Attached files
file | filename |
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EX-31.1 - EX-31.1 - Quest Energy Partners, L.P. | d69843exv31w1.htm |
EX-31.2 - EX-31.2 - Quest Energy Partners, L.P. | d69843exv31w2.htm |
EX-32.1 - EX-32.1 - Quest Energy Partners, L.P. | d69843exv32w1.htm |
EX-32.2 - EX-32.2 - Quest Energy Partners, L.P. | d69843exv32w2.htm |
Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2009
Commission file number: 001-33787
QUEST ENERGY PARTNERS, L.P.
(Exact name of registrant specified in its charter)
Delaware (State or other jurisdiction of incorporation or organization) |
26-0518546 (I.R.S. Employer Identification No.) |
210 Park Avenue, Suite 2750, Oklahoma City, OK 73102
(Address of principal executive offices) (Zip Code)
(Address of principal executive offices) (Zip Code)
405-600-7704
Registrants telephone number, including area code
Registrants telephone number, including area code
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such
shorter period that the registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes
o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated
filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
(Check one):
Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o (Do not check if a smaller reporting company) |
Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
As of
November 2, 2009, the issuer had 12,316,521 common units outstanding.
QUEST ENERGY PARTNERS, L.P.
FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2009
FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2009
TABLE OF CONTENTS
i
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PART I FINANCIAL INFORMATION
Item 1. | Financial Statements |
QUEST ENERGY PARTNERS, L.P AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
($ in thousands, except unit data)
($ in thousands, except unit data)
September 30, | December 31, | |||||||
2009 | 2008 | |||||||
(Unaudited) | ||||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 18,011 | $ | 3,706 | ||||
Restricted cash |
301 | 112 | ||||||
Accounts receivable trade, net |
8,323 | 11,696 | ||||||
Other receivables |
1,850 | 2,590 | ||||||
Due from affiliates |
3,890 | | ||||||
Other current assets |
576 | 2,031 | ||||||
Inventory |
8,329 | 8,782 | ||||||
Current derivative financial instrument assets |
19,625 | 42,995 | ||||||
Total current assets |
60,905 | 71,912 | ||||||
Property and equipment, net |
15,684 | 17,367 | ||||||
Oil and gas properties under full cost method of accounting, net |
36,064 | 151,120 | ||||||
Other assets, net |
2,628 | 4,167 | ||||||
Long-term derivative financial instrument assets |
4,653 | 30,836 | ||||||
Total assets |
$ | 119,934 | $ | 275,402 | ||||
LIABILITIES AND EQUITY/(DEFICIT) |
||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | 4,867 | $ | 7,380 | ||||
Revenue payable |
3,391 | 3,221 | ||||||
Accrued expenses |
3,011 | 1,770 | ||||||
Due to affiliates |
| 4,697 | ||||||
Current portion of notes payable |
29,865 | 41,882 | ||||||
Current derivative financial instrument liabilities |
1,413 | 12 | ||||||
Total current liabilities |
42,547 | 58,962 | ||||||
Long-term derivative financial instrument liabilities |
5,294 | 4,230 | ||||||
Asset retirement obligations |
4,943 | 4,592 | ||||||
Notes payable |
160,054 | 189,090 | ||||||
Commitments and contingencies |
||||||||
Partners equity/(deficit): |
||||||||
Common unitholders Issued 12,331,521 at September
30, 2009 and December 31, 2008 (9,100,000 public;
3,231,521 affiliate); outstanding 12,316,521 at
September 30, 2009 and December 31, 2008; respectively
(9,100,000 public; 3,216,521 affiliate) |
(17,697 | ) | 45,832 | |||||
Subordinated unitholder affiliate; 8,857,981 units
issued and outstanding at September 30, 2009 and December
31, 2008 |
(71,530 | ) | (25,857 | ) | ||||
General Partner affiliate; 431,827 units issued and
outstanding at September 30, 2009 and December 31, 2008 |
(3,677 | ) | (1,447 | ) | ||||
Total partners equity/(deficit) |
(92,904 | ) | 18,528 | |||||
Total liabilities and partners equity |
$ | 119,934 | $ | 275,402 | ||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
F-1
Table of Contents
QUEST ENERGY PARTNERS, L.P AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in thousands, except per unit data)
(Unaudited)
($ in thousands, except per unit data)
(Unaudited)
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Oil and gas sales |
$ | 18,151 | $ | 49,454 | $ | 56,260 | $ | 136,908 | ||||||||
Costs and expenses: |
||||||||||||||||
Oil and gas production |
8,458 | 9,821 | 23,216 | 34,104 | ||||||||||||
Transportation expense |
10,879 | 8,583 | 31,272 | 25,921 | ||||||||||||
General and administrative expenses |
5,570 | 734 | 13,249 | 5,501 | ||||||||||||
Depreciation, depletion and amortization |
9,076 | 13,196 | 24,766 | 34,750 | ||||||||||||
Impairment of oil and gas properties |
| | 95,169 | | ||||||||||||
Recovery of misappropriated funds, net of liabilities assumed |
| | (31 | ) | | |||||||||||
Total costs and expenses |
33,983 | 32,334 | 187,641 | 100,276 | ||||||||||||
Operating income (loss) |
(15,832 | ) | 17,120 | (131,381 | ) | 36,632 | ||||||||||
Other income (expense): |
||||||||||||||||
Gain (loss) from derivative financial instruments |
8,752 | 145,132 | 31,078 | (4,482 | ) | |||||||||||
Other income (expense) |
(33 | ) | 40 | 94 | 154 | |||||||||||
Interest expense, net |
(3,370 | ) | (4,354 | ) | (11,274 | ) | (8,747 | ) | ||||||||
Total other income (expense) |
5,349 | 140,818 | 19,898 | (13,075 | ) | |||||||||||
Net income (loss) |
$ | (10,483 | ) | $ | 157,938 | $ | (111,483 | ) | $ | 23,557 | ||||||
General partners interest in net income (loss) |
$ | (210 | ) | $ | 3,159 | $ | (2,230 | ) | $ | 471 | ||||||
Limited partners interest in net income (loss) |
$ | (10,273 | ) | $ | 154,779 | $ | (109,253 | ) | $ | 23,086 | ||||||
Net income (loss) per limited partner unit: (basic and diluted) |
$ | (0.49 | ) | $ | 7.30 | $ | (5.16 | ) | $ | 1.09 | ||||||
Weighted average limited partner units outstanding: |
||||||||||||||||
Common units (basic and diluted) |
12,317 | 12,332 | 12,317 | 12,329 | ||||||||||||
Subordinated units (basic and diluted) |
8,858 | 8,858 | 8,858 | 8,858 | ||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
F-2
Table of Contents
QUEST ENERGY PARTNERS, L.P AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
($ in thousands)
(Unaudited)
($ in thousands)
(Unaudited)
For the Nine Months Ended | ||||||||
September 30, | ||||||||
2009 | 2008 | |||||||
Cash flows from operating activities: |
||||||||
Net income (loss) |
$ | (111,483 | ) | $ | 23,557 | |||
Adjustments to reconcile net income (loss) to cash provided by (used in) operations: |
||||||||
Depreciation, depletion and amortization |
24,766 | 34,750 | ||||||
Unit-based compensation |
51 | 21 | ||||||
Change in fair value of derivative financial instruments |
52,018 | (13,312 | ) | |||||
Impairment of oil and gas properties |
95,169 | | ||||||
Amortization of deferred loan costs |
1,781 | 847 | ||||||
Bad debt expense |
| 97 | ||||||
Other
non-cash items affecting net income |
(55 | ) | | |||||
Change in assets and liabilities: |
||||||||
Accounts receivable |
3,373 | (5,818 | ) | |||||
Other receivables |
740 | (513 | ) | |||||
Other current assets |
1,455 | 120 | ||||||
Other assets |
| 13,696 | ||||||
Due to/from affiliates |
(9,468 | ) | 734 | |||||
Accounts payable |
(2,727 | ) | (4,266 | ) | ||||
Revenue payable |
58 | (146 | ) | |||||
Accrued expenses |
2,074 | (1,222 | ) | |||||
Other long-term liabilities |
| (33 | ) | |||||
Other |
(1 | ) | (1 | ) | ||||
Net cash from operating activities |
57,751 | 48,511 | ||||||
Cash flows from investing activities: |
||||||||
Restricted cash |
(189 | ) | 1,093 | |||||
Proceeds from sale of oil and gas properties |
116 | | ||||||
Acquisition of business PetroEdge |
| (71,213 | ) | |||||
Equipment, development and leasehold |
(1,384 | ) | (78,214 | ) | ||||
Net cash from investing activities |
(1,457 | ) | (148,334 | ) | ||||
Cash flows from financing activities: |
||||||||
Proceeds from bank borrowings |
102 | 45,000 | ||||||
Repayments of note borrowings |
(12,849 | ) | (534 | ) | ||||
Proceeds from revolver note |
| 89,000 | ||||||
Repayments
of revolver note |
(29,000 | ) | | |||||
Contributions (distributions) |
| 636 | ||||||
Distributions to unitholders |
| (22,573 | ) | |||||
Syndication costs |
| (265 | ) | |||||
Refinancing costs |
(242 | ) | (1,893 | ) | ||||
Net cash from financing activities |
(41,989 | ) | 109,371 | |||||
Net increase in cash and cash equivalents |
14,305 | 9,548 | ||||||
Cash and cash equivalents, beginning of period |
3,706 | 169 | ||||||
Cash and cash equivalents, end of period |
$ | 18,011 | $ | 9,717 | ||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
F-3
Table of Contents
QUEST ENERGY PARTNERS, L.P AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF PARTNERS EQUITY/(DEFICIT)
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2009
(Amounts subsequent to December 31, 2008 are unaudited)
(in thousands, except unit amounts)
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2009
(Amounts subsequent to December 31, 2008 are unaudited)
(in thousands, except unit amounts)
Common | General | General | Total | |||||||||||||||||||||||||
Units | Common | Subordinated | Subordinated | Partner | Partner | Partners | ||||||||||||||||||||||
Issued | Unitholders | Units | Unitholders | Units | Interest | Equity/(Deficit) | ||||||||||||||||||||||
Balance, December 31, 2008 |
12,331,521 | $ | 45,832 | 8,857,981 | $ | (25,857 | ) | 431,827 | $ | (1,447 | ) | $ | 18,528 | |||||||||||||||
Net loss |
| (63,580 | ) | | (45,673 | ) | | (2,230 | ) | (111,483 | ) | |||||||||||||||||
Unit-based compensation |
51 | | | | | 51 | ||||||||||||||||||||||
Balance, September 30, 2009 |
12,331,521 | $ | (17,697 | ) | 8,857,981 | $ | (71,530 | ) | 431,827 | $ | (3,677 | ) | $ | (92,904 | ) | |||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
F-4
Table of Contents
QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(Unaudited)
1. Basis of Presentation
These condensed consolidated financial statements have been prepared by Quest Energy Partners,
L.P. (Quest Energy, the Partnership or QELP) without audit pursuant to the rules and
regulations of the Securities and Exchange Commission (SEC) and reflect all adjustments that are,
in the opinion of management, necessary for a fair statement of the results for the interim
periods, on a basis consistent with the annual audited financial statements. All such adjustments
are of a normal recurring nature. Certain information, accounting policies and footnote disclosures
normally included in financial statements prepared in accordance with accounting principles
generally accepted in the United States of America (GAAP) have been omitted pursuant to such
rules and regulations, although the Partnership believes that the disclosures are adequate to make
the information presented not misleading. These financial statements should be read in conjunction
with the financial statements and the summary of significant accounting policies and notes included
in the Partnerships Annual Report on Form 10-K/A for the year ended December 31, 2008 (the 2008
Form 10-K/A).
The preparation of financial statements in conformity with GAAP requires management to make
estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure
of contingent assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual results could differ from
those estimates. The operating results for the interim periods are not necessarily indicative of
the results to be expected for the full year.
Unless the context clearly requires otherwise, references to us, we, our or the
Partnership are intended to mean Quest Energy Partners, L.P. and its consolidated subsidiaries.
Going Concern
The accompanying condensed consolidated financial statements have been prepared assuming that
the Partnership 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 Partnership and its predecessor have incurred significant losses from 2004 through
2008 and into 2009, mainly attributable to the operations, impairment of oil and gas properties,
unrealized gains and losses from derivative financial instruments, legal restructurings,
financings, the current legal and operational structure and, to a lesser degree, the cash
expenditures resulting from the investigation related to certain unauthorized transfers, repayments
and re-transfers of funds to entities controlled by our former chief executive officer (the
Transfers). We have determined that there is substantial doubt about our ability to continue as a
going concern.
While we were in compliance with the covenants in our credit agreements as of December 31,
2008 and September 30, 2009, there is no assurance that we will be in compliance as of December 31,
2009. If defaults exist in subsequent periods that are not waived by our lenders, our assets could
be subject to foreclosure or other collection efforts. Our Amended and Restated Credit Agreement,
as amended (Quest Cherokee Credit Agreement) limits the amount we can borrow to a borrowing base
amount, determined by the lenders at their sole discretion. Outstanding borrowings in excess of the
borrowing base will be required to be repaid in either four equal monthly installments following
notice of the new borrowing base or immediately if the borrowing base is reduced in connection with
a sale or disposition of certain properties in excess of 5% of the borrowing base. In July 2009,
the borrowing base under the Quest Cherokee Credit Agreement was reduced from $190 million to $160
million, which, following the principal payment of $15 million we made on June 30, 2009, resulted
in the outstanding borrowings under the Quest Cherokee Credit Agreement exceeding the new borrowing
base by $14 million. The borrowing base deficiency was repaid on July 8, 2009. We anticipate that in connection with the redetermination of our borrowing base in November
2009, our borrowing base will be further reduced from its current level of $160 million. In the
event of a borrowing base reduction, we expect to be able to make the required payments
resulting from the borrowing base deficiency out of our existing funds.
Under the terms of our Second Lien Senior Term Loan Agreement, as amended (Second Lien Loan
Agreement), we are required to make quarterly payments of $3.8 million. We have made payments
through August 17, 2009. The balance remaining of $29.8 million which was previously due on
September 30, 2009, is now due on November 16, 2009, as a result of the extension obtained under
the Fourth Amendment to Second Lien Senior Term Loan Agreement entered into on October 30, 2009.
While we are currently negotiating further extensions to this loan, there can be no assurance that
such negotiations will be successful or that we will be able to repay amounts due under the Second
Lien Loan Agreement in accordance with the terms of the agreement. Failure to make the remaining
principal payment under the Second Lien Loan Agreement (absent any waiver granted or amendment to
the agreement) would be a default under the terms of both credit agreements, resulting in payment
acceleration of both loans.
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Our parent, Quest Resource Corporation (QRCP) has pledged its ownership in our general
partner to secure its term loan credit agreement and historically has been almost exclusively
dependent upon distributions from its interest in Quest Midstream Partners, L.P. (Quest Midstream
or QMLP) and us for revenue and cash flow. QRCP has not received any distributions from Quest
Midstream in 2009; furthermore, we suspended distributions on our subordinated units starting with
the third quarter of 2008 and all units starting with the fourth quarter of 2008, do not expect to
have any available cash to pay distributions and are unable to estimate at this time when such
distributions may, if ever, be resumed. If QRCP were to default under its credit agreement, the
lenders of QRCPs credit facility could obtain control of our general partner or sell control of
our general partner to a third party. In the past, QRCP has not satisfied all of the financial
covenants contained in its credit agreement. In QRCPs Annual Report on Form 10-K/A for the year
ended December 31, 2008, its independent registered public accounting firm expressed doubt about
its ability to continue as a going concern if it is unable to restructure its debt obligations,
issue equity securities and/or sell assets. On September 11, 2009, QRCP amended and restated its
credit agreement to add an additional $8 million revolving credit facility to finance QRCPs
drilling program in the Appalachian Basin, general and administrative expenses and working capital
and other corporate expenses. Under the terms of the amended and restated credit agreement, the
total amount due on July 11, 2010 by QRCP under its credit agreement is estimated to be
approximately $21 million. As a result, QRCP will need to raise a significant amount of equity
capital during the first half of 2010 to pay this amount and further fund its drilling program. 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.
Based on the foregoing, we have determined that there is substantial doubt about our ability
to continue as a going concern, absent an amendment of our credit agreements.
Recombination On July 2, 2009, QELP, QRCP, QMLP and other parties thereto entered into an
Agreement and Plan of Merger (the Merger Agreement) pursuant to which, following a series of
mergers and an entity conversion, QRCP, QELP and the successor to QMLP will become wholly-owned
subsidiaries of PostRock Energy Corporation (PostRock), a new, publicly-traded corporation (the
Recombination). On October 2, 2009, the Merger Agreement was amended to, among other things,
reflect certain technical changes as the result of an internal restructuring. On October 6, 2009,
PostRock filed with the SEC a registration statement on Form S-4, which included a joint proxy
statement/prospectus, relating to the Recombination.
While we are working toward the completion of the Recombination before year-end, it remains
subject to the satisfaction of a number of conditions, including, among others, the arrangement of
one or more satisfactory credit facilities for PostRock and its subsidiaries, the approval of the
transaction by our unitholders, the unitholders of QMLP and the stockholders of QRCP, and consents
from each entitys existing lenders. There can be no assurance that these conditions will be met or
that the Recombination will occur.
Upon completion of the Recombination, the equity of PostRock would be owned approximately 44%
by current QMLP common unit holders, approximately 33% by current QELP common unit holders (other
than QRCP), and approximately 23% by current QRCP stockholders.
The accompanying financial statements do not include any adjustments that might result from
the outcome of this uncertainty.
Recent Accounting Pronouncements
In June 2009, the Financial Accounting Standards Board (the FASB) issued FASB Accounting Standards Codification (ASC) Topic 105 Generally Accepted Accounting Principles, which
establishes FASB ASC as the sole source of authoritative GAAP. Pursuant to the provisions of FASB ASC 105, the
Partnership has updated references to GAAP in its financial statements for the period ended
September 30, 2009. The adoption of this standard did not have a material impact on our
consolidated financial statements.
In March 2008, the FASB issued FASB ASC 815-10 Derivatives and Hedging that does not change
the accounting for derivatives but does require enhanced disclosures about derivative strategies
and accounting practices. We adopted these provisions effective January 1, 2009. See Note 4
Derivative Financial Instruments for the impact to our disclosures.
The Partnership adopted the provisions of FASB ASC 260 Earnings Per Share, effective January
1, 2009, relating to whether instruments granted in share-based payment transactions are considered
participating securities prior to vesting and therefore included in the allocation of earnings for
purposes of calculating earnings per unit (EPU) under the two-class method as required by FASB
ASC 260. FASB ASC 260 provides that unvested unit-based awards that contain non-forfeitable rights
to dividends are participating securities and should be included in the computation of EPU. The
Partnerships bonus units contain non-forfeitable rights to dividends and thus require these awards
to be included in the EPU computation. All prior periods have been conformed to the current year
presentation. During periods of losses, EPU will not be impacted, as the Partnerships
participating securities are not obligated to share in the losses of the Partnership and thus, are
not included in the EPU computation. See Note 8. Net Income Per Limited Partner Unit.
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The Partnership also adopted the provisions of FASB ASC 260 Earnings Per Share, effective
January 1, 2009, relating to the comparability of EPU calculation for master limited partnerships
with incentive distribution rights (IDR). FASB ASC 260 requires retrospective restatement of
prior periods. IDRs will be awarded as certain targeted distributions are met. At this time, the
Company has not met any targeted distributions, thus adoption of the IDR provisions within FASB ASC
260 has had no impact to the Partnerships basic EPU calculation.
In December 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 crude oil and natural gas
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.
In May 2009, the FASB issued FASB ASC 855 Subsequent Events. FASB ASC 855 establishes general
standards of accounting for and disclosure of transactions and events that occur after the balance
sheet date but before financial statements are issued or are available to be issued. It also
requires the disclosure of the date through which an entity has evaluated subsequent events and the
basis for that date. We adopted FASB ASC 855 beginning with the period ended June 30, 2009.
2. Acquisition
PetroEdge On July 11, 2008, QRCP completed the acquisition of privately held PetroEdge
Resources LLC (WV) (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. At the time of the acquisition, PetroEdge owned
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 .
At closing, QRCP sold the producing well bores to our subsidiary, Quest Cherokee LLC (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 wellbores) and a gathering system were retained by PetroEdge 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. We funded our purchase of the PetroEdge wellbores with borrowings
under our Quest Cherokee Credit Agreement and the proceeds of a $45 million, six-month term loan.
See Note 3. Long-Term Debt.
Pro Forma Summary Data Related to Acquisition
The following unaudited pro forma information summarizes the results of operations for the
three and nine month periods ended September 30, 2008, as if our acquisition of the PetroEdge
assets had occurred at the beginning of the period (in thousands, except per unit data):
Three Months | Nine Months | |||||||
Ended | Ended | |||||||
September 30, | September 30, | |||||||
2008 | 2008 | |||||||
Pro forma revenue |
$ | 49,454 | $ | 143,458 | ||||
Pro forma net income |
$ | 157,938 | $ | 19,020 | ||||
Pro forma net income per limited partner unit basic and diluted |
$ | 7.31 | $ | 0.88 |
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3. Long-Term Debt
The following is a summary of our long-term debt as of the dates indicated (in thousands):
September 30, | December 31, | |||||||
2009 | 2008 | |||||||
Borrowings under bank senior credit facilities |
||||||||
Quest Cherokee Credit Agreement |
$ | 160,000 | $ | 189,000 | ||||
Second Lien Loan Agreement |
29,800 | 41,200 | ||||||
Notes payable to banks and finance companies, secured by equipment and vehicles |
119 | 772 | ||||||
Total debt |
189,919 | 230,972 | ||||||
Less current maturities included in current liabilities |
29,865 | 41,882 | ||||||
Total long-term debt |
$ | 160,054 | $ | 189,090 | ||||
Credit Facilities
A. Quest Cherokee Credit Agreement.
Quest Cherokee, LLC (Quest Cherokee) is a
party to the
Quest Cherokee Credit Agreement with Royal Bank of Canada (RBC) , KeyBank National
Association (KeyBank) and the lenders party thereto for a $250 million revolving credit facility,
which is guaranteed by Quest Energy. Availability under the revolving credit facility is tied to a
borrowing base that is redetermined by the lenders every six months taking into account the value
of Quest Cherokees proved reserves.
The borrowing base was $160 million and the amount borrowed under the Quest Cherokee Credit
Agreement was $160 million as of September 30, 2009. As a result, there was no additional
borrowing availability. The weighted average interest rate under the Quest Cherokee Credit
Agreement for the quarter ended September 30, 2009 was 4.36%.
In July 2009, the borrowing base under the Quest Cherokee Credit Agreement was reduced from
$190 million to $160 million, which, following the payment discussed below, resulted in the
outstanding borrowings under the Quest Cherokee Credit Agreement exceeding the new borrowing base
by $14 million. In anticipation of the reduction in the borrowing base, Quest Energy amended or
exited certain of its above market natural gas price derivative contracts and, in return, received
approximately $26 million. The strike prices on the derivative contracts that Quest Energy did not
exit were set to market prices at the time. At the same time, Quest Energy entered into new natural
gas price derivative contracts to increase the total amount of its future estimated proved developed
producing natural gas production hedged to approximately 85% through 2013. On June 30, 2009, using
these proceeds, Quest Energy made a principal payment of $15 million on the Quest Cherokee Credit
Agreement. On July 8, 2009, Quest Energy repaid the $14 million borrowing base deficiency.
We anticipate that in connection with the redetermination of our borrowing base in November
2009, our borrowing base will be further reduced from its current level of $160 million. In the
event of a borrowing base reduction, we expect to be able to make the required payments
resulting from the borrowing base deficiency out of our existing funds.
On June 18, 2009, Quest Energy and Quest Cherokee entered into a Third Amendment to Amended
and Restated Credit Agreement that, among other things, permits Quest Cherokees obligations under
oil and gas derivative contracts with BP Corporation North America, Inc. or any of its affiliates
to be secured by the liens under the Quest Cherokee Credit Agreement on a pari passu basis with the
obligations under the Quest Cherokee Credit Agreement. On June 30, 2009, Quest Energy and Quest
Cherokee entered into a Fourth Amendment to Amended and Restated Credit Agreement that deferred
Quest Energys obligation to deliver certain financial statements.
Quest Cherokee was in compliance with all of its covenants under the Quest Cherokee Credit
Agreement as of September 30, 2009.
B. Second Lien Loan Agreement.
Quest Energy and Quest Cherokee are parties to the
Second Lien Loan Agreement dated as of July 11, 2008, with RBC, KeyBank, Société Générale and the
parties thereto for a $45 million term loan originally due and maturing on September 30, 2009.
Quest Energy made quarterly principal payments of $3.8 million on February 17, 2009, May 15,
2009 and August 17, 2009.
F-8
Table of Contents
As of September 30, 2009 and December 31, 2008, $29.8 million and $41.2 million was
outstanding under the Second Lien Loan Agreement, respectively. The weighted average interest rate
under the Second Lien Loan Agreement for the quarter ended September 30, 2009 was 11.25%.
On June 30, 2009, Quest Energy and Quest Cherokee entered into a Second Amendment to the
Second Lien Loan Agreement that deferred Quest Energys obligation to deliver certain financial
statements to the lenders. On September 30, 2009, Quest Energy and Quest Cherokee entered into a
Third Amendment to the Second Lien Loan Agreement that extended the maturity date of the loan from
September 30, 2009, to October 31, 2009. On October 30, 2009, Quest Energy and Quest Cherokee
entered into a Fourth Amendment to the Second Lien Loan Agreement that extended the
maturity of the loan to November 16, 2009. While we are currently
negotiating further extensions to this loan, there can be no assurance that such negotiations will
be successful or that we will be able to repay amounts due under the Second Lien Loan Agreement in
accordance with the terms of the Second Lien Loan Agreement.
Quest Cherokee was in compliance with all of its covenants under the Second Lien Loan
Agreement as of September 30, 2009.
4. Derivative Financial Instruments
Our objective in entering into derivative financial instruments is to manage exposure to
commodity price and interest rate fluctuations, protect our returns on investments, and achieve a
more predictable cash flow in connection with our acquisition activities and borrowings related to
these activities. These transactions limit exposure to declines in prices or increases in interest
rates, but also limit the benefits we would realize if prices increase or interest rates decrease.
When prices for oil and natural gas or interest rates are volatile, a significant portion of the
effect of our derivative financial instrument management activities consists of non-cash income or
expense due to changes in the fair value of our derivative financial instrument contracts. Cash
charges or gains only arise from payments made or received on monthly settlements of contracts or
if we terminate a contract prior to its expiration. 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.
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.
We account for our derivative financial instruments in accordance with FASB ASC 815
Derivatives and Hedging. FASB ASC 815 requires that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded on the balance sheet as either an
asset or liability measured at its fair value. FASB ASC 815 requires that changes in the
derivatives fair value be recognized currently in earnings unless specific hedge accounting
criteria are met, or exemptions for normal purchases and normal sales (NPNS) as permitted by FASB
ASC 815 exist. We do not designate our derivative financial instruments as hedging instruments for
financial accounting purposes, and, as a result, we recognize the change in the respective
instruments fair value currently in earnings. In accordance with FASB ASC 815, the table below
outlines the classification of our derivative financial instruments on our condensed consolidated
balance sheets and their financial impact in our condensed consolidated statement of operations (in
thousands):
F-9
Table of Contents
Fair Value of Derivative Financial Instruments
September 30, | December 31, | |||||||||||
Derivative Financial Instruments | Balance Sheet location | 2009 | 2008 | |||||||||
Commodity contracts | Current derivative financial instrument asset |
$ | 19,625 | $ | 42,995 | |||||||
Commodity contracts | Long-term derivative financial instrument asset |
4,653 | 30,836 | |||||||||
Commodity contracts | Current derivative financial instrument liability |
(1,413 | ) | (12 | ) | |||||||
Commodity contracts | Long-term derivative financial instrument liability |
(5,294 | ) | (4,230 | ) | |||||||
$ | 17,571 | $ | 69,589 | |||||||||
The Effect of Derivative Financial Instruments
Three Months Ended | Nine Months Ended | |||||||||||||||||||
September 30, | September 30, | |||||||||||||||||||
Derivative Financial Instruments | Statement of Operations location | 2009 | 2008 | 2009 | 2008 | |||||||||||||||
Commodity contracts | Gain (loss) from derivative
financial instruments |
$ | 8,752 | $ | 145,132 | $ | 31,078 | $ | (4,482 | ) | ||||||||||
Settlements in the normal course of maturities of our derivative financial instrument
contracts result in cash receipts from or cash disbursement to our derivative contract
counterparties and are, therefore, realized gains or losses. Changes in the fair value of our
derivative financial instrument contracts are included in income currently with a corresponding
increase or decrease in the balance sheet fair value amounts. Gains and losses associated with
derivative financial instruments related to oil and gas production were as follows for the periods
indicated (in thousands):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Realized gains (losses) |
$ | 19,616 | $ | (7,525 | ) | $ | 83,096 | $ | (17,795 | ) | ||||||
Unrealized gains (losses) |
(10,864 | ) | 152,657 | (52,018 | ) | 13,313 | ||||||||||
Total |
$ | 8,752 | $ | 145,132 | $ | 31,078 | $ | (4,482 | ) | |||||||
In June 2009, we amended or exited certain of our above market natural gas price derivative
contracts for periods beginning in the second quarter of 2010 through the fourth quarter of 2012.
In return, we received approximately $26 million. Concurrent with this, the strike prices on the
derivative contracts that we did not exit were set to market prices at the time and we entered into
new natural gas price derivative contracts to increase the total amount of our future estimated
proved developed producing natural gas production hedged to approximately 85% through 2013.
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The
following table summarizes the estimated volumes, fixed prices and fair values
attributable to oil and gas derivative contracts as of September 30, 2009:
Remainder of | Year Ending December 31, | |||||||||||||||||||||||
2009 | 2010 | 2011 | 2012 | Thereafter | Total | |||||||||||||||||||
($ in thousands, except volumes and per unit data) | ||||||||||||||||||||||||
Natural Gas Swaps: |
||||||||||||||||||||||||
Contract volumes (Mmbtu) |
3,687,360 | 16,129,060 | 13,550,302 | 11,000,004 | 9,000,003 | 53,366,729 | ||||||||||||||||||
Weighted-average fixed
price per Mmbtu |
$ | 7.78 | $ | 6.26 | $ | 6.80 | $ | 7.13 | $ | 7.28 | $ | 6.85 | ||||||||||||
Fair value, net |
$ | 11,939 | $ | 5,020 | $ | 1,048 | $ | 1,676 | $ | 1,178 | $ | 20,861 | ||||||||||||
Natural Gas Collars: |
||||||||||||||||||||||||
Contract volumes (Mmbtu) |
187,500 | | | | | 187,500 | ||||||||||||||||||
Weighted-average fixed
price per Mmbtu: |
||||||||||||||||||||||||
Floor |
$ | 11.00 | $ | | $ | | $ | | $ | | $ | 11.00 | ||||||||||||
Ceiling |
$ | 15.00 | $ | | $ | | $ | | $ | | $ | 15.00 | ||||||||||||
Fair value, net |
$ | 1,154 | $ | | $ | | $ | | $ | | $ | 1,154 | ||||||||||||
Total Natural Gas Contracts: |
||||||||||||||||||||||||
Contract volumes (Mmbtu) |
3,874,860 | 16,129,060 | 13,550,302 | 11,000,004 | 9,000,003 | 53,554,229 | ||||||||||||||||||
Weighted-average fixed
price per Mmbtu |
$ | 7.94 | $ | 6.26 | $ | 6.80 | $ | 7.13 | $ | 7.28 | $ | 6.87 | ||||||||||||
Fair value, net |
$ | 13,093 | $ | 5,020 | $ | 1,048 | $ | 1,676 | $ | 1,178 | $ | 22,015 | ||||||||||||
Basis Swaps: |
||||||||||||||||||||||||
Contract volumes (Bbl) |
| 3,630,000 | 8,549,998 | 9,000,000 | 9,000,003 | 30,180,001 | ||||||||||||||||||
Weighted-average fixed
price per Bbl |
$ | | $ | 0.63 | $ | 0.67 | $ | 0.70 | $ | 0.71 | $ | 0.69 | ||||||||||||
Fair value, net |
$ | | $ | (957 | ) | $ | (1,512 | ) | $ | (1,393 | ) | $ | (1,138 | ) | $ | (5,000 | ) | |||||||
Crude Oil Swaps: |
||||||||||||||||||||||||
Contract volumes (Bbl) |
9,000 | 30,000 | | | | 39,000 | ||||||||||||||||||
Weighted-average fixed
price per Bbl |
$ | 90.07 | $ | 87.50 | $ | | $ | | $ | | $ | 88.09 | ||||||||||||
Fair value, net |
$ | 170 | $ | 386 | $ | | $ | | $ | | $ | 556 | ||||||||||||
Total fair value, net |
$ | 13,263 | $ | 4,449 | $ | (464 | ) | $ | 283 | $ | 40 | $ | 17,571 |
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The
following table summarizes the estimated volumes, fixed prices and fair values
attributable to 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): |
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 | ||||||||||
Total fair value, net |
$ | 42,983 | $ | 16,612 | $ | 5,585 | $ | 4,409 | $ | 69,589 |
5. Fair Value Measurements
Our financial instruments include commodity derivatives, debt, cash, receivables and payables.
The carrying value of our debt approximates fair value due to the variable nature of the interest
rates. The carrying amount of cash, receivables and accounts payable approximates fair value
because of the short-term nature of those instruments.
Effective January 1, 2009, we adopted FASB ASC 820 Fair Value Measurements and Disclosures
which applies 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. 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.
FASB ASC 820 also establishes a hierarchy that prioritizes the inputs used to measure fair
value. The three levels of the fair value hierarchy are as follows:
| Level 1 Quoted prices available in active markets for identical assets or liabilities as of the reporting date. |
| 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. |
| Level 3 Pricing inputs include significant inputs that are generally less observable from objective sources. |
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 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 the dates indicated (in
thousands):
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Table of Contents
Netting and | ||||||||||||||||||||
Level | Level | Level | Cash | Total Net Fair | ||||||||||||||||
September 30, 2009 | 1 | 2 | 3 | Collateral* | Value | |||||||||||||||
Derivative financial instruments assets |
$ | | $ | 5,663 | $ | 18,615 | $ | | $ | 24,278 | ||||||||||
Derivative financial instruments liabilities |
$ | | $ | (133 | ) | $ | (6,574 | ) | $ | | $ | (6,707 | ) | |||||||
Total |
$ | | $ | 5,530 | $ | 12,041 | $ | | $ | 17,571 | ||||||||||
December 31, 2008 | ||||||||||||||||||||
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 us and our counterparties and the payable or receivable for cash collateral held or placed with the same counterparties. |
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 condensed consolidated balance sheets.
In order to determine the fair value of 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):
Nine Months Ended | ||||
September 30, 2009 | ||||
Balance at beginning of period |
$ | 60,947 | ||
Realized and unrealized gains included in earnings |
25,309 | |||
Purchases, sales, issuances, and settlements |
(74,215 | ) | ||
Transfers into and out of Level 3 |
| |||
Balance as of September 30, 2009 |
$ | 12,041 | ||
6. Asset Retirement Obligations
The following table reflects the changes to the Partnerships asset retirement liability for
the nine months ended September 30, 2009 (in thousands):
Nine months ended | ||||
September 30, 2009 | ||||
Asset retirement obligations at beginning of period |
$ | 4,592 | ||
Liabilities incurred |
| |||
Liabilities settled |
| |||
Accretion |
351 | |||
Revisions in estimated cash flows |
| |||
Asset retirement obligations at end of period |
$ | 4,943 | ||
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Table of Contents
7. Equity Compensation Plans
We have an equity compensation plan for our employees, consultants and non-employee directors
pursuant to which unit awards may be granted. During 2008, 30,000 bonus common units were awarded
under our long-term incentive plan, of which, 15,000 vested in 2008 and the remaining 15,000 vests
ratably over two years. As of September 30, 2009, there were approximately 2.1 million units
available for future awards. Unit-based compensation expense was less than $0.1 million for the
three and nine months ended September 30, 2009 and 2008.
8. Net Income Per Limited Partner Unit
Subject to applicability of FASB ASC 260 Earnings Per Share, Partnership income is allocated
98% to the limited partners, including the holders of subordinated units, and 2% to the general
partner. Income allocable to the limited partners is first allocated to the common unitholders up
to the quarterly minimum distribution of $0.40 per unit, with remaining income allocated to the
subordinated unitholders up to the minimum distribution amount. Basic and diluted net income per
common and subordinated partner unit is determined by dividing net income attributable to common
and subordinated partners by the weighted average number of outstanding common and subordinated
partner units during the period.
FASB ASC 260 addresses the computation of earnings per share by entities that have issued
securities other than common stock that contractually entitle the holder to participate in
dividends and earnings of the entity when, and if, it declares dividends on its common stock (or
partnership distributions to unitholders). Under FASB ASC 260, in accounting periods where the
Partnerships aggregate net income exceeds aggregate dividends declared in the period, the
Partnership is required to present earnings per unit as if all of the earnings for the periods were
distributed.
Earnings per limited partner unit are presented for the three and nine month periods ended
September 30, 2009. The following table sets forth the computation of basic and diluted net loss
per limited partner unit (in thousands, except unit and per unit data):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Net income (loss) |
$ | (10,483 | ) | $ | 157,398 | $ | (111,483 | ) | $ | 23,557 | ||||||
Less: General Partner 2.0% ownership |
(210 | ) | (3,159 | ) | (2,230 | ) | (471 | ) | ||||||||
Net income (loss) available to limited partners |
$ | (10,273 | ) | $ | 154,779 | $ | (109,253 | ) | $ | (23,086 | ) | |||||
Basic and diluted weighted average number of
units: |
||||||||||||||||
Common units |
12,316,521 | 12,309,021 | 12,316,521 | 12,308,282 | ||||||||||||
Subordinated units |
8,857,981 | 8,857,981 | 8,857,981 | 8,857,981 | ||||||||||||
Unvested unit-based awards participating |
| 22,500 | | 20,283 | ||||||||||||
Basic and diluted weighted average number of
units |
21,174,502 | 21,189,502 | 21,174,502 | 21,186,546 | ||||||||||||
Basic and diluted net income (loss) per
limited partner unit: |
$ | (0.49 | ) | $ | 7.30 | $ | (5.16 | ) | $ | 1.09 | ||||||
Effective January 1, 2009, the Partnership adopted the provisions of FASB ASC 260 requiring
participating securities to be included in the allocation of earnings when calculating EPU under
the two-class method. All prior period EPU data presented above has been retrospectively adjusted
to conform to the new requirements of this Staff Position. During periods of losses, basic EPU will
not be impacted by the two-class method, as the Partnerships participating securities are not
obligated to share in the losses of the Partnership and thus, are not included in the EPU share
computation.
The Partnership also adopted the provisions of FASB ASC 260 on January 1, 2009, relating to
the comparability of EPU calculations for master limited partnerships with IDRs. Through September
30, 2009, the Partnership has not met any targeted distributions and thus, the provisions on IDRs
has had no impact to the Partnerships EPU calculation.
Because
we reported a net loss for the three and nine months ended September 30, 2009, participating
securities covering 15,000 common shares were excluded from the computation of net loss per share
because their effect would have been antidilutive.
F-14
Table of Contents
9. Impairment of Oil and Gas Properties
At the end of each quarterly period, the unamortized cost of oil and natural gas properties,
net of related deferred income taxes, is limited to the full cost ceiling, computed as the sum of
the estimated future net revenues from our proved reserves using current period-end prices
discounted at 10%, and adjusted for related income tax effects (ceiling test). In the event our
capitalized costs exceed the ceiling limitation at the end of the reporting date, we subsequently
evaluate the limitation based on price changes that occur after the balance sheet date to assess
impairment as currently permitted by Staff Accounting Bulletin Topic 12Oil and Gas Producing
Activities. Under full cost accounting rules, any ceiling test write-downs of oil and natural gas
properties may not be reversed in subsequent periods. Since we do not designate our derivative
financial instruments as hedges, we are not allowed to use the impacts of the derivative financial
instruments in our ceiling test computation. As a result, decreases in commodity prices which
contribute to ceiling test write-downs may be offset by mark-to-market gains which are not
reflected in our ceiling test results.
Under the present full cost accounting rules, we are required to compute the after-tax present
value of our proved oil and natural gas properties using spot market prices for oil and natural gas
at our balance sheet date. The base for our spot prices for natural gas is Henry Hub and for oil is
Cushing, Oklahoma. The Partnership had previously recognized a ceiling test impairment of $95.2 million
during the first quarter of 2009 while no impairment was necessary for the second quarter of 2009.
As of September 30, 2009, the ceiling test computation utilizing spot prices on that day resulted
in the carrying costs of our unamortized proved oil and natural gas properties, net of deferred
taxes, exceeding the September 30, 2009 present value of future net revenues by approximately $6.9
million. As a result of subsequent increases in spot prices, the need to recognize an impairment
for the quarter ended September 30, 2009, was eliminated. Natural gas, which is sold at other natural
gas marketing hubs where we conduct operations, is subject to prices which reflect variables that
can increase or decrease spot natural gas prices at these hubs such as market demand,
transportation costs and quality of the natural gas being sold. Those differences are referred to
as the basis differentials. Typically, basis differentials result in natural gas prices which are
lower than Henry Hub, except in Appalachia, where we have typically received a premium to Henry
Hub. We may face further ceiling test write-downs in future periods, depending on the level of
commodity prices, drilling results and well performance.
The calculation of the ceiling test is based upon estimates of proved reserves. There are
numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the
future rates of production and in the timing of development activities. The accuracy of any reserve
estimate is a function of the quality of available data and of engineering and geological
interpretation and judgment. Results of drilling, testing, production and changes in economics
related to the properties subsequent to the date of the estimate may justify revision of such
estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural
gas that are ultimately recovered.
10. 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. Below is a brief description of any material legal proceedings
that were initiated against us since December 31, 2008 and any material developments in existing
material legal proceedings that have occurred since December 31, 2008. For additional information
regarding our legal proceedings, please see Note 11 to our consolidated financial statements
included in our 2008 Form 10-K/A and Note 10 to our consolidated financial statements included in
our Forms 10-Q for the three months ended March 31, 2009 and June 30, 2009.
Federal
Individual Securities Litigation
J. Steven Emerson, Emerson Partners, J. Steven Emerson Roth IRA, J. Steven Emerson IRA RO II,
and Emerson Family Foundation v. Quest Resource Corporation, Inc., Quest Energy Partners L.P.,
Jerry Cash, David E. Grose, and John Garrison, Case No. 5:09-cv-1226-M, U.S. District Court for the
Western District of Oklahoma, filed November 3, 2009
On November 3, 2009 a complaint was filed in the United States District Court for the Western
District of Oklahoma naming QRCP, QELP, and certain current and former officers and directors as
defendants. The complaint was filed by individual shareholders of QRCP stock and individual
purchasers of QELP common units. The complaint asserts claims under Sections 10(b) and 20(a) of
the Securities Exchange Act of 1934. The complaint alleges that the defendants violated the
federal securities laws by issuing false and misleading statements and/or concealing material
information concerning unauthorized transfers from subsidiaries of QRCP to entities controlled by
QRCPs former chief executive officer, Mr. Jerry D. Cash. The complaint also alleges that QRCP and
QELP issued false and misleading statements and or/concealed material information concerning a
misappropriation by its former chief financial officer, Mr. David E. Grose, of $1 million in
company funds and receipt of unauthorized kickbacks of approximately $850,000 from a company
vendor. The complaint also alleges that, as a result of these actions, the price of QRCP stock and
QELP common units was artificially inflated when the plaintiff purchased QRCP stock and QELP common
units. The plaintiffs seek $10 million in damages. QRCP and QELP intend to defend vigorously
against the plaintiffs claims.
Federal Derivative Case
William Dean Enders, derivatively on behalf of nominal defendant Quest Energy Partners, L.P.
v. Jerry D. Cash, David E. Grose, David C. Lawler, Gary Pittman, Mark Stansberry, J. Philip
McCormick, Douglas Brent Mueller, Mid Continent Pipe & Equipment, LLC, Reliable Pipe & Equipment,
LLC, RHB Global, LLC, RHB, Inc., Rodger H. Brooks, Murrell, Hall, McIntosh & Co. PLLP, and Eide
Bailly LLP, Case No. CIV-09-752-F, U.S. District Court for the Western District of Oklahoma, filed
July 17, 2009
On July 17, 2009, a complaint was filed in the United States District Court for the Western
District of Oklahoma, purportedly on Quest Energys behalf, which names certain of its current and
former officers and directors, external auditors and vendors. The factual allegations relate to,
among other things, the transfers and lack of effective internal controls. The complaint asserts
claims for breach of fiduciary duty, waste of corporate assets, unjust enrichment, conversion,
disgorgement under the Sarbanes-Oxley Act of 2002, and
aiding and abetting breaches of fiduciary duties against the individual defendants and vendors
and professional negligence and breach
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of contract against the external auditors. The complaint
seeks monetary damages, disgorgement, costs and expenses and equitable and/or injunctive relief. It
also seeks Quest Energy to take all necessary actions to reform and improve its corporate
governance and internal procedures. On September 8, 2009, the case was transferred to Judge
Miles-LaGrange who is presiding over the other federal cases discussed below, and the case number was changed to
CIV-09-752-M. All proceedings in this matter are currently stayed under Judge
Miles-Lagranges order of October 16, 2009.
Personal Injury Litigation
St. Paul Surplus Lines Insurance Company v. Quest Cherokee Oilfield Service, LLC, et al.,
CJ-2009-1078, District Court of Tulsa County, State of Oklahoma, filed February 11, 2009
Quest Cherokee Oilfield Service, LLC (QCOS) has been named as a defendant in this
declaratory action. This action arises out of the Trigoso matter discussed below. 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.
Jacob Dodd v. Arvilla Oilfield Services, LLC, et al., Case No. 08-C-47, Circuit Court of
Ritchie County, State of West Virginia, filed May 8, 2008
Quest Eastern, et al. has been named in this personal injury lawsuit arising out of an
automobile collision and was served on May 12, 2009. Limited discovery has taken place. Quest
Eastern intends to vigorously defend against this claim.
Litigation Related to Oil and Gas Leases
Edward E. Birk, et ux., and Brian L. Birk, et ux., v. Quest Cherokee, LLC, Case No. 09-CV-27,
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. Plaintiffs claim that they are entitled to an overriding royalty
interest (1/16th in some leases, and 1/32nd 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 Cherokee has filed an answer defending its position. Quest Cherokee intends to defend vigorously
against these claims.
Robert C. Aker, et al. v. Quest Cherokee, LLC, et al., Case No. 3-09CV101, U.S. District Court
for the Western District of Pennsylvania, 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 filed a motion to dismiss for lack of
jurisdiction, 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.
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
QRCP, et al. have been named in the above-referenced lawsuit. The lawsuit was served on May
22, 2009. Defendants have filed a motion to dismiss certain claims, 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.
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Kim E. Kuhn, Scott Tomlinson, Todd Tomlinson, Charles Willier, Brian Sefcik v. Quest Cherokee,
LLC, Case No. 2009 CV 43, District Court of Wilson County, State of Kansas, filed July 27, 2009
Quest Cherokee has been named as a defendant by the landowners identified above for allegedly
refusing to execute a Surface and Use Agreement. Plaintiffs seek monetary damages for breach of
contract, damages to their property caused by Quest Cherokee, to terminate Quest Cherokees access
to the property, and attorneys fees. Quest Cherokee denies plaintiffs allegations and will
vigorously defend against the plaintiffs claims.
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
QRCP,
et al. have been named in the above-referenced lawsuit. Plaintiffs
are royalty owners who allege underpayment of royalties owed to them.
Plaintiffs also allege, among other things, that defendants engaged
in self-dealing and breached fiduciary duties owed to plaintiffs, and
that defendants acted fraudulently toward the plaintiffs. Plaintiffs
also allege that the gathering fees and related charges should not
have been deducted in paying royalties. QRCP intends to defend this
action vigorously.
Below is a brief description of any material developments that have occurred in our ongoing
material legal proceedings since December 31, 2008. Additional information with respect to our
material legal proceedings can be found in our 2008 Form 10-K/A.
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 naming QRCP, QELP and Quest Energy GP, LLC (Quest Energy GP) and
certain of their current and former officers and directors as defendants. The complaints were filed
by certain stockholders on behalf of themselves and other stockholders who purchased QRCP common
stock between May 2, 2005 and August 25, 2008 and QELP 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 QRCP to entities controlled by QRCPs former
chief executive officer, Mr. Jerry D. Cash. The complaints also allege that, as a result of these
actions, QRCPs stock price and the unit price of QELP 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. On September 24, 2009, the court appointed lead plaintiffs for
each of the QRCP class and the QELP class. The lead plaintiffs must file a consolidated amended
complaint within 60 days after being appointed. No further activity is expected in the purported
class action until an amended consolidated complaint is filed. On October 13, 2009, the lead
plaintiffs filed a motion for partial modification of the automatic discovery stay provided by the
Private Securities Litigation Reform Act of 1995. QRCP, QELP and Quest Energy GP intend to defend
vigorously against plaintiffs claims.
QRCP and QELP have received letters from their directors and officers insurance carriers
reserving their rights to limit or preclude coverage under various provisions and exclusions in the
policies, including for the committing of a deliberate criminal or fraudulent act by a past,
present, or future chief executive officer or chief financial officer. QELP recently received a
letter from its directors and officers liability insurance carrier that it will not provide
insurance coverage based on Mr. Cashs alleged written admission that he engaged in acts for which
coverage is excluded. QELP is reviewing the letter and evaluating its options.
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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 answered the complaint and denied plaintiffs claims. On July
21, 2009, the court granted plaintiffs motion to compel production of Quest Cherokees
electronically stored information, or ESI, and directed the parties to decide upon a timeframe for
producing Quest Cherokees ESI. Discovery has been stayed until December 5, 2009 to allow the
parties to discuss settlement terms. Quest Cherokee has received an
initial settlement offer from plaintiffs counsel and is in the
process of evaluating the offer and its response to the same.
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
QCOS was 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 Winter 2010. QCOS intends to defend vigorously against plaintiffs claims.
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.
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 were originally filed 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 November 4, 2009, the total
amount of acreage covered by the leases at issue in these lawsuits was approximately 5,100 acres.
Quest Cherokee intends to vigorously defend against those claims. Following is a list of those
cases:
Housel v. Quest Cherokee, LLC, Case No. 06-CV-26-I, District Court of Montgomery County,
State of Kansas, filed March 2, 2006
Roger Dean Daniels v. Quest Cherokee, LLC, Case No. 06-CV-61, District Court of Montgomery
County, State of Kansas, filed May 5, 2006 (currently on appeal with the Kansas Court of Appeals,
Case No. 08-100576-A; oral argument scheduled for November 18, 2009)
Carol R. Knisely, et al. v. Quest Cherokee, LLC, Case No. 07-CV-58-I, District Court of
Montgomery County, State of Kansas, filed April 16, 2007
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Scott Tomlinson, et al. v. Quest Cherokee, LLC, Case No. 2007-CV-45, District Court of
Wilson County, State of Kansas, filed August 29, 2007 (trial set for December 2009)
Ilene T. Bussman et al. v. Quest Cherokee, LLC, Case No. 07-CV-106-PA, 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, 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, District Court of
Wilson County, State of Kansas, filed September 18, 2008 (settled and dismissed in August 2009)
Richard Winder v. Quest Cherokee, LLC, Case Nos. 07-CV-141 and 08-CV-20, District Court of
Neosho County, State of Kansas, filed December 7, 2007, and February 27, 2008
Quest Cherokee v. Hinkle, et. al. & Admiral Bay, Case No. 2006-CV-74, District Court of
Labette County, State of Kansas, filed September 15, 2006 (trial set for February 2010)
Central Natural Resources, Inc. v. Quest Cherokee, LLC, et al., Case No. 04-C-100-PA,
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
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 issued
an opinion affirming the District Courts decision and remanded the case to the District Court for
further proceedings consistent with that decision. Central Natural Resources filed a motion seeking
to dismiss all of its remaining claims, without prejudice, and a journal entry of dismissal has
been approved by the District Court.
Central Natural Resources, Inc. v. Quest Cherokee, LLC, et al., Case No. CJ-06-07, 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 alleged that it is entitled to the coal bed methane gas produced and
revenues from these leases and that Quest Cherokee is a trespasser. Plaintiff sought 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 contended it has valid leases from the owners of the
coal bed methane gas rights. The issue was
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whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of
the gas rights. All claims have been dismissed by agreement of all of the parties and a journal
entry of dismissal has been approved by the District Court.
Other
Well Refined Drilling Co. v. Quest Cherokee, LLC, Case No. 2007-CV-91, 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, District Court of Wilson County, State of Kansas, filed
September 4, 2007
Quest Cherokee was 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 contended that Quest Cherokee
owed certain sums for services provided by the plaintiff in connection with drilling wells for
Quest Cherokee. Plaintiff had also filed mechanics liens against the oil and gas leases on which
those wells are located and also sought foreclosure of those liens. Quest Cherokee had answered
those petitions and had denied plaintiffs claims. The claims in these lawsuits have been settled
and dismissed by agreement of all of the parties.
Barbara Cox v. Quest Cherokee, LLC, Case No. CIV-08-0546, U.S. District Court for the District
of New Mexico, filed April 18, 2008
Quest Cherokee was 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
alleged 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. The parties have settled this
case and dismissal is expected before the end of November 2009
Environmental Matters
As of September 30, 2009, 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.
Financial Advisor Contract
In January 2009, Quest Energy GP engaged a financial advisor to us in connection with the
review of our strategic alternatives. Under the terms of the agreement, the financial advisor
received a one-time advisory fee of $50,000 in January 2009 and was 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 was entitled to inestimable fees if
certain transactions occur. On July 1, 2009, Quest Energy GP entered into an amendment to its
original financial advisor agreement, which provided that the monthly advisory fee increased to
$200,000 per month with a total of $800,000, representing the aggregate fees for each of April,
May, June and July 2009, which amount was paid upon execution of the amendment. The additional
financial advisor fees payable if certain transactions occurred were canceled; however, the
financial advisor was still entitled to a fairness opinion fee of $650,000 in connection with any
merger, sale or acquisition involving Quest Energy GP or Quest Energy, which amount was paid in
connection with the delivery of a fairness opinion at the time of the execution of the Merger
Agreement.
11. Related Party Transactions
Settlement Agreements
As discussed in our 2008 Form 10-K/A, we and QRCP filed lawsuits, related to the Transfers,
seeking, among other things, to recover the funds that were transferred. On May 19, 2009, we, QRCP,
and Quest Midstream entered into settlement agreements with Mr. Cash, the controlled-entity and the
other owners to settle this litigation. Under the terms of the settlement, and based on a
settlement allocation agreed to by our board of directors and the board of directors of QRCP, 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
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located in Texas and we received Mr. Cashs interest in STP Newco, Inc (STP) which consisted
of 100% of the common stock of the company.
While QRCP estimated the value of these assets to be less than the amount of the unauthorized
transfers and cost of the internal investigation, Mr. Cash represented that they comprised
substantially all of Mr. Cashs net worth and the majority of the value of the controlled-entity.
We and QRCP 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.
STP owns interests in certain oil producing properties in Oklahoma, and other assets and
liabilities. STPs accounting and operation records provided to us, at the date of the settlement,
were in poor condition and we are in the process of reconstructing the financial records in order
to determine the estimated fair value of the assets acquired and liabilities assumed in connection
with the settlement. Based on documents QRCP received prior to the settlement, the estimated fair
value of the net assets to be assumed was expected to provide us reimbursement for all of the costs
of the internal investigation and the costs of the litigation against Mr. Cash that have been paid
by us; however, the financial information we received prior to closing contained errors related to
Mr. Cashs ownership interests in the properties as well as amounts due vendors and royalty owners.
Based on work performed to date, we and QRCP, believe that the actual estimated fair value of net
assets of STP that we received is less than previously expected. We and QRCP expect to complete our
analysis of STPs financial information and our final valuation of the oil producing properties
obtained from STP by December 31, 2009. We and QRCP also are in the process of determining what
further actions can be taken with regards to this matter and intend to pursue all remedies
available under the law.
Based on the information available at this time, we have estimated the fair value of the
assets and liabilities obtained in connection with the settlement. As additional information
becomes available other assets and/or liabilities may be identified and recorded. The estimated
fair value of the assets and liabilities received is as follows (in thousands):
Oil & gas properties |
$ | 1,076 | ||
Current liabilities |
(326 | ) | ||
Long-term debt |
(719 | ) | ||
Net assets received |
$ | 31 | ||
Merger Agreement and Support Agreement
As discussed in Note 1 Basis of Presentation, on July 2, 2009, we entered into
the Merger Agreement with QRCP, Quest Midstream, and other parties thereto pursuant to which,
following a series of mergers and an entity conversion, QRCP, Quest Energy and the successor to
Quest Midstream will become wholly-owned subsidiaries of PostRock. On October 2, 2009, the Merger
Agreement was amended to, among other things, reflect certain technical changes as the result of an
internal restructuring. Additionally, since shortly before execution of the Merger Agreement one of
the Quest Midstream investors had abandoned its Quest Midstream common units, which were
inadvertently included in calculating the Quest Midstream exchange ratio contained in the Merger
Agreement, the amendment also permitted Quest Midstream to make a distribution of additional common
units to its common unitholders in order to increase the number of outstanding common units to
match, as closely as practicable, the number set forth in the Merger Agreement. The effect of the
distribution was to preserve the relative ownership percentages of PostRock agreed to by the
parties without the need to amend the Quest Midstream exchange ratio.
Additionally, in connection with the Merger Agreement, on July 2, 2009, we entered into a
Support Agreement with QRCP, Quest Midstream and certain Quest Midstream unitholders (the Support
Agreement), which was amended on October 2, 2009 to, among other things, add an additional Quest
Midstream common unitholder as a party. Pursuant to the Support Agreement, as amended, QRCP has,
subject to certain conditions, agreed to vote the common and subordinated units of Quest Energy and
Quest Midstream that it owns in favor of the Recombination and the holders of approximately 73% of
the common units of Quest Midstream have, subject to certain conditions, agreed to vote their
common units in favor of the Recombination.
12. Subsequent Events
We
evaluated our activity after September 30, 2009 until the date of issuance, November 5,
2009, for recognized and unrecognized subsequent events not discussed elsewhere in these footnotes
and determined there were none.
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ITEM 2. | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. |
Forward-looking statements
This quarterly report contains forward-looking statements that do not directly or exclusively
relate to historical facts. You can typically identify forward-looking statements by the use of
forward-looking words, such as may, will, could, project, believe, intend,
anticipate, expect, estimate, continue, potential, plan, forecast and other words of
similar import. Forward-looking statements include information concerning possible or assumed
future results of our operations, including statements about the Recombination, projected financial
information, valuation information, possible outcomes from strategic alternatives other than the
Recombination, the expected amounts, timing and availability of financing, availability under
credit facilities, levels of capital expenditures, sources of funds, and funding requirements,
among others.
These forward-looking statements represent our intentions, plans, expectations, assumptions
and beliefs about future events and are subject to risks, uncertainties and other factors. Many of
those factors are outside of our control and could cause actual results to differ materially from
the results expressed or implied by those forward-looking statements. Those factors include, among
others, the risk factors described in Part II, Item IA. Risk Factors, as well as the risk factors
described in Item 1A. Risk Factors in our 2008 Form 10-K/A.
In light of these risks, uncertainties and assumptions, the events described in the
forward-looking statements might not occur or might occur to a different extent or at a different
time than as described. You should consider the areas of risk and uncertainty described above and
discussed in Part II, Item IA. Risk Factors, as well as the risk factors described in Item 1A.
Risk Factors in our 2008 Form 10-K/A in connection with any written or oral forward-looking
statements that may be made after the date of this report by us. Except as may be required by law,
we undertake no obligation to publicly update or revise any forward-looking statements, whether as
a result of new information, future events or otherwise.
Overview of QELP
We are a publicly traded master limited partnership formed in 2007 by Quest Resource
Corporation (QRCP) to acquire, exploit and develop oil and natural gas properties. Our principal
oil and gas production operations are located in the Cherokee Basin of southeastern Kansas and
northeastern Oklahoma; Seminole County, Oklahoma; and West Virginia and New York in the Appalachian
Basin.
Operating Highlights
Our significant operational highlights include:
| We reduced production costs in the current quarter by $0.13 per Mcfe from the prior year quarter. | ||
| We sustained natural gas production levels similar to the prior year despite minimal current period capital expenditures on acquisition and development. |
Financial Highlights
Our significant financial highlights include:
| We reduced total debt by $41.1 million since December 31, 2008. |
| We increased cash and cash equivalents by $14.3 million since December 31, 2008. |
| We repriced our derivatives during the second quarter of 2009 and received $26 million as a result. |
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Recent Developments
Global Financial Crisis and Impact on Capital Markets and Commodity Prices
Currently, there is unprecedented uncertainty in the financial markets. This uncertainty
presents additional potential risks to us and our subsidiaries and affiliates. These risks include
the availability and costs associated with our borrowing capabilities and raising additional debt
and equity capital.
Additionally, the current global economic outlook coupled with exceptional unconventional
resource development success in the U.S. has resulted in a significant decline in natural gas
prices across the United States. Gas price declines impact us in two different ways. First, the
basis differential from NYMEX pricing to sales point pricing for our Cherokee Basin gas production
has narrowed significantly. Our Cherokee Basin basis differential
averaged $0.49 per Mmbtu in the
third quarter of 2009 and was $0.23 per Mmbtu in October 2009 which is down from an average of
$1.79 per Mmbtu in the third quarter of 2008 and $3.38 per Mmbtu in October 2008. The second
impact has been the absolute value erosion of natural gas prices. Our operations and financial
condition are significantly impacted by absolute natural gas prices. On September 30, 2009, the
spot market price for natural gas at Henry Hub was $3.30 per Mmbtu, a 53.7% decrease from September
30, 2008.
For oil, worldwide demand has decreased by over 5% from 2007 levels creating an oversupply
environment similar to natural gas. The recent recovery of oil prices into the $70 per barrel range
has had a small positive impact on revenues during the second half of 2009. Our management believes
that managing price volatility will continue to be a challenge. The spot market price for oil at
Cushing, Oklahoma at September 30, 2009 was $70.46 per barrel, a 30.0% decrease from the price at
September 30, 2008. It is impossible to predict the duration or outcome of these price declines or
the long-term impact on drilling and operating costs and the impacts, whether favorable or
unfavorable, to our results of operations, liquidity and capital resources. 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.
Suspension of Distributions
We suspended distributions on our subordinated units starting with the third quarter of 2008
and on all units starting with the fourth quarter of 2008. Distributions on all of our units
continue to be suspended. We do not expect to have any available cash to pay distributions in 2009
and we are unable to estimate at this time when such distributions may, if ever, be resumed. The
terms of our credit agreements restrict our ability to pay distributions, among other things. Even
if the restrictions on the payment of distributions under our credit agreements are removed, we may
continue to not pay distributions in order to conserve cash for the repayment of indebtedness or
other business purposes.
Even if we do not pay distributions, our unitholders may be liable for taxes on their share of
our taxable income.
Settlement Agreements
As discussed in our 2008 Form 10-K/A, we and QRCP filed lawsuits, related to certain
unauthorized transfers, repayments and re-transfers of funds (the Transfers) to entities
controlled by Jerry D. Cash, our former chief executive office, seeking, among other things, to
recover the funds that were transferred. On May 19, 2009, we, QRCP, and Quest Midstream Partners,
L.P. (Quest Midstream) entered into settlement agreements with Mr. Cash, the controlled-entity
and the other owners to settle this litigation. Under the terms of the settlement, and based on a
settlement allocation agreed to by our board of directors and the board of directors of QRCP, 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 and we
received Mr. Cashs interest in STP Newco, Inc (STP) which consisted of 100% of the common stock
of the company.
While QRCP estimated the value of these assets to be less than the amount of the unauthorized
transfers and cost of the internal investigation, Mr. Cash represented that they comprised
substantially all of Mr. Cashs net worth and the majority of the value of the controlled-entity.
We and QRCP 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.
STP owns interests in certain oil producing properties in Oklahoma, and other assets and
liabilities. STPs accounting and operation records provided to us, at the date of the settlement,
were in poor condition and we are in the process of reconstructing the financial records in order
to determine the estimated fair value of the assets acquired and liabilities assumed in connection
with the
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settlement. Based on documents QRCP received prior to the settlement, the estimated fair value
of the net assets to be assumed was expected to provide us reimbursement for all of the costs of
the internal investigation and the costs of the litigation against Mr. Cash that have been paid by
us; however, the financial information we received prior to closing contained errors related to Mr.
Cashs ownership interests in the properties as well as amounts due vendors and royalty owners.
Based on work performed to date, we and QRCP, believe that the actual estimated fair value of net
assets of STP that we received is less than previously expected. We and QRCP expect to complete our
analysis of STPs financial information and our final valuation of the oil producing properties
obtained from STP by December 31, 2009. We and QRCP also are in the process of determining what
further actions can be taken with regards to this matter and intend to pursue all remedies
available under the law.
Based on the information available at this time, we have valued the known assets and
liabilities. As additional information becomes available other assets and/or liabilities may be
identified and recorded. The fair value of the assets and liabilities we received is as follows (in
thousands):
Oil & gas properties |
$ | 1,076 | ||
Current liabilities |
(326 | ) | ||
Long-term debt |
(719 | ) | ||
Net assets received |
$ | 31 | ||
Recombination
On July 2, 2009, we entered into an Agreement and Plan of Merger (the Merger Agreement) with
QRCP, Quest Midstream, and other parties thereto pursuant to which, following a series of mergers
and an entity conversion, QRCP, QELP and the successor to Quest Midstream will become wholly-owned
subsidiaries of PostRock Energy Corporation (PostRock), a new, publicly-traded corporation (the
Recombination). On October 2, 2009, the Merger Agreement was amended to, among other things,
reflect certain technical changes as a result of an internal restructuring. On October 6, 2009,
PostRock filed with the SEC a registration statement on Form S-4, which included a joint proxy
statement/prospectus, relating to the Recombination.
While we are working toward the completion of the Recombination before the end of 2009; it
remains subject to the satisfaction of a number of conditions, including, among others, the
arrangement of one or more satisfactory credit facilities for PostRock and its subsidiaries, the
approval of the transaction by our unitholders, the unitholders of Quest Midstream and the
stockholders of QRCP, and consents from each entitys existing lenders. There can be no assurance
that these conditions will be met or that the Recombination will occur.
Upon completion of the Recombination, the equity of PostRock would be owned approximately 44%
by current Quest Midstream common unitholders, approximately 33% by our current common unitholders
(other than QRCP), and approximately 23% by current QRCP stockholders.
Additionally, in connection with the Merger Agreement, on July 2, 2009, we entered into a
Support Agreement with QRCP, Quest Midstream and certain Quest Midstream unitholders (the Support
Agreement), which was amended on October 2, 2009 to, among other things, add an additional Quest
Midstream common unitholder as a party. Pursuant to the Support Agreement, as amended, QRCP has,
subject to certain conditions, agreed to vote the common and subordinated units of us and Quest
Midstream that it owns in favor of the Recombination and the holders of approximately 73% of the
common units of Quest Midstream have, subject to certain conditions, agreed to vote their common
units in favor of the Recombination.
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Results of Operations
The following discussion of financial condition and results of operations should be read in
conjunction with the condensed consolidated financial statements and the related notes, which are
included elsewhere in this report.
Three Months Ended September 30, 2009 Compared to the Three Months Ended September 30, 2008
Overview. Operating data for the periods indicated are as follows (in thousands):
Three Months Ended | ||||||||||||||||
September 30, | Increase/ | |||||||||||||||
2009 | 2008 | (Decrease) | ||||||||||||||
Oil and gas sales |
$ | 18,151 | $ | 49,454 | $ | (31,303 | ) | (63.3 | )% | |||||||
Oil and gas production costs |
$ | 8,458 | $ | 9,821 | $ | (1,363 | ) | (13.9 | )% | |||||||
Transportation expense |
$ | 10,879 | $ | 8,583 | $ | 2,296 | 26.8 | % | ||||||||
Depreciation, depletion and amortization |
$ | 9,076 | $ | 13,196 | $ | (4,120 | ) | (31.2 | )% | |||||||
General and administrative expenses |
$ | 5,570 | $ | 734 | $ | 4,836 | 658.9 | % | ||||||||
Gain from derivative financial instruments |
$ | 8,752 | $ | 145,132 | $ | (136,380 | ) | (94.0 | )% | |||||||
Interest expense, net |
$ | 3,370 | $ | 4,354 | $ | (984 | ) | (22.6 | )% |
Production. Oil and gas production data for the periods indicated are as follows:
Three Months Ended | ||||||||||||||||
September 30, | Increase/ | |||||||||||||||
2009 | 2008 | (Decrease) | ||||||||||||||
Production Data: |
||||||||||||||||
Natural gas production (Mmcf) |
5,317 | 5,694 | (377 | ) | (6.6 | )% | ||||||||||
Oil production (Mbbl) |
20 | 19 | 1 | 5.3 | % | |||||||||||
Total production (Mmcfe) |
5,437 | 5,808 | (371 | ) | (6.4 | )% | ||||||||||
Average daily production (Mmcfe/d) |
59.1 | 63.1 | (4.0 | ) | (6.3 | )% | ||||||||||
Average Sales Price per Unit: |
||||||||||||||||
Natural gas (Mcf) |
$ | 3.18 | $ | 8.30 | $ | (5.12 | ) | (61.7 | )% | |||||||
Oil (Bbl) |
$ | 64.21 | $ | 116.89 | $ | (52.68 | ) | (45.1 | )% | |||||||
Natural gas equivalent (Mcfe) |
$ | 3.34 | $ | 8.51 | $ | (5.17 | ) | (60.8 | )% | |||||||
Average Unit Costs per Mcfe: |
||||||||||||||||
Production costs |
$ | 1.56 | $ | 1.69 | $ | (0.13 | ) | (7.7 | )% | |||||||
Transportation expense |
$ | 2.00 | $ | 1.48 | $ | 0.52 | 35.1 | % | ||||||||
Depreciation, depletion and amortization |
$ | 1.67 | $ | 2.27 | $ | (0.60 | ) | (26.4 | )% |
Oil and Gas Sales. Oil and gas sales decreased $31.3 million, or 63.3%, to $18.2 million for
the three months ended September 30, 2009, from $49.5 million for the three months ended September
30, 2008. This decrease was the result of a decrease in average realized prices and a small
decrease in volumes. The decrease in the average realized price accounted for $30.1 million of the
decrease. Our average product prices, which exclude hedge settlements, on an equivalent basis
(Mcfe) decreased to $3.34 per Mcfe for the three months ended September 30, 2009 from $8.51 per
Mcfe for the three months ended September 30, 2008. A decline in volumes of 371 Mmcfe for the
quarter further reduced oil and gas sales by $1.2 million for the three months ended September 30,
2009, compared to the three months ended September 30, 2008.
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 $0.9 million, or 5.1%, to $19.3
million for the three months ended September 30, 2009, from $18.4 million for the three months
ended September 30, 2008.
Oil and gas production costs decreased $1.4 million, or 13.9%, to $8.4 million for the three
months ended September 30, 2009, from $9.8 million for the three months ended September 30, 2008.
This decrease was primarily due to cost-cutting measures that began in the third quarter of 2008
continuing into the current year, including a reduction in field
headcount by approximately half while
simultaneously reducing overtime hours for the three months ended September 30, 2009 compared
to the three months ended
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September 30, 2008. In addition, well service improvement measures
resulted in fewer wells going offline, reduced loss of production due to offline wells, and fewer
well repairs in the current period. Production costs including gross production taxes and ad
valorem taxes were $1.56 per Mcfe for the three months ended September 30, 2009 as compared to
$1.69 per Mcfe for the three months ended September 30, 2008. The decrease in per unit cost was due
to the cost-cutting and well service improvement measures discussed above.
Transportation expense increased $2.3 million, or 26.8%, to $10.9 million for the three months
ended September 30, 2009, from $8.6 million for the three months ended September 30, 2008. The
increase was primarily due to an increase in the contracted transportation rate. Transportation
expense was $2.00 per Mcfe for the three months ended September 30, 2009 as compared to $1.48 per
Mcfe for the three months ended September 30, 2008.
Depreciation, Depletion and Amortization. We are subject to variances in our depletion rates
from period to period due to changes in our proved 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 decreased approximately $4.1 million, or 31.2% , for the
three months ended September 30, 2009 to $9.1 million from $13.2 million in 2008. On a per unit
basis, we had a decrease of $0.60 per Mcfe to $1.67 per Mcfe for the three months ended September
30, 2009 from $2.27 per Mcfe for the three months ended September 30, 2008. This decrease was
primarily due to the impairment of our oil and gas properties in the fourth quarter of 2008 and the
first quarter of 2009, which decreased our rate per unit, as well as the resulting decrease in the
depletable pool.
General and Administrative Expenses. General and administrative expenses increased $4.8
million, or 658.9%, to $5.6 million for the three months ended September 30, 2009, from $0.7
million for the three months ended September 30, 2008. The increase is primarily due to increased accounting
and audit fees related to our reaudits and restatements as well as increased legal, professional and investment banker fees related to
our Recombination activities.
Gain from Derivative Financial Instruments. Gain from derivative financial instruments
decreased $136.4 million to $8.8 million for the three months ended September 30, 2009, from $145.1
million for the three months ended September 30, 2008. We recorded a $19.6 million realized gain
and $10.9 million unrealized loss on our derivative contracts for the three months ended September
30, 2009 compared to a $7.5 million realized loss and $152.7 million unrealized gain for the three
months ended September 30, 2008. Unrealized gains and losses are attributable to changes in oil and
natural gas prices and volumes hedged from one period end to another.
Interest Expense, net. Interest expense, net, decreased $1.0 million, or 22.6% , to $3.4 million for
the three months ended September 30, 2009, from $4.4 million for the three months ended September
30, 2008. The decrease in interest expense for the three months ended September 30, 2009 compared
to the three months ended September 30, 2008, is due both to lower average outstanding debt levels
and to lower interest rates.
Nine Months Ended September 30, 2009 Compared to the Nine Months Ended September 30, 2008
Overview. Operating data for the periods indicated are as follows (in thousands):
Nine Months Ended | ||||||||||||||||
September 30, | Increase/ | |||||||||||||||
2009 | 2008 | (Decrease) | ||||||||||||||
Oil and gas sales |
$ | 56,260 | $ | 136,908 | $ | (80,648 | ) | (58.9 | )% | |||||||
Oil and gas production costs |
$ | 23,216 | $ | 34,104 | $ | (10,888 | ) | (31.9 | )% | |||||||
Transportation expense |
$ | 31,272 | $ | 25,921 | $ | 5,351 | 20.6 | % | ||||||||
Depreciation, depletion and amortization |
$ | 24,766 | $ | 34,750 | $ | (9,984 | ) | (28.7 | )% | |||||||
General and administrative expenses |
$ | 13,249 | $ | 5,501 | $ | 7,748 | 140.8 | % | ||||||||
Impairment of oil and gas properties |
$ | 95,169 | $ | | $ | 95,169 | * | |||||||||
Gain (loss) from derivative financial instruments |
$ | 31,078 | $ | (4,482 | ) | $ | 35,560 | 793.4 | % | |||||||
Interest expense, net |
$ | 11,274 | $ | 8,747 | $ | 2,527 | 28.9 | % |
* | Not meaningful |
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Production. Oil and gas production data for the periods indicated are as follows:
Nine Months Ended | ||||||||||||||||
September 30, | Increase/ | |||||||||||||||
2009 | 2008 | (Decrease) | ||||||||||||||
Production Data: |
||||||||||||||||
Natural gas production (Mmcf) |
16,107 | 15,755 | 352 | 2.2 | % | |||||||||||
Oil production (Mbbl) |
60 | 47 | 13 | 27.7 | % | |||||||||||
Total production (Mmcfe) |
16,467 | 16,037 | 430 | 2.7 | % | |||||||||||
Average daily production (Mmcfe/d) |
60.3 | 58.5 | 1.8 | 3.1 | % | |||||||||||
Average Sales Price per Unit: |
||||||||||||||||
Natural gas (Mcf) |
$ | 3.30 | $ | 8.36 | $ | (5.06 | ) | (60.5 | )% | |||||||
Oil (Bbl) |
$ | 52.27 | $ | 110.40 | $ | (58.13 | ) | (52.7 | )% | |||||||
Natural gas equivalent (Mcfe) |
$ | 3.42 | $ | 8.54 | $ | (5.12 | ) | (60.0 | )% | |||||||
Average Unit Costs per Mcfe: |
||||||||||||||||
Production costs |
$ | 1.41 | $ | 2.13 | $ | (0.72 | ) | (33.8 | )% | |||||||
Transportation expense |
$ | 1.90 | $ | 1.62 | $ | 0.28 | 17.3 | % | ||||||||
Depreciation, depletion and amortization |
$ | 1.50 | $ | 2.17 | $ | (0.67 | ) | (30.9 | )% |
Oil and Gas Sales. Oil and gas sales decreased $80.6 million, or 58.9%, to $56.3 million for
the nine months ended September 30, 2009, from $136.9 million for the nine months ended September
30, 2008. This decrease was the result of a decrease in average realized prices, partially offset
by higher volumes. The decrease in the average realized price accounted for $82.1 million of the
decrease. Our average product prices, which exclude hedge settlements, on an equivalent basis
(Mcfe) decreased to $3.42 per Mcfe for the nine months ended September 30, 2009 from $8.54 per Mcfe
for the nine months ended September 30, 2008. This decrease was
offset by slightly higher volumes of 430
Mmcfe, resulting in increased oil and gas sales of $1.5 million for the nine months ended September
30, 2009, compared to the nine months ended September 30, 2008. The increased volumes resulted from
the PetroEdge acquisition.
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 decreased $5.5 million, or 9.2%, to $54.5
million for the nine months ended September 30, 2009, from $60.0 million for the nine months ended
September 30, 2008.
Oil and gas production costs decreased $10.9 million, or 31.9% to $23.2 million for the nine
months ended September 30, 2009, from $34.1 million for the nine months ended September 30, 2008.
This decrease was primarily due to cost-cutting and well service improvement measures such as a
reduction in field headcount by approximately one-third while overtime hours were simultaneously reduced for the nine
months ended September 30, 2009 compared to the nine months ended September 30, 2008. The
reductions came at the same time we absorbed the operations of PetroEdge, which increased our total
production, further reducing our cost per Mcfe. In addition, well service improvement measures
resulted in fewer wells going offline, reduced loss of production due to offline wells, and fewer
well repairs in the current period compared to the prior period. Production costs including gross production taxes and ad
valorem taxes were $1.41 per Mcfe for the nine months ended September 30, 2009 as compared to $2.13
per Mcfe for the nine months ended September 30, 2008. The decrease in per unit cost was due to the
cost-cutting and well service improvement measures discussed above, as well as higher volumes over
which to spread fixed costs.
Transportation expense increased $5.4 million, or 20.6%, to $31.3 million for the nine months
ended September 30, 2009, from $25.9 million for the nine months ended September 30, 2008. The
increase was due to an increase in the contracted transportation rate and increased volumes.
Transportation expense was $1.90 per Mcfe for the nine months ended September 30, 2009 as compared
to $1.62 per Mcfe for the nine months ended September 30, 2008.
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 decreased approximately $10.0 million,
or 28.7%, for the nine months ended September 30, 2009
to $24.8 million from $34.8 million for the nine months ended September 30, 2008. On a per unit basis, we had a decrease of $0.67 per
Mcfe to $1.50 per Mcfe for the nine months ended September 30, 2009 from $2.17 per Mcfe for the nine months ended September 30, 2008. This decrease was primarily due to the
impairments of our oil and gas properties in the fourth quarter of 2008 and the first quarter of
2009, offset by decreases in proved reserves due to the effect of lower prices.
General and Administrative Expenses. General and administrative expenses increased $7.7
million, or 140.8%, to $13.2 million for the nine months ended September 30, 2009, from $5.5
million for the nine months ended September 30, 2008. The increase is
primarily due increased legal, audit and other professional fees in connection with the
restatement and reaudits of our financial statements as well as increased legal, professional and
investment banker fees related to our Recombination activities.
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Impairment of Oil and Gas Properties. Under the present full cost accounting rules, we are
required to compute the after-tax present value of our proved oil and natural gas properties using
spot market prices for oil and natural gas at our balance sheet date. The base for our spot prices
for natural gas is Henry Hub and for oil is Cushing, Oklahoma. We had previously
recognized a ceiling test impairment of $95.2 million during the first quarter of 2009 while no
impairment was necessary for the second quarter of 2009. As of September 30, 2009, the ceiling test
computation utilizing spot prices on that day resulted in the carrying costs of our unamortized
proved oil and natural gas properties, net of deferred taxes, exceeding the September 30, 2009
present value of future net revenues by approximately $6.9 million. As a result of subsequent
increases in spot prices, the need to recognize an impairment for the quarter ended September 30,
2009, was eliminated. A ceiling test impairment was not required for the nine months ended
September 30, 2008 based on price levels at that time.
Gain/(Loss) from Derivative Financial Instruments. Gain from derivative financial instruments
increased $35.6 million to a gain of $31.1 million for the nine months ended September 30, 2009,
from a loss of $4.5 million for the nine months ended September 30, 2008. We recorded $83.1 million
of realized gain and $52.0 million of unrealized loss on our derivative contracts for the nine
months ended September 30, 2009 compared to a $17.8 million realized loss and $13.3 million
unrealized gain for the nine months ended September 30, 2008. Included in the current year realized
gain was $26 million cash received as a result of amending or exiting certain of our above market derivative
financial instruments. Unrealized gains and losses are attributable to changes in oil and natural
gas prices and volumes hedged from one period end to another.
Interest Expense,
net. Interest expense, net, increased $2.5 million, or 28.9%, to $11.3 million
during the nine months ended September 30, 2009, from $8.7 million during the nine months ended
September 30, 2008. The increased interest expense for the nine months ended September 30, 2009
relates to higher average debt balances during the nine months ended September 30, 2009 compared to the
nine months ended September 30, 2008 partially offset by lower interest rates in the current year
period.
Liquidity and Capital Resources
Overview. 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. 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.
Our primary sources of liquidity are cash
generated from our operations, amounts, if any, available in the future
under the Amended and Restated Credit Agreement, as amended (the Quest Cherokee
Credit Agreement) and funds from future private and
public equity and debt offerings.
At September 30, 2009 we had no availability under the Quest Cherokee Credit Agreement. In
July 2009, the borrowing base under the Quest Cherokee Credit Agreement was reduced from $190
million to $160 million, which resulted in the outstanding borrowings under the Quest Cherokee
Credit Agreement exceeding the new borrowing base by $14 million. In anticipation of the reduction
in the borrowing base, we amended or exited certain of our above market natural gas price
derivative contracts and, in return, received approximately $26 million. At the same time, we
entered into new natural gas price derivative contracts to increase the total amount of our future estimated
proved developed producing natural gas production hedged to approximately 85% through 2013. On June
30, 2009, using these proceeds, we made a principal payment of $15 million on the Quest Cherokee
Credit Agreement. On July 8, 2009, we repaid the $14 million borrowing base deficiency. We anticipate that in connection with the redetermination of our borrowing base in November
2009, our borrowing base will be further reduced from its current level of $160 million. In the
event of a borrowing base reduction, we expect to be able to make the required payments
resulting from the borrowing base deficiency out of our existing funds.
The Second Lien Senior Term Loan Agreement, as amended (the Second Lien Loan Agreement) originally due and maturing on September 30, 2009, has been
extended to November 16, 2009. Management is currently pursuing various options to restructure or
refinance our credit agreements. There can be no assurance that such efforts will be successful or
that the terms of any new or restructured indebtedness will be favorable to us.
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.
Prices of oil and natural gas have historically been very volatile and can significantly impact the
cash received 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 and general and administrative expenses.
Cash
flows from operations totaled $57.8 million for the nine months ended September 30, 2009
as compared to cash flows from operations of $48.5 million for the nine months ended September 30,
2009. The increase is attributable primarily to higher realized gains on derivatives partially
offset by lower revenues as a result of lower realized prices on oil and gas.
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Cash
Flows from Investing Activities. Net cash used in investing activities totaled $1.5
million for the nine months ended September 30, 2009 as compared to $148.3 million for the nine
months ended September 30, 2008. In 2009, we significantly curbed our acquisition and development
activity due to the decline in oil and gas prices as well as liquidity constraints. Cash outflows
from investing activities in the nine months ended September 30, 2008 included $71.2 million
related to the acquisition of the PetroEdge assets. The following table sets forth our capital
expenditures by major categories for the nine months ended September 30, 2009.
Nine Months Ended | ||||
September 30, 2009 | ||||
(in thousands) | ||||
Capital expenditures: |
||||
Leasehold acquisition |
$ | 1,027 | ||
Development |
212 | |||
Other items |
145 | |||
Total capital expenditures |
$ | 1,384 | ||
Cash Flows from Financing Activities. Net cash used in financing activities totaled $42.0
million for the nine months ended September 30, 2009 as compared to cash provided by financing
activities of $109.4 million for the nine months ended September 30, 2008. In 2009, cash used by
financing was primarily comprised of $41.8 million of repayment on our revolving facility and term
loan discussed under Credit Agreements below.
Working Capital. At September 30, 2009, we had current assets of $60.9 million. Our working
capital (current assets minus current liabilities, excluding the short-term derivative assets and
liabilities of $19.6 million and $1.4 million, respectively) was $0.1 million at September 30,
2009, compared to a working capital (excluding the short-term derivative assets and liabilities of
$43.0 million and $12,000, respectively) deficit of $30.0 million at December 31, 2008. The change
is primarily due to our realized gains on derivatives partially including $26 million received from
the early exit or amendment of derivatives that were subsequently reset to market prices.
Credit Agreements
A. Quest Cherokee Credit Agreement.
Quest Cherokee, LLC (Quest Cherokee) is a party to
the Quest Cherokee Credit Agreement, with Royal Bank of Canada (RBC), KeyBank National Association (KeyBank) and the lenders
party thereto for a $250 million revolving credit facility, which is guaranteed by Quest Energy.
Availability under the revolving credit facility is tied to a borrowing base that is redetermined
by the lenders every six months taking into account the value of Quest Cherokees proved reserves.
The borrowing base was $160.0 million and the amount borrowed under the Quest Cherokee Credit
Agreement was $160.0 million as of September 30, 2009. As a result, there was no additional
borrowing availability. The weighted average interest rate under the Quest Cherokee Credit
Agreement for the quarter ended September 30, 2009 was 4.36%.
In July 2009, the borrowing base under the Quest Cherokee Credit Agreement was reduced from
$190 million to $160 million, which, following the payment discussed below, resulted in the
outstanding borrowings under the Quest Cherokee Credit Agreement exceeding the new borrowing base
by $14 million. In anticipation of the reduction in the borrowing base, Quest Energy amended or
exited certain of its above market natural gas price derivative contracts and, in return, received
approximately $26 million. The strike prices on the derivative contracts that Quest Energy did not
exit were set to market prices at the time. At the same time, Quest Energy entered into new natural
gas price derivative contracts to increase the total amount of its future estimated proved developed
producing natural gas production hedged to approximately 85% through 2013. On June 30, 2009, using
these proceeds, Quest Energy made a principal payment of $15 million on the Quest Cherokee Credit
Agreement. On July 8, 2009, Quest Energy repaid the $14 million borrowing base deficiency. We anticipate that in connection with the redetermination of our borrowing base in November
2009, our borrowing base will be further reduced from its current level of $160 million. In the
event of a borrowing base reduction, we expect to be able to make the required payments
resulting from the borrowing base deficiency out of our existing funds.
On June 18, 2009, Quest Energy and Quest Cherokee entered into a Third Amendment to Amended
and Restated Credit Agreement that, among other things, permits Quest Cherokees obligations under
oil and gas derivative contracts with BP Corporation North America, Inc. or any of its affiliates
to be secured by the liens under the Quest Cherokee Credit Agreement on a pari passu basis with the
obligations under the Quest Cherokee Credit Agreement. On June 30, 2009, Quest Energy and Quest
Cherokee entered into a
Fourth Amendment to Amended and Restated Credit Agreement that deferred Quest Energys
obligation to deliver certain financial statements.
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Quest Cherokee was in compliance with all of its covenants under the Quest Cherokee Credit
Agreement as of September 30, 2009.
B. Second Lien Loan Agreement.
Quest Energy and Quest Cherokee are parties to the Second Lien Loan Agreement dated as of July
11, 2008, with RBC, KeyBank, Société Générale and the parties thereto for a $45 million term loan
originally due and maturing on September 30, 2009.
Quest Energy made quarterly principal payments of $3.8 million on February 17, 2009, May 15,
2009 and August 17, 2009.
As of September 30, 2009 and December 31, 2008, $29.8 million and $41.2 million was
outstanding under the Second Lien Loan Agreement, respectively. The weighted average interest rate
under the Second Lien Loan Agreement for the quarter ended September 30, 2009 was 11.25%.
On June 30, 2009, Quest Energy and Quest Cherokee entered into a Second Amendment to the
Second Lien Loan Agreement that deferred Quest Energys obligation to deliver certain financial
statements to the lenders. On September 30, 2009, Quest Energy and Quest Cherokee entered into a
Third Amendment to the Second Lien Loan Agreement that extended the maturity date of the loan from
September 30, 2009, to October 31, 2009. On October 30, 2009, Quest Energy and Quest Cherokee
entered into a Fourth Amendment to the Second Lien Loan Agreement that extended the
maturity of the loan to November 16, 2009. While we are currently
negotiating further extensions to this loan, there can be no assurance that such negotiations will
be successful or that we will be able to repay amounts due under the Second Lien Loan Agreement in
accordance with the terms of the Second Lien Loan Agreement.
Quest Cherokee was in compliance with all of its covenants under the Second Lien Loan
Agreement as of September 30, 2009.
Contractual Obligations
We have numerous contractual commitments in the ordinary course of business, debt service
requirements and operating lease commitments. Other than those discussed below, these commitments
have not materially changed since our prior year end on December 31, 2008.
On July 1, 2009, Quest Energy GP, LLC (Quest Energy GP) entered into an amendment to the
original agreement with its financial advisor, which provided that the monthly advisory fee
increased to $200,000 per month with a total of $800,000, representing the aggregate fees for each
of April, May, June and July 2009, which amount was paid upon execution of the amendment. Fees
through July 2009 have been expensed and properly accrued as of September 30, 2009. The additional
financial advisor fees payable if certain transactions occurred were canceled; however, the
financial advisor was entitled to a fairness opinion fee of $650,000 in connection with any merger,
sale or acquisition involving Quest Energy GP or Quest Energy, which amount was paid in connection
with the delivery of a fairness opinion at the time of the execution of the Merger Agreement.
In addition, we are a party to a management services agreement with Quest Energy Service,
pursuant to which Quest Energy Service, through its affiliates and employees, carries out the
directions of our general partner and provides us with legal, accounting, finance, tax, property
management, engineering and risk management services. Quest Energy Service may additionally provide
us with acquisition services in respect of opportunities for us to acquire long-lived, stable and
proved oil and gas reserves.
Off-balance Sheet Arrangements
At September 30, 2009, 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.
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ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. |
Commodity Price Risk
Our most significant market risk relates to the prices we receive for our oil and natural gas
production. 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.
The
following table summarizes the estimated volumes, fixed prices and fair values
attributable to oil and gas derivative contracts as of September 30, 2009:
Remainder of | Year Ending December 31, | |||||||||||||||||||||||
2009 | 2010 | 2011 | 2012 | Thereafter | Total | |||||||||||||||||||
($ in thousands, except volumes and per unit data) | ||||||||||||||||||||||||
Natural Gas Swaps: |
||||||||||||||||||||||||
Contract volumes (Mmbtu) |
3,687,360 | 16,129,060 | 13,550,302 | 11,000,004 | 9,000,003 | 53,366,729 | ||||||||||||||||||
Weighted-average fixed
price per Mmbtu |
$ | 7.78 | $ | 6.26 | $ | 6.80 | $ | 7.13 | $ | 7.28 | $ | 6.85 | ||||||||||||
Fair value, net |
$ | 11,939 | $ | 5,020 | $ | 1,048 | $ | 1,676 | $ | 1,178 | $ | 20,861 | ||||||||||||
Natural Gas Collars: |
||||||||||||||||||||||||
Contract volumes (Mmbtu) |
187,500 | | | | | 187,500 | ||||||||||||||||||
Weighted-average fixed
price per Mmbtu: |
||||||||||||||||||||||||
Floor |
$ | 11.00 | $ | | $ | | $ | | $ | | $ | 11.00 | ||||||||||||
Ceiling |
$ | 15.00 | $ | | $ | | $ | | $ | | $ | 15.00 | ||||||||||||
Fair value, net |
$ | 1,154 | $ | | $ | | $ | | $ | | $ | 1,154 | ||||||||||||
Total Natural Gas Contracts: |
||||||||||||||||||||||||
Contract volumes (Mmbtu) |
3,874,860 | 16,129,060 | 13,550,302 | 11,000,004 | 9,000,003 | 53,554,229 | ||||||||||||||||||
Weighted-average fixed
price per Mmbtu |
$ | 7.94 | $ | 6.26 | $ | 6.80 | $ | 7.13 | $ | 7.28 | $ | 6.87 | ||||||||||||
Fair value, net |
$ | 13,093 | $ | 5,020 | $ | 1,048 | $ | 1,676 | $ | 1,178 | $ | 22,015 | ||||||||||||
Basis Swaps: |
||||||||||||||||||||||||
Contract volumes (Bbl) |
| 3,630,000 | 8,549,998 | 9,000,000 | 9,000,003 | 30,180,001 | ||||||||||||||||||
Weighted-average fixed
price per Bbl |
$ | | $ | 0.63 | $ | 0.67 | $ | 0.70 | $ | 0.71 | $ | 0.69 | ||||||||||||
Fair value, net |
$ | | $ | (957 | ) | $ | (1,512 | ) | $ | (1,393 | ) | $ | (1,138 | ) | $ | (5,000 | ) | |||||||
Crude Oil Swaps: |
||||||||||||||||||||||||
Contract volumes (Bbl) |
9,000 | 30,000 | | | | 39,000 | ||||||||||||||||||
Weighted-average fixed
price per Bbl |
$ | 90.07 | $ | 87.50 | $ | | $ | | $ | | $ | 88.09 | ||||||||||||
Fair value, net |
$ | 170 | $ | 386 | $ | | $ | | $ | | $ | 556 | ||||||||||||
Total fair value, net |
$ | 13,263 | $ | 4,449 | $ | (464 | ) | $ | 283 | $ | 40 | $ | 17,571 |
In June 2009, we amended or exited certain of our above market natural gas price derivative
contracts for periods beginning in the second quarter of 2010 through the fourth quarter of 2012.
In return, we received approximately $26 million. Concurrent with this, the strike prices on the
derivative contracts that we did not exit were set to market prices at the time and we entered into
new natural gas price derivative contracts to increase the total
amount of our future estimated proved
developed producing natural gas production hedged to approximately 85% through 2013. Except for the
commodity derivative contracts noted above, there have been no material changes in market risk
exposures that would affect the quantitative and qualitative disclosures presented as of December
31, 2008, in Item 7A of our 2008 Form 10-K/A.
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ITEM 4. | 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 achieving
their control objectives.
In connection with the preparation of this Quarterly Report on Form 10-Q, our management,
under the supervision and with the participation of the current principal executive officer and
current principal financial officer of our general partner, conducted an evaluation of the
effectiveness of the design and operation of our disclosure controls and procedures as of September
30, 2009. Based on that evaluation, the principal executive officer and principal financial officer
of our general partner have concluded that our disclosure controls and procedures were not
effective as of September 30, 2009. Notwithstanding this determination, our management believes
that the condensed consolidated financial statements in this Quarterly Report on Form 10-Q 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.
In connection with the preparation of our 2008 Form 10-K/A, 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. As a result of that evaluation, management identified numerous control
deficiencies that constituted material weaknesses as of December 31, 2008. 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.
Management identified the following control deficiencies that constituted material weaknesses
as of December 31, 2008:
(1) | 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 (7) below. We did not maintain an effective control environment because of the following material weaknesses: |
(a) | We did not maintain a tone and control consciousness that consistently emphasized adherence to accurate financial reporting and enforcement of our 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 to our policies and procedures. | ||
(b) | 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. | ||
(c) | 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. |
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, depreciation, depletion and amortization, impairment of
oil and gas properties and cash management described in items (2) to (7) below.
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(2) | 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: |
(a) | 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. | ||
(b) | 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. |
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 (7)
below.
(3) | 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: |
(a) | 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. | ||
(b) | 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. | ||
(c) | 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. | ||
(d) | 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. | ||
(e) | 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. |
(4) | 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. |
(5) | 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. |
(6) | 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. |
(7) | 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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Each of the control deficiencies described in items (1) through (7) 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.
Changes in Internal Control Over Financial Reporting
As discussed above, as of December 31, 2008, we had material weaknesses in our internal
control over financial reporting.
The remediation efforts, outlined below, are intended both to address the identified material
weaknesses and to enhance our overall financial control environment. In January 2009, Mr. Eddie M.
LeBlanc, III was appointed Chief Financial Officer (our principal financial and accounting
officer). In May 2009, Mr. David C. Lawler was appointed Chief Executive Officer (our principal
executive officer). The design and implementation of these and other remediation efforts are the
commitment and responsibility of this new leadership team.
Under the management services agreement between us and Quest Energy Service, LLC (Quest
Energy Service) all of our financial reporting services are provided by Quest Energy Service. QRCP
has advised us that it is currently in the process of remediating the weaknesses in internal
control over financial reporting referred to above by designing and implementing new procedures and
controls throughout QRCP and its subsidiaries and affiliates for whom it is responsible for
providing accounting and finance services, including us, and by strengthening the accounting
department through adding new personnel and resources. QRCP has obtained, and has advised us that
it will continue to seek, the assistance of the Audit Committee of our general partner in
connection with this process of remediation.
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, Quest Energy Service has effected personnel changes in its accounting and financial
reporting functions. It has also advised us that it has 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, Quest Energy Service has 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 and our disclosure controls and procedures.
During 2009, we have made the following changes to address the previously reported material
weaknesses in internal control over financial reporting and disclosure controls and procedures:
a) | We hired additional experienced accounting personnel with specific experience in (1) financial reporting for public companies; (2) preparing consolidated financial statements; (3) oil and gas property and pipeline asset accounting; (4) inter-company accounts and investments in subsidiaries; and (5) GAAP revenue accounting. |
b) | We implemented a closing calendar and consolidation process that includes accrual based financial statements being reviewed by qualified personnel in a timely manner. |
c) | We review consolidating financial statements with senior management, the audit committee of the board of directors and the full board of directors. |
d) | We complete disclosure checklists for both GAAP and SEC required disclosures to ensure disclosures are complete. |
e) | We have created a disclosure committee as part of our SEC filing process. |
In addition, during the third quarter of 2009, we have:
a) | Communicated internally to employees regarding ethics and the availability of our internal fraud hotline; |
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b) | Evaluated and prioritized the material weaknesses noted above and developed specific actions necessary in order to remediate them; |
c) | Performed a preliminary assessment of our accounting and disclosure policies and procedures and begun the process of updating and revising them; and |
d) | Begun regular meetings of the disclosure committee. |
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 and
disclosure controls and procedures. We are committed to continuing to improve our internal control
processes and will continue to diligently and vigorously review our internal control over financial
reporting and our disclosure controls and procedures. As we continue to evaluate and work to
improve our internal control over financial reporting and our disclosure controls and procedures,
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.
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PART II OTHER INFORMATION
ITEM 1. | LEGAL PROCEEDINGS. |
See Part I, Item I, Note 10 to our consolidated financial statements entitled Commitments and
Contingencies, which is incorporated herein by reference.
We are subject, from time to time, to certain legal proceedings and claims in the ordinary
course of conducting our business. As of September 30, 2009, as a result of the Transfers and the
restatements of our financial statements, we are involved in litigation outside the ordinary course
of our business. Except for those legal proceedings listed in Part I, Item I, Note 10 to our
consolidated financial statements included in this Form 10-Q or in our 2008 Form 10-K/A, 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, results of operations
or cash flow. 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.
ITEM 1A. | RISK FACTORS. |
Risks Related to the Recombination
While the Recombination is pending, we will be subject to business uncertainties and contractual
restrictions that could adversely affect our business.
Uncertainty about our financial condition and the effect of the Recombination on employees,
customers and suppliers may have an adverse effect on us pending consummation of the Recombination
and, consequently, on the combined company. These uncertainties may impair our ability to attract,
retain and motivate key personnel until the Recombination is consummated and for a period of time
thereafter, and could cause customers, suppliers and others who deal with us to seek to change
existing business relationships with us. Employee retention may be particularly challenging during
the pendency of the Recombination because employees may experience uncertainty about their future
roles with the combined company, and we have experienced resignations of officers and other key
personnel since the date of the Merger Agreement. If, despite our retention efforts, key employees
depart because of issues relating to the uncertainty and difficulty of integration or a desire not
to remain with the combined company, the combined companys business could be seriously harmed.
The Merger Agreement restricts us, without QRCPs and QMLPs consent and subject to certain
exceptions, from taking certain specified actions until the Recombination occurs or the Merger
Agreement terminates. These restrictions may prevent us from pursuing otherwise attractive business
opportunities and making other changes to our business that may arise prior to completion of the
Recombination or termination of the Merger Agreement.
Even absent these restrictions, we may not have the liquidity or resources available or the
ability under our credit agreements to pursue alternatives to the Recombination, even if we
determine that another opportunity would be more beneficial. In addition, management is devoting
substantial time and other human resources to the proposed transaction and related matters, which
could limit their ability to pursue other attractive business opportunities, including potential
joint ventures, stand-alone projects and other transactions. If we are unable to pursue such other
attractive business opportunities, then our growth prospects and the long-term strategic position
of our business and the combined business could be adversely affected.
QRCPs control over us may preclude us from pursuing alternative transactions that may be more
beneficial to our common unitholders than the Recombination.
As the holder of all of our subordinated units, which has a class vote on merger proposals,
QRCP effectively has veto power over any alternative transactions that we might consider pursuing,
even alternative transactions that could be more beneficial to our common unitholders than the
Recombination.
Our partnership agreement limits our general partners fiduciary duties to unitholders and
restricts the remedies available to holders of our common units and subordinated units for actions
taken by our general partner that might otherwise constitute breaches of fiduciary duty.
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The Recombination involves conflicts of interest between us and our public unitholders, on the
one hand, and QEGP and it affiliates, including QRCP, on the other hand. As permitted by Delaware
law, our partnership agreement contains certain provisions concerning the resolution of conflicts
of interest that reduce the fiduciary standards to which QEGP, the board of directors of QEGP and
the conflicts committee of QEGP would otherwise be held under state law and that restrict the
remedies available to unitholders for actions taken by QEGP, the board of directors of QEGP or the
conflicts committee of QEGP in resolving such conflicts of interest. Specifically, under the our
partnership agreement:
| any conflict of interest and any resolution thereof shall be permitted and deemed approved by all of our partners, and shall not constitute a breach of our partnership agreement or of any duty stated or implied by law or equity, if the resolution or course of action in respect of conflict of interest is approved by a majority of the members of the conflicts committee acting in good faith (meaning they believed that such approval was in our best interests); | ||
| it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and | ||
| our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees for any acts or omissions, unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal. |
The conflicts committee of the board of directors of QEGP has unanimously (i) determined that
the Merger Agreement and the QELP merger are advisable, fair to and in the best interests of us and
the holders of our common units (other than QEGP and its affiliates), (ii) approved the Merger
Agreement and the QELP merger and (iii) recommended approval and adoption of the Merger Agreement
and the QELP merger by the holders of our common units (other than QEGP and its affiliates). The
members of the conflicts committee, although meeting the independence standards required of
directors who serve on an audit committee of a board of directors of a company listed or admitted
to trading on the Nasdaq Global Market, were appointed by QRCP, as the sole member of QEGP, and not
elected by our unitholders.
Our financial projections may not prove accurate.
The Merger Agreement is subject to closing conditions that could result in the completion of the
Recombination being delayed or not consummated, and the Recombination may not be consummated even
if our unitholders and the QRCP stockholders and QMLP unitholders approve the Merger Agreement and
the Recombination.
Under the Merger Agreement, completion of the Recombination is conditioned upon the
satisfaction of closing conditions, including, among others, the arrangement of one or more credit
facilities for PostRock and its subsidiaries on terms reasonably acceptable to the board of
directors of QRCP and the conflicts committee of each of QEGP and QMLPs general partner, the
approval of the transaction by our unitholders, QRCP stockholders and QMLP unitholders, and
consents from each entitys existing lenders. The required conditions to closing may not be
satisfied or, if permissible, waived, in a timely manner, if at all, and the Recombination may not
occur. Given the distressed nature of the parties, PostRock may not be able to obtain one or more
credit facilities on terms
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that the conflicts committee of each of QEGP and QMLPs general partner finds reasonably
acceptable. In addition, we, QRCP and QMLP can agree not to consummate the Recombination even if
our unitholders, QRCP stockholders and QMLP unitholders approve the Merger Agreement and the
Recombination and any of QRCP, QELP or QMLP may terminate the Merger Agreement if the Recombination
has not been consummated by March 31, 2010.
Failure to complete the Recombination could negatively impact the value of our common units 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.
If the Recombination is not completed for any reason, we could be subject to several risks
including the following:
| there may be events of default under our indebtedness and such indebtedness may be accelerated and become immediately due and payable, which may result in our bankruptcy (please read If the Recombination is delayed or not consummated or if the Merger Agreement is terminated, there may be events of default under our indebtedness enabling the lenders to accelerate such indebtedness, which could lead to the foreclosure of collateral and our bankruptcy); |
| the market price of our common units may decline to the extent that the current market price reflects market assumptions that the Recombination will be completed and that the combined company will experience a potentially enhanced financial position; |
| there will be 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; |
| there may be an adverse impact on relationships with customers, suppliers and others to the extent they believe that we cannot compete in the marketplace or continue as a solvent entity without the Recombination or otherwise remain uncertain about our future prospects in the absence of the Recombination; and |
| we may experience difficulty in retaining and recruiting current and prospective employees. |
We will incur significant transaction and merger-related integration costs in connection with the
Recombination.
As
of September 30, 2009, QELP, QRCP and QMLP have already incurred
approximately $7.3
million in aggregate transaction costs in connection with the Recombination and expect to pay
approximately $6.7 million in additional aggregate transaction costs subsequent to
September 30, 2009. These transaction costs include investment banking, legal and accounting fees and expenses,
SEC filing fees, printing expenses, mailing expenses, proxy solicitation expenses and other related
charges. These amounts are preliminary estimates that are subject to change. A portion of the
transaction costs will be incurred regardless of whether the Recombination is consummated. We and
QMLP will each pay 45% of the combined transaction costs and QRCP will pay 10% of the combined
transaction costs, except that we and QRCP will share equally the costs of printing and mailing the
definitive joint proxy statement/prospectus to, and soliciting proxies (including fees of proxy
solicitors) from, QRCP stockholders and our unitholders and QMLP will pay the cost of mailing the
definitive joint proxy statement to, and soliciting proxies from, its unitholders. These costs will
reduce the cash available to the combined company following completion of the Recombination and
will adversely impact its liquidity and ability to make capital expenditures.
Risks Related to Our Financial Condition
Former senior management were terminated in 2008 following the discovery of various
misappropriations of funds of QRCP and QELP.
In August of 2008, Jerry Cash, the former chairman, president and chief executive officer of
QRCP, QEGP and QMGP, resigned and David E. Grose, the former chief financial officer of QRCP, QEGP
and QMGP, was terminated, following the discovery of the misappropriation of $10 million
principally from QRCP by Mr. Cash with the assistance of Mr. Grose from 2005 through mid-2008.
Additionally, the Oklahoma Department of Securities has filed a lawsuit alleging that Mr. Grose and
Brent Mueller, the former purchasing manager of QRCP, each received kickbacks of approximately $0.9
million from several related suppliers over a two-year
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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 pled guilty to one felony
count of misprision of justice. We have filed lawsuits against all three of these individuals
seeking an asset freeze and damages related to the transfers, kickbacks and thefts. Pursuant to a
settlement agreement with Mr. Cash, QELP, QRCP and QMLP recovered assets valued at $3.4 million
from him and released all further claims against him. As a result of these activities, we recorded
a consolidated loss of $6.6 million. We have incurred costs
totaling approximately $8.0 million in
connection with the investigation of these misappropriations, legal fees, accountants fees and
other related expenses. There can be no assurance that we will be 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.
For more detail concerning these unauthorized transfers, please read Items 1. and 2. Business
and Properties Recent Developments in our 2008 Form 10-K/A.
QELP and QRCP are involved in securities lawsuits that may result in judgments, settlements, and/or
indemnity obligations that are not covered by insurance and that may have a material adverse effect
on us.
Between September 2008 and August 2009, four federal securities class action lawsuits, one
federal individual securities lawsuit, two federal derivative lawsuits and three state court
derivative lawsuits have been filed naming QELP, QRCP and certain current and former officers and
directors as defendants. The securities lawsuits allege the defendants violated the federal
securities laws by issuing false and misleading statements and/or concealing material facts
concerning the unauthorized transfers of funds by former management described above and seek class
certification, money damages, interest, attorneys fees, costs and expenses. The complaints allege
that, as a result of these actions, QELPs unit price and QRCPs stock price were artificially
inflated. The derivative lawsuits assert claims for breach of fiduciary duty, abuse of control,
gross mismanagement, waste of corporate assets and unjust enrichment and seek disgorgement, money
damages, costs, expenses and equitable or injunctive relief. Additional lawsuits may be filed. For
more information, please read Note 10 to our consolidated financial statements in this quarterly
report and Note 11 to our consolidated financial statements in our 2008 Form 10-K/A.
We have incurred and will continue to incur substantial costs, legal fees and other expenses
in connection with their defense against these claims. In addition, the final settlements or the
courts final decisions in the securities cases could result in judgments against us that are not
covered by insurance or which exceed the policy limits. We may also be obligated to indemnify
certain of the individual defendants in the securities cases, which indemnity obligations may not
be covered by insurance. We have received letters from our directors and officers insurance
carriers reserving their rights to limit or preclude coverage under various provisions and
exclusions in the policies, including for the committing of a deliberate criminal or fraudulent act
by a past, present, or future chief executive officer or chief financial officer. We received a
letter from our directors and officers liability insurance carrier stating that the carrier will
not provide insurance coverage based on Mr. Cashs alleged written admission that he engaged in
acts for which coverage is excluded. We are reviewing the letter and evaluating our options. If
these lawsuits have not been settled, tried or dismissed prior to the closing of the Recombination,
PostRock will become subject to some or all of these lawsuits and would face the same risks with
respect to these lawsuits as QRCP and QELP. We and PostRock might not have sufficient cash on hand
to fund any such payment of expenses, judgments and indemnity obligations and might be forced to
file for bankruptcy or take other actions that could have a material adverse effect on our
financial condition and the price of our common units. Furthermore, certain of the officers and
directors of PostRock may continue to be subject to these actions after the closing of the
Recombination, which could adversely affect the ability of management and the board of directors of
PostRock to implement its business strategy.
U.S. government investigations could affect our results of operations.
Numerous government entities are currently conducting investigations of QELP and some of our
former officers and directors. The Oklahoma Department of Securities has filed lawsuits against Mr.
Cash, Mr. Grose and Mr. Mueller. In addition, 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 QELP and the misappropriations by these individuals.
We cannot anticipate the timing, outcome or possible financial or other impact of these
investigations. 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
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to business practices resulting from these investigations could adversely affect our and
PostRocks results of operations and financial condition and our and PostRocks ability to continue
as a going concern.
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
for the year ended December 31, 2008 contained a statement expressing substantial doubt as to our
ability to continue as a going concern. We and our predecessor have incurred significant losses
from 2004 through 2008, mainly attributable to operations, impairment of oil and gas properties,
unrealized gains and losses from derivative financial instruments, legal restructurings,
financings, the current legal and operational structure and the losses attributable to certain
unauthorized transfers, repayments and re-transfers of funds to entities controlled by the former
chief executive officer of each of QELP, QRCP and QMLP and the associated costs to investigate such
transfers. If the Recombination is not consummated and we are unable to restructure our
indebtedness or complete some other strategic transaction, then 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 units and our results of operations.
We have identified significant and pervasive material weaknesses in our internal control over
financial reporting.
Following the discovery of the unauthorized transfers by certain members of senior management
discussed above and in connection with our managements review of our internal control over
financial reporting as of December 31, 2008, control deficiencies that constituted material
weaknesses related to the following items were identified:
| 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. | ||
| We did not maintain effective monitoring controls to determine the adequacy of our internal control over financial reporting and related policies and procedures. | ||
| 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. | ||
| We did not establish and maintain effective controls to ensure the correct application of GAAP related to derivative instruments. | ||
| We did not establish and maintain effective controls to ensure completeness and accuracy of depreciation, depletion and amortization expense. | ||
| 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. | ||
| We did not establish and maintain effective controls to adequately segregate the duties over cash management. |
These material weaknesses resulted in the misstatement of certain of our annual and interim
consolidated financial statements during the last three years. Based on managements evaluation,
because of the material weaknesses described above, management concluded that our internal control
over financial reporting was not effective as of December 31, 2008 and continued not to be
effective as of September 30, 2009.
Under the management services agreement between us and Quest Energy Service, LLC, all of our
financial reporting services are provided by Quest Energy Service. While certain actions have been
taken to address the deficiencies identified, it is unlikely that the remediation plan and timeline
for implementation will eliminate all deficiencies for the year ended December 31, 2009. Additional
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measures may be necessary and these measures, along with other measures we expect to be taken
to improve our internal control 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.
We have restated certain of our historical financial statements.
As discussed above, as a result of the misappropriation of funds by prior senior management
and other significant and material errors identified in prior year financial statements and the
material weaknesses in internal control over financial reporting, our general partners board of
directors determined on December 31, 2008 that the audited consolidated financial statements for us
or our predecessor as of and for the years ended December 31, 2007, 2006 and 2005 and 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 and that it would
be necessary to restate these financial statements.
The restated consolidated financial statements 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:
| The transfers described above, which were not approved expenditures were not properly accounted for as losses. | ||
| Hedge accounting was inappropriately applied for commodity derivative instruments and the valuation of commodity derivative instruments was incorrectly computed. | ||
| Errors were identified in the accounting for the formation of 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. 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 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. | ||
| 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. | ||
| 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 previously discussed errors and an additional error related to the methods used in calculating depreciation, depletion and amortization, errors existed in depreciation, depletion and amortization expense and accumulated depreciation, depletion and amortization. | ||
| 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 ceiling test calculations. |
Although the items listed above comprise the most significant errors (by dollar amount),
numerous other errors were identified and restatement adjustments made.
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As a result of the need to completely restate and reaudit all of the financial statements for
the periods discussed above, management was unable to prepare and file our annual report for 2008
and our quarterly reports for the third quarter of 2008 and the first and second quarters of 2009
on a timely basis. Moreover, we were required to file amendments to certain of our periodic reports
to correct an error identified in July 2009 related to the incorrect classification of realized
gains on commodity derivative instruments during the year ended December 31, 2008, which affected
the financial statements for the quarters ended March 31, June 30, and September 30, 2008 and the
year ended December 31, 2008.
If the Recombination is delayed or not consummated or if the Merger Agreement is terminated, there
may be events of default under our indebtedness enabling the lenders to accelerate such
indebtedness, which could lead to our foreclosure of collateral and bankruptcy.
We have been in default under our credit agreements. In June 2009, we entered into amendments
to our credit agreements that, among other things, deferred until August 15, 2009 the obligation to
deliver to RBC certain financial information.
The current balance of $29.8 million of indebtedness under the Second Lien Loan Agreement has
been extended to November 16, 2009. We do not expect to be able to pay such amount on that date and
there can be no assurance that we will be able to obtain a further extension of the maturity date.
An event of default under either of our credit agreements would cause an event of default
under our other credit agreement. If there is an event of default under either of our credit
agreements, the lenders thereunder could accelerate the indebtedness and foreclose on the
collateral. As of September 30, 2009, there was $160.0 million outstanding under the Quest Cherokee
Credit Agreement and $29.8 million outstanding under our Second Lien Loan Agreement.
In July 2009, our borrowing base under our revolving credit agreement was reduced from $190
million to $160 million, which, following the principal payment discussed below, resulted in the
outstanding borrowings under the revolving credit agreement exceeding the new borrowing base by $14
million. In anticipation of the reduction in the borrowing base, Quest Cherokee amended or exited
certain of its above the market natural gas price derivative contracts and, in return, received
approximately $26 million. On June 30, 2009, using these proceeds, Quest Cherokee made a principal
payment of $15 million on the first lien loan agreement. On July 8, 2009, Quest Cherokee repaid the
$14 million borrowing base deficiency. We anticipate that in
connection with the redetermination of our borrowing base in November
2009, our borrowing base will be further reduced from its current
level of $160 million. In the event of a borrowing base reduction, we
expect to be able to make the required payments resulting from the
borrowing base deficiency out of our existing funds.
If we are required to make these prepayments or pay the full amounts of the indebtedness upon
acceleration, we may be able to raise the funds only by selling assets or it may be unable to raise
the funds at all, in which event we may be forced to file for bankruptcy protection or liquidation.
If defaults occur and the Recombination is delayed or the Merger Agreement is terminated and
we are unable to obtain waivers from our lenders or to obtain alternative financing to repay the
credit facilities, we may be required to obtain additional waivers or our lender may foreclose on
our assets, issue additional equity securities or refinance the credit agreements at unfavorable
prices.
Risks Related to Our Business
The current financial crisis and economic conditions have had, and may continue to have, a material
adverse impact on our business and financial condition.
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 and the solvency of counterparties, 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 more onerous terms and, in some cases, ceased
to provide any new funding.
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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 impact of difficult economic
conditions, they could materially adversely affect our business and financial condition. For
example:
| our ability to obtain credit and access the capital markets to fund the exploration or development of reserves, the construction of additional assets or the acquisition of assets or businesses from third parties may continue to be restricted; | ||
| our hedging arrangements could become ineffective if our counterparties are unable to perform their obligations or seek bankruptcy; | ||
| 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 | ||
| the demand for oil and natural gas could further decline due to deteriorating economic conditions, which could adversely affect our business, financial condition or results of operations. |
During
the first half of 2010, we
believe we will need to raise a significant amount of equity
capital to fund our proposed 2010 drilling program and pay down outstanding indebtedness.
We may not be able to
raise a sufficient amount of equity capital for these purposes at the appropriate time due to
market conditions or our financial condition and prospects or may have to issue shares at a
significant discount to the market price. If we are not able to raise this equity capital, it would
have a material adverse impact on our ability to meet indebtedness repayment obligations and fund
our operations and capital expenditures and we may be forced to file for bankruptcy. In addition,
if we issue and sell additional common units in an equity offering, our unitholders ownership will
be diluted and our unit price may decrease due to the additional common units available in the
market.
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 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 or cause
us to file for bankruptcy.
Energy prices are very volatile, and if commodity prices remain low or continue to decline, our
revenues, profitability and cash flows will be adversely affected. 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 fund our capital expenditures and meet our financial commitments.
The current global credit and economic environment has resulted in reduced demand for natural
gas and significantly lower natural gas prices. Gas prices have seen a greater percentage decline
over the past twelve months than oil prices due in part to a substantial supply of natural gas on
the market and in storage. The prices we receive for our oil and natural gas production will
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 and will likely continue to be volatile in the future. For example,
during the nine months ended September 30, 2009, the near month NYMEX natural gas futures price
ranged from a high of $6.07 per Mmbtu to a low of $2.51 per Mmbtu. Approximately 98% of our
production is natural gas. The prices that we receive for our production, and the levels of our
production, depend on a variety of factors that are beyond our control, such as:
| the domestic and foreign supply of and demand for oil and natural gas; | ||
| the price and level of foreign imports of oil and natural gas; | ||
| the level of consumer product demand; | ||
| weather conditions; | ||
| 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; | ||
| actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls; | ||
| the impact of the U.S. dollar exchange rates on oil and gas prices; | ||
| technological advances affecting energy consumption; | ||
| domestic and foreign governmental regulations and taxation; | ||
| the impact of energy conservation efforts; | ||
| the costs, proximity and capacity of gas pipelines and other transportation facilities; and | ||
| the price and availability of alternative fuels. |
Our revenues, profitability and cash flow depend upon the prices and demand for oil and gas,
and a drop in prices will significantly affect our financial results and impede our growth. In
particular, declines in commodity prices will:
| reduce the amount of cash flow available for capital expenditures, including for the drilling of wells and the construction of infrastructure to transport the natural gas we produce; | ||
| 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; | ||
| reduce the drilling and production activity of our third party customers and increase the rate at which our customers shut in wells; and | ||
| limit our ability to borrow money or raise additional capital. |
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 have had and may continue to 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 will be 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, due to the low price of natural gas as of December 31, 2008, revisions resulting
from further technical analysis and production during the year, our proved reserves decreased 20.8%
to 167.1 Bcfe at December 31, 2008 from 211.1 Bcfe at December 31, 2007, and the standardized
measure of our proved reserves decreased 51.6% to $156.1 million as of December 31, 2008 from
$322.5 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) compared to $6.43 at December 31,
2007. Primarily as a result of this decrease, we recognized a non-cash impairment of $245.6 million
for the year ended December 31, 2008. Due to a further decline in the spot price for natural gas
during 2009, we incurred an additional impairment charge of
approximately $95.2 million for the
nine months ended September 30, 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 which
could result in a reduction in our credit facility borrowing base.
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As a result of our financial condition, we have had to significantly reduce our capital
expenditures, which will ultimately reduce cash flow and result in the loss of some leases.
Due to the global economic and financial crisis, the decline in commodity prices, the
unauthorized transfers of funds by prior senior management and restrictions in their credit
agreements, as described in more detail in other risk factors, we have not been able to raise the
capital necessary to implement our drilling plans for 2009 and 2010. We reduced our capital
expenditure budget from $155.4 million in 2008 to $9.7 million in 2009. In addition, we plan to
drill only seven new wells in 2009, after drilling 328 new wells in 2008. We do not expect to
drill a substantial number of wells if the Recombination is not completed. The effect of this
reduced capital expenditures and drilling program is that we may not be able to maintain our
reserves levels and may lose leases that require a certain level of drilling activity.
Please read Certain of our undeveloped leasehold acreage is subject to leases that may expire in the near
future. Our failure to maintain our reserve levels could
adversely affect the borrowing base under the Quest Cherokee Credit
Agreement.
We face the risks of leverage.
As
of September 30, 2009, we had borrowed $160 million under the Quest Cherokee Credit
Agreement. 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. Under certain circumstances, the use of leverage may create a greater risk of
loss to unitholders 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 cash flow. If we do not make our debt service payments when due, our lenders may foreclose on
assets securing such debt.
Our future level of debt could have important consequences, including the following:
| 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; | ||
| 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. Any failure by us to meet these obligations could result in litigation, non-performance by contract counterparties or bankruptcy; | ||
| our funds available for operations and future business opportunities will be reduced by that portion of our cash flow required to make principal or interest payments on our debt; | ||
| we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and | ||
| our flexibility in responding to changing business and economic conditions may be limited. |
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 indebtedness, we will be forced to take actions such as
reducing or delaying business activities, acquisitions, 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 restrict our
business and financing activities.
The operating and financial restrictions and covenants in our credit agreements and the terms
of any future financing agreements may restrict our ability to finance future operations or capital
needs or to engage, expand or pursue our business activities. Our credit agreements and any future
financings agreements may restrict our ability to:
| incur indebtedness; | ||
| grant liens; |
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| pay dividends; | ||
| redeem or repurchase equity interests; | ||
| make certain acquisitions and investments, loans or advances; | ||
| lease equipment; | ||
| enter into a merger, consolidation or sale of assets; | ||
| dispose of property; | ||
| enter into hedging arrangements with certain counterparties; | ||
| limit the use of loan proceeds; | ||
| make capital expenditures above specified amounts; and | ||
| enter into transactions with affiliates. |
We are also be required to comply with certain financial covenants and ratios. 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, our indebtedness may become immediately due and payable, the interest rates on our
credit agreements may increase and the lenders 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 in which event we may be forced to file for bankruptcy.
For a description of our credit facilities, please read Item 2. Managements Discussion and
Analysis of Financial Condition and Results of Operations Liquidity and Capital Resources
Credit Agreements.
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 market interest rates. 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 may be unable to pass through all of our costs and expenses for gathering and compression to
royalty owners under our gas leases, which would reduce our net income and cash flows.
Under the midstream services agreement we are required to pay fees for gathering, dehydration
and treating services and fees for compression services to Quest
Midstream for each Mmbtu of gas
produced from our wells in the Cherokee Basin. The terms of some of our existing gas leases may
not, and the terms of some of the gas leases that we may acquire in the future may not, allow us to
charge the full amount of these costs and expenses to the royalty owners under the leases. On
August 6, 2007, certain mineral interest owners filed a putative class action lawsuit against Quest
Cherokee, that, among other things, alleges Quest Cherokee improperly charged certain expenses to
the mineral and/or overriding royalty interest owners under leases covering the acres leased by
Quest Cherokee in Kansas. We will be responsible for any judgments or settlements with respect to
this litigation. Please see Note 10 to our consolidated financial statements in this quarterly
report for a discussion of this litigation. To the extent that we are unable to charge the full
amount of these costs and expenses to our royalty owners, our net income and cash flows will be
reduced.
We depend on one customer for sales of our Cherokee Basin natural gas. A reduction by this customer
in the volumes of gas it purchases from us could result in a substantial decline in our revenues
and net income.
During the year ended December 31, 2008, we sold substantially all of our natural gas produced
in the Cherokee Basin at market-based prices 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. Sales under this contract accounted for
approximately 93% and 83% of our
consolidated revenue for
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the year ended December 31, 2008 and for the nine months ended September 30, 2009,
respectively. If ONEOK were to reduce the volume of gas it purchases under this agreement, our
revenue and cash flow would decline and our results of operations and financial condition could be
materially adversely affected.
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.
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. Our future oil and gas
reserves, production and cash flow depend on our success in developing and exploiting our 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. Similarly, we may not be able to replace in 2010 the reserves
we expect to produce in 2010. Our failure to maintain our reserve
levels could adversely affect the borrowing base under the Quest Cherokee
Credit Agreement.
As of December 31, 2008, our proved reserve-to-production ratio was 7.8 years. Because this
ratio includes 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 they have estimated and can
change when we drill additional wells, make acquisitions and under other circumstances.
There is a significant delay between the time we drill and complete a CBM well and when the well
reaches peak production. As a result, there will be a significant lag time between when we make
capital expenditures and when we 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 we expend capital
expenditures to drill and complete a well and when we will begin to recognize significant cash flow
from those expenditures may adversely affect our cash flow from operations. Our average cost to
drill and complete a CBM well is between $110,000 to $120,000.
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:
| a constant level of future oil and gas prices; | ||
| geological conditions; | ||
| production levels; | ||
| capital expenditures; | ||
| operating and development costs; |
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| the effects of governmental regulations and taxation; and | ||
| availability of funds. |
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.
As of December 31, 2008, in connection with an evaluation by our independent reservoir
engineering firm, we (on a consolidated basis) had a downward revision of our estimated proved
reserves of approximately 123.2 Bcfe. A decrease in natural gas prices between January 1, 2008 and
December 31, 2008 had an estimated impact of 31.1 Bcfe. A decrease in natural gas prices between
the date of our acquisition of the PetroEdge assets and December 31, 2008 had an estimated impact
of approximately 35.5 Bcfe of the reduction. The estimated
remaining 61.6 Bcfe reduction was
attributable to (a) the elimination of 43.2 Bcfe in proved reserves as a result of further technical
analysis of the reserves acquired from PetroEdge, and (b) a
decrease of approximately 13.4 Bcfe due
to the adverse impact on estimated reserves of an expected increase in gathering and compression
costs.
Our standardized measure is calculated using unhedged oil and gas prices and is determined in
accordance with the rules and regulations of the SEC. The present value of future net cash flows
from our estimated proved reserves is not necessarily the same as the market value of our estimated
proved reserves. The estimated discounted future net cash flows from our estimated proved reserves
is based 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:
| the actual prices we receive for oil and gas; | ||
| our actual operating costs in producing oil and gas; | ||
| the amount and timing of actual production; | ||
| the amount and timing of our capital expenditures; | ||
| supply of and demand for oil and gas; and | ||
| changes in governmental regulations or taxation. |
The timing of both production and 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 FASB ASC 932 Extractive
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 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:
| high costs, shortages or delivery delays of drilling rigs, equipment, labor or other services; | ||
| adverse weather conditions; | ||
| difficulty disposing of water produced as part of the coal bed methane production process; | ||
| equipment failures or accidents; | ||
| title problems; | ||
| pipe or cement failures or casing collapses; |
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| compliance with environmental and other governmental requirements; | ||
| environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases; | ||
| lost or damaged oilfield drilling and service tools; | ||
| loss of drilling fluid circulation; | ||
| unexpected operational events and drilling conditions; | ||
| increased risk of wellbore instability due to horizontal drilling; | ||
| unusual or unexpected geological formations; | ||
| natural disasters, such as fires; | ||
| blowouts, surface craterings and explosions; and | ||
| uncontrollable flows of oil, gas or well fluids. |
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.
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 natural gas, we have entered into, and may in the future enter into,
derivative arrangements for a significant portion of our oil and natural 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.
The prices at which we enter into derivative financial instruments covering our production in
the future is dependent upon commodity prices at the time we enter into these transactions, which
may be substantially lower than current oil and natural gas prices. Accordingly, our commodity
price risk management strategy will not protect us from significant and sustained declines in oil
and natural gas prices received for our future production. Conversely, our commodity price risk
management strategy may limit our ability to realize cash flow from commodity price increases.
Furthermore, we have a policy that requires, and our credit facilities mandate, that we enter into
derivative transactions related to only a portion of our expected production volumes and, as a
result, we have direct commodity price exposure on the portion of our production volumes that is
not covered by a derivative financial instrument.
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:
| a counterparty may not perform its obligation under the applicable derivative instrument; | ||
| 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. |
Because of our lack of asset and geographic diversification, adverse developments in our operating
areas would adversely affect our results of operations.
Substantially all of our assets are 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.
The oil and gas industry is highly competitive and 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.
Natural gas also competes with other forms of energy available to our 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, 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.
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:
| damage to wells, pipelines, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism; | ||
| inadvertent damage from construction, farm and utility equipment; | ||
| leaks of gas or oil spills as a result of the malfunction of equipment or facilities; | ||
| fires and explosions; and | ||
| other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. |
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.
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In accordance with typical industry practice, we 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.
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, 2006 and 2008 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, results of
operations and ability to resume and sustain the payment of cash distributions to our unitholders.
Shortages of crews could delay our operations, adversely affect our ability to increase our
reserves and production and adversely affect our results of operations.
Wage increases and shortages in personnel 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 revenues 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.
Certain of our undeveloped leasehold acreage is subject to leases that may expire in the near
future.
In the Cherokee Basin, as of September 30, 2009, we held oil and gas leases on approximately
535,817 net acres, of which 135,691 net acres
(or 25.3%) 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 20,037 net acres
are scheduled to expire before December 31, 2009 and an
additional 77,892 net acres are scheduled
to expire before December 31, 2010. If these leases expire and are not renewed, we will lose the
right to develop the related properties.
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, based on reserves as of December
31, 2008, approximately 270 gross proved undeveloped drilling locations and approximately 1,599
additional gross potential drilling locations in the Cherokee 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. The assignment of proved reserves to these locations is based on the assumptions regarding
gas prices in our December 31, 2008 reserve report, which prices have declined since the date of
the report. In addition, no proved reserves are assigned to any of the approximately 1,599 Cherokee
Basin potential drilling locations we have identified and therefore, there exists 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 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 identified will be drilled within the
timeframe specified in our 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 substantially decline in value. In such an instance, the amount paid for such oil or gas
lease or leases would be lost. It is managements practice, in acquiring oil and gas leases, or
undivided interests in oil
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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.
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, liability for natural resource damages
or damages to third parties, 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 Clean Air Act and comparable
state laws and regulations that impose obligations related to air emissions, (2) the federal
Resource Conservation and Recovery Act (RCRA)and comparable state laws that impose requirements
for the handling, storage, treatment or discharge of waste from our facilities, (3) the federal
Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as
Superfund, and comparable state laws that regulate the cleanup of hazardous substances that may
have been released at properties owned or operated by us or our predecessors or locations to which
we or our predecessors has sent waste for disposal and (4) the federal Clean Water Act 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 limiting or
enjoining future operations or imposing additional compliance requirements or operational
limitation on such operations. Certain environmental laws, 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. 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 which could adversely affect our ability to resume and continue the
payment of distributions.
We may face unanticipated water and other waste disposal costs.
We may be 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 produce, and our ability to remove and dispose of sufficient quantities of
water from the various zones will determine whether 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 fails 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
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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:
| we cannot obtain future permits from applicable regulatory agencies; | ||
| water of lesser quality or requiring additional treatment is produced; | ||
| our wells produce excess water; | ||
| new laws and regulations require water to be disposed in a different manner; or | ||
| costs to transport the produced water to the disposal wells increase. |
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 U.S. Environmental Protection Agency (EPA), the individual states administer some or all of
the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. 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. However,
drilling fluids, produced waters, and most of the other wastes associated with the exploration,
development, production and transportation of oil and gas are currently excluded from regulation as
hazardous wastes under RCRA. These wastes may be regulated by EPA or state agencies as
non-hazardous solid wastes. Moreover, 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.
Recent and future environmental laws and regulations may significantly limit, and increase the cost
of, our exploration, production and transportation operations.
Recent and future environmental laws and regulations, including additional federal and state
restrictions on greenhouse gas emissions that may be passed in response to climate change concerns,
may increase our capital and operating costs and also reduce the demand for the oil and natural gas we produce.
The oil and gas industry is a direct source of certain greenhouse gas (GHG) emissions, such as
carbon dioxide and methane, and future restrictions on such emissions could impact our future
operations. Specifically, on April 17, 2009, the EPA issued a notice of its proposed finding and
determination that emissions of carbon dioxide, methane, and other
GHGs present an endangerment to
human health and the environment because emissions of such gases are, according to EPA,
contributing to warming of the earths atmosphere. EPAs proposed finding and determination, and
any final action in the future, may allow it to begin regulating
emissions of GHGs from stationary and mobile sources under existing
provisions of the federal Clean Air Act. Although it may take EPA several years to adopt and impose
regulations limiting emissions of GHGs, any such regulation could require us to incur costs to
reduce emissions of GHGs associated with our operations. Similarly, on June 26, 2009, the U.S.
House of Representatives approved adoption of the American Clean Energy and Security Act of 2009,
also known as the Waxman-Markey cap-and-trade legislation or ACESA. ACESA would establish an
economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG
emissions to obtain GHG emission allowances corresponding to their annual emissions of GHGs. The
U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in
the United States. Any laws or regulations that may be adopted to restrict or reduce emissions of
GHGs would likely require us to incur increased capital expenditures
and operating costs and could have an adverse effect on
demand for the oil and natural gas we produce. At the state level, more than one-third of the
states, including California, have begun taking actions to control and/or reduce emissions of GHGs.
The California Global Warming Solutions Act of 2006, also known as AB 32, caps Californias
greenhouse gas emissions at 1990 levels by 2020, and the California Air Resources Board is
currently developing mandatory reporting regulations and early action measures to reduce GHG
emissions prior to January 1, 2012. Although most of the regulatory initiatives developed or being
developed by the various states have to date been focused on large sources of GHG emissions, such
as coal-fired electric power plants, it is possible that smaller sources of emissions could become
subject to GHG emission limitations in the future.
In addition, the U.S. Congress is currently considering certain other legislation which, if
adopted in its current proposed form, could subject companies involved in oil and natural gas
exploration and production activities to substantial additional regulation. If such legislation is
adopted, federal tax incentives could be curtailed, and hedging activities as well as certain other
business activities of exploration and production companies could be limited, resulting in
increased operating costs. Any such limitations or increased operating costs could have a material
adverse effect on our business.
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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 per share and cash flows. 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 per share 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:
| mistaken assumptions about reserves, future production, volumes, revenues and costs, including synergies; | ||
| an inability to integrate successfully the businesses we acquire; | ||
| 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; | ||
| a significant increase in our interest expense or financial leverage if we incur additional debt to finance the acquisition; | ||
| the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate; | ||
| an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; | ||
| limitations on rights to indemnity from the seller; | ||
| mistaken assumptions about the overall costs of equity or debt; | ||
| the diversion of managements and employees attention from other business concerns; | ||
| the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges; | ||
| unforeseen difficulties operating in new product areas or new geographic areas; and | ||
| customer or key employee losses at the acquired businesses. |
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 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 currently 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:
| geology; | ||
| well economics; | ||
| availability of third party services; |
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| transportation charges; | ||
| content, quantity and quality of oil and gas produced; | ||
| volume of waste water produced; | ||
| state and local regulations and permit requirements; and | ||
| production, severance, ad valorem and other taxes. |
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.
Our success depends on key management personnel, the loss of any of whom could disrupt our
business.
The success of our operations and activities is dependent to a significant extent on the
efforts and abilities of our management. We have not obtained, and we do not anticipate obtaining,
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. If the key personnel do not devote
significant time and effort to the management and operation of the business, our financial results
may suffer.
Please see Item 1A. Risk FactorsRisks Inherent in an Investment in Our Common Units and
Tax Risks to Our Common Unitholders in our 2008 Form 10-K/A for additional risk factors.
ITEM 2. | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS. |
None.
ITEM 3. | DEFAULTS UPON SENIOR SECURITIES. |
None.
ITEM 4. | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. |
None.
ITEM 5. | OTHER INFORMATION. |
None.
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ITEM 6. | EXHIBITS |
*2.1 | First Amendment dated as of October 2, 2009 to the Agreement and Plan of Merger, dated as of July 2, 2009, by and among New Quest Holdings Corp. (n/k/a PostRock Energy Corporation), Quest Resource Corporation, Quest Midstream Partners, L.P., Quest Energy Partners, L.P., Quest Midstream GP, LLC, Quest Energy GP, LLC, Quest Resource Acquisition Corp., Quest Energy Acquisition, LLC, Quest Midstream Holdings Corp. and Quest Midstream Acquisition, LLC (incorporated herein by reference to Exhibit 2.2 to PostRock Energy Corporations Registration Statement on Form S-4 filed on October 6, 2009). | |
*10.1 | Third Amendment to Second Lien Senior Term Loan Agreement, dated as of September 30, 2009, 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 10.1 to Quest Energy Partners, L.P.s Current Report on Form 8-K filed on October 1, 2009). | |
*10.2 | Fourth Amendment to Second Lien Senior Term Loan Agreement, dated as of October 31, 2009, 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 10.1 to Quest Energy Partners, L.P.'s Current Report on Form 8-K filed on November 2, 2009). | |
*10.3 | First Amendment dated as of October 2, 2009 to the Support Agreement, dated as of July 2, 2009, by and among Quest Resource Corporation, Quest Energy Partners, L.P., Quest Midstream Partners, L.P., Alerian Opportunity Partners IV, LP, Alerian Opportunity Partners IX, LP and certain other unitholders of Quest Midstream Partners, L.P. party thereto (incorporated herein by reference to Exhibit 10.61 to PostRock Energy Corporations Registration Statement on Form S-4 filed on October 6, 2009) |
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. |
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
Quarterly Report on Form 10-Q. 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 Partnership 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
no 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 Partnerships 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 Partnership or its
business or operations on the date hereof.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized this
5th day of November, 2009.
Quest Energy Partners, L.P. | ||||||
By: | Quest Energy GP, LLC, its general partner | |||||
By: | /s/ David C. Lawler
|
|||||
Chief Executive Officer and President | ||||||
By: | /s/ Eddie M. LeBlanc, III
|
|||||
Chief Financial Officer |
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