$0.8 million in deferred loan costs related to the Original
Note.
Note 5
Property
Oil and gas properties, pipeline assets and other property and
equipment were comprised of the following as of
December 31, 2008, 2007 and 2006 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Oil and gas properties under the full cost method of accounting:
|
|
|
|
|
|
|
|
|
|
|
|
|
Properties being amortized
|
|
$
|
299,629
|
|
|
$
|
380,033
|
|
|
$
|
288,646
|
|
Properties not being amortized
|
|
|
10,108
|
|
|
|
7,986
|
|
|
|
8,108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas properties, at cost
|
|
|
309,737
|
|
|
|
388,019
|
|
|
|
296,754
|
|
Less: accumulated depletion, depreciation and amortization
|
|
|
(137,200
|
)
|
|
|
(87,066
|
)
|
|
|
(55,476
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties, net
|
|
$
|
172,537
|
|
|
$
|
300,953
|
|
|
$
|
241,278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline assets, at cost
|
|
$
|
333,966
|
|
|
$
|
306,317
|
|
|
$
|
132,715
|
|
Less: accumulated depreciation
|
|
|
(23,527
|
)
|
|
|
(11,791
|
)
|
|
|
(6,061
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline assets, net
|
|
$
|
310,439
|
|
|
$
|
294,526
|
|
|
$
|
126,654
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other property and equipment at cost
|
|
$
|
33,994
|
|
|
$
|
27,712
|
|
|
$
|
21,115
|
|
Less: accumulated depreciation
|
|
|
(10,131
|
)
|
|
|
(6,207
|
)
|
|
|
(4,435
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other property and equipment, net
|
|
$
|
23,863
|
|
|
$
|
21,505
|
|
|
$
|
16,680
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2008, the Companys net book value
of oil and gas properties exceeded the full cost ceiling.
Accordingly, a provision for impairment was recognized in the
fourth quarter of 2008 of $298.9 million. The provision for
impairment was primarily attributable to declines in the
prevailing market prices of oil and gas at the measurement date
and revisions of reserves due to further technical analysis and
production of gas during 2008. See Note 21
Supplemental Information on Oil and Gas Producing Activities
(Unaudited).
Depreciation on pipeline assets and other property and equipment
is computed on the straight-line basis over the following
estimated useful lives:
|
|
|
|
|
Pipelines
|
|
|
15 to 40 years
|
|
Buildings
|
|
|
25 years
|
|
Machinery and equipment
|
|
|
10 years
|
|
Software and computer equipment
|
|
|
3 to 5 years
|
|
Furniture and fixtures
|
|
|
10 years
|
|
Vehicles
|
|
|
7 years
|
|
For the years ended December 31, 2008, 2007, 2006 and 2005,
depletion, depreciation and amortization expense (excluding
impairment amounts discussed above) on oil and gas properties
amounted to $50.4 million, $31.7 million,
$22.4 million and $19.4 million, respectively;
depreciation expense on pipeline assets amounted to
$16.2 million, $5.8 million, $2.5 million and
$1.4 million, respectively; and depreciation expense on
other property and equipment amounted to $3.8 million,
$2.3 million, $2.1 million and $1.4 million,
respectively.
F-34
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 6
Minority Interests
A rollforward of minority interest balances related to
QRCPs investments in Quest Energy and Quest Midstream for
the periods indicated is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Quest Energy:
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
$
|
145,364
|
|
|
$
|
|
|
|
$
|
|
|
Contributions, net
|
|
|
|
|
|
|
151,025
|
|
|
|
|
|
Distributions
|
|
|
(13,438
|
)
|
|
|
|
|
|
|
|
|
Minority interest in earnings (loss)
|
|
|
(73,295
|
)
|
|
|
(5,661
|
)
|
|
|
|
|
Stock compensation expense related to QELP unit-based awards
|
|
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year
|
|
$
|
58,666
|
|
|
$
|
145,364
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quest Midstream:
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
$
|
152,021
|
|
|
$
|
84,173
|
|
|
$
|
|
|
Contributions, net
|
|
|
|
|
|
|
73,424
|
|
|
|
84,187
|
|
Distributions
|
|
|
(7,629
|
)
|
|
|
(9,470
|
)
|
|
|
|
|
Minority interest in earnings (loss)
|
|
|
1,027
|
|
|
|
2,757
|
|
|
|
(14
|
)
|
Stock compensation expense related to QMLP unit-based awards
|
|
|
451
|
|
|
|
1,137
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year
|
|
$
|
145,870
|
|
|
$
|
152,021
|
|
|
$
|
84,173
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total minority interest liability at end of year
|
|
$
|
204,536
|
|
|
$
|
297,385
|
|
|
$
|
84,173
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quest
Energy
During November 2007, QELP completed its initial public offering
of 9,100,000 common units (representing a 42.1% limited partner
interest) for net proceeds of $151.3 million
($163.8 million less $12.5 million for underwriting
discounts, structuring fees and offering costs). QELP was formed
by Quest to own, operate, acquire and develop Quests oil
and gas production operations in the Cherokee Basin. Quest
contributed assets to QELP in exchange for an aggregate 55.9%
limited partner interest (consisting of common and subordinated
limited partner units) in QELP, a 2% general partner interest
and incentive distribution rights (IDRs). IDRs entitle the
holder to specified increasing percentages of cash distributions
as QELPs
per-unit
cash distributions increase. In addition, Quest maintains
control over the assets owned by QELP through sole indirect
ownership of the general partner interests. Net proceeds from
the offering were used to refinance a portion of the existing
debt secured by the assets contributed to QELP.
The QELP common units have preference over the subordinated
units with respect to cash distributions. Accordingly, all
proceeds from the sale of the common units were recorded as
minority interest on the consolidated balance sheet. The
subordinated units will convert into an equal number of common
units upon termination of the subordination period. Generally,
the subordination period will end when either:
(i) QELP has paid at least $0.40 per quarter on each
outstanding common unit, subordinated unit and general partner
unit for any three consecutive non-overlapping four-quarter
periods ending on or after December 31, 2012; or
F-35
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(ii) QELP has paid at least $0.50 per quarter on each
outstanding common unit, subordinated unit and general partner
unit for any two consecutive non-overlapping four-quarter
periods ending on or after December 31, 2010; or
(iii) if the unitholders remove QELPs general partner
other than for cause and units held by its general partner and
its affiliates are not voted in favor of such removal.
The results of operations and financial position of QELP are
included in our consolidated financial statements. The portion
of QELPs results of operations that is attributable to
common units held by the public (units not held by Quest) is
recorded as minority interests.
Pursuant to the terms of its partnership agreement, QELP is
required to pay a minimum quarterly distribution of $0.40 per
unit to the extent it has sufficient cash available for
distribution. During 2008, QELP paid the following distributions:
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
|
|
|
|
$0.41
|
|
|
per unit on all outstanding units
|
Second Quarter
|
|
|
|
|
|
|
$0.43
|
|
|
per unit on all outstanding units
|
Third Quarter
|
|
|
|
|
|
|
$0.40
|
|
|
per unit on only the common units and a proportionate
distribution on the general partner units
|
Fourth Quarter
|
|
|
|
|
|
|
$0
|
|
|
|
No distributions may be made to the subordinated unitholders
until minimum quarterly distributions to the common unitholders,
plus any arrearages, have been made.
Quest
Midstream
During 2006, QMLP was formed by Quest to own, operate, acquire
and develop midstream assets. Quest transferred pipeline assets
and certain associated liabilities to QMLP as a capital
contribution in exchange for 4,900,000 Class B
subordinated units and 35,134 Class A subordinated
units, which currently represents an aggregate 35.69% limited
partner interest in QMLP, as well as an 85% interest in the
general partner of QMLP, which owns a 2% general partner
interest and incentive distribution rights. The IDRs entitle the
holder to specified increasing percentages of cash distributions
as QMLPs per-unit cash distributions increase. At the same
time, QMLP issued 4,864,866 common units to private
investors for net proceeds of $84.2 million
($90 million less $5.8 million for placement fees and
offering costs).
In November 2007, QMLP completed the purchase of the
KPC Pipeline for a purchase price of approximately
$133 million in cash, subject to adjustment for working
capital at closing, and assumed liabilities of approximately
$1.2 million. In connection with this acquisition, QMLP
issued 3,750,000 common units to private investors for
approximately $75 million of gross proceeds
($73.6 million after offering costs). As a result of these
two issuances, private investors currently own an approximate
62.31% limited partner interest in QMLP. Quest maintains control
over the assets owned by QMLP through its majority ownership
interest in QMLPs general partner.
The QMLP common units have preference over the subordinated
units with respect to cash distributions. Accordingly, all
proceeds from the sale of the common units were recorded as
minority interest on the consolidated balance sheet. The
subordinated units will convert into an equal number of common
units upon termination of the subordination period. Generally,
the subordination period will end when either:
(i) QMLP has paid at least $0.425 per quarter on each
outstanding common unit, subordinated unit and general partner
unit for any three consecutive non-overlapping four quarter
periods ending on or after December 22, 2013; or
(ii) if the QMLP unitholders remove its general partner
other than for cause and units held by the general partner and
its affiliates are not voted in favor of such removal.
F-36
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The results of operations and financial position of QMLP are
included in our consolidated financial statements. The portion
of QMLPs results of operations that is attributable to
common units held by the private investors (units we do not
hold) is recorded as minority interests.
Pursuant to the terms of its partnership agreement, QMLP is
required to pay a minimum quarterly distribution to the common
unitholders of $0.425 per unit to the extent it has sufficient
cash available for distribution. During 2008, QMLP paid the
following distributions:
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
|
|
|
|
$0.425
|
|
|
per unit on only the common units and a proportionate
distribution on the general partner units
|
Second Quarter
|
|
|
|
|
|
|
$0.425
|
|
|
per unit on only the common units and a proportionate
distribution on the general partner units
|
Third Quarter
|
|
|
|
|
|
|
$0
|
|
|
|
Fourth Quarter
|
|
|
|
|
|
|
$0
|
|
|
|
No distribution may be made to the subordinated unitholders
until minimum quarterly distributions to the common unitholders,
plus any arrearages, have been made.
Note 7
Derivative Financial Instruments
We are exposed to commodity price and interest rate risk, and
management believes it prudent to periodically reduce our
exposure to cash-flow variability resulting from this
volatility. Accordingly, we enter into certain derivative
financial instruments in order to manage exposure to commodity
price risk inherent in the Companys oil and gas production
operations. Specifically, we utilize futures, swaps and options.
Futures contracts and commodity swap agreements are used to fix
the price of expected future oil and gas sales at major industry
trading locations, such as Henry Hub, Louisiana for gas and
Cushing, Oklahoma for oil. Basis swaps are used to fix or float
the price differential between the price of gas at Henry Hub and
various other market locations. Options are used to fix a floor
and a ceiling price (collar) for expected future oil and gas
sales. Derivative financial instruments are also used to manage
commodity price risk inherent in customer pricing requirements
and to fix margins on the future sale of natural gas. Interest
rate swaps are used to fix or float interest rates attributable
to the Companys existing or anticipated indebtedness.
Settlements of any exchange-traded contracts are guaranteed by
the New York Mercantile Exchange (NYMEX) or the Intercontinental
Exchange and are subject to nominal credit risk.
Over-the-counter traded swaps, options and physical delivery
contracts expose us to credit risk to the extent the
counterparty is unable to satisfy its settlement commitment. We
monitor the creditworthiness of each counterparty and assess the
impact, if any, on fair value. In addition, we routinely
exercise our contractual right to net realized gains against
realized losses when settling with our swap and option
counterparties.
Interest Rate Derivatives
In the past,
the Company has entered into interest rate derivatives to
mitigate its exposure to fluctuations in interest rates on
variable rate debt. These instruments were not designated as
hedges and, therefore, were recorded in the consolidated balance
sheet at fair value with changes in fair value recognized in
earnings as they occurred.
Commodity Derivatives
At
December 31, 2008, 2007 and 2006, QELP was a party to
derivative financial instruments in order to manage commodity
price risk associated with a portion of our expected future
sales of our oil and gas production. None of these derivative
instruments have been designated as hedges. Accordingly, we
record all derivative instruments in the consolidated balance
sheet at fair value with changes in fair value recognized in
earnings as they occur. Both realized and unrealized gains and
losses associated with derivative financial instruments are
currently recognized in other income (expense) as they occur.
F-37
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Gains and losses associated with derivative financial
instruments related to gas and oil production were as follows
for the years ended December 31, 2008, 2007, 2006 and
2005 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Realized gains (losses)
|
|
$
|
8,174
|
|
|
$
|
7,279
|
|
|
$
|
(17,712
|
)
|
|
$
|
(26,964
|
)
|
Unrealized gains (losses)
|
|
|
72,533
|
|
|
|
(5,318
|
)
|
|
|
70,402
|
|
|
|
(46,602
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
80,707
|
|
|
$
|
1,961
|
|
|
$
|
52,690
|
|
|
$
|
(73,566
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following tables summarize the estimated volumes, fixed
prices and fair value attributable to oil and gas derivative
contracts as of December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ending December 31,
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
Thereafter
|
|
|
Total
|
|
|
|
($ in thousands, except volumes and per unit data)
|
|
|
Natural Gas Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Mmbtu)
|
|
|
14,629,200
|
|
|
|
12,499,060
|
|
|
|
2,000,004
|
|
|
|
2,000,004
|
|
|
|
31,128,268
|
|
Weighted-average fixed price per Mmbtu
|
|
$
|
7.78
|
|
|
$
|
7.42
|
|
|
$
|
8.00
|
|
|
$
|
8.11
|
|
|
$
|
7.67
|
|
Fair value, net
|
|
$
|
38,107
|
|
|
$
|
14,071
|
|
|
$
|
2,441
|
|
|
$
|
2,335
|
|
|
$
|
56,954
|
|
Natural Gas Collars:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Mmbtu):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
|
750,000
|
|
|
|
630,000
|
|
|
|
3,549,996
|
|
|
|
3,000,000
|
|
|
|
7,929,996
|
|
Ceiling
|
|
|
750,000
|
|
|
|
630,000
|
|
|
|
3,549,996
|
|
|
|
3,000,000
|
|
|
|
7,929,996
|
|
Weighted-average fixed price per Mmbtu:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
$
|
11.00
|
|
|
$
|
10.00
|
|
|
$
|
7.39
|
|
|
$
|
7.03
|
|
|
$
|
7.79
|
|
Ceiling
|
|
$
|
15.00
|
|
|
$
|
13.11
|
|
|
$
|
9.88
|
|
|
$
|
7.39
|
|
|
$
|
9.52
|
|
Fair value, net
|
|
$
|
3,630
|
|
|
$
|
1,875
|
|
|
$
|
3,144
|
|
|
$
|
2,074
|
|
|
$
|
10,723
|
|
Total Natural Gas Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Mmbtu)
|
|
|
15,379,200
|
|
|
|
13,129,060
|
|
|
|
5,550,000
|
|
|
|
5,000,004
|
|
|
|
39,058,264
|
|
Weighted-average fixed price per Mmbtu
|
|
$
|
7.94
|
|
|
$
|
7.55
|
|
|
$
|
7.61
|
|
|
$
|
7.44
|
|
|
$
|
7.70
|
|
Fair value, net
|
|
$
|
41,737
|
|
|
$
|
15,946
|
|
|
$
|
5,585
|
|
|
$
|
4,409
|
|
|
$
|
67,677
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Bbl)
|
|
|
36,000
|
|
|
|
30,000
|
|
|
|
|
|
|
|
|
|
|
|
66,000
|
|
Weighted-average fixed per Bbl
|
|
$
|
90.07
|
|
|
$
|
87.50
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
88.90
|
|
Fair value, net
|
|
$
|
1,246
|
|
|
$
|
666
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,912
|
|
F-38
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following tables summarize the estimated volumes, fixed
prices and fair value attributable to gas derivative contracts
as of December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ending
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
Thereafter
|
|
|
Total
|
|
|
|
($ in thousands, except volumes and per unit data)
|
|
|
Natural Gas Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Mmbtu)
|
|
|
8,595,876
|
|
|
|
12,629,365
|
|
|
|
10,499,225
|
|
|
|
|
|
|
|
31,724,466
|
|
Weighted-average fixed price per Mmbtu
|
|
$
|
6.39
|
|
|
$
|
7.70
|
|
|
$
|
7.31
|
|
|
$
|
|
|
|
$
|
7.22
|
|
Fair value, net
|
|
$
|
1,517
|
|
|
$
|
1,721
|
|
|
$
|
(4,565
|
)
|
|
$
|
|
|
|
$
|
(1,327
|
)
|
Natural Gas Collars:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Mmbtu):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
|
7,027,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,027,566
|
|
Ceiling
|
|
|
7,027,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,027,566
|
|
Weighted-average fixed price per Mmbtu:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
$
|
6.54
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
6.54
|
|
Ceiling
|
|
$
|
7.53
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
7.53
|
|
Fair value, net
|
|
$
|
(1,617
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(1,617
|
)
|
Total Natural Gas Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Mmbtu)
|
|
|
15,623,442
|
|
|
|
12,629,365
|
|
|
|
10,499,225
|
|
|
|
|
|
|
|
38,752,032
|
|
Weighted-average fixed price per Mmbtu
|
|
$
|
6.46
|
|
|
$
|
7.70
|
|
|
$
|
7.31
|
|
|
$
|
|
|
|
$
|
7.09
|
|
Fair value, net
|
|
$
|
(100
|
)
|
|
$
|
1,721
|
|
|
$
|
(4,565
|
)
|
|
$
|
|
|
|
$
|
(2,944
|
)
|
F-39
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following tables summarize the estimated volumes, fixed
prices and fair value attributable to natural gas derivative
contracts as of December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ending
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Thereafter
|
|
|
Total
|
|
|
|
($ in thousands, except volumes and per unit data)
|
|
|
Natural Gas Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Mmbtu)
|
|
|
2,353,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,353,885
|
|
Weighted-average fixed price per Mmbtu
|
|
$
|
7.20
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
7.20
|
|
Fair value, net
|
|
$
|
2,107
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
2,107
|
|
Natural Gas Collars:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Mmbtu):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
|
8,432,595
|
|
|
|
7,027,566
|
|
|
|
|
|
|
|
|
|
|
|
15,460,161
|
|
Ceiling
|
|
|
8,432,595
|
|
|
|
7,027,566
|
|
|
|
|
|
|
|
|
|
|
|
15,460,161
|
|
Weighted-average fixed price per Mmbtu:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
$
|
6.63
|
|
|
$
|
6.54
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
6.59
|
|
Ceiling
|
|
$
|
7.54
|
|
|
$
|
7.53
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
7.54
|
|
Fair value, net
|
|
$
|
3,512
|
|
|
$
|
(2,856
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
656
|
|
Natural Gas Basis Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Mmbtu)
|
|
|
1,825,000
|
|
|
|
1,464,000
|
|
|
|
|
|
|
|
|
|
|
|
3,289,000
|
|
Weighted-average fixed price
|
|
$
|
(1.15
|
)
|
|
$
|
(1.03
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(1.10
|
)
|
Fair value, net
|
|
$
|
(389
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(389
|
)
|
Total Natural Gas Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Mmbtu)
|
|
|
10,786,480
|
|
|
|
7,027,566
|
|
|
|
|
|
|
|
|
|
|
|
17,814,046
|
|
Weighted-average fixed price per Mmbtu
|
|
$
|
6.75
|
|
|
$
|
6.54
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
6.67
|
|
Fair value, net
|
|
$
|
5,230
|
|
|
$
|
(2,856
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
2,374
|
|
Note 8
Financial Instruments
The Companys financial instruments include commodity
derivatives, debt, cash, receivables and payables. The carrying
value of the Companys debt approximates fair value as of
December 31, 2008, 2007 and 2006. The carrying amount of
cash, receivables and accounts payable approximates fair value
because of the short-term nature of those instruments.
Fair Value
The following table sets forth, by
level within the fair value hierarchy, our assets and
liabilities that were measured at fair value on a recurring
basis as of December 31, 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Netting and
|
|
|
|
|
|
|
Level
|
|
|
Level
|
|
|
Level
|
|
|
Cash
|
|
|
Total Net Fair
|
|
At December 31, 2008
|
|
1
|
|
|
2
|
|
|
3
|
|
|
Collateral*
|
|
|
Value
|
|
|
Derivative financial instruments assets
|
|
$
|
|
|
|
$
|
8,866
|
|
|
$
|
64,883
|
|
|
$
|
(4,160
|
)
|
|
$
|
69,589
|
|
Derivative financial instruments liabilities
|
|
$
|
|
|
|
$
|
(224
|
)
|
|
$
|
(3,936
|
)
|
|
$
|
4,160
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
8,642
|
|
|
$
|
60,947
|
|
|
$
|
|
|
|
$
|
69,589
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
Amounts represent the effect of legally enforceable master
netting agreements between the Company and its counterparties
and the payable or receivable for cash collateral held or placed
with the same counterparties.
|
F-40
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Risk management assets and liabilities in the table above
represent the current fair value of all open derivative
positions, excluding those derivatives designated as NPNS. We
classify all of these derivative instruments as Derivative
financial instrument assets or Derivative financial
instrument liabilities in our consolidated balance sheets.
In order to determine the fair value amounts presented above, we
utilize various factors, including market data and assumptions
that market participants would use in pricing assets or
liabilities as well as assumptions about the risks inherent in
the inputs to the valuation technique. These factors include not
only the credit standing of the counterparties involved and the
impact of credit enhancements (such as cash deposits, letters of
credit and parental guarantees), but also the impact of our
nonperformance risk on our liabilities. We utilize observable
market data for credit default swaps to assess the impact of
non-performance credit risk when evaluating our assets from
counterparties.
In certain instances, we may utilize internal models to measure
the fair value of our derivative instruments. Generally, we use
similar models to value similar instruments. Valuation models
utilize various inputs which include quoted prices for similar
assets or liabilities in active markets, quoted prices for
identical or similar assets or liabilities in markets that are
not active, other observable inputs for the assets or
liabilities, and market-corroborated inputs, which are inputs
derived principally from or corroborated by observable market
data by correlation or other means.
The following table sets forth a reconciliation of changes in
the fair value of risk management assets and liabilities
classified as Level 3 in the fair value hierarchy (in
thousands):
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
Balance at beginning of year
|
|
$
|
3,444
|
|
Realized and unrealized gains included in earnings
|
|
|
68,038
|
|
Purchases, sales, issuances, and settlements
|
|
|
(10,535
|
)
|
Transfers into and out of Level 3
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2008
|
|
$
|
60,947
|
|
|
|
|
|
|
Note 9
Asset Retirement Obligations
The following table describes the changes to the Companys
assets retirement liability for the years ending
December 31, 2008, 2007 and 2006 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Asset retirement obligations at beginning of year
|
|
$
|
2,938
|
|
|
$
|
1,410
|
|
|
$
|
1,150
|
|
Liabilities incurred
|
|
|
134
|
|
|
|
178
|
|
|
|
175
|
|
Liabilities settled
|
|
|
(22
|
)
|
|
|
(7
|
)
|
|
|
(7
|
)
|
Acquisition of KPC pipeline
|
|
|
|
|
|
|
1,194
|
|
|
|
|
|
Acquisition of PetroEdge
|
|
|
2,193
|
|
|
|
|
|
|
|
|
|
Accretion
|
|
|
388
|
|
|
|
163
|
|
|
|
92
|
|
Revisions in estimated cash flows
|
|
|
291
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations at end of year
|
|
$
|
5,922
|
|
|
$
|
2,938
|
|
|
$
|
1,410
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-41
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 10
Stockholders Equity
Stockholders Rights Plan
On
May 31, 2006, the board of directors of QRCP declared a
dividend distribution of one right for each share of common
stock of QRCP, and the dividend was distributed on June 15,
2006. The rights are governed by a Rights Agreement, dated as of
May 31, 2006, between QRCP and Computershare (formerly UMB
Bank, n.a.). Pursuant to the Rights Agreement, each right
entitles the registered holder to purchase from QRCP one
one-thousandth of a share (Unit) of Series B
Junior Participating Preferred Stock, $0.001 par value per
share, at a purchase price of $75.00 per Unit. The rights,
however, will not become exercisable unless and until, among
other things, any person acquires 15% or more of the outstanding
shares of common stock of QRCP. If a person acquires 15% or more
of the outstanding stock of QRCP (subject to certain exceptions
more fully described in the Rights Agreement), each right will
entitle the holder (other than the person who acquired 15% or
more of the outstanding common stock) to purchase common stock
of QRCP having a value equal to twice the exercise price of a
right. The rights are redeemable under certain circumstances at
$0.001 per right and will expire, unless earlier redeemed,
on May 31, 2016.
Stock Awards
Under the 2005 Omnibus Stock
Award Plan (as amended) (the Plan) there are
available for issuance 2,700,000 shares of QRCPs
Common Stock. The Shares that have been granted are subject to
pro rata vesting which ranges from 0 to 4 years. During
this vesting period, the fair value of the stock awards granted
is recognized pro rata as compensation expense in general and
administrative expenses. For the years ended December 31,
2008, 2007, 2006 and 2005, QRCP recognized $1.9 million,
$6.1 million, $1.0 million and $1.2 million, of
compensation expense related to stock awards. A summary of
changes in the non-vested restricted shares for the years ending
December 31, 2008, 2007 and 2006 is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
Number of
|
|
|
average
|
|
|
|
non-vested
|
|
|
grant-date
|
|
|
|
restricted shares
|
|
|
fair value
|
|
|
Non-vested restricted shares at December 31, 2005
|
|
|
108,000
|
|
|
$
|
10.00
|
|
Granted
|
|
|
75,000
|
|
|
|
8.95
|
|
Vested
|
|
|
(62,000
|
)
|
|
|
11.73
|
|
Forfeited
|
|
|
(4,000
|
)
|
|
|
10.00
|
|
|
|
|
|
|
|
|
|
|
Non-vested restricted shares at December 31, 2006
|
|
|
117,000
|
|
|
$
|
9.43
|
|
Granted
|
|
|
1,192,968
|
|
|
|
8.71
|
|
Vested
|
|
|
(222,472
|
)
|
|
|
9.21
|
|
Forfeited
|
|
|
(5,621
|
)
|
|
|
8.67
|
|
|
|
|
|
|
|
|
|
|
Non-vested restricted shares at December 31, 2007
|
|
|
1,081,875
|
|
|
$
|
8.69
|
|
Granted(a)
|
|
|
405,362
|
(a)
|
|
|
7.50
|
|
Vested
|
|
|
(470,912
|
)
|
|
|
8.28
|
|
Forfeited
|
|
|
(533,949
|
)
|
|
|
8.75
|
|
|
|
|
|
|
|
|
|
|
Non-vested restricted shares at December 31, 2008
|
|
|
482,376
|
|
|
$
|
8.01
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Includes 140,000 stock options converted to 70,000
restricted shares during the year.
|
As of December 31, 2008, total unrecognized stock-based
compensation expense related to non-vested restricted shares was
$1.6 million, which is expected to be recognized over a weighted
average period of approximately 1.28 years.
Stock Options
The Plan also provides for the
granting of options to purchase shares of QRCPs common
stock. QRCP has granted stock options to employees and
non-employees under the Plan. The options expire 10 years
following the date of grant and have a weighted average
remaining life of 8.78 years.
F-42
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
A summary of changes in stock options outstanding during the
years ending December 31, 2008, 2007, and 2006 is presented
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average
|
|
|
|
Stock
|
|
|
exercise price per
|
|
|
|
options
|
|
|
share
|
|
|
Options outstanding at December 31, 2004
|
|
|
|
|
|
$
|
|
|
Granted
|
|
|
250,000
|
|
|
|
10.00
|
|
Exercised
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding at December 31, 2005
|
|
|
250,000
|
|
|
|
10.00
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(100,000
|
)
|
|
|
10.00
|
|
|
|
|
|
|
|
|
|
|
Options outstanding at December 31, 2006
|
|
|
150,000
|
|
|
|
10.00
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
100,000
|
|
|
|
10.05
|
|
Exercised
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding at December 31, 2007
|
|
|
250,000
|
|
|
|
10.00
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
300,000
|
|
|
|
0.63
|
|
Exercised
|
|
|
(10,000
|
)
|
|
|
10.05
|
|
Converted
|
|
|
(140,000
|
)
|
|
|
10.03
|
|
|
|
|
|
|
|
|
|
|
Options outstanding at December 31, 2008
|
|
|
400,000
|
|
|
|
2.98
|
|
|
|
|
|
|
|
|
|
|
Options exercisable at December 31, 2008
|
|
|
250,000
|
|
|
$
|
4.38
|
|
|
|
|
|
|
|
|
|
|
The weighted average grant date fair value of stock options
granted during 2008, 2007 and 2005 were $0.54, $7.96, and $7.40,
respectively.
The weighted average remaining term of options outstanding and
options exercisable at December 31, 2008 was 9.10 and
8.68 years, respectively. Options outstanding and options
exercisable at December 31, 2008 had no aggregate intrinsic
value.
QRCP determines the fair value of stock option awards using the
Black-Scholes option pricing model. The expected life of the
option is estimated based upon historical exercise behavior. The
expected forfeiture rate was estimated based upon historical
forfeiture experience. The volatility assumption was estimated
based upon expectations of volatility over the life of the
option as measured by historical and implied volatility. The
risk-free interest rate was based on the U.S. Treasury rate
for a term commensurate with the expected life of the option.
The dividend yield was based upon a
12-month
average dividend yield. QRCP used the following weighted-average
F-43
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
assumptions to estimate the fair value of stock options granted
during the years ending December 31, 2008, 2007 and 2005:
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
2005
|
|
Expected option life years
|
|
10
|
|
10
|
|
10
|
Volatility
|
|
69.8%
|
|
61.1%
|
|
59.6%
|
Risk-free interest rate
|
|
5.42%
|
|
5.35%
|
|
5.32%
|
Dividend yield
|
|
|
|
|
|
|
Fair value
|
|
$0.41-$0.61
|
|
$7.96
|
|
$7.40
|
For the years ended December 31, 2008, 2007, 2006 and 2005,
we recognized $0.2 million, $0.5 million,
$0.2 million and $0.5 million of compensation expense
related to stock options. As of December 31, 2008, there
was $0.2 million of total unrecognized compensation cost
related to stock options, which is expected to be recognized
over a weighted average period of 1.38 years.
During 2008, we converted 140,000 stock options held by certain
directors into 70,000 shares of unvested restricted stock. As a
result, we recognized additional compensation expense of
$0.1 million for the year ended December 31, 2008.
Earnings (Loss) per Share
A reconciliation of
the numerator and denominator used in the basic and diluted per
share calculations for the years ending December 31, 2008,
2007, 2006 and 2005, is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common shareholders
|
|
$
|
(167,384
|
)
|
|
$
|
(44,154
|
)
|
|
$
|
29,508
|
|
|
$
|
(95,885
|
)
|
Shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
|
|
|
27,011
|
|
|
|
22,379
|
|
|
|
22,119
|
|
|
|
8,352
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total basic earnings (loss) per share
|
|
$
|
(6.20
|
)
|
|
$
|
(1.97
|
)
|
|
$
|
1.33
|
|
|
$
|
(11.48
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common shareholders
|
|
$
|
(167,384
|
)
|
|
$
|
(44,154
|
)
|
|
$
|
29,508
|
|
|
$
|
(95,885
|
)
|
Shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares and common stock equivalents
|
|
|
27,011
|
|
|
|
22,379
|
|
|
|
22,130
|
|
|
|
8,352
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total diluted earnings (loss) per share
|
|
$
|
(6.20
|
)
|
|
$
|
(1.97
|
)
|
|
$
|
1.33
|
|
|
$
|
(11.48
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Because we have reported a net loss in the years ended
December 31, 2008, 2007 and 2005, restricted stock awards
covering 871,344; 781,540; and 25,545 common shares,
respectively, and the effect of outstanding options to purchase
193,288; 188,082; and 54,110 common shares, respectively,
were excluded from the computation of net loss per share because
their effect would have been antidilutive.
F-44
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 11
Income Taxes
Because we have recorded a full valuation allowance against our
net deferred tax assets, federal and state income tax expense,
both current and deferred, was zero for the years ended
December 31, 2008, 2007, 2006 and 2005.
A reconciliation of federal income taxes at the statutory
federal rates to our actual provision for income taxes for the
years ended December 31, 2008, 2007, 2006 and 2005 are as
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Income tax expense (benefit) at statutory rate
|
|
$
|
(58,584
|
)
|
|
$
|
(15,454
|
)
|
|
$
|
10,328
|
|
|
$
|
(33,556
|
)
|
State income tax expense (benefit), net of federal
|
|
|
(3,789
|
)
|
|
|
(956
|
)
|
|
|
620
|
|
|
|
(2,341
|
)
|
Carryover depletion in excess of cost
|
|
|
|
|
|
|
|
|
|
|
(736
|
)
|
|
|
(525
|
)
|
Other
|
|
|
300
|
|
|
|
752
|
|
|
|
(51
|
)
|
|
|
(1,941
|
)
|
Change in valuation allowance
|
|
|
62,073
|
|
|
|
15,658
|
|
|
|
(10,161
|
)
|
|
|
38,363
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total tax expense (benefit)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes reflect the net tax effects of temporary
differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts
used for income tax reporting. Deferred tax assets are reduced
by a valuation allowance if it is deemed more likely than not
that some or all of the deferred assets will not be realized
based on the weight of all available evidence. Based on the
negative evidence that existed as of each reporting period, we
recorded a full valuation allowance against our net deferred tax
asset as of December 31, 2008, 2007, 2006 and 2005.
Deferred tax assets and liabilities as of December 31,
2008, 2007, 2006 and 2005 were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Current deferred income tax assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative expense recorded for book, not for tax
|
|
$
|
|
|
|
$
|
|
|
|
$
|
3,310
|
|
|
$
|
15,765
|
|
Accrued liabilities
|
|
|
219
|
|
|
|
749
|
|
|
|
|
|
|
|
117
|
|
Allowance for bad debts
|
|
|
78
|
|
|
|
79
|
|
|
|
70
|
|
|
|
53
|
|
Unearned revenue
|
|
|
236
|
|
|
|
111
|
|
|
|
167
|
|
|
|
75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current deferred income tax assets
|
|
|
533
|
|
|
|
939
|
|
|
|
3,547
|
|
|
|
16,010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent deferred income tax assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative expense recorded for books, not for tax
|
|
|
|
|
|
|
|
|
|
|
4,055
|
|
|
|
9,809
|
|
Accrued liabilities
|
|
|
|
|
|
|
|
|
|
|
526
|
|
|
|
429
|
|
Partnership basis differences
|
|
|
7,401
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment basis differences
|
|
|
18,434
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net operating loss carryforwards
|
|
|
72,635
|
|
|
|
61,577
|
|
|
|
38,239
|
|
|
|
22,314
|
|
Other tax credit carryforwards
|
|
|
4,352
|
|
|
|
2,164
|
|
|
|
2,164
|
|
|
|
1,379
|
|
Misappropriation of assets
|
|
|
3,728
|
|
|
|
3,728
|
|
|
|
2,982
|
|
|
|
746
|
|
Other expense recorded for books, not for tax
|
|
|
1,320
|
|
|
|
1,997
|
|
|
|
494
|
|
|
|
334
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total noncurrent deferred income tax assets
|
|
|
107,870
|
|
|
|
69,466
|
|
|
|
48,460
|
|
|
|
35,011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred income tax assets
|
|
|
108,403
|
|
|
|
70,405
|
|
|
|
52,007
|
|
|
|
51,021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-45
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Current deferred income tax liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative income recorded for books, not for tax
|
|
|
|
|
|
|
|
|
|
|
(5,259
|
)
|
|
|
(18
|
)
|
Other
|
|
|
|
|
|
|
|
|
|
|
(539
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current deferred income tax liabilities
|
|
|
|
|
|
|
|
|
|
|
(5,798
|
)
|
|
|
(18
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent deferred income tax liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative income recorded for books, not for tax
|
|
|
|
|
|
|
|
|
|
|
(2,990
|
)
|
|
|
(198
|
)
|
Partnership basis differences
|
|
|
|
|
|
|
(21,542
|
)
|
|
|
(4,790
|
)
|
|
|
|
|
Property and equipment basis differences
|
|
|
|
|
|
|
(2,533
|
)
|
|
|
(7,757
|
)
|
|
|
(9,973
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total noncurrent deferred income tax liabilities
|
|
|
|
|
|
|
(24,075
|
)
|
|
|
(15,537
|
)
|
|
|
(10,171
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred income tax liabilities
|
|
|
|
|
|
|
(24,075
|
)
|
|
|
(21,335
|
)
|
|
|
(10,189
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred income tax assets
|
|
|
108,403
|
|
|
|
46,330
|
|
|
|
30,672
|
|
|
|
40,832
|
|
Valuation allowance
|
|
|
(108,403
|
)
|
|
|
(46,330
|
)
|
|
|
(30,672
|
)
|
|
|
(40,832
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax asset (liability)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We have net operating loss (NOL) carryforwards of
approximately $195 million at December 31, 2008 that
are available to reduce future U.S. taxable income. If not
utilized, such carryforwards will expire from 2021 through 2026.
Our ability to utilize NOL carryforwards to reduce future
federal taxable income and federal income tax of the Company is
subject to various limitations under the Internal Revenue Code
of 1986, as amended (the Code). The utilization of
such carryforwards may be limited upon the occurrence of certain
ownership changes, including the issuance or exercise of rights
to acquire stock, the purchase or sale of stock by 5%
stockholders, as defined in the Treasury regulations, and the
offering of stock of the QRCP during any three-year period
resulting in an aggregate change of more than 50% in the
beneficial ownership of QRCP.
QRCP completed a private placement of its common stock on
November 14, 2005. In connection with this offering,
15,258,144 shares of common stock were issued. This
issuance may constitute an owner shift as defined in
the Regulations under
1.382-2T.
This event will subject approximately $40 million of
NOLs to limitations under Section 382 of the Code.
The current annual limitation on NOLs incurred prior to
the owner shift is expected to be approximately $4 million.
NOLs incurred after November 14, 2005 through
December 31, 2008 are not currently limited.
FIN 48 provides guidance for recognizing and measuring
uncertain tax positions. We file income tax returns in the
U.S. federal jurisdiction and various state and local
jurisdictions. Tax years 2001 to present remain open for the
majority of taxing authorities due to NOL utilization. Our
policy is to recognize interest and penalties, if any, related
to unrecognized tax benefits as income tax expense. We have no
amounts recorded for unrecognized tax benefits.
Note 12
Commitments and Contingencies
Litigation
We are subject, from time to time,
to certain legal proceedings and claims in the ordinary course
of conducting our business. We record a liability related to our
legal proceedings and claims when we have determined that it is
probable that we will be obligated to pay and the related amount
can be reasonably estimated. Except for those legal proceedings
listed below, we believe there are no pending legal proceedings
in which we are currently involved which, if adversely
determined, could have a material adverse effect on our
financial position,
F-46
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
results of operations or cash flow. We intend to defend
vigorously against the claims described below. We are unable to
predict the outcome of these proceedings or reasonably estimate
a range of possible loss that may result.
Federal
Securities Class Actions
Michael Friedman, individually and on behalf of all others
similarly situated v. Quest Energy Partners LP, Quest
Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David
E. Grose
, Case
No. 08-cv-936-M
U.S., District Court for the Western District of Oklahoma, filed
September 5, 2008
James Jents, individually and on behalf of all others
similarly situated v. Quest Resource Corporation, Jerry
Cash, David E. Grose, and John Garrison,
Case
No. 08-cv-968-M,
U.S. District Court for the Western District of Oklahoma,
filed September 12, 2008
J. Braxton Kyzer and Bapui Rao, individually and on
behalf of all others similarly situated v. Quest Energy
Partners LP, Quest Energy GP LLC, Quest Resource Corporation and
David E. Grose,
Case
No. 08-cv-1066-M,
U.S. District Court for the Western District of Oklahoma,
filed October 6, 2008
Paul Rosen, individually and on behalf of all others
similarly situated v. Quest Energy Partners LP, Quest
Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David
E. Grose,
Case
No. 08-cv-978-M,
U.S. District Court for the Western District of Oklahoma,
filed September 17, 2008
Four putative class action complaints were filed in the United
States District Court for the Western District of Oklahoma
against the Company, Quest Energy Partners, L.P., and Quest
Energy GP, LLC and certain of our current and former officers
and directors. The complaints were filed by certain stockholders
on behalf of themselves and other stockholders who purchased our
common stock between May 2, 2005 and August 25, 2008
and Quest Energy common units between November 7, 2007 and
August 25, 2008. The complaints assert claims under
Sections 10(b) and 20(a) of the Securities Exchange Act of
1934 and
Rule 10b-5
promulgated thereunder, and Sections 11 and 15 of the
Securities Act of 1933. The complaints allege that the
defendants violated the federal securities laws by issuing false
and misleading statements
and/or
concealing material facts concerning certain unauthorized
transfers of funds from subsidiaries of the Company to entities
controlled by the Companys former chief executive officer,
Mr. Jerry D. Cash. The complaints also allege that, as a
result of these actions, our stock price and the unit price of
Quest Energy was artificially inflated during the class period.
On December 29, 2008 the court consolidated these
complaints as
Michael Friedman, individually and on behalf of
all others similarly situated v. Quest Energy Partners LP,
Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and
David E. Grose
, Case
No. 08-cv-936-M,
in the Western District of Oklahoma. Various individual
plaintiffs have filed multiple rounds of motions seeking
appointment as lead plaintiff, however the court has not yet
ruled on these motions and appointed a lead plaintiff. Once a
lead plaintiff is appointed, the lead plaintiff must file a
consolidated amended complaint within 60 days after being
appointed. No further activity is expected in the purported
class action until a lead plaintiff is appointed and an amended
consolidated complaint is filed. The Company, Quest Energy and
Quest Energy GP intend to defend vigorously against
plaintiffs claims.
Federal
Derivative Case
James Stephens, derivatively on behalf of nominal
defendant Quest Resource Corporation. v. William H. Damon
III, Jerry Cash, David Lawler, David E. Grose, James B. Kite
Jr., John C. Garrison and Jon H. Rateau,
Case
No. 08-cv-1025-M,
U.S. District Court for the Western District of Oklahoma,
filed September 25, 2008
On September 25, 2008 a complaint was filed in the United
States District Court for the Western District of Oklahoma,
purportedly on our behalf, entitled
James Stephens,
derivatively on behalf on nominal defendant Quest Resource
Corporation v. William H. Damon III, Jerry Cash, David
Lawler, David E. Grose, James B. Kite Jr., John C. Garrison and
Jon H. Rateau
, Case
No. 08-cv-1025-M.
The complaint names certain of our current and former officers
and directors as defendants. The factual allegations mirror
those in the purported class actions described above, and the
complaint asserts claims for breach of fiduciary duty, abuse of
control, gross mismanagement, waste
F-47
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
of corporate assets, and unjust enrichment. The complaint seeks
disgorgement, costs, expenses, and equitable
and/or
injunctive relief. On October 16, 2008, the court stayed
this case pending the courts ruling on any motions to
dismiss the class action claims. The Company intends to defend
vigorously against these claims.
State
Court Derivative Cases
Tim Bodeker, derivatively on behalf of nominal defendant
Quest Resource Corporation v. Jerry Cash, David E. Grose,
Bob G. Alexander, David C. Lawler, James B. Kite, John C.
Garrison, Jon H. Rateau and William H. Damon III,
Case
No. CJ-2008-9042,
in the District Court of Oklahoma County, State of Oklahoma,
filed October 8, 2008
William H. Jacobson, derivatively on behalf of nominal
defendant Quest Resource Corporation v. Jerry Cash, David
E. Grose, David C. Lawler, James B. Kite, Jon H. Rateau, Bob G.
Alexander, William H. Damon III, John C. Garrison, Murrell,
Hall, McIntosh & Co., LLP, and Eide Bailly, LLP,
Case
No. CJ-2008-9657
,
in the District Court of Oklahoma County, State of Oklahoma,
filed October 27, 2008
Amy Wulfert, derivatively on behalf of nominal defendant
Quest Resource Corporation, v. Jerry D. Cash, David C.
Lawler, Jon C. Garrison, John H. Rateau, James B. Kite Jr.,
William H. Damon III, David E. Grose, N. Malone Mitchell III,
and Bryan Simmons,
Case
No. CJ-2008-9042
consolidated December 30, 2008, in the District Court of
Oklahoma County, State of Oklahoma (Original Case
No. CJ-2008-9624,
filed October 24, 2008)
The factual allegations in these petitions mirror those in the
purported class actions discussed above. All three petitions
assert claims for breach of fiduciary duty, abuse of control,
gross mismanagement, and unjust enrichment. The
Jacobson
petition also asserts claims against the two auditing firms
named in that suit for professional negligence and aiding and
abetting the director defendants breaches of fiduciary
duties. The
Wulfert
petition also asserts a claim against
Mr. Bryan Simmons for aiding and abetting
Messrs. Cashs and Groses breaches of fiduciary
duties. The petitions seek damages, costs, expenses, and
equitable relief. On November 12, 2008, the parties to
these lawsuits filed a motion to consolidate the actions and
appoint lead counsel. The court has not yet ruled on this
motion. Under the proposed order, the defendants need not
respond to the individual petitions. Once the actions are
consolidated, the proposed order provides that counsel for the
parties shall meet and confer, within thirty days from the date
of the entry of the order, regarding the scheduling of the
filing of a consolidated derivative petition and the
defendants responses to that petition. The Company intends
to defend vigorously against plaintiffs claims.
Royalty
Owner Class Action
Hugo Spieker, et al. v. Quest Cherokee, LLC
Case
No. 07-1225-MLB
in the U.S. District Court, District of Kansas, filed
August 6, 2007
Quest Cherokee was named as a defendant in a class action
lawsuit filed by several royalty owners in the
U.S. District Court for the District of Kansas. The case
was filed by the named plaintiffs on behalf of a putative class
consisting of all Quest Cherokees royalty and overriding
royalty owners in the Kansas portion of the Cherokee Basin.
Plaintiffs contend that Quest Cherokee failed to properly make
royalty payments to them and the putative class by, among other
things, paying royalties based on reduced volumes instead of
volumes measured at the wellheads, by allocating expenses in
excess of the actual costs of the services represented, by
allocating production costs to the royalty owners, by improperly
allocating marketing costs to the royalty owners, and by making
the royalty payments after the statutorily proscribed time for
doing so without providing the required interest. Quest Cherokee
has answered the complaint and denied plaintiffs claims.
Discovery in that case is ongoing. Quest Cherokee intends to
defend vigorously against these claims.
F-48
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Personal
Injury Litigation
Segundo Francisco Trigoso and Dana Jara De Trigoso v.
Quest Cherokee Oilfield Service, LLC,
CJ-2007-11079,
in the District Court of Oklahoma County, State of Oklahoma,
filed December 27, 2007
Quest Cherokee Oilfield Service, LLC (QCOS) has been
named in this lawsuit filed by plaintiffs Segundo Francisco
Trigoso and Dana Jara De Trigoso. Plaintiffs allege that Segundo
Francisco Trigoso was seriously injured while working for QCOS
on September 29, 2006 and that the conduct of QCOS was
substantially certain to cause injury to Segundo Francisco
Trigoso. Plaintiffs seek unspecified damages for physical
injuries, emotional injuries, loss of consortium and pain and
suffering. Plaintiffs also seek punitive damages. Various
motions for summary judgment have been filed and denied by the
court. It is expected that the court will set this matter for
trial in Fall 2009. QCOS intends to defend vigorously against
plaintiffs claims.
St. Paul Surplus Lines Insurance Company v. Quest
Cherokee Oilfield Service, LLC, et al,
CJ-2009-1078, in the
District Court of Tulsa County, State of Oklahoma, filed
February 11, 2009
QCOS has been named as a defendant in this declaratory action.
This action arises out of the
Trigoso
matter discussed
above. Plaintiff alleges that no coverage is owed QCOS under the
excess insurance policy issued by plaintiff. The contentions of
plaintiff primarily rest on their position that the allegations
made in
Trigoso
are intentional in nature and that the
excess insurance policy does not cover such claims. QCOS will
vigorously defend the declaratory action.
Environmental Matters
As of
December 31, 2008, there were no known environmental or
regulatory matters related to our operations which are
reasonably expected to result in a material liability to us.
Like other oil and gas producers and marketers, our 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.
Operating Lease Commitments
We have a leasing
agreement for pipeline capacity that includes renewal options
and options to increase capacity, which would also increase
rentals. The initial term of this lease began June 1, 1992
and ends October 31, 2009.
We have lease agreements to obtain natural gas compressors as
and when required. Terms of the leases on the gas compressors
call for a minimum obligation of one year and are month to month
thereafter.
In addition, we have operating leases for office space,
warehouse facilities and office equipment expiring in various
years through 2017.
Future minimum rental payments under all non-cancelable
operating leases as of December 31, 2008, were as follows
(in thousands):
|
|
|
|
|
Year ending December 31,
|
|
|
|
|
2009
|
|
$
|
4,050
|
|
2010
|
|
|
1,553
|
|
2011
|
|
|
1,524
|
|
2012
|
|
|
1,240
|
|
2013
|
|
|
1,085
|
|
Thereafter
|
|
|
2,690
|
|
|
|
|
|
|
Total minimum lease obligations
|
|
$
|
12,142
|
|
|
|
|
|
|
Total rental expense under operating leases was approximately
$17.2 million, $10.3 million, $7.4 million, and
$5.6 million for the years ended December 31, 2008,
2007, 2006 and 2005, respectively. Included in 2008 are
$3.1 million of expenses for the pipeline capacity lease
discussed above.
F-49
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Financial Advisor Contracts
In October
2008, Quest Midstream GP engaged a financial advisor in
connection with the review of Quest Midstreams strategic
alternatives. Under the terms of the agreement, the financial
advisor received an advisory fee of $250,000 in October 2008 and
is entitled to additional monthly advisory fees of $75,000 from
December 2008 through September 2009, that is due ($750 thousand
in arrearages) on October 1, 2009. In addition, the
financial advisor is entitled to fees ranging from
$2.0 million to $4.0 million, reduced by 50% of the
advisory fees previously paid by Quest Midstream, depending on
whether or not certain transactions occur. During 2008, the
Company recorded $0.3 million of expense relating to this
agreement.
In October 2008, QRCP engaged a financial advisor with respect
to a review of its strategic alternatives. Under the terms
of the agreement, the financial advisor receives a monthly
retention fee of $150,000 per month. In addition, the
financial advisor is entitled to fees, which are not currently
estimable, if certain transactions occur. During 2008, QRCP
recorded $0.3 million of expense relating to this agreement.
In January 2009, Quest Energy GP engaged a financial
advisor to QELP in connection with the review of QELPs
strategic alternatives. Under the terms of the agreement, the
financial advisor received a one-time advisory fee of $50,000 in
January 2009 and is entitled to additional monthly advisory fees
of $25,000 for a minimum period of six months payable on the
last day of the month beginning January 31, 2009. In
addition, the financial advisor is entitled to fees, which are
not currently estimable, if certain transactions occur.
Note 13
Other Assets
Intangible Assets
Balances for the
contract-related intangibles acquired in the KPC Pipeline
acquisition were as follows as of December 31, 2008 (in
thousands):
|
|
|
|
|
Gross carrying amount
|
|
$
|
9,934
|
|
Accumulated amortization
|
|
|
4,340
|
|
|
|
|
|
|
Net carrying amount
|
|
$
|
5,594
|
|
|
|
|
|
|
These intangibles are recorded in Other Assets and are being
amortized over the term of the related contracts, which range
from one to ten years. Amortization expense in 2008 amounted to
$4.3 million. Projected amortization expense over the next
five years is expected to be $3.8 million,
$0.5 million, $0.5 million, $0.5 million and
$0.5 million. The weighted average amortization period is
2.4 years.
Deferred Financing Costs
The remaining
unamortized deferred financing costs at December 31, 2008,
2007 and 2006 were $8.1 million, $8.5 million and
$9.5 million, respectively, and are being amortized over
the life of the related credit facilities. In November 2007, the
credit facilities with Guggenheim Corporate Funding, LLC were
repaid, resulting in a charge of $9.0 million in
unamortized loan fees and $4.1 million in prepayment
penalties which are included with interest expense in 2007.
Deposits
The balance of long-term deposits at
December 31, 2008 and 2006 was $1.3 million and
$0.2 million, respectively. There were no long-term
deposits at December 31, 2007.
Note 14
Supplemental Cash Flow Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(in thousands)
|
|
|
Cash paid for interest
|
|
$
|
21,813
|
|
|
$
|
32,884
|
|
|
$
|
20,940
|
|
|
$
|
10,315
|
|
Cash paid for income taxes
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
F-50
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(in thousands)
|
|
|
Accrued purchases of property and equipment
|
|
$
|
1,492
|
|
|
$
|
861
|
|
|
$
|
1,305
|
|
|
$
|
328
|
|
Accrued distributions QMP
|
|
$
|
|
|
|
$
|
3,600
|
|
|
$
|
|
|
|
$
|
|
|
Accrued distributions QEP
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Note 15
Related Party Transactions
During the years ended December 31, 2005, 2006 and 2007,
our former chief executive officer, Mr. Jerry D. Cash made
certain unauthorized transfers, repayments and re-transfers of
funds totaling $2.0 million, $6.0 million and
$2.0 million, respectively, to entities that he controlled.
The Oklahoma Department of Securities has filed a lawsuit
alleging that our former chief financial officer, Mr. David
Grose, and our former purchasing manager, Mr. Brent
Mueller, stole approximately $1.0 million. In addition to
this theft, the Oklahoma Department of Securities has also filed
a lawsuit alleging that our former chief financial officer and
former purchasing manager received kickbacks totaling
approximately $1.8 million ($0.9 million each) from
several related suppliers beginning in 2005.
Note 16
Operating Segments
We divide our operations into two reportable business segments:
|
|
|
|
|
Oil and gas production; and
|
|
|
|
Natural gas pipelines, including transporting, selling,
gathering, treating and processing natural gas.
|
Both of these segments are exclusively located in the
continental United States, and each segment uses the same
accounting policies as those described in the summary of
significant accounting policies (see Note 2
Summary of Significant Accounting Policies). Our reportable
segments are strategic business units that offer different
products and services. Each segment is managed separately
because each segment involves different products and marketing
strategies. We do not allocate income taxes to our operating
segments.
F-51
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Operating segment data for the periods indicated is as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
$
|
147,937
|
|
|
$
|
105,285
|
|
|
$
|
72,410
|
|
|
$
|
70,628
|
|
Natural gas pipelines
|
|
|
63,722
|
|
|
|
39,032
|
|
|
|
25,833
|
|
|
|
11,732
|
|
Elimination of inter-segment revenue
|
|
|
(35,546
|
)
|
|
|
(29,179
|
)
|
|
|
(20,819
|
)
|
|
|
(7,793
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas pipelines, net of inter-segment revenue
|
|
|
28,176
|
|
|
|
9,853
|
|
|
|
5,014
|
|
|
|
3,939
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment revenues
|
|
$
|
176,113
|
|
|
$
|
115,138
|
|
|
$
|
77,424
|
|
|
$
|
74,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
$
|
(284,244
|
)
|
|
$
|
5,999
|
|
|
$
|
1,861
|
|
|
$
|
23,508
|
|
Natural gas pipelines
|
|
|
17,198
|
|
|
|
11,964
|
|
|
|
10,063
|
|
|
|
2,580
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment operating profit
|
|
|
(267,046
|
)
|
|
|
17,963
|
|
|
|
11,924
|
|
|
|
26,088
|
|
General and administrative expenses
|
|
|
(28,269
|
)
|
|
|
(21,023
|
)
|
|
|
(8,655
|
)
|
|
|
(6,218
|
)
|
Loss on misappropriation of funds
|
|
|
|
|
|
|
(2,000
|
)
|
|
|
(6,000
|
)
|
|
|
(2,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating income (loss)
|
|
$
|
(295,315
|
)
|
|
$
|
(5,060
|
)
|
|
$
|
(2,731
|
)
|
|
$
|
17,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(25,373
|
)
|
|
|
(43,628
|
)
|
|
|
(20,567
|
)
|
|
|
(28,225
|
)
|
Gain (loss) from derivative financial instruments
|
|
|
80,707
|
|
|
|
1,961
|
|
|
|
52,690
|
|
|
|
(73,566
|
)
|
Loss on early extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,355
|
)
|
Other income (expense) and sale of assets
|
|
|
329
|
|
|
|
(331
|
)
|
|
|
102
|
|
|
|
401
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes and minority interests
|
|
$
|
(239,652
|
)
|
|
$
|
(47,058
|
)
|
|
$
|
29,494
|
|
|
$
|
(95,875
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
$
|
239,467
|
|
|
$
|
91,265
|
|
|
$
|
98,591
|
|
|
$
|
32,636
|
|
Natural gas pipelines
|
|
|
27,649
|
|
|
|
173,604
|
|
|
|
60,080
|
|
|
|
9,279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures
|
|
$
|
267,116
|
|
|
$
|
264,869
|
|
|
$
|
158,671
|
|
|
$
|
41,915
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
$
|
53,663
|
|
|
$
|
33,812
|
|
|
$
|
24,392
|
|
|
$
|
20,795
|
|
Natural gas pipelines
|
|
|
16,782
|
|
|
|
5,970
|
|
|
|
2,619
|
|
|
|
1,449
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depreciation, depletion and amortization
|
|
$
|
70,445
|
|
|
$
|
39,782
|
|
|
$
|
27,011
|
|
|
$
|
22,244
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Identifiable assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
$
|
193,195
|
|
|
$
|
320,880
|
|
|
$
|
257,800
|
|
Natural gas pipelines
|
|
|
313,644
|
|
|
|
296,104
|
|
|
|
126,812
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total identifiable assets
|
|
$
|
506,839
|
|
|
$
|
616,984
|
|
|
$
|
384,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating profit represents total revenues less costs
and expenses attributable thereto, excluding interest and
general corporate expenses.
F-52
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 17
Profit Sharing Plan
Substantially all of our employees are covered by our profit
sharing plan under Section 401(k) of the Internal Revenue
Code. Eligible employees may make contributions to the plan by
electing to defer some of their compensation. Our match is
discretionary; however, historically we have matched 100% of
total contributions up to a total of five percent of their
annual compensation. Our matching contribution vests using a
graduated vesting schedule over six years of service. During the
years ended December 31, 2008, 2007, 2006 and 2005, we made
cash contributions to the plan of $0.6 million,
$0.6 million, $0.4 million and $0.4 million,
respectively.
During 2005, we contributed 49,842 shares of Quest common
stock to the plan. This profit sharing contribution related to
the year ended December 31, 2004 and was valued at
$0.5 million. Expense related to this contribution was
recorded in general and administrative expenses.
Note 18
Restatement
As reported on a Current Report on
Form 8-K
filed on January 2, 2009, on December 31, 2008, the
board of directors of QRCP determined that the consolidated
financial statements of QRCP as of and for the years ended
December 31, 2007, 2006 and 2005 and its unaudited
consolidated financial statements as of and for the three months
ended March 31, 2008 and as of and for the three and six
months ended June 30, 2008 should no longer be relied upon
as the result of the discovery of the Transfers to entities
controlled by QRCPs former chief executive officer,
Mr. Jerry D. Cash. Management identified other errors in
these financial statements, as described below, and the board of
directors concluded that QRCP had, and as of December 31,
2008 continued to have, material weaknesses in its internal
control over financial reporting.
The
Form 10-K
for the year ended December 31, 2008, to which these
consolidated financial statements form a part, includes restated
and reaudited consolidated financial statements for QRCP as of
December 31, 2007 and 2006 and for the years ended
December 31, 2007, 2006 and 2005. After filing the Form
10-K, QRCP will subsequently file amended Quarterly Reports on
Form 10-Q/A
including restated quarterly consolidated financial statements
for the quarters ended March 31, 2008 and June 30,
2008 and a Quarterly Report on Form 10-Q for the quarter
ended September 30, 2008.
As a result of the Transfers, the restated consolidated
financial statements show a reduction of $10 million in
cash balances of QRCP for periods ended on and after
December 31, 2007 and an increase in accumulated deficit
for periods ended on and after December 31, 2007 of
$10 million. The Transfers began in June of 2004 and
continued through July 1, 2008, but as a result of certain
repayments and the amounts involved, the cash balance and
accumulated deficit as reported on QRCPs consolidated
balance sheet as of December 31, 2004 were not materially
inaccurate as a result of the Transfers made prior to that date.
F-53
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Although the items listed below comprise the most significant
errors (by dollar amount), numerous other errors were identified
and restatement adjustments made. We have recorded restatement
adjustments to properly reflect the amounts as of and for the
periods affected, including the amounts included in
Note 20 Supplemental Financial
Information Quarterly Financial Data (Unaudited).
The tables below present previously reported stockholders
equity, major restatement adjustments and restated
stockholders (deficit) equity as well as previously
reported net income (loss), major restatement adjustments and
restated net income (loss) as of and for the periods indicated
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Stockholders (deficit) equity as previously reported
|
|
$
|
91,853
|
|
|
$
|
117,354
|
|
|
$
|
115,673
|
|
A Effect of the Transfers
|
|
|
(10,000
|
)
|
|
|
(8,000
|
)
|
|
|
(2,000
|
)
|
B Reversal of hedge accounting
|
|
|
707
|
|
|
|
(2,389
|
)
|
|
|
(8,177
|
)
|
C Accounting for formation of Quest Cherokee
|
|
|
(19,055
|
)
|
|
|
(19,159
|
)
|
|
|
(19,185
|
)
|
D Capitalization of costs in full cost pool
|
|
|
(23,936
|
)
|
|
|
(12,748
|
)
|
|
|
(5,388
|
)
|
E Recognition of costs in proper periods
|
|
|
(1,987
|
)
|
|
|
(321
|
)
|
|
|
(316
|
)
|
F Capitalized interest
|
|
|
1,713
|
|
|
|
1,367
|
|
|
|
286
|
|
G Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
H Depreciation, depletion and amortization
|
|
|
10,450
|
|
|
|
7,209
|
|
|
|
3,275
|
|
I Impairment of oil and gas properties
|
|
|
30,719
|
|
|
|
30,719
|
|
|
|
|
|
J Other errors
|
|
|
(3,695
|
)
|
|
|
809
|
|
|
|
(383
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders (deficit) equity as restated
|
|
$
|
76,769
|
|
|
$
|
114,841
|
|
|
$
|
83,785
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Net income (loss) as previously reported
|
|
$
|
(30,414
|
)
|
|
$
|
(48,478
|
)
|
|
$
|
(31,951
|
)
|
A Effect of the Transfers
|
|
|
(2,000
|
)
|
|
|
(6,000
|
)
|
|
|
(2,000
|
)
|
B Reversal of hedge accounting
|
|
|
1,183
|
|
|
|
53,387
|
|
|
|
(42,854
|
)
|
C Accounting for formation of Quest Cherokee
|
|
|
104
|
|
|
|
26
|
|
|
|
(14,402
|
)
|
D Capitalization of costs in full cost pool
|
|
|
(11,188
|
)
|
|
|
(7,360
|
)
|
|
|
(5,388
|
)
|
E Recognition of costs in proper periods
|
|
|
(1,666
|
)
|
|
|
(5
|
)
|
|
|
721
|
|
F Capitalized interest
|
|
|
346
|
|
|
|
1,081
|
|
|
|
154
|
|
G Stock-based compensation
|
|
|
(702
|
)
|
|
|
405
|
|
|
|
(790
|
)
|
H Depreciation, depletion and amortization
|
|
|
3,241
|
|
|
|
3,934
|
|
|
|
757
|
|
I Impairment of oil and gas properties
|
|
|
|
|
|
|
30,719
|
|
|
|
|
|
J Other errors
|
|
|
(3,058
|
)
|
|
|
1,799
|
|
|
|
(132
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) as restated
|
|
$
|
(44,154
|
)
|
|
$
|
29,508
|
|
|
$
|
(95,885
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The most significant errors (by dollar amount) consist of the
following:
(A)
The Transfers, which were not approved
expenditures of QRCP, were not properly accounted for as losses.
As a result of these losses not being recorded, cash and
accumulated deficit were overstated as of December 31,
2007, 2006 and 2005, and loss from misappropriation of funds was
understated for the years ended December 31, 2007, 2006 and
2005.
F-54
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(B)
Hedge accounting was inappropriately applied for
the Companys commodity derivative instruments and the
valuation of commodity derivative instruments was incorrectly
computed. The fair value of the commodity derivative instruments
previously reported were over/(under) stated by
$(2.6) million, $0.5 million and $6.3 million as
of December 31, 2007, 2006 and 2005, respectively. In
addition, we incorrectly presented realized gains and losses
related to commodity derivative instruments within oil and gas
sales. As a result of these errors, current and long-term
derivative financial instrument assets, current and long-term
derivative financial instrument liabilities, accumulated other
comprehensive income and accumulated deficit were
over/(under)stated as of December 31, 2007, 2006 and 2005,
and oil and gas sales and gain (loss) from derivative financial
instruments were over/(under)stated for the years ended
December 31, 2007, 2006 and 2005.
(C)
Errors were identified in the accounting for the
formation of Quest Cherokee in December 2003 in which:
(i) no value was ascribed to the subsidiary Class A
units that were issued to ArcLight in connection with the
transaction, (ii) a debt discount (and related accretion)
and minority interest were not recorded, (iii) transaction
costs were inappropriately capitalized to oil and gas
properties, and (iv) subsequent to December 2003, interest
expense was improperly stated as a result of these errors. In
2005, the debt relating to this transaction was repaid and the
Class A units were repurchased. Due to the errors that
existed in the previous accounting, additional errors resulted
in 2005 including: (i) a loss on extinguishment of debt was
not recorded, and (ii) oil and gas properties, pipeline
assets were overstated. Subsequent to the 2005 transaction,
depreciation, depletion and amortization expense was also
overstated due to these errors.
(D)
Certain general and administrative expenses
unrelated to oil and gas production were inappropriately
capitalized to oil and gas properties, and certain operating
expenses were inappropriately capitalized to oil and gas
properties being amortized. These items resulted in errors in
valuation of the full cost pool, oil and gas production expenses
and general and administrative expenses. As a result of these
errors, oil and gas properties being amortized and accumulated
deficit were over/(under)stated as of December 31, 2007,
2006 and 2005, and oil and gas production expenses and general
and administrative expenses were over/(under)stated for the
years ended December 31, 2007, 2006 and 2005.
(E)
Invoices were not properly accrued resulting in
the understatement of accounts payable and numerous other
balance sheet and income statement accounts. As a result of
these errors, accounts receivable, other current assets,
property and equipment, pipeline assets, properties being and
not being amortized and accumulated deficit were
over/(under)stated as of December 31, 2007, 2006 and 2005,
and oil and gas production expenses, pipeline operating expenses
and general and administrative expenses were over/(under)stated
for the years ended December 31, 2007, 2006 and 2005.
(F)
Capitalized interest was not recorded on
pipeline construction. As a result of this error, pipeline
assets and accumulated deficit were understated as of
December 31, 2007, 2006 and 2005, interest expense was
overstated for the years ended December 31, 2007, 2006 and
2005.
(G)
Errors were identified in stock-based
compensation expense, including the use of incorrect grant
dates, valuation errors, and incorrect vesting periods. As a
result of these errors, additional paid-in capital and
accumulated deficit were over/(under)stated as of
December 31, 2007, 2006 and 2005, and general and
administrative expenses were over/(under)stated for the years
ended December 31, 2007, 2006 and 2005.
(H)
As a result of previously discussed errors and
an additional error related to the method used in calculating
depreciation, depletion and amortization, errors existed in our
depreciation, depletion and amortization expense and our
accumulated depreciation, depletion and amortization. As a
result of these errors, accumulated depreciation, depletion and
amortization were over/(under)stated as of December 31,
2007, 2006 and 2005 and depreciation, depletion and amortization
expense was over/(under)stated for the years ended
December 31, 2007, 2006 and 2005.
(I)
As a result of previously discussed errors
relating to oil and gas properties and hedge accounting and
errors relating to the treatment of deferred taxes, errors
existed in our ceiling test calculations. As a result of these
errors,
F-55
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
the Company incorrectly recorded a $30.7 million impairment
to its oil and gas properties during the year ended
December 31, 2006.
(J)
We identified other errors during the reaudit
and restatement process where the impact on net income was not
deemed significant enough to warrant separate disclosure of
individual errors. Included in this amount is the minority
interest effect of the errors discussed above.
Outstanding shares
Errors were identified in
the calculation of outstanding shares in all periods as we
incorrectly included restricted share grants in our calculation
of issued shares when the restrictions lapsed, rather than the
date at which the restricted shares were granted. This error did
not affect net income, but did impact our issued and outstanding
share amounts as well as our weighted average share amount (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Previously reported issued shares
|
|
|
22,701
|
|
|
|
22,206
|
|
|
|
22,072
|
|
Total restatement adjustments
|
|
|
852
|
|
|
|
160
|
|
|
|
140
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restated issued shares
|
|
|
23,553
|
|
|
|
22,366
|
|
|
|
22,212
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Previously reported outstanding shares
|
|
|
22,701
|
|
|
|
22,206
|
|
|
|
22,072
|
|
Total restatement adjustments
|
|
|
(230
|
)
|
|
|
43
|
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restated outstanding shares
|
|
|
22,471
|
|
|
|
22,249
|
|
|
|
22,104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-56
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table outlines the effects of the restatement
adjustments on our Consolidated Statement of Operations for the
period indicated (in thousands, except share and per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
As Previously
|
|
|
Restatement
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
113,035
|
|
|
$
|
(7,750
|
)
|
|
$
|
105,285
|
|
Gas pipeline revenue
|
|
|
9,853
|
|
|
|
|
|
|
|
9,853
|
|
Other revenue (expense)
|
|
|
(9
|
)
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
122,879
|
|
|
|
(7,741
|
)
|
|
|
115,138
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
27,995
|
|
|
|
8,300
|
|
|
|
36,295
|
|
Pipeline operating
|
|
|
21,079
|
|
|
|
19
|
|
|
|
21,098
|
|
General and administrative expenses
|
|
|
17,976
|
|
|
|
3,047
|
|
|
|
21,023
|
|
Depreciation, depletion and amortization
|
|
|
41,401
|
|
|
|
(1,619
|
)
|
|
|
39,782
|
|
Impairment of oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from misappropriation of funds
|
|
|
|
|
|
|
2,000
|
|
|
|
2,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
108,451
|
|
|
|
11,747
|
|
|
|
120,198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
14,428
|
|
|
|
(19,488
|
)
|
|
|
(5,060
|
)
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) from derivative financial instruments
|
|
|
(6,502
|
)
|
|
|
8,463
|
|
|
|
1,961
|
|
Gain (loss) on sale of assets
|
|
|
(322
|
)
|
|
|
|
|
|
|
(322
|
)
|
Loss on early extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income
|
|
|
|
|
|
|
(9
|
)
|
|
|
(9
|
)
|
Interest expense
|
|
|
(42,916
|
)
|
|
|
(1,128
|
)
|
|
|
(44,044
|
)
|
Interest income
|
|
|
416
|
|
|
|
|
|
|
|
416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(49,324
|
)
|
|
|
7,326
|
|
|
|
(41,998
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes and minority interests
|
|
|
(34,896
|
)
|
|
|
(12,162
|
)
|
|
|
(47,058
|
)
|
Income tax benefit (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) before minority interests
|
|
|
(34,896
|
)
|
|
|
(12,162
|
)
|
|
|
(47,058
|
)
|
Minority interests
|
|
|
4,482
|
|
|
|
(1,578
|
)
|
|
|
2,904
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(30,414
|
)
|
|
$
|
(13,740
|
)
|
|
$
|
(44,154
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(1.37
|
)
|
|
$
|
(0.60
|
)
|
|
$
|
(1.97
|
)
|
Diluted
|
|
$
|
(1.37
|
)
|
|
$
|
(0.60
|
)
|
|
$
|
(1.97
|
)
|
Weighted average common and common equivalent shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
22,240,600
|
|
|
|
138,879
|
|
|
|
22,379,479
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
22,240,600
|
|
|
|
138,879
|
|
|
|
22,379,479
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-57
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table outlines the effects of the restatement
adjustments on our Consolidated Balance Sheet for the period
indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2007
|
|
|
|
As Previously
|
|
|
Restatement
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
16,680
|
|
|
$
|
(10,000
|
)
|
|
$
|
6,680
|
|
Restricted cash
|
|
|
1,236
|
|
|
|
|
|
|
|
1,236
|
|
Accounts receivable trade, net
|
|
|
15,768
|
|
|
|
(211
|
)
|
|
|
15,557
|
|
Other receivables
|
|
|
1,632
|
|
|
|
(152
|
)
|
|
|
1,480
|
|
Other current assets
|
|
|
3,717
|
|
|
|
245
|
|
|
|
3,962
|
|
Inventory
|
|
|
6,622
|
|
|
|
|
|
|
|
6,622
|
|
Current derivative financial instrument assets
|
|
|
6,729
|
|
|
|
1,279
|
|
|
|
8,008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
52,384
|
|
|
|
(8,839
|
)
|
|
|
43,545
|
|
Oil and gas properties under full cost method of accounting, net
|
|
|
300,717
|
|
|
|
236
|
|
|
|
300,953
|
|
Pipeline assets, net
|
|
|
297,279
|
|
|
|
(2,753
|
)
|
|
|
294,526
|
|
Other property and equipment, net
|
|
|
21,394
|
|
|
|
111
|
|
|
|
21,505
|
|
Other assets, net
|
|
|
8,268
|
|
|
|
273
|
|
|
|
8,541
|
|
Long-term derivative financial instrument assets
|
|
|
1,568
|
|
|
|
1,899
|
|
|
|
3,467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
681,610
|
|
|
$
|
(9,073
|
)
|
|
$
|
672,537
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
27,911
|
|
|
$
|
3,291
|
|
|
$
|
31,202
|
|
Revenue payable
|
|
|
6,806
|
|
|
|
919
|
|
|
|
7,725
|
|
Accrued expenses
|
|
|
9,058
|
|
|
|
(671
|
)
|
|
|
8,387
|
|
Current portion of notes payable
|
|
|
666
|
|
|
|
|
|
|
|
666
|
|
Current derivative financial instrument liabilities
|
|
|
8,241
|
|
|
|
(133
|
)
|
|
|
8,108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
52,682
|
|
|
|
3,406
|
|
|
|
56,088
|
|
Long-term liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term derivative financial instrument liabilities
|
|
|
5,586
|
|
|
|
725
|
|
|
|
6,311
|
|
Asset retirement obligation
|
|
|
3,813
|
|
|
|
(875
|
)
|
|
|
2,938
|
|
Long-term portion of notes payable
|
|
|
233,046
|
|
|
|
|
|
|
|
233,046
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
242,445
|
|
|
|
(150
|
)
|
|
|
242,295
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority interests
|
|
|
294,630
|
|
|
|
2,755
|
|
|
|
297,385
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders (deficit) equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock
|
|
|
23
|
|
|
|
1
|
|
|
|
24
|
|
Additional paid-in capital
|
|
|
212,819
|
|
|
|
(967
|
)
|
|
|
211,852
|
|
Accumulated other comprehensive income (loss)
|
|
|
(1,485
|
)
|
|
|
1,485
|
|
|
|
|
|
Accumulated deficit
|
|
|
(119,504
|
)
|
|
|
(15,603
|
)
|
|
|
(135,107
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders (deficit) equity
|
|
|
91,853
|
|
|
|
(15,084
|
)
|
|
|
76,769
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders (deficit) equity
|
|
$
|
681,610
|
|
|
$
|
(9,073
|
)
|
|
$
|
672,537
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-58
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table outlines the effects of the restatement
adjustments on our Consolidated Statement of Cash Flows for the
period indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, 2007
|
|
|
|
As Previously
|
|
|
Restatement
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(30,414
|
)
|
|
|
(13,740
|
)
|
|
$
|
(44,154
|
)
|
Adjustments to reconcile net income (loss) to cash provided by
operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
44,120
|
|
|
|
(4,338
|
)
|
|
|
39,782
|
|
Stock-based compensation
|
|
|
5,549
|
|
|
|
532
|
|
|
|
6,081
|
|
Stock-based compensation Minority interests
|
|
|
|
|
|
|
1,137
|
|
|
|
1,137
|
|
Stock issued for services and retirement plan
|
|
|
1,262
|
|
|
|
(1,262
|
)
|
|
|
|
|
Amortization of deferred loan costs
|
|
|
4,620
|
|
|
|
6,600
|
|
|
|
11,220
|
|
Change in fair value of derivative financial instruments
|
|
|
6,502
|
|
|
|
(1,184
|
)
|
|
|
5,318
|
|
Amortization of gas swap fees
|
|
|
187
|
|
|
|
(187
|
)
|
|
|
|
|
Bad debt expense
|
|
|
|
|
|
|
22
|
|
|
|
22
|
|
Minority interest
|
|
|
(4,482
|
)
|
|
|
1,578
|
|
|
|
(2,904
|
)
|
Loss on disposal of property and equipment
|
|
|
|
|
|
|
1,363
|
|
|
|
1,363
|
|
Other
|
|
|
323
|
|
|
|
(323
|
)
|
|
|
|
|
Change in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
(86
|
)
|
|
|
86
|
|
|
|
|
|
Accounts receivable
|
|
|
(5,928
|
)
|
|
|
|
|
|
|
(5,928
|
)
|
Other receivables
|
|
|
(1,260
|
)
|
|
|
15
|
|
|
|
(1,245
|
)
|
Other current assets
|
|
|
(2,649
|
)
|
|
|
(178
|
)
|
|
|
(2,827
|
)
|
Inventory
|
|
|
(989
|
)
|
|
|
989
|
|
|
|
|
|
Other assets
|
|
|
|
|
|
|
15
|
|
|
|
15
|
|
Accounts payable
|
|
|
13,129
|
|
|
|
1,218
|
|
|
|
14,347
|
|
Revenue payable
|
|
|
2,268
|
|
|
|
468
|
|
|
|
2,736
|
|
Accrued expenses
|
|
|
6,560
|
|
|
|
(2,559
|
)
|
|
|
4,001
|
|
Other long-term liabilities
|
|
|
|
|
|
|
220
|
|
|
|
220
|
|
Other
|
|
|
|
|
|
|
(388
|
)
|
|
|
(388
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
38,712
|
|
|
|
(9,916
|
)
|
|
|
28,796
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
|
|
|
|
(86
|
)
|
|
|
(86
|
)
|
Other assets
|
|
|
(8,598
|
)
|
|
|
8,598
|
|
|
|
|
|
Acquisition of business KPC
|
|
|
|
|
|
|
(133,725
|
)
|
|
|
(133,725
|
)
|
Equipment, development, leasehold and pipeline
|
|
|
(272,270
|
)
|
|
|
133,613
|
|
|
|
(138,657
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(280,868
|
)
|
|
|
8,400
|
|
|
|
(272,468
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from bank borrowings
|
|
|
268,580
|
|
|
|
(224,000
|
)
|
|
|
44,580
|
|
F-59
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, 2007
|
|
|
|
As Previously
|
|
|
Restatement
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Repayments of note borrowings
|
|
|
(225,441
|
)
|
|
|
|
|
|
|
(225,441
|
)
|
Proceeds from revolver note
|
|
|
|
|
|
|
224,000
|
|
|
|
224,000
|
|
Repayment of revolver note
|
|
|
(35,000
|
)
|
|
|
|
|
|
|
(35,000
|
)
|
Proceeds from Quest Energy
|
|
|
163,800
|
|
|
|
|
|
|
|
163,800
|
|
Proceeds from Quest MidStream
|
|
|
75,230
|
|
|
|
|
|
|
|
75,230
|
|
Syndication costs
|
|
|
(14,288
|
)
|
|
|
(330
|
)
|
|
|
(14,618
|
)
|
Distributions to unit holders
|
|
|
(5,894
|
)
|
|
|
22
|
|
|
|
(5,872
|
)
|
Proceeds from subordinated debt
|
|
|
|
|
|
|
|
|
|
|
|
|
Repayment of subordinated debt
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinancing costs
|
|
|
(10,142
|
)
|
|
|
(5
|
)
|
|
|
(10,147
|
)
|
Change in other long-term liabilities
|
|
|
171
|
|
|
|
(171
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
217,016
|
|
|
|
(484
|
)
|
|
|
216,532
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash
|
|
|
(25,140
|
)
|
|
|
(2,000
|
)
|
|
|
(27,140
|
)
|
Cash and cash equivalents, beginning of period
|
|
|
41,820
|
|
|
|
(8,000
|
)
|
|
|
33,820
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
16,680
|
|
|
$
|
(10,000
|
)
|
|
$
|
6,680
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-60
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table outlines the effects of the restatement
adjustments on our Consolidated Statement of Operations for the
period indicated (in thousands, except share and per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
|
|
As Previously
|
|
|
Restatement
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
65,551
|
|
|
$
|
6,859
|
|
|
$
|
72,410
|
|
Gas pipeline revenue
|
|
|
5,014
|
|
|
|
|
|
|
|
5,014
|
|
Other revenue (expense)
|
|
|
(80
|
)
|
|
|
80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
70,485
|
|
|
|
6,939
|
|
|
|
77,424
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
21,208
|
|
|
|
4,130
|
|
|
|
25,338
|
|
Pipeline operating
|
|
|
13,247
|
|
|
|
(96
|
)
|
|
|
13,151
|
|
General and administrative expenses
|
|
|
8,840
|
|
|
|
(185
|
)
|
|
|
8,655
|
|
Depreciation, depletion and amortization
|
|
|
28,025
|
|
|
|
(1,014
|
)
|
|
|
27,011
|
|
Impairment of oil and gas properties
|
|
|
30,719
|
|
|
|
(30,719
|
)
|
|
|
|
|
Loss from misappropriation of funds
|
|
|
|
|
|
|
6,000
|
|
|
|
6,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
102,039
|
|
|
|
(21,884
|
)
|
|
|
80,155
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(31,554
|
)
|
|
|
28,823
|
|
|
|
(2,731
|
)
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) from derivative financial instruments
|
|
|
6,410
|
|
|
|
46,280
|
|
|
|
52,690
|
|
Gain (loss) on sale of assets
|
|
|
3
|
|
|
|
|
|
|
|
3
|
|
Loss on early extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income
|
|
|
|
|
|
|
99
|
|
|
|
99
|
|
Interest expense
|
|
|
(23,483
|
)
|
|
|
2,526
|
|
|
|
(20,957
|
)
|
Interest income
|
|
|
390
|
|
|
|
|
|
|
|
390
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(16,680
|
)
|
|
|
48,905
|
|
|
|
32,225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes and minority interests
|
|
|
(48,234
|
)
|
|
|
77,728
|
|
|
|
29,494
|
|
Income tax benefit (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) before minority interests
|
|
|
(48,234
|
)
|
|
|
77,728
|
|
|
|
29,494
|
|
Minority interests
|
|
|
(244
|
)
|
|
|
258
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(48,478
|
)
|
|
$
|
77,986
|
|
|
$
|
29,508
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(2.19
|
)
|
|
$
|
3.52
|
|
|
$
|
1.33
|
|
Diluted
|
|
$
|
(2.19
|
)
|
|
$
|
3.52
|
|
|
$
|
1.33
|
|
Weighted average common and common equivalent shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
22,100,753
|
|
|
|
18,744
|
|
|
|
22,119,497
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
22,100,753
|
|
|
|
18,744
|
|
|
|
22,129,607
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-61
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table outlines the effects of the restatement
adjustments on our Consolidated Balance Sheet for the period
indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2006
|
|
|
|
As Previously
|
|
|
Restatement
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
41,820
|
|
|
$
|
(8,000
|
)
|
|
$
|
33,820
|
|
Restricted cash
|
|
|
1,150
|
|
|
|
|
|
|
|
1,150
|
|
Accounts receivable trade, net
|
|
|
9,840
|
|
|
|
(189
|
)
|
|
|
9,651
|
|
Other receivables
|
|
|
371
|
|
|
|
(136
|
)
|
|
|
235
|
|
Other current assets
|
|
|
1,068
|
|
|
|
8
|
|
|
|
1,076
|
|
Inventory
|
|
|
5,632
|
|
|
|
|
|
|
|
5,632
|
|
Current derivative financial instrument assets
|
|
|
10,795
|
|
|
|
3,314
|
|
|
|
14,109
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
70,676
|
|
|
|
(5,003
|
)
|
|
|
65,673
|
|
Oil and gas properties under full cost method of accounting, net
|
|
|
233,593
|
|
|
|
7,685
|
|
|
|
241,278
|
|
Pipeline assets, net
|
|
|
128,570
|
|
|
|
(1,916
|
)
|
|
|
126,654
|
|
Other property and equipment, net
|
|
|
16,212
|
|
|
|
468
|
|
|
|
16,680
|
|
Other assets, net
|
|
|
9,467
|
|
|
|
162
|
|
|
|
9,629
|
|
Long-term derivative financial instrument assets
|
|
|
4,782
|
|
|
|
3,240
|
|
|
|
8,022
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
463,300
|
|
|
$
|
4,636
|
|
|
$
|
467,936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
14,778
|
|
|
$
|
1,633
|
|
|
$
|
16,411
|
|
Revenue payable
|
|
|
4,540
|
|
|
|
449
|
|
|
|
4,989
|
|
Accrued expenses
|
|
|
2,525
|
|
|
|
(1,739
|
)
|
|
|
786
|
|
Current portion of notes payable
|
|
|
324
|
|
|
|
|
|
|
|
324
|
|
Current derivative financial instrument liabilities
|
|
|
5,244
|
|
|
|
3,635
|
|
|
|
8,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
27,411
|
|
|
|
3,978
|
|
|
|
31,389
|
|
Long-term liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term derivative financial instrument liabilities
|
|
|
7,449
|
|
|
|
3,429
|
|
|
|
10,878
|
|
Asset retirement obligation
|
|
|
1,410
|
|
|
|
|
|
|
|
1,410
|
|
Long-term portion of notes payable
|
|
|
225,245
|
|
|
|
|
|
|
|
225,245
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
234,104
|
|
|
|
3,429
|
|
|
|
237,533
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority interests
|
|
|
84,431
|
|
|
|
(258
|
)
|
|
|
84,173
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders (deficit) equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock
|
|
|
22
|
|
|
|
|
|
|
|
22
|
|
Additional paid-in capital
|
|
|
205,994
|
|
|
|
(222
|
)
|
|
|
205,772
|
|
Accumulated other comprehensive income (loss)
|
|
|
428
|
|
|
|
(428
|
)
|
|
|
|
|
Accumulated deficit
|
|
|
(89,090
|
)
|
|
|
(1,863
|
)
|
|
|
(90,953
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders (deficit) equity
|
|
|
117,354
|
|
|
|
(2,513
|
)
|
|
|
114,841
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders (deficit) equity
|
|
$
|
463,300
|
|
|
$
|
4,636
|
|
|
$
|
467,936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-62
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table outlines the effects of the restatement
adjustments on our Consolidated Statement of Cash Flows for the
period indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, 2006
|
|
|
|
As Previously
|
|
|
Restatement
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(48,478
|
)
|
|
|
77,986
|
|
|
$
|
29,508
|
|
Adjustments to reconcile net income (loss) to cash provided by
operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
30,898
|
|
|
|
(3,887
|
)
|
|
|
27,011
|
|
Impairment of oil and gas properties
|
|
|
30,719
|
|
|
|
(30,719
|
)
|
|
|
|
|
Stock-based compensation
|
|
|
779
|
|
|
|
258
|
|
|
|
1,037
|
|
Stock issued for services and retirement plan
|
|
|
857
|
|
|
|
47
|
|
|
|
904
|
|
Amortization of deferred loan costs
|
|
|
1,204
|
|
|
|
865
|
|
|
|
2,069
|
|
Change in fair value of derivative financial instruments
|
|
|
(16,644
|
)
|
|
|
(53,758
|
)
|
|
|
(70,402
|
)
|
Amortization of gas swap fees
|
|
|
208
|
|
|
|
(208
|
)
|
|
|
|
|
Amortization of deferred hedging gains
|
|
|
(328
|
)
|
|
|
328
|
|
|
|
|
|
Bad debt expense
|
|
|
37
|
|
|
|
48
|
|
|
|
85
|
|
Minority interest
|
|
|
244
|
|
|
|
(258
|
)
|
|
|
(14
|
)
|
Other
|
|
|
(3
|
)
|
|
|
3
|
|
|
|
|
|
Change in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
3,167
|
|
|
|
(3,167
|
)
|
|
|
|
|
Accounts receivable
|
|
|
(219
|
)
|
|
|
823
|
|
|
|
604
|
|
Other receivables
|
|
|
(29
|
)
|
|
|
137
|
|
|
|
108
|
|
Other current assets
|
|
|
894
|
|
|
|
(34
|
)
|
|
|
860
|
|
Inventory
|
|
|
(37
|
)
|
|
|
37
|
|
|
|
|
|
Other assets
|
|
|
|
|
|
|
(819
|
)
|
|
|
(819
|
)
|
Accounts payable
|
|
|
2,400
|
|
|
|
150
|
|
|
|
2,550
|
|
Revenue payable
|
|
|
(505
|
)
|
|
|
249
|
|
|
|
(256
|
)
|
Accrued expenses
|
|
|
1,836
|
|
|
|
(1,699
|
)
|
|
|
137
|
|
Other long-term liabilities
|
|
|
|
|
|
|
167
|
|
|
|
167
|
|
Other
|
|
|
|
|
|
|
1,053
|
|
|
|
1,053
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
7,000
|
|
|
|
(12,398
|
)
|
|
|
(5,398
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
|
|
|
|
3,168
|
|
|
|
3,168
|
|
Other assets
|
|
|
(5,712
|
)
|
|
|
5,712
|
|
|
|
|
|
Equipment, development, leasehold and pipeline
|
|
|
(166,905
|
)
|
|
|
(1,410
|
)
|
|
|
(168,315
|
)
|
Proceeds from sale of oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(172,617
|
)
|
|
|
7,470
|
|
|
|
(165,147
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from bank borrowings
|
|
|
200,170
|
|
|
|
(75,000
|
)
|
|
|
125,170
|
|
Repayments of note borrowings
|
|
|
(31,339
|
)
|
|
|
30,750
|
|
|
|
(589
|
)
|
F-63
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, 2006
|
|
|
|
As Previously
|
|
|
Restatement
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Proceeds from revolver note
|
|
|
|
|
|
|
75,000
|
|
|
|
75,000
|
|
Repayment of revolver note
|
|
|
(44,250
|
)
|
|
|
(30,750
|
)
|
|
|
(75,000
|
)
|
Proceeds from Quest MidStream
|
|
|
84,187
|
|
|
|
|
|
|
|
84,187
|
|
Refinancing costs
|
|
|
(4,568
|
)
|
|
|
(1
|
)
|
|
|
(4,569
|
)
|
Change in other long-term liabilities
|
|
|
167
|
|
|
|
(167
|
)
|
|
|
|
|
Equity offering costs
|
|
|
|
|
|
|
(393
|
)
|
|
|
(393
|
)
|
Proceeds from issuance of common stock
|
|
|
511
|
|
|
|
(511
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
204,878
|
|
|
|
(1,072
|
)
|
|
|
203,806
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash
|
|
|
39,261
|
|
|
|
(6,000
|
)
|
|
|
33,261
|
|
Cash and cash equivalents, beginning of period
|
|
|
2,559
|
|
|
|
(2,000
|
)
|
|
|
559
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
41,820
|
|
|
$
|
(8,000
|
)
|
|
$
|
33,820
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-64
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table outlines the effects of the restatement
adjustments on our Consolidated Statement of Operations for the
period indicated (in thousands, except share and per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2005
|
|
|
|
As Previously
|
|
|
Restatement
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
44,565
|
|
|
$
|
26,063
|
|
|
$
|
70,628
|
|
Gas pipeline revenue
|
|
|
3,939
|
|
|
|
|
|
|
|
3,939
|
|
Other revenue (expense)
|
|
|
389
|
|
|
|
(389
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
48,893
|
|
|
|
25,674
|
|
|
|
74,567
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
14,388
|
|
|
|
4,144
|
|
|
|
18,532
|
|
Pipeline operating
|
|
|
8,470
|
|
|
|
(767
|
)
|
|
|
7,703
|
|
General and administrative expenses
|
|
|
4,802
|
|
|
|
1,416
|
|
|
|
6,218
|
|
Depreciation, depletion and amortization
|
|
|
22,199
|
|
|
|
45
|
|
|
|
22,244
|
|
Impairment of oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from misappropriation of funds
|
|
|
|
|
|
|
2,000
|
|
|
|
2,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
49,859
|
|
|
|
6,838
|
|
|
|
56,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(966
|
)
|
|
|
18,836
|
|
|
|
17,870
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) from derivative financial instruments
|
|
|
(4,668
|
)
|
|
|
(68,898
|
)
|
|
|
(73,566
|
)
|
Gain (loss) on sale of assets
|
|
|
12
|
|
|
|
|
|
|
|
12
|
|
Loss on early extinguishment of debt
|
|
|
|
|
|
|
(12,355
|
)
|
|
|
(12,355
|
)
|
Other income
|
|
|
|
|
|
|
389
|
|
|
|
389
|
|
Interest expense
|
|
|
(26,365
|
)
|
|
|
(1,906
|
)
|
|
|
(28,271
|
)
|
Interest income
|
|
|
46
|
|
|
|
|
|
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(30,975
|
)
|
|
|
(82,770
|
)
|
|
|
(113,745
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes and minority interests
|
|
|
(31,941
|
)
|
|
|
(63,934
|
)
|
|
|
(95,875
|
)
|
Income tax benefit (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) before minority interests
|
|
|
(31,941
|
)
|
|
|
(63,934
|
)
|
|
|
(95,875
|
)
|
Minority interests
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
(31,941
|
)
|
|
|
(63,934
|
)
|
|
|
(95,875
|
)
|
Preferred stock dividends
|
|
|
(10
|
)
|
|
|
|
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss available to common shareholders
|
|
$
|
(31,951
|
)
|
|
$
|
(63,934
|
)
|
|
$
|
(95,885
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) available to common shareholders per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(3.81
|
)
|
|
$
|
(7.67
|
)
|
|
$
|
(11.48
|
)
|
Diluted
|
|
$
|
(3.81
|
)
|
|
$
|
(7.67
|
)
|
|
$
|
(11.48
|
)
|
Weighted average common and common equivalent shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
8,390,092
|
|
|
|
(38,147
|
)
|
|
|
8,351,945
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
8,390,092
|
|
|
|
(38,147
|
)
|
|
|
8,351,945
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-65
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table outlines the effects of the restatement
adjustments on our Consolidated Balance Sheet for the period
indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2005
|
|
|
|
As Previously
|
|
|
Restatement
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
2,559
|
|
|
$
|
(2,000
|
)
|
|
$
|
559
|
|
Restricted cash
|
|
|
4,318
|
|
|
|
|
|
|
|
4,318
|
|
Accounts receivable trade, net
|
|
|
9,658
|
|
|
|
682
|
|
|
|
10,340
|
|
Other receivables
|
|
|
343
|
|
|
|
|
|
|
|
343
|
|
Other current assets
|
|
|
1,936
|
|
|
|
|
|
|
|
1,936
|
|
Inventory
|
|
|
2,782
|
|
|
|
|
|
|
|
2,782
|
|
Current derivative financial instrument assets
|
|
|
95
|
|
|
|
(47
|
)
|
|
|
48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
21,691
|
|
|
|
(1,365
|
)
|
|
|
20,326
|
|
Oil and gas properties under full cost method of accounting, net
|
|
|
183,370
|
|
|
|
(18,362
|
)
|
|
|
165,008
|
|
Pipeline assets, net
|
|
|
72,849
|
|
|
|
(3,796
|
)
|
|
|
69,053
|
|
Other property and equipment, net
|
|
|
13,490
|
|
|
|
49
|
|
|
|
13,539
|
|
Other assets, net
|
|
|
6,310
|
|
|
|
|
|
|
|
6,310
|
|
Long-term derivative financial instrument assets
|
|
|
93
|
|
|
|
439
|
|
|
|
532
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
297,803
|
|
|
$
|
(23,035
|
)
|
|
$
|
274,768
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
12,381
|
|
|
$
|
1,962
|
|
|
$
|
14,343
|
|
Revenue payable
|
|
|
5,044
|
|
|
|
201
|
|
|
|
5,245
|
|
Accrued expenses
|
|
|
649
|
|
|
|
|
|
|
|
649
|
|
Current portion of notes payable
|
|
|
407
|
|
|
|
|
|
|
|
407
|
|
Current derivative financial instrument liabilities
|
|
|
38,195
|
|
|
|
4,098
|
|
|
|
42,293
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
56,676
|
|
|
|
6,261
|
|
|
|
62,937
|
|
Long-term liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term derivative financial instrument liabilities
|
|
|
23,723
|
|
|
|
2,592
|
|
|
|
26,315
|
|
Asset retirement obligation
|
|
|
1,150
|
|
|
|
|
|
|
|
1,150
|
|
Long-term portion of notes payable
|
|
|
100,581
|
|
|
|
|
|
|
|
100,581
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
125,454
|
|
|
|
2,592
|
|
|
|
128,046
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority interests
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies
Stockholders equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock
|
|
|
22
|
|
|
|
|
|
|
|
22
|
|
Additional paid-in capital
|
|
|
203,434
|
|
|
|
790
|
|
|
|
204,224
|
|
Accumulated other comprehensive income (loss)
|
|
|
(47,171
|
)
|
|
|
47,171
|
|
|
|
|
|
Accumulated deficit
|
|
|
(40,612
|
)
|
|
|
(79,849
|
)
|
|
|
(120,461
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
115,673
|
|
|
|
(31,888
|
)
|
|
|
83,785
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
297,803
|
|
|
$
|
(23,035
|
)
|
|
$
|
274,768
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-66
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table outlines the effects of the restatement
adjustments on our Consolidated Statement of Cash Flows for the
period indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, 2005
|
|
|
|
As Previously
|
|
|
Restatement
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(31,941
|
)
|
|
|
(63,934
|
)
|
|
$
|
(95,875
|
)
|
Adjustments to reconcile net income (loss) to cash provided by
operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
22,949
|
|
|
|
(705
|
)
|
|
|
22,244
|
|
Accretion of debt discount
|
|
|
9,586
|
|
|
|
1,892
|
|
|
|
11,478
|
|
Stock-based compensation
|
|
|
352
|
|
|
|
865
|
|
|
|
1,217
|
|
Stock issued for services and retirement plan
|
|
|
285
|
|
|
|
274
|
|
|
|
559
|
|
Amortization of deferred loan costs
|
|
|
5,106
|
|
|
|
(609
|
)
|
|
|
4,497
|
|
Change in fair value of derivative financial instruments
|
|
|
4,668
|
|
|
|
41,934
|
|
|
|
46,602
|
|
Amortization of deferred hedging gains
|
|
|
(831
|
)
|
|
|
831
|
|
|
|
|
|
Bad debt expense
|
|
|
192
|
|
|
|
110
|
|
|
|
302
|
|
Loss on early extinguishment of debt
|
|
|
|
|
|
|
12,355
|
|
|
|
12,355
|
|
Other
|
|
|
56
|
|
|
|
(56
|
)
|
|
|
|
|
Change in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
(4,318
|
)
|
|
|
4,318
|
|
|
|
|
|
Accounts receivable
|
|
|
(3,646
|
)
|
|
|
(823
|
)
|
|
|
(4,469
|
)
|
Other receivables
|
|
|
181
|
|
|
|
|
|
|
|
181
|
|
Other current assets
|
|
|
(1,695
|
)
|
|
|
2
|
|
|
|
(1,693
|
)
|
Inventory
|
|
|
(2,499
|
)
|
|
|
2,499
|
|
|
|
|
|
Other assets
|
|
|
|
|
|
|
788
|
|
|
|
788
|
|
Accounts payable
|
|
|
(4,957
|
)
|
|
|
(9,910
|
)
|
|
|
(14,867
|
)
|
Revenue payable
|
|
|
1,537
|
|
|
|
(19
|
)
|
|
|
1,518
|
|
Accrued expenses
|
|
|
61
|
|
|
|
|
|
|
|
61
|
|
Other long-term liabilities
|
|
|
|
|
|
|
210
|
|
|
|
210
|
|
Other
|
|
|
|
|
|
|
116
|
|
|
|
116
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
(4,914
|
)
|
|
|
(9,862
|
)
|
|
|
(14,776
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
|
|
|
|
(4,318
|
)
|
|
|
(4,318
|
)
|
Other assets
|
|
|
(6,071
|
)
|
|
|
6,071
|
|
|
|
|
|
Acquisition of minority interest ArcLight
|
|
|
|
|
|
|
(26,100
|
)
|
|
|
(26,100
|
)
|
Equipment, development, leasehold and pipeline
|
|
|
(67,530
|
)
|
|
|
32,218
|
|
|
|
(35,312
|
)
|
Proceeds from sale of oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(73,601
|
)
|
|
|
7,871
|
|
|
|
(65,730
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-67
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, 2005
|
|
|
|
As Previously
|
|
|
Restatement
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from bank borrowings
|
|
|
100,103
|
|
|
|
|
|
|
|
100,103
|
|
Repayments of note borrowings
|
|
|
(135,565
|
)
|
|
|
|
|
|
|
(135,565
|
)
|
Proceeds from subordinated debt
|
|
|
15,000
|
|
|
|
|
|
|
|
15,000
|
|
Repayment of subordinated debt
|
|
|
(83,912
|
)
|
|
|
|
|
|
|
(83,912
|
)
|
Refinancing costs
|
|
|
(6,272
|
)
|
|
|
(9
|
)
|
|
|
(6,281
|
)
|
Dividends paid
|
|
|
(10
|
)
|
|
|
|
|
|
|
(10
|
)
|
Proceeds from issuance of common stock
|
|
|
185,272
|
|
|
|
|
|
|
|
185,272
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
74,616
|
|
|
|
(9
|
)
|
|
|
74,607
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash
|
|
|
(3,899
|
)
|
|
|
(2,000
|
)
|
|
|
(5,899
|
)
|
Cash and cash equivalents, beginning of period
|
|
|
6,458
|
|
|
|
|
|
|
|
6,458
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
2,559
|
|
|
$
|
(2,000
|
)
|
|
$
|
559
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 19
Subsequent Events
Impairment
of oil and gas properties
Due to a further decline in natural gas prices, subsequent to
December 31, 2008 we expect to incur an additional
impairment charge on our oil and gas properties of approximately
$75 million to $95 million as of March 31, 2009.
Settlement
Agreements
We filed lawsuits, related to the Transfers, against
Mr. Cash, the entity controlled by Mr. Cash that was
used in connection with the Transfers and two former officers,
who are the other owners of the controlled-entity, seeking,
among other things, to recover the funds that were transferred.
On May 19, 2009, we entered into settlement agreements with
Mr. Cash, the controlled-entity and the other owners to
settle this litigation. Under the terms of the settlement
agreements, QRCP received (1) approximately
$2.4 million in cash and (2) 60% of the
controlled-entitys interest in a gas well located in
Louisiana and a landfill gas development project located in
Texas. While QRCP estimates the value of these assets to be less
than the amount of the Transfers and cost of the internal
investigation, they represent substantially all of
Mr. Cashs net worth and the majority of the value of
the controlled-entity. We did not take Mr. Cashs
stock in QRCP, which he had pledged to secure personal loans
with a principal balance far in excess of the current market
value of the stock. QELP received all of Mr. Cashs
equity interest in STP Newco, Inc. (STP), which owns
certain oil producing properties in Oklahoma, and other assets
as reimbursement for all of the costs of the internal
investigation and the costs of the litigation against
Mr. Cash that have been paid by QELP.
F-68
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 20
Supplemental Financial Information Quarterly
Financial Data (Unaudited)
Summarized unaudited quarterly financial data for 2008 and 2007
are as follows (in thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarters Ended
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
June 30,
|
|
|
March 31,
|
|
|
|
2008
|
|
|
2008
|
|
|
2008
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
Total revenues
|
|
$
|
52,819
|
|
|
$
|
41,993
|
|
|
$
|
38,510
|
|
|
$
|
42,791
|
|
Operating income (loss)(1)
|
|
|
(296,484
|
)
|
|
|
1,302
|
|
|
|
(4,927
|
)
|
|
|
4,796
|
|
Net income (loss)
|
|
|
(172,254
|
)
|
|
|
87,851
|
|
|
|
(57,886
|
)
|
|
|
(25,095
|
)
|
Net income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(6.38
|
)
|
|
$
|
5.10
|
|
|
$
|
(2.53
|
)
|
|
$
|
(1.11
|
)
|
Diluted
|
|
$
|
(6.38
|
)
|
|
$
|
5.05
|
|
|
$
|
(2.53
|
)
|
|
$
|
(1.11
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarters Ended
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
June 30,
|
|
|
March 31,
|
|
|
|
2007
|
|
|
2007
|
|
|
2007
|
|
|
2007
|
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
(Restated)
|
|
|
Total revenues
|
|
$
|
33,620
|
|
|
$
|
25,640
|
|
|
$
|
29,362
|
|
|
$
|
26,516
|
|
Operating income (loss)(1)
|
|
|
(262
|
)
|
|
|
(4,189
|
)
|
|
|
(1,154
|
)
|
|
|
545
|
|
Net income (loss)
|
|
|
(21,206
|
)
|
|
|
492
|
|
|
|
(1,380
|
)
|
|
|
(22,060
|
)
|
Net income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.94
|
)
|
|
$
|
0.02
|
|
|
$
|
(0.06
|
)
|
|
$
|
(0.99
|
)
|
Diluted
|
|
$
|
(0.94
|
)
|
|
$
|
0.02
|
|
|
$
|
(0.06
|
)
|
|
$
|
(0.99
|
)
|
|
|
|
(1)
|
|
Total revenue less total costs and expenses.
|
As discussed in Note 18 Restatement, the
Company has restated its consolidated financial statements. Such
restatements also impacted the Companys consolidated
financial statements as of and for the quarterly periods ended
March 31 and June 30, 2008 and March 31, June 30,
September 30 and December 31, 2007. See Note 18 for
more detailed descriptions of the adjustments below. The
adjustments to the applicable quarterly financial statement line
items are presented below for the periods indicated (in
thousands):
The following table outlines the effects of the restatement
adjustments on our summarized unaudited quarterly financial data
for the periods indicated (in thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended March 31, 2008
|
|
|
|
As Previously
|
|
|
Restatement
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Total revenues
|
|
$
|
44,304
|
|
|
$
|
(1,513
|
)
|
|
$
|
42,791
|
|
Operating income (loss)
|
|
|
11,215
|
|
|
|
(6,420
|
)
|
|
|
4,795
|
|
Net income (loss)
|
|
|
(11,643
|
)
|
|
|
(13,452
|
)
|
|
|
(25,095
|
)
|
Net income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.50
|
)
|
|
$
|
(0.61
|
)
|
|
$
|
(1.11
|
)
|
Diluted
|
|
$
|
(0.50
|
)
|
|
$
|
(0.61
|
)
|
|
$
|
(1.11
|
)
|
F-69
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended June 30, 2008
|
|
|
|
As Previously
|
|
|
Restatement
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Total revenues
|
|
$
|
47,123
|
|
|
$
|
(8,613
|
)
|
|
$
|
38,510
|
|
Operating income (loss)
|
|
|
8,499
|
|
|
|
(13,426
|
)
|
|
|
(4,927
|
)
|
Net income (loss)
|
|
|
4,965
|
|
|
|
(62,851
|
)
|
|
|
(57,886
|
)
|
Net income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.22
|
|
|
$
|
(2.75
|
)
|
|
$
|
(2.53
|
)
|
Diluted
|
|
$
|
0.22
|
|
|
$
|
(2.75
|
)
|
|
$
|
(2.53
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended March 31, 2007
|
|
|
|
As Previously
|
|
|
Restatement
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Total revenues
|
|
$
|
27,078
|
|
|
$
|
(562
|
)
|
|
$
|
26,516
|
|
Operating income (loss)
|
|
|
4,416
|
|
|
|
(3,871
|
)
|
|
|
545
|
|
Net income (loss)
|
|
|
(3,311
|
)
|
|
|
(18,749
|
)
|
|
|
(22,060
|
)
|
Net income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.15
|
)
|
|
$
|
(0.84
|
)
|
|
$
|
(0.99
|
)
|
Diluted
|
|
$
|
(0.15
|
)
|
|
$
|
(0.84
|
)
|
|
$
|
(0.99
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended June 30, 2007
|
|
|
|
As Previously
|
|
|
Restatement
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Total revenues
|
|
$
|
29,640
|
|
|
$
|
(278
|
)
|
|
$
|
29,362
|
|
Operating income (loss)
|
|
|
3,689
|
|
|
|
(4,843
|
)
|
|
|
(1,154
|
)
|
Net income (loss)
|
|
|
(4,487
|
)
|
|
|
3,107
|
|
|
|
(1,380
|
)
|
Net income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.20
|
)
|
|
$
|
0.14
|
|
|
$
|
(0.06
|
)
|
Diluted
|
|
$
|
(0.20
|
)
|
|
$
|
0.14
|
|
|
$
|
(0.06
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended September 30, 2007
|
|
|
|
As Previously
|
|
|
Restatement
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Total revenues
|
|
$
|
30,277
|
|
|
$
|
(4,637
|
)
|
|
$
|
25,640
|
|
Operating income (loss)
|
|
|
5,064
|
|
|
|
(9,253
|
)
|
|
|
(4,189
|
)
|
Net income (loss)
|
|
|
1,974
|
|
|
|
(1,482
|
)
|
|
|
492
|
|
Net income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.09
|
|
|
$
|
(0.07
|
)
|
|
$
|
0.02
|
|
Diluted
|
|
$
|
0.09
|
|
|
$
|
(0.07
|
)
|
|
$
|
0.02
|
|
F-70
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended December 31, 2007
|
|
|
|
As Previously
|
|
|
Restatement
|
|
|
As
|
|
|
|
Reported
|
|
|
Adjustments
|
|
|
Restated
|
|
|
Total revenues
|
|
$
|
35,884
|
|
|
$
|
(2,264
|
)
|
|
$
|
33,620
|
|
Operating income (loss)
|
|
|
1,259
|
|
|
|
(1,521
|
)
|
|
|
(262
|
)
|
Net income (loss)
|
|
|
(24,590
|
)
|
|
|
3,384
|
|
|
|
(21,206
|
)
|
Net income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(1.11
|
)
|
|
$
|
0.17
|
|
|
$
|
(0.94
|
)
|
Diluted
|
|
$
|
(1.11
|
)
|
|
$
|
0.17
|
|
|
$
|
(0.94
|
)
|
Note 21
Supplemental Information on Oil and Gas Producing Activities
(Unaudited)
The supplementary, oil and gas data that follows is presented in
accordance with SFAS No. 69,
Disclosures about Oil
and Gas Producing Activities,
and includes
(1) capitalized costs, costs incurred and results of
operations related to oil and gas producing activities,
(2) net proved oil and gas reserves, and (3) a
standardized measure of discounted future net cash flows
relating to proved oil and gas reserves.
Net
Capitalized Costs
The Companys aggregate capitalized costs related to oil
and gas producing activities as of the periods indicated are
summarized as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Oil and gas properties and related leasehold costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
299,629
|
|
|
$
|
380,033
|
|
|
$
|
288,646
|
|
Unproved
|
|
|
10,108
|
|
|
|
7,986
|
|
|
|
8,108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
309,737
|
|
|
|
388,019
|
|
|
|
296,754
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(137,200
|
)
|
|
|
(87,066
|
)
|
|
|
(55,476
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
$
|
172,537
|
|
|
$
|
300,953
|
|
|
$
|
241,278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved properties not subject to amortization consisted mainly
of leaseholds acquired through acquisitions. We will continue to
evaluate our unproved properties; however, the timing of the
ultimate evaluation and disposition of the properties has not
been determined.
Costs
Incurred
Costs incurred in oil and gas property acquisition, exploration
and development activities that have been capitalized as of the
periods indicated are summarized as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Acquisition of proved and unproved properties
|
|
$
|
158,294
|
(a)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Exploration costs
|
|
|
1,273
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development costs
|
|
|
276,265
|
|
|
|
217,539
|
|
|
|
143,229
|
|
|
|
49,833
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
435,832
|
|
|
$
|
217,539
|
|
|
$
|
143,229
|
|
|
$
|
49,833
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Includes the acquisition of the PetroEdge & Seminole
County, Oklahoma properties.
|
F-71
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Results
of Operations for Oil and Gas Producing Activities
The following table includes revenues and expenses associated
directly with our oil and natural gas producing activities. It
does not include any interest costs or general and
administrative costs and, therefore, is not necessarily
indicative of the contribution to consolidated net operating
results of our oil and natural gas operations (in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Production revenues
|
|
$
|
147,937
|
|
|
$
|
105,285
|
|
|
$
|
72,410
|
|
|
$
|
70,628
|
|
Production costs
|
|
|
(44,111
|
)
|
|
|
(36,295
|
)
|
|
|
(25,338
|
)
|
|
|
(18,532
|
)
|
Depreciation and depletion and amortization
|
|
|
(53,663
|
)
|
|
|
(33,812
|
)
|
|
|
(24,392
|
)
|
|
|
(20,795
|
)
|
Impairment of oil and gas properties
|
|
|
(298,861
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(248,698
|
)
|
|
|
35,178
|
|
|
|
22,680
|
|
|
|
31,301
|
|
Imputed income tax provision(1)
|
|
|
|
|
|
|
(13,368
|
)
|
|
|
(8,618
|
)
|
|
|
(11,894
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations for oil and natural gas producing activity
|
|
$
|
(256,341
|
)
|
|
$
|
21,810
|
|
|
$
|
14,062
|
|
|
$
|
19,407
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The imputed income tax provision is hypothetical (at the
statutory rate) and determined without regard to our deduction
for general and administrative expenses, interest costs and
other income tax credits and deductions, nor whether the
hypothetical tax provision will be payable.
|
Oil and
Gas Reserve Quantities
The following reserve schedule was developed by our reserve
engineers and sets forth the changes in estimated quantities for
our proved reserves, all of which are located in the United
States. We retained Cawley, Gillespie & Associates,
Inc., independent third-party reserve engineers, to perform an
independent evaluation of proved reserves as of
December 31, 2008, 2007, 2006 and 2005.
Users of this information should be aware that the process of
estimating quantities of proved, proved
developed and proved undeveloped oil and
natural gas reserves is very complex, requiring significant
subjective decisions in the evaluation of all available
geological, engineering and economic data for each reservoir.
The data for a given reservoir may also change substantially
over time as a result of numerous factors including, but not
limited to, additional development activity, evolving production
history, and continual reassessment of the viability of
production under varying economic conditions. Consequently,
material revisions (upwards or downward) to existing reserve
estimates may occur from time to time. Although every reasonable
effort is made to ensure that reserve estimates reported
represent the most accurate assessments possible, the
significance of the subjective
F-72
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
decisions required and variances in available data for various
reservoirs make these estimates generally less precise than
other estimates presented in connection with financial statement
disclosures.
|
|
|
|
|
|
|
|
|
|
|
Gas Mcf
|
|
|
Oil Bbls
|
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
Balance, December 31, 2004
|
|
|
149,843,900
|
|
|
|
47,834
|
|
Purchase of reserves in place
|
|
|
|
|
|
|
|
|
Extensions, discoveries, and other additions
|
|
|
390,468
|
|
|
|
|
|
Sale of reserves
|
|
|
|
|
|
|
|
|
Revisions of previous estimates(1)
|
|
|
(6,342,690
|
)
|
|
|
(6,054
|
)
|
Production
|
|
|
(9,572,378
|
)
|
|
|
(9,480
|
)
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2005
|
|
|
134,319,300
|
|
|
|
32,300
|
|
Purchase of reserves in place
|
|
|
|
|
|
|
|
|
Extensions, discoveries, and other additions
|
|
|
27,696,254
|
|
|
|
|
|
Sale of reserves
|
|
|
|
|
|
|
|
|
Revisions of previous estimates(2)
|
|
|
48,329,663
|
|
|
|
9,780
|
|
Production
|
|
|
(12,305,217
|
)
|
|
|
(9,808
|
)
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2006
|
|
|
198,040,000
|
|
|
|
32,272
|
|
Purchase of reserves in place
|
|
|
|
|
|
|
|
|
Extensions, discoveries, and other additions
|
|
|
26,368,000
|
|
|
|
|
|
Sale of reserves
|
|
|
|
|
|
|
|
|
Revisions of previous estimates(3)
|
|
|
3,490,473
|
|
|
|
11,354
|
|
Production
|
|
|
(16,975,067
|
)
|
|
|
(7,070
|
)
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007
|
|
|
210,923,406
|
|
|
|
36,556
|
|
Purchase of reserves in place
|
|
|
94,727,687
|
|
|
|
1,560,946
|
|
Extensions, discoveries, and other additions
|
|
|
13,897,600
|
|
|
|
|
|
Sale of reserves
|
|
|
(4,386,200
|
)
|
|
|
|
|
Revisions of previous estimates(2)
|
|
|
(123,204,433
|
)
|
|
|
(833,070
|
)
|
Production
|
|
|
(21,328,687
|
)
|
|
|
(69,812
|
)
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
|
170,629,373
|
|
|
|
694,620
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
Balance, December 31, 2005
|
|
|
71,638,300
|
|
|
|
32,300
|
|
Balance, December 31, 2006
|
|
|
122,390,360
|
|
|
|
32,272
|
|
Balance, December 31, 2007
|
|
|
140,966,295
|
|
|
|
36,556
|
|
Balance, December 31, 2008
|
|
|
136,544,572
|
|
|
|
682,030
|
|
|
|
|
(1)
|
|
The downward revision was due to a change in performance of
wells on a portion of Quest Cherokees acreage.
|
(2)
|
|
Lower prices at December 31, 2008 as compared to
December 31, 2007 and December 31, 2006 as compared to
December 31, 2005 reduced the economic lives of the
underlying oil and gas properties and thereby decreased the
estimated future reserves.
|
(3)
|
|
During 2007, higher prices increased the economic lives of the
underlying oil and natural gas properties and thereby increased
the estimated future reserves.
|
F-73
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Standardized
Measure of Discounted Future Net Cash Flows
The following information is based on our best estimate of the
required data for the Standardized Measure of Discounted Future
Net Cash Flows as of the periods indicated in accordance with
SFAS No. 69,
Disclosures About Oil and Gas
Producing Activities
which requires the use of a 10%
discount rate. Future income taxes are based on year-end
statutory rates. This information is not the fair market value,
nor does it represent the expected present value of future cash
flows of our proved oil and gas reserves (in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Future cash inflows
|
|
$
|
898,214
|
|
|
$
|
1,351,980
|
|
|
$
|
1,197,198
|
|
|
$
|
1,258,580
|
|
Future production costs
|
|
|
570,142
|
|
|
|
732,488
|
|
|
|
638,844
|
|
|
|
366,475
|
|
Future development costs
|
|
|
60,318
|
|
|
|
119,448
|
|
|
|
126,272
|
|
|
|
122,428
|
|
Future income tax expense
|
|
|
|
|
|
|
56,371
|
|
|
|
60,024
|
|
|
|
230,651
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
267,754
|
|
|
|
443,673
|
|
|
|
372,058
|
|
|
|
539,026
|
|
10% annual discount for estimated timing of cash flows
|
|
|
103,660
|
|
|
|
157,496
|
|
|
|
141,226
|
|
|
|
201,087
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows related
to proved reserves
|
|
$
|
164,094
|
|
|
$
|
286,177
|
|
|
$
|
230,832
|
|
|
$
|
337,939
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Future cash inflows are computed by applying year-end prices,
adjusted for location and quality differentials on a
property-by-property
basis, to year-end quantities of proved reserves, except in
those instances where fixed and determinable price changes are
provided by contractual arrangements at year-end. The discounted
future cash flow estimates do not include the effects of our
derivative instruments. See the following table for oil and gas
prices as of the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Crude oil price per Bbl
|
|
$
|
44.60
|
|
|
$
|
96.10
|
|
|
$
|
61.06
|
|
|
$
|
55.63
|
|
Natural gas price per Mcf
|
|
$
|
5.71
|
|
|
$
|
6.43
|
|
|
$
|
6.03
|
|
|
$
|
9.27
|
|
F-74
QUEST
RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The principal changes in the standardized measure of discounted
future net cash flows relating to proven oil and natural gas
properties were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Present value, beginning of period
|
|
$
|
286,177
|
|
|
$
|
230,832
|
|
|
$
|
337,939
|
|
|
$
|
280,481
|
|
Net changes in prices and production costs
|
|
|
(122,702
|
)
|
|
|
13,716
|
|
|
|
(289,149
|
)
|
|
|
181,950
|
|
Net changes in future development costs
|
|
|
(4,247
|
)
|
|
|
(43,530
|
)
|
|
|
(60,330
|
)
|
|
|
(46,074
|
)
|
Previously estimated development costs incurred
|
|
|
66,060
|
|
|
|
74,310
|
|
|
|
93,397
|
|
|
|
25,532
|
|
Sales of oil and gas produced, net
|
|
|
(103,826
|
)
|
|
|
(68,990
|
)
|
|
|
(47,072
|
)
|
|
|
(52,096
|
)
|
Extensions and discoveries
|
|
|
15,986
|
|
|
|
49,901
|
|
|
|
48,399
|
|
|
|
1,624
|
|
Purchases of reserves in-place
|
|
|
119,733
|
|
|
|
|
|
|
|
0
|
|
|
|
0
|
|
Sales of reserves in-place
|
|
|
(5,045
|
)
|
|
|
|
|
|
|
0
|
|
|
|
0
|
|
Revisions of previous quantity estimates
|
|
|
(147,464
|
)
|
|
|
6,735
|
|
|
|
84,559
|
|
|
|
(26,524
|
)
|
Net change in income taxes
|
|
|
36,360
|
|
|
|
880
|
|
|
|
107,365
|
|
|
|
(23,979
|
)
|
Accretion of discount
|
|
|
31,804
|
|
|
|
25,264
|
|
|
|
44,771
|
|
|
|
37,867
|
|
Timing differences and other(a)
|
|
|
(8,742
|
)
|
|
|
(2,941
|
)
|
|
|
(89,047
|
)
|
|
|
(40,842
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present value, end of period
|
|
$
|
164,094
|
|
|
$
|
286,177
|
|
|
$
|
230,832
|
|
|
$
|
337,939
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
The change in timing differences and other are related to
revisions in the Companys estimated time of production and
development
|
F-75
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this annual report on
Form 10-K
to be signed on its behalf by the undersigned, thereunto duly
authorized this 2nd day of June, 2009.
Quest Resource Corporation
/s/
David C.
Lawler
Chief Executive Officer and President
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/
David
C. Lawler
David
C. Lawler
|
|
Director, Chief Executive
Officer and President
(principal executive officer)
|
|
June 2, 2009
|
|
|
|
|
|
*
Jon
H. Rateau
|
|
Director
|
|
June 2, 2009
|
|
|
|
|
|
*
John
C. Garrison
|
|
Director
|
|
June 2, 2009
|
|
|
|
|
|
*
James
B. Kite, Jr.
|
|
Director
|
|
June 2, 2009
|
|
|
|
|
|
*
Gregory
McMichael
|
|
Director
|
|
June 2, 2009
|
|
|
|
|
|
*
William
H. Damon III
|
|
Director
|
|
June 2, 2009
|
|
|
|
|
|
/s/
Eddie
M. LeBlanc
Eddie
M. LeBlanc
|
|
Chief Financial Officer (principal financial and accounting
officer)
|
|
June 2, 2009
|
|
|
|
|
|
|
|
*By:
|
|
/s/
Eddie
M. LeBlanc
Eddie
M. LeBlanc
Attorney-in-Fact
|
|
|
|
|
146
INDEX TO
EXHIBITS
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
2
|
.1*
|
|
Amended and Restated Agreement and Plan of Merger, dated as of
February 6, 2008, by and among the Company, Pinnacle Gas
Resources, Inc., and Quest MergerSub, Inc. (incorporated herein
by reference to Exhibit 2.1 to the Companys Current Report
on Form 8-K filed on February 6, 2008).
|
|
2
|
.2*
|
|
Membership Interest Purchase Agreement, dated as of June 5,
2008, by and between PetroEdge Resources Partners, LLC and the
Company (incorporated herein by reference to Exhibit 2.1 to the
Companys Current Report on Form 8-K/A filed on June 19,
2008).
|
|
2
|
.3*
|
|
Agreement for Purchase and Sale, dated July 11, 2008, by and
among the Company, Quest Eastern Resource LLC and Quest Cherokee
LLC (incorporated herein by reference to Exhibit 2.1 to the
Companys Current Report on Form 8-K filed on July 16,
2008).
|
|
3
|
.1*
|
|
The Companys Restated Articles of Incorporation
(incorporated herein by reference to Exhibit 3.1 to the
Companys Registration Statement on Form 8-A12/G (Amendment
No. 2) filed on December 7, 2005).
|
|
3
|
.2*
|
|
Certificate of Designations for Series B Junior Participating
Preferred Stock (incorporated herein by reference to Exhibit 3.1
to the Companys Current Report on Form 8-K filed on June
1, 2006).
|
|
3
|
.3*
|
|
Amendment to the Companys Restated Articles of
Incorporation (incorporated herein by reference to Exhibit 3.1
to the Companys Current Report on Form 8-K filed on June
6, 2006).
|
|
3
|
.4*
|
|
Third Amended and Restated Bylaws of the Company (as adopted on
May 7, 2008) (incorporated herein by reference to Exhibit 3.1 to
Quest Resource Corporations Quarterly Report on Form 10-Q
filed on May 12, 2008).
|
|
4
|
.1*
|
|
Specimen of certificate for shares of Common Stock (incorporated
herein by reference to Exhibit 4.1 to the Companys
Annual Report on
Form 10-K
filed on March 10, 2008).
|
|
4
|
.2*
|
|
Rights Agreement dated as of May 31, 2006, between the Company
and UMB Bank, n.a., which includes as Exhibit A, the Certificate
of Designations, Preferences and Rights of Series B Preferred
Stock, as Exhibit B, the Form of Rights Certificate, and as
Exhibit C, the Summary of Rights to Purchase Preferred Stock
(incorporated herein by reference to Exhibit 4.1 to the
Companys Current Report on Form 8-K filed on June 1, 2006).
|
|
10
|
.1*
|
|
Non-Competition Agreement by and between the Company, Quest
Cherokee, LLC, Cherokee Energy Partners LLC, Quest Oil &
Gas Corporation, Quest Energy Service, Inc., STP Cherokee, Inc.,
Ponderosa Gas Pipeline Company, Inc., Producers Service
Incorporated and J-W Gas Gathering, L.L.C., dated as of the 22nd
day of December, 2003 (incorporated herein by reference to
Exhibit 10.6 to the Companys Current Report on Form 8-K
filed on January 6, 2004).
|
|
10
|
.2
|
|
Summary of Director Compensation Arrangements.
|
|
10
|
.3*
|
|
Management Annual Incentive Plan (incorporated herein by
reference to Appendix C to the Companys Proxy Statement
filed on May 20, 2008).
|
|
10
|
.4*
|
|
The Companys Amended and Restated 2005 Omnibus Stock Award
Plan (incorporated herein by reference to Exhibit 10.4 to the
Companys Current Report on Form 8-K filed on February 6,
2008).
|
|
10
|
.5*
|
|
Amendments to 2005 Omnibus Stock Award Plan (incorporated herein
by reference to Appendix A to the Companys Proxy
Statement filed on May 20, 2008).
|
|
10
|
.6*
|
|
The Company Bonus Compensation Plan (incorporated herein by
reference to Exhibit 10.1 to the Companys Current Report
on Form 8-K filed on May 21, 2007).
|
|
10
|
.7
|
|
Form of the Companys 2005 Omnibus Stock Award Plan
Nonqualified Stock Option Agreement.
|
|
10
|
.8*
|
|
Form of the Companys 2005 Omnibus Stock Award Plan Bonus
Shares Award Agreement (incorporated herein by reference to
Exhibit 10.9 to the Companys Registration Statement on
Form S-1 filed on December 12, 2005).
|
|
10
|
.9*
|
|
The Companys 2008 Supplemental Bonus Plan (incorporated
herein by reference to Exhibit 10.1 to the Current Report on
Form 8-K filed on October 24, 2008).
|
|
10
|
.10
|
|
Form of Indemnification Agreement for Directors.
|
|
10
|
.11
|
|
Form of Indemnification Agreement for Officers.
|
147
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
10
|
.12*
|
|
Purchase Agreement, dated as of October 16, 2007, by and
among Quest Midstream Partners, L.P., Quest Midstream GP, LLC,
the Company, Alerian Opportunity Partners IX, L.P., Bel Air MLP
Energy Infrastructure Fund, LP, Tortoise Capital Resources
Corporation, Tortoise Gas and Oil Corporation, Dalea Partners,
LP, Hartz Capital MLP, LLC, ZLP Fund, L.P., KED MME Investment
Partners, LP, Eagle Income Appreciation Partners, L.P., Eagle
Income Appreciation II, L.P., Citigroup Financial Products,
Inc., and The Northwestern Mutual Life Insurance Company
(incorporated herein by reference to Exhibit 10.1 to the
Companys Current Report on Form 8-K filed on
November 2, 2007).
|
|
10
|
.13*
|
|
Amended and Restated Investors Rights Agreement, dated as
of November 1, 2007, by and among Quest Midstream Partners,
L.P., Quest Midstream GP, LLC, the Company, Alerian Opportunity
Partners IV, L.P., Swank MLP Convergence Fund, LP, Swank
Investment Partners, LP, The Cushing MLP Opportunity
Fund I, LP, The Cushing GP Strategies Fund, LP, Tortoise
Capital Resources Corporation, Alerian Opportunity Partners IX,
L.P., Bel Air MLP Energy Infrastructure Fund, LP, Tortoise Gas
and Oil Corporation, Dalea Partners, LP, Hartz Capital MLP, LLC,
ZLP Fund, L.P., KED MME Investment Partners, LP, Eagle Income
Appreciation Partners, L.P., Eagle Income Appreciation II, L.P.,
Citigroup Financial Products, Inc., and The Northwestern Mutual
Life Insurance Company (incorporated herein by reference to
Exhibit 10.2 to the Companys Current Report on Form 8-K
filed on November 2, 2007).
|
|
10
|
.14*
|
|
Second Amended and Restated Agreement of Limited Partnership of
Quest Midstream Partners, L.P., dated as of November 1, 2007, by
and among Quest Midstream GP, LLC, the Company, Alerian
Opportunity Partners IV, L.P., Swank MLP Convergence Fund, LP,
Swank Investment Partners, LP, The Cushing MLP Opportunity
Fund I, LP, The Cushing GP Strategies Fund, LP, Tortoise
Capital Resources Corporation, Alerian Opportunity Partners IX,
L.P., Bel Air MLP Energy Infrastructure Fund, LP, Tortoise Gas
and Oil Corporation, Dalea Partners, LP, Hartz Capital MLP, LLC,
ZLP Fund, L.P., KED MME Investment Partners, LP, Eagle Income
Appreciation Partners, L.P., Eagle Income Appreciation II, L.P.,
Citigroup Financial Products, Inc., and The Northwestern Mutual
Life Insurance Company (incorporated herein by reference to
Exhibit 10.3 to the Companys Current Report on Form 8-K
filed on November 2, 2007).
|
|
10
|
.15*
|
|
Amendment No. 1 to Second Amended and Restated Agreement of
Limited Partnership of Quest Midstream Partners, L.P., adopted
effective as of January 1, 2007, by Quest Midstream GP, LLC
(incorporated by reference to Exhibit 10.3 to the Companys
Quarterly Report on Form 10-Q filed May 12, 2008).
|
|
10
|
.16*
|
|
Omnibus Agreement dated as of December 22, 2006, by and among
the Company, Quest Midstream GP, LLC, Bluestem Pipeline, LLC and
Quest Midstream Partners, L.P. (incorporated herein by reference
to Exhibit 10.3 to the Companys Current Report on Form 8-K
filed on December 29, 2006).
|
|
10
|
.17*
|
|
Registration Rights Agreement dated as of December 22, 2006, by
and among Quest Midstream Partners, L.P., Alerian Opportunity
Partners IV, LP, Swank MLP Convergence Fund, LP, Swank
Investment Partners, LP, The Cushing MLP Opportunity
Fund I, LP, The Cushing GP Strategies Fund, LP, Tortoise
Capital Resources Corporation, Huizenga Opportunity Partners, LP
and HCM Energy Holdings, LLC (incorporated herein by reference
to Exhibit 10.4 to the Companys Current Report on Form 8-K
filed on December 29, 2006).
|
|
10
|
.18*
|
|
First Amendment to Registration Rights Agreement, dated as of
November 1, 2007, by and among Quest Midstream Partners, L.P.,
the Company, Alerian Opportunity Partners IV, L.P., Swank MLP
Convergence Fund, LP, Swank Investment Partners, LP, The Cushing
MLP Opportunity Fund I, LP, The Cushing GP Strategies Fund,
LP, Tortoise Capital Resources Corporation, Alerian Opportunity
Partners IX, L.P., Bel Air MLP Energy Infrastructure Fund, LP,
Tortoise Gas and Oil Corporation, Dalea Partners, LP, Hartz
Capital MLP, LLC, ZLP Fund, L.P., KED MME Investment Partners,
LP, Eagle Income Appreciation Partners, L.P., Eagle Income
Appreciation II, L.P., Citigroup Financial Products, Inc., and
The Northwestern Mutual Life Insurance Company (incorporated
herein by reference to Exhibit 10.4 to the Companys
Current Report on Form 8-K filed on November 2, 2007).
|
|
10
|
.19*
|
|
Midstream Services and Gas Dedication Agreement between Bluestem
Pipeline, LLC and the Company entered into on December 22, 2006,
but effective as of December 1, 2006 (incorporated herein by
reference to Exhibit 10.6 to the Companys Current Report
on Form 8-K filed on December 29, 2006).
|
148
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
10
|
.20*
|
|
Amendment No. 1 to the Midstream Services and Gas Dedication
Agreement, dated as of August 9, 2007, by and between the
Company and Bluestem Pipeline, LLC (incorporated herein by
reference to Exhibit 10.1 to the Companys Current
Report on Form 8-K filed on August 13, 2007).
|
|
10
|
.21*
|
|
Assignment and Assumption Agreement, dated as of November 15,
2007, by and among the Company, Quest Energy Partners, L.P. and
Bluestem Pipeline, LLC (incorporated herein by reference to
Exhibit 10.5 to the Companys Current Report on Form 8-K
filed on November 21, 2007).
|
|
10
|
.22
|
|
Amendment No. 2 to the Midstream Services and Gas
Dedication Agreement, dated as of February 27, 2009, by and
between Quest Energy Partners, L.P. and Bluestem Pipeline, LLC.
|
|
10
|
.23
|
|
Second Amended and Restated Limited Liability Company Agreement
of Quest Midstream GP, LLC.
|
|
10
|
.24*
|
|
Employment Agreement dated April 10, 2007 between the Company
and David Lawler (incorporated herein by reference to Exhibit
10.1 to the Companys Current Report on Form 8-K filed on
April 13, 2007).
|
|
10
|
.25*
|
|
First Amendment to Employment Agreement, dated October 20, 2008,
between the Company and David Lawler (incorporated herein by
reference to Exhibit 10.2 to the Current Report on Form 8-K
filed on October 24, 2008).
|
|
10
|
.26*
|
|
Nonqualified Stock Option Agreement, dated October 20, 2008,
between the Company and David Lawler (incorporated herein by
reference to Exhibit 10.4 to the Current Report on Form 8-K
filed on October 24, 2008).
|
|
10
|
.27*
|
|
Employment Agreement dated March 7, 2007 between the Company and
David Bolton (incorporated herein by reference to Exhibit 10.6
to the Companys Quarterly Report on Form 10-Q filed on May
10, 2007).
|
|
10
|
.28*
|
|
Employment Agreement dated December 3, 2007 between the Company
and Jack T. Collins (incorporated herein by reference to
Exhibit 10.28 to the Companys Annual Report on
Form 10-K
filed on March 10, 2008).
|
|
10
|
.29*
|
|
First Amendment to Employment Agreement, dated October 23, 2008,
between the Company and Jack Collins (incorporated herein by
reference to Exhibit 10.3 to the Current Report on Form 8-K
filed on October 24, 2008).
|
|
10
|
.30*
|
|
Nonqualified Stock Option Agreement, dated October 23, 2008,
between the Company and Jack Collins (incorporated herein by
reference to Exhibit 10.5 to the Current Report on Form 8-K
filed on October 24, 2008).
|
|
10
|
.31*
|
|
Employment Agreement dated March 21, 2007 between the Company
and Richard Marlin (incorporated herein by reference to
Exhibit 10.30 to the Companys Annual Report on
Form 10-K
filed on March 10, 2008).
|
|
10
|
.32
|
|
First Amendment to Employment Agreement, dated December 29,
2008, between the Company and Richard Marlin.
|
|
10
|
.33*
|
|
Employment Agreement dated July 14, 2008 between the Company and
Tom Lopus (incorporated herein by reference to Exhibit 10.15 to
the Companys Quarterly Report on Form 10-Q filed on August
11, 2009).
|
|
10
|
.34*
|
|
Nonqualified Stock Option Agreement, dated January 12, 2009,
between the Company and Eddie LeBlanc (incorporated herein by
reference to Exhibit 10.1 to the Companys Current Report
on
Form 8-K
filed on January 14, 2009).
|
|
10
|
.35*
|
|
Office Lease dated May 31, 2007 between the Company and Oklahoma
Tower Realty Investors, L.L.C. (incorporated herein by reference
to Exhibit 10.5 to the Companys Quarterly Report on Form
10-Q filed on June 30, 2007).
|
|
10
|
.36*
|
|
Assignment and Assumptions of Leases, dated as of February 28,
2008, by and between Chesapeake Energy Corporation and the
Company (incorporated herein by reference to Exhibit 10.7 to the
Companys Quarterly Report on Form 10-Q filed on May 12,
2008).
|
|
10
|
.37*
|
|
Amended and Restated Credit Agreement, dated as of November 1,
2007, by and among Quest Midstream Partners, L.P., Bluestem
Pipeline, LLC, Royal Bank of Canada, RBC Capital Markets and the
Lenders party thereto (incorporated herein by reference to
Exhibit 10.5 to the Companys Current Report on
Form 8-K filed on November 2, 2007).
|
149
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
10
|
.38*
|
|
First Amendment to the Amended and Restated Credit Agreement,
dated as of November 1, 2007 among Quest Midstream Partners,
L.P., Bluestem Pipeline, LLC, Royal Bank of Canada and certain
guarantors. (incorporated herein by reference to Exhibit 10.29
to the Companys Registration Statement on Form S-4
filed on February 7, 2008).
|
|
10
|
.39*
|
|
Second Amendment to Amended and Restated Credit Agreement, dated
as of October 28, 2008, but effective as of November 5, 2008, by
and among Quest Midstream Partners, L.P., Bluestem Pipeline,
LLC, Quest Kansas General Partner, L.L.C., Quest Kansas
Pipeline, L.L.C., Quest Pipeline (KPC), Royal Bank of Canada and
the Lenders party thereto (incorporated herein by reference to
Exhibit 10.4 to the Companys Current Report on Form 8-K
filed on November 7, 2008).
|
|
10
|
.40*
|
|
Guaranty by Quest Kansas General Partner, L.L.C., Quest Kansas
Pipeline, L.L.C., and Quest Pipeline (KPC) in favor of Royal
Bank of Canada, dated as of November 1, 2007 (incorporated
herein by reference to Exhibit 10.9 to the Companys
Quarterly Report on Form 10-Q filed on November 9, 2007).
|
|
10
|
.41
|
|
Guaranty by Quest Transmission Company, LLC in favor of Royal
Bank of Canada, dated as of February, 21, 2008.
|
|
10
|
.42
|
|
Pledge and Security Agreement by Quest Transmission Company, LLC
in favor of Royal Bank of Canada, dated as of February 21, 2008.
|
|
10
|
.43*
|
|
Pledge and Security Agreement by Quest Kansas General Partner,
L.L.C. in favor of Royal Bank of Canada, dated as of November 1,
2007 (incorporated herein by reference to Exhibit 10.10 to the
Companys Quarterly Report on Form 10-Q filed on November
9, 2007).
|
|
10
|
.44*
|
|
Pledge and Security Agreement by Quest Kansas Pipeline, L.L.C.
in favor of Royal Bank of Canada, dated as of November 1, 2007
(incorporated herein by reference to Exhibit 10.11 to the
Companys Report on Form 10-Q filed on November 9, 2007).
|
|
10
|
.45*
|
|
Pledge and Security Agreement by Quest Pipelines (KPC) in favor
of Royal Bank of Canada, dated as of November 1, 2007
(incorporated herein by reference to Exhibit 10.12 to the
Companys Quarterly Report on Form 10-Q filed on November
9, 2007).
|
|
10
|
.46*
|
|
Amended and Restated Pledge and Security Agreement by Bluestem
Pipeline, LLC in favor of Royal Bank of Canada, dated as of
November 1, 2007 (incorporated herein by reference to Exhibit
10.13 to the Companys Quarterly Report on Form 10-Q filed
on November 9, 2007).
|
|
10
|
.47*
|
|
Amended and Restated Pledge and Security Agreement by Quest
Midstream Partners, L.P. in favor of Royal Bank of Canada, dated
as of November 1, 2007 (incorporated herein by reference to
Exhibit 10.14 to the Companys Quarterly Report on Form
10-Q filed on November 9, 2007).
|
|
10
|
.48
|
|
First Amendment to Amended and Restated Pledge and Security
Agreement by Quest Midstream Partners, L.P. in favor of Royal
Bank of Canada, dated as of February 21, 2008.
|
|
10
|
.49*
|
|
Settlement and Release Agreement dated November 8, 2007 between
Quest Midstream GP, LLC, the Company and Richard Andrew Hoover
(incorporated herein by reference to Exhibit 10.1 to the
Companys Current Report on Form 8-K filed on November 15,
2007).
|
|
10
|
.50*
|
|
First Amended and Restated Agreement of Limited Partnership of
Quest Energy Partners, L.P., dated November 15, 2007, by and
between the Company and 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 (File No. 001-33787)
filed on November 21, 2007).
|
|
10
|
.51*
|
|
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).
|
|
10
|
.52*
|
|
Contribution, Conveyance and Assumption Agreement, dated as of
November 15, 2007, by and among Quest Energy Partners, L.P.,
Quest Energy GP, LLC, the Company, Quest Cherokee, LLC, Quest
Oil & Gas, LLC, and Quest Energy Service, LLC (incorporated
herein by reference to Exhibit 10.1 to the Companys
Current Report on Form 8-K filed on November 21, 2007).
|
|
10
|
.53*
|
|
Omnibus Agreement, dated as November 15, 2007, by and among
Quest Energy Partners, L.P., Quest Energy GP, LLC and the
Company (incorporated herein by reference to Exhibit 10.2 to the
Companys Current Report on Form 8-K filed on November 21,
2007).
|
150
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
10
|
.54*
|
|
Management Services Agreement, dated as of November 15, 2007, by
and among Quest Energy GP, LLC, Quest Energy Partners, L.P. and
Quest Energy Service, LLC (incorporated herein by reference to
Quest Energy Partners, L.P.s Current Report on Form 8-K
filed on November 21, 2007).
|
|
10
|
.55*
|
|
Amended and Restated Credit Agreement, dated as of November 15,
2007, by and among the Company, as the Initial Co-Borrower,
Quest Cherokee, LLC, as the Borrower, Quest Energy Partners,
L.P., as a Guarantor, Royal Bank of Canada, as Administration
Agent and Collateral Agent, KeyBank National Association, as
Documentation Agent, and the lenders from time to time party
thereto (incorporated herein by reference to Exhibit 10.3 to the
Companys Current Report on Form 8-K filed on November 21,
2007).
|
|
10
|
.56*
|
|
First Amendment to Amended and Restated Credit Agreement, dated
as of April 15, 2008, by and among Quest Cherokee, LLC, Royal
Bank of Canada, KeyBank National Association, and the lenders
Party Thereto (incorporated herein by reference to Exhibit 10.1
to the Companys Current Report on Form 8-K filed on April
23, 2008).
|
|
10
|
.57*
|
|
Second Amendment to Amended and Restated Credit Agreement, dated
as of October 28, 2008, but effective as of November 5, 2008, by
and among Quest Cherokee, LLC, Quest Energy Partners, L.P.,
Quest Cherokee Oilfield Service, LLC, Royal Bank of Canada,
KeyBank National Association and the Lenders party thereto
(incorporated herein by reference to Exhibit 10.3 to the
Companys Current Report on Form 8-K filed on November 7,
2008).
|
|
10
|
.58*
|
|
Amended and Restated Credit Agreement, dated as of July 11,
2008, by and among the Company, as the Borrower, Royal Bank of
Canada, as Administrative Agent and Collateral Agent, and the
lenders from time to time party thereto (incorporated herein by
reference to Exhibit 10.1 to the Companys Current Report
on Form 8-K filed on July 16, 2008).
|
|
10
|
.59*
|
|
First Amendment to Amended and Restated Credit Agreement, dated
as of October 24, 2008, by and among the Company, Royal Bank of
Canada and the Guarantors party thereto (incorporated herein by
reference to Exhibit 10.1 to the Companys Current Report
on Form 8-K filed on October 31, 2008).
|
|
10
|
.60*
|
|
Second Amendment to Amended and Restated Credit Agreement, dated
as of November 4, 2008, by and among the Company, Royal Bank of
Canada and the Guarantors party thereto (incorporated herein by
reference to Exhibit 10.1 to the Companys Current Report
on Form 8-K filed on November 7, 2008).
|
|
10
|
.61
|
|
Third Amendment to Amended and Restated Credit Agreement, dated
as of January 30, 2009, by and among the Company, Royal
Bank of Canada and the Guarantors party thereto.
|
|
10
|
.62
|
|
Fourth Amendment to Amended and Restated Credit Agreement, dated
as of May 29, 2009, by and among the Company, Royal Bank of
Canada and the Guarantors party thereto.
|
|
10
|
.63*
|
|
Loan Transfer Agreement, dated as of November 15, 2007, by and
among the Company, Quest Cherokee, LLC, Quest Oil & Gas,
LLC, Quest Energy Service, Inc., Quest Cherokee Oilfield
Service, LLC, Guggenheim Corporate Funding, LLC, Wells Fargo
Foothill, Inc., and Royal Bank of Canada (incorporated herein by
reference to Exhibit 10.6 to the Companys Current Report
on Form 8-K filed on November 21, 2007).
|
|
10
|
.64*
|
|
Guaranty for Credit Agreement by Quest Oil & Gas, LLC and
Quest Energy Service, LLC in favor of Royal Bank of Canada,
dated as of November 15, 2007 (incorporated herein by reference
to Exhibit 10.7 to the Companys Current Report on Form 8-K
filed on November 21, 2007).
|
|
10
|
.65*
|
|
Pledge and Security Agreement for Credit Agreement by Quest
Energy Service, LLC for the benefit of Royal Bank of Canada,
dated as of November 15, 2007 (incorporated herein by reference
to Exhibit 10.8 to the Companys Current Report on Form 8-K
filed on November 21, 2007).
|
|
10
|
.66*
|
|
Pledge and Security Agreement for Credit Agreement by Quest Oil
& Gas, LLC for the benefit of Royal Bank of Canada, dated
as of November 15, 2007 (incorporated herein by reference to
Exhibit 10.9 to the Companys Current Report on Form 8-K
filed on November 21, 2007).
|
|
10
|
.67
|
|
First Amendment to Pledge and Security Agreement for Amended and
Restated Credit Agreement by Quest Oil & Gas, LLC for the
benefit of Royal Bank of Canada, dated May 29, 2009.
|
|
10
|
.68*
|
|
Pledge and Security Agreement for Credit Agreement by the
Company for the benefit of Royal Bank of Canada, dated as of
November 15, 2007 (incorporated herein by reference to Exhibit
10.10 to the Companys Current Report on Form 8-K filed on
November 21, 2007).
|
151
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
10
|
.69*
|
|
First Amendment to Pledge and Security Agreement for Amended and
Restated Credit Agreement by the Company for the benefit of
Royal Bank of Canada, dated as of July 11, 2008 (incorporated
herein by reference to Exhibit 10.4 to the Companys
Current Report on Form 8-K filed on July 16, 2008).
|
|
10
|
.70*
|
|
Guaranty for Amended and Restated Credit Agreement by Quest
Energy Partners, L.P. in favor of Royal Bank of Canada, dated as
of November 15, 2007 (incorporated herein by reference to
Exhibit 10.11 to the Companys Current Report on Form 8-K
filed on November 21, 2007).
|
|
10
|
.71*
|
|
Guaranty for Amended and Restated Credit Agreement by Quest
Cherokee Oilfield Service, LLC in favor of Royal Bank of Canada,
dated as of November 15, 2007 (incorporated herein by reference
to Exhibit 10.12 to the Companys Current Report on Form
8-K filed on November 21, 2007).
|
|
10
|
.72*
|
|
Pledge and Security Agreement for Amended and Restated Credit
Agreement by Quest Energy Partners, L.P. for the benefit of
Royal Bank of Canada, dated as of November 15, 2007
(incorporated herein by reference to Exhibit 10.13 to the
Companys Current Report on Form 8-K filed on November 21,
2007).
|
|
10
|
.73*
|
|
Pledge and Security Agreement for Amended and Restated Credit
Agreement by Quest Cherokee Oilfield Service, LLC for the
benefit of Royal Bank of Canada, dated as of November 15, 2007
(incorporated herein by reference to Exhibit 10.14 to the
Companys Current Report on Form 8-K filed on November 21,
2007).
|
|
10
|
.74*
|
|
Pledge and Security Agreement for Amended and Restated Credit
Agreement by Quest Cherokee, LLC for the benefit of Royal Bank
of Canada, dated as of November 15, 2007 (incorporated herein by
reference to Exhibit 10.15 to the Companys Current Report
on Form 8-K filed on November 21, 2007).
|
|
10
|
.75*
|
|
Pledge and Security Agreement for Amended and Restated Credit
Agreement by Quest Eastern Resource LLC for the benefit of Royal
Bank of Canada, dated as of July 11, 2008 (incorporated herein
by reference to Exhibit 10.2 to the Companys Current
Report on Form 8-K filed on July 16, 2008).
|
|
10
|
.76*
|
|
Pledge and Security Agreement for Amended and Restated Credit
Agreement, dated as of July 11, 2008, by Quest Mergersub, Inc.,
for the benefit of Royal Bank of Canada (incorporated herein by
reference to Exhibit 10.3 to the Companys Current Report
on Form 8-K filed on July 16, 2008).
|
|
10
|
.77*
|
|
Guaranty for Amended and Restated Credit Agreement by Quest
Eastern Resource LLC in favor of Royal Bank of Canada, dated as
of July 11, 2008 (incorporated herein by reference to Exhibit
10.5 to the Companys Current Report on Form 8-K filed on
July 16, 2008).
|
|
10
|
.78*
|
|
Guaranty for Amended and Restated Credit Agreement by Quest
MergerSub, Inc. in favor of Royal Bank of Canada, dated as of
July 11, 2008 (incorporated herein by reference to Exhibit 10.6
to the Companys Current Report on Form 8-K filed on July
16, 2008).
|
|
10
|
.79*
|
|
Second Lien Senior Term Loan Agreement, dated as of July 11,
2008, by and among Quest Cherokee, LLC, Quest Energy Partners,
L.P., Royal Bank of Canada, KeyBank National Association,
Société Générale, the lenders party thereto
and RBC Capital Markets (incorporated herein by reference to
Exhibit 10.7 to the Companys Current Report on Form 8-K
filed on July 16, 2008).
|
|
10
|
.80*
|
|
First Amendment to Second Lien Senior Term Loan Agreement, dated
as of October 28, 2008, but effective as of November 5, 2008, by
and among Quest Cherokee, LLC, Quest Energy Partners, L.P.,
Quest Cherokee Oilfield Service, LLC, Royal Bank of Canada,
Keybank National Association, Société
Générale and the Lenders party thereto (incorporated
herein by reference to Exhibit 10.2 to the Companys
Current Report on Form 8-K filed on November 7, 2008).
|
|
10
|
.81*
|
|
Guaranty for Second Lien Term Loan Agreement by Quest Cherokee
Oilfield Service, LLC in favor of Royal Bank of Canada, dated as
of July 11, 2008 (incorporated herein by reference to Exhibit
10.8 to the Companys Current Report on Form 8-K filed on
July 16, 2008).
|
|
10
|
.82*
|
|
Guaranty for Second Lien Term Loan Agreement by Quest Energy
Partners, L.P. in favor of Royal Bank of Canada, dated as of
July 11, 2008 (incorporated herein by reference to Exhibit 10.9
to the Companys Current Report on Form 8-K filed on July
16, 2008).
|
|
10
|
.83*
|
|
Pledge and Security Agreement for Second Lien Term Loan
Agreement by Quest Cherokee Oilfield Service, LLC for the
benefit of Royal Bank of Canada, dated as of July 11, 2008
(incorporated herein by reference to Exhibit 10.10 to the
Companys Current Report on Form 8-K filed on July 16,
2008).
|
152
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description
|
|
|
10
|
.84*
|
|
Pledge and Security Agreement for Second Lien Term Loan
Agreement by Quest Energy Partners, L.P. for the benefit of
Royal Bank of Canada, dated as of July 11, 2008 (incorporated
herein by reference to Exhibit 10.11 to the Companys
Current Report on Form 8-K filed on July 16, 2008).
|
|
10
|
.85*
|
|
Pledge and Security Agreement for Second Lien Term Loan
Agreement by Quest Cherokee, LLC for the benefit of Royal Bank
of Canada, dated as of July 11, 2008 (incorporated herein by
reference to Exhibit 10.12 to the Companys Current Report
on Form 8-K filed on July 16, 2008).
|
|
10
|
.86*
|
|
Intercreditor Agreement, dated as of July 11, 2008, by and
between Royal Bank of Canada and Quest Cherokee, LLC
(incorporated herein by reference to Exhibit 10.13 to the
Companys Current Report on Form 8-K filed on
July 16, 2008).
|
|
10
|
.87*
|
|
First Amendment to Office Lease, dated as of February 7, 2008,
by and between Cullen Allen Holdings L.P. and Quest Midstream
Partners, L.P. (incorporated herein by reference to Exhibit 10.6
to the Companys Quarterly Report on Form 10-Q filed on May
12, 2008).
|
|
10
|
.88
|
|
Settlement Agreement by and among Quest Resource Corporation,
Quest Energy Partners, L.P., Quest Midstream Partners, L.P. and
Jerry D. Cash, effective March 30, 2009.
|
|
10
|
.89
|
|
Full and Final Settlement Agreement and Mutual Release, by and
among Quest Resource Corporation, Quest Energy Partners, L.P.,
Quest Midstream Partners, L.P., Rockport Energy, LLC, Rockport
Georgetown Partners, LLC, Rockport Georgetown Holdings, LP,
Jerry D. Cash, Bryan T. Simmons and Steven Hochstein, dated May
19, 2009.
|
|
21
|
.1
|
|
List of Subsidiaries.
|
|
23
|
.1
|
|
Consent of Cawley, Gillespie & Associates, Inc.
|
|
23
|
.2
|
|
Consent of UHY, LLP.
|
|
24
|
.1
|
|
Power of Attorney.
|
|
31
|
.1
|
|
Certification by principal 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 principal 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 principal 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 principal 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.
|
|
|
|
Management contracts and compensatory plans and arrangements
required to be filed as Exhibits pursuant to Item 15(a) of
this report.
|
PLEASE NOTE: Pursuant to the rules and regulations of the
Securities and Exchange Commission, we have filed or
incorporated by reference the agreements referenced above as
exhibits to this Annual Report on
Form 10-K.
The agreements have been filed to provide investors with
information regarding their respective terms. The agreements are
not intended to provide any other factual information about the
Company or its business or operations. In particular, the
assertions embodied in any representations, warranties and
covenants contained in the agreements may be subject to
qualifications with respect to knowledge and materiality
different from those applicable to investors and may be
qualified by information in confidential disclosure schedules
not included with the exhibits. These disclosure schedules may
contain information that modifies, qualifies and creates
exceptions to the representations, warranties and covenants set
forth in the agreements. Moreover, certain representations,
warranties and covenants in the agreements may have been used
for the purpose of allocating risk between the parties, rather
than establishing matters as facts. In addition, information
concerning the subject matter of the representations, warranties
and covenants may have changed after the date of the respective
agreement, which subsequent information may or may not be fully
reflected in the Companys public disclosures. Accordingly,
investors should not rely on the representations, warranties and
covenants in the agreements as characterizations of the actual
state of facts about the Company or its business or operations
on the date hereof.
153
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