QELP Quest Energy Partners, L.P. (MM)

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K/A

(Amendment No. 1)

 

 

For the fiscal year ended December 31, 2008

 

Commission file number: 001-33787

 

 

 

 

QUEST ENERGY PARTNERS, L.P.

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

 

 

Registrant’s telephone number, including area code:

405-600-7704

Securities Registered Pursuant to Section 12(b) of the Exchange Act:

 

 

Securities Registered Pursuant to Section 12(g) of the Exchange Act:

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes  o      No  þ

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.  Yes  o      No  þ

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  o      No  þ

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  o      No  o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   þ

 

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):

 

(Do not check if a smaller reporting company)

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes  o      No  þ

 

The aggregate market value of the common units held by non-affiliates computed by reference to the last reported sale of the registrant’s common units on June 30, 2008, the last business day of the registrant’s most recently completed second fiscal quarter, at $16.32 per common unit was $148,512,000. This figure assumes that only the directors and officers of the registrant, their spouses and controlled corporations were affiliates. As of June 9, 2009, the registrant had 12,316,521 common units outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

None

 

 

EXPLANATORY NOTE TO AMENDMENT NO. 1

 

This Amendment No. 1 on Form 10-K/A (the “Amendment”) to the Annual Report on Form 10-K, originally filed with the Securities and Exchange Commission (the “SEC”) on June 16, 2009 (the “Original Filing”), of Quest Energy Partners, L.P. (the “Partnership”) is being filed 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. This error resulted in an understatement of revenue and an overstatement of the gain from derivative financial instruments by approximately $14.6 million for the year ended December 31, 2008 of which $2.4 million, $17.8 million, $15.1 million and $(20.7) million related to the quarters ended March 31, June 30, September 30, and December 31, 2008, respectively. The error had no effect on net income (loss), net income (loss) per unit, partners’ equity or the Partnership’s Consolidated Balance Sheet, Consolidated Statement of Cash Flows or Consolidated Statement of Partners’ Equity as of and for the year ended December 31, 2008, or any of the interim periods during 2008. In accordance with the guidance in Staff Accounting Bulletin No. 99, “Materiality,” management evaluated this error from a quantitative and qualitative perspective and concluded it was not material to any period.

 

This Amendment sets forth the Original Filing in its entirety; however, this Amendment only amends (i) amounts and disclosures related to the above error within the consolidated financial statements and elsewhere within the Original Filing; (ii) disclosures for certain events occurring subsequent to the Original Filing as identified in Note 4 — Long-Term Debt and Note 17 — Subsequent Events, and (iii) other insignificant items to correct for certain typographical and other minor errors identified within the Original Filing. Except as set forth in the preceding sentence, the Partnership has not modified or updated disclosures presented in the original filing to reflect events or developments that have occurred after the date of the Original Filing. Among other things, forward-looking statements made in the Original Filing have not been revised to reflect events, results or developments that have occurred or facts that have become known to us after the date of the Original Filing (other than as discussed above), and such forward-looking statements should be read in their historical context. This Amendment should be read in conjunction with the Partnership’s filings made with the SEC subsequent to the Original Filing, including any amendments to those filings.

 

In addition, in accordance with applicable SEC rules, this Amendment includes currently-dated certifications from our general partner’s Chief Executive Officer and President, who is our principal executive officer, and our general partner’s Chief Financial Officer, who is our principal financial officer, in Exhibits 31.1, 31.2, 32.1 and 32.2.

 

TABLE OF CONTENTS

 

 

GUIDE TO READING THIS REPORT

 

As used in this report, unless we indicate otherwise:

 

 

In this report we also use some oil and natural gas industry terms that are defined under the caption “Glossary of Selected Terms” at the end of Items 1 and 2, “Business and Properties” of this report.

EXPLANATORY NOTE TO ANNUAL REPORT

 

This Annual Report on Form 10-K/A for the year ended December 31, 2008 includes our restated and reaudited consolidated financial statements as of December 31, 2007 and for the period from November 15, 2007 to December 31, 2007 and our Predecessor’s restated and reaudited carve out financial statements, as of and for the years ended December 31, 2005 and 2006, and for the period from January 1, 2007 to November 14, 2007. We recently filed (i) an amended Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2008 including restated consolidated financial statements as of March 31, 2008 and for the three month periods ended March 31, 2008 and 2007; (ii) an amended Quarterly Report on Form 10-Q/A for the quarter ended June 30, 2008 including restated consolidated financial statements as of June 30, 2008 and for the three and six month periods ended June 30, 2008 and 2007; and (iii) a Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 including consolidated financial statements for the three and nine month periods ended September 30, 2008 and 2007.

 

We were formed by QRCP in 2007 in order to conduct, in a master limited partnership structure, the exploration and production operations previously conducted by QRCP’s wholly-owned subsidiaries, Quest Cherokee, LLC (“Quest Cherokee”) and Quest Cherokee Oilfield Service, LLC (“QCOS”). QRCP owns 100% of our general partner and therefore controls the election of the board of directors of our general partner. Since our initial public offering, our general partner has had the same executive officers as QRCP. We do not have any employees, other than field level employees, and we depend on QRCP to provide us with all general and administrative functions necessary to operate our business. QRCP provides these services to us pursuant to the terms of the management services agreement between us and Quest Energy Service, LLC (“Quest Energy Service”), a wholly-owned subsidiary of QRCP. The management services agreement obligates Quest Energy Service to provide all personnel (other than field personnel) and any facilities, goods and equipment necessary to perform the services we need including acquisition services, general and administrative services such as SEC reporting and filings, Sarbanes-Oxley compliance, accounting, audit, finance, tax, benefits, compensation and human resource administration, property management, risk management, land, marketing, legal and engineering.

 

Investigation — On August 22, 2008, in connection with an inquiry from the Oklahoma Department of Securities, the boards of directors of QRCP, Quest Energy GP, our general partner, and Quest Midstream GP, LLC (“Quest Midstream GP”), the general partner of Quest Midstream, a private limited partnership controlled by QRCP, held a joint working session to address certain unauthorized transfers, repayments and re-transfers of funds (the “Transfers”) to entities controlled by the former chief executive officer, Jerry D. Cash.

 

A joint special committee comprised of one member designated by each of the boards of directors of Quest Energy GP, QRCP, and Quest Midstream GP was immediately appointed to oversee an independent internal investigation of the Transfers. In connection with this investigation, other errors were identified in prior year financial statements and management and the board of directors concluded that we had material weaknesses in our internal control over financial reporting. As of December 31, 2008, these material weaknesses continued to exist. 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.

 

As reported on a Current Report on Form 8-K initially filed on January 2, 2009 and amended on February 6, 2009, on December 31, 2008, the board of directors of Quest Energy GP determined that our audited consolidated financial statements as of December 31, 2007, and for the period from November 15, 2007 to December 31, 2007, our 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 and the Predecessor’s audited consolidated financial statements as of and for the years ended December 31, 2005 and 2006, and for the period from January 1, 2007 to November 14, 2007 should no longer be relied upon. The Predecessor’s financial statements represent the carve out financial position, results of operations, cash flows and changes in partners’ capital of the Cherokee Basin operations of QRCP, and reflect the operations of Quest Cherokee and QCOS, located in the Cherokee Basin (other than its

midstream assets), which QRCP contributed to us at the completion of our initial public offering on November 15, 2007.

 

Additionally, the amended 8-K reported that our management had concluded that the reported cash balances and partners’ equity of the Predecessor will be reduced by a total of $9.5 million as of November 14, 2007, which represents the total amount of the Transfers that had been funded by Quest Cherokee as of the closing of our initial public offering. Our management concluded that such Transfers had indirectly resulted in Quest Cherokee borrowing an additional $9.5 million under its credit facilities prior to November 15, 2007. QRCP repaid this additional indebtedness of Quest Cherokee at the closing of our initial public offering. We have no obligation to repay such amount to QRCP. Notwithstanding the foregoing, our reported cash balances and partners’ equity as of December 31, 2007 and June 30, 2008 continued to reflect the Transfers and accordingly were overstated by $10 million (consisting of the $9.5 million funded by Quest Cherokee that had been repaid by QRCP at the closing of our initial public offering and an additional $0.5 million that was recorded on our balance sheet in error — the additional $0.5 million was funded after the closing of our initial public offering by another subsidiary of QRCP in which we have no ownership interest).

 

Restatement and Reaudit — In October 2008, Quest Energy GP’s audit committee engaged a new independent registered public accounting firm to audit our consolidated financial statements for 2008 and, in January 2009, engaged them to reaudit our consolidated financial statements as of December 31, 2007 and for the period from November 15, 2007 to December 31, 2007 and the Predecessor’s audited consolidated financial statements as of and for the years ended December 31, 2005 and 2006, and for the period from January 1, 2007 to November 14, 2007.

 

The restated consolidated financial statements included in this Form 10-K/A 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:

 

 

Although the items listed above comprise the most significant errors (by dollar amount), numerous other errors were identified and restatement adjustments made. The tables below present previously reported partners’ equity, major restatement adjustments and restated partners’ equity as well as previously reported loss, major restatement adjustments and restated net income (loss) as of and for the periods indicated (in thousands):

 

 

 

Reconciliations from amounts previously included in our consolidated financial statements to restated amounts on a financial statement line item basis are presented in Note 16 — Restatement in the notes to the accompanying consolidated financial statements.

 

Other Matters — In addition to the items for which we have restated our consolidated financial statements, the Oklahoma Department of Securities has filed a lawsuit alleging:

 

 

We experienced significant increased costs in the second half of 2008 and continue to experience such increased costs in the first half of 2009 due to, among other things (as more fully described in Items 1 and 2. “Business and Properties — Recent Developments — Internal Investigation; Restatements and Reaudits”):

 

 

All dollar amounts and other data presented in our previously filed Annual Report on Form 10-K for the year ended December 31, 2007 have been revised to reflect the restated amounts throughout this Form 10-K/A, even where such amounts are not labeled as restated.

ITEMS 1 AND 2.   BUSINESS AND PROPERTIES.

 

Overview

 

We are a publicly traded master limited partnership formed in 2007 by QRCP to acquire, exploit and develop oil and natural gas properties. In November 2007, we consummated the initial public offering of our common units and acquired the oil and gas properties contributed to us by QRCP in connection with that offering. In July 2008, we acquired from QRCP the interest in wellbores and related assets associated with the proved developed producing and proved developed non-producing reserves of PetroEdge Resources (WV) LLC (“PetroEdge”) located in the Appalachian Basin. See “— Oil and Gas Production — Appalachian Basin” and “— Recent Developments — PetroEdge Acquisition” for further information regarding this acquisition.

 

Our primary business objective for 2009 has been adjusted in response to the recent turmoil in the financial markets and the economy in general, including the reduction in commodity prices which was then exacerbated by the significantly increased general and administrative costs we have incurred as a result of the investigation and the reaudits and restatements of our consolidated financial statements. In 2009, our primary focus is to maintain our assets while working towards the completion of a recombination of us, QRCP and Quest Midstream into a newly formed holding company structure (the “Recombination”) in order to simplify our organizational structure. On July 2, 2009, we, Quest Midstream, QRCP and other parties thereto entered into an Agreement and Plan of Merger, which followed the execution of a non-binding letter of intent by the three Quest entities that was publicly announced on June 3, 2009 with respect to the Recombination. We are also working with our lenders to restructure our debt. We are no longer focused on traditional master limited partnership goals and objectives like the payment of cash distributions and we do not expect to pay distributions in 2009 and we are unable to estimate at this time when distributions may be resumed. The completion of the Recombination will be subject to a number of conditions and uncertainties. For more information, please read “— Recent Developments — Outlook for 2009; Recombination” and Item 1A. “Risk Factors — The Merger Agreement for the Recombination is subject to closing conditions that could result in the completion of the Recombination being delayed or not consummated, which could lead to liquidation or bankruptcy” and “— Failure to complete the proposed Recombination could negatively impact the market price 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.”

 

After taking into effect the acquisition of the PetroEdge assets that we acquired from QRCP and the acquisition of oil producing assets in Seminole County, Oklahoma, based on the most recently available reserve reports listed below, as of December 31, 2008, we had a total of approximately 167.1 Bcfe of net proved reserves with estimated future net cash flows discounted at 10%, which we refer to as the “standardized measure,” of $156.1 million. As of such date, approximately 83.2% of the net proved reserves were proved developed and 97.6% were gas.

 

We operate in one reportable segment engaged in the exploration, development and production of oil and gas properties. Our properties can be summarized as follows:

 

 

Oil and Gas Production

 

Cherokee Basin.   Our oil and gas production operations are primarily focused on the development of coal bed methane or CBM in a 15-county region in southeastern Kansas and northeastern Oklahoma known as the Cherokee Basin. As of December 31, 2008, we had 152.7 Bcfe of estimated net proved reserves in the Cherokee Basin, of which approximately 97.7% were CBM and 81.6% were proved developed. We operate approximately 99% of our existing Cherokee Basin wells, with an average net working interest of approximately 99% and an average net revenue interest of approximately 82%. We believe we are the largest producer of natural gas in the Cherokee Basin with an average net daily production of 57.3 Mmcfe for the year ended December 31, 2008. Our estimated net proved reserves in the Cherokee Basin at December 31, 2008 had a standardized measure of $129.8 million. Our Cherokee Basin reserves have an average proved reserve-to-production ratio of 7.3 years (5.0 years for our proved developed properties) as of December 31, 2008. Our typical Cherokee Basin CBM well has a predictable production profile and a standard economic life of approximately 15 years.

 

As of December 31, 2008, we were operating approximately 2,438 gross gas wells in the Cherokee Basin, of which over 95% were multi-seam wells, and 27 gross oil wells. As of December 31, 2008, we owned the development rights to approximately 557,603 net acres throughout the Cherokee Basin and had only developed approximately 59.6% of our acreage. For 2009, we budgeted approximately $3.8 million to drill seven new gross wells, connect and complete 49 existing gross wells, and connect and complete three existing salt water disposal wells in the Cherokee Basin. All of these new gas wells will be drilled on locations that are classified as containing proved reserves in our December 31, 2008 reserve report. In 2009, we plan to recomplete an estimated 10 gross wells, and we budgeted another $1.9 million for equipment, vehicle replacement, and other capital purchases. Recompletions generally consist of converting wells that were originally completed with single seam completions into multi-seam completions, which allows us to produce additional gas from different depths. In addition, we budgeted $2.4 million related to lease renewals and extensions for acreage that is expiring in 2009. However, we intend to fund these capital expenditures only to the extent that we have available cash from operations after taking into account our debt service obligations. We can give no assurance that any such funds will be available. For 2008, we had total capital expenditures of approximately $79 million, including $47 million to complete 328 gross wells and recomplete or restimulate 70 gross wells, which was within the budgeted amount. As of December 31, 2008, our undeveloped acreage contained approximately 1,893 gross CBM drilling locations, of which approximately 624 were classified as proved undeveloped. Over 97% of the CBM wells that have been drilled on our acreage to date have been successful. Historically, our Cherokee Basin acreage was developed utilizing primarily 160-acre spacing. However, during 2008, we developed some areas on 80-acre spacing. We are currently evaluating the results of this 80-acre spacing program. None of our acreage or producing wells are associated with coal mining operations.

 

Our acreage position in the Cherokee Basin is served by Bluestem Pipeline, LLC (“Bluestem”), a wholly-owned subsidiary of Quest Midstream. Bluestem owns and operates a natural gas gathering pipeline network of approximately 2,173 miles with a daily throughput capacity of approximately 85 Mmcf/d which is operated at about 90% capacity. We transport 99% of our Cherokee Basin gas production through Bluestem’s gas gathering pipeline network to interstate pipeline delivery points. As of December 31, 2008, we had an inventory of approximately 185 gross drilled CBM wells awaiting connection to Bluestem’s gas gathering pipeline.

 

Appalachian Basin.   On July 11, 2008, we acquired from QRCP producing properties in the Appalachian Basin that are operated by Quest Eastern Resource LLC (“Quest Eastern”), formerly PetroEdge, now a wholly-owned subsidiary of QRCP. Since the end of 2006, QRCP has actively pursued opportunities in the Marcellus Shale of the Appalachian Basin. At the time of the acquisition, we believed the characteristics of the Appalachian Basin were well suited to our structure as a master limited partnership.

 

On July 11, 2008, QRCP consummated the acquisition of PetroEdge for approximately $142 million, including transaction costs, after taking into account post-closing adjustments. The assets acquired were approximately 78,000 net acres of oil and natural gas producing properties in the Appalachian Basin with estimated proved reserves of 99.6 Bcfe as of May 1, 2008 and net production of approximately 3.3 Mmcfe/d. Simultaneous with the closing, QRCP sold oil and natural gas producing wells with estimated proved developed reserves of 32.9 Bcfe as of May 1, 2008 and all of the current net production to us for cash consideration of approximately $72 million, subject to post-closing adjustment. As of December 31, 2008, there were approximately 10.9 Bcfe of estimated net proved

developed reserves associated with the Appalachian Basin assets sold to us. The remaining assets retained by QRCP had, as of December 31, 2008, an additional 7.7 Bcfe of estimated net proved undeveloped reserves. The 18.6 Bcfe of estimated net proved reserves in the Appalachian Basin, as of December 31, 2008, were approximately 68% proved developed. The decrease in estimated reserves from 99.6 Bcfe to 18.6 Bcfe is due primarily to a decrease in natural gas prices between May 1, 2008, the date of the PetroEdge reserve report, and year-end (35.5 Bcfe) and revisions due to further technical analysis of the reserves (43.2 Bcfe). Upon further technical analysis, our management discovered that the Marcellus zone proved developed non-producing reserves associated with 82 wells, totaling 14.6 Bcfe, were not completed and were not directly offset by productive wells; therefore those reserves were removed from the reserve report as of December 31, 2008. Well performance for certain producing wells was judged not to be meeting expectation and the reserves expected to be recovered from such wells was reduced by 2.6 Bcfe. The proved undeveloped reserves acquired were evaluated by an independent reservoir engineering firm other than Cawley, Gillespie & Associates, Inc. at the time of the PetroEdge acquisition. The evaluation included proved undeveloped locations based upon acre spacing, assuming blanket coverage of the area by productive zones. Securities and Exchange Commission (“SEC”) rules require a proved undeveloped location to be recorded in reserves only if it is directly offset by a productive well. The reserve report prepared at the time of the acquisition included 145 locations, totaling 26.0 Bcfe, that have been removed from the reserve report as of December 31, 2008. The personnel responsible for analyzing and validating the reserve report used for this acquisition are no longer part of our management team.

 

As of December 31, 2008, we owned approximately 500 gross gas wells in the Appalachian Basin. Quest Eastern operates approximately 99% of these existing wells on our behalf. We have an average net working interest of approximately 93% and an average net revenue interest of approximately 75%. Our average net daily production in the Appalachian Basin was approximately 2.9 Mmcfe for the year ended December 31, 2008. Our estimated net proved reserves in the Appalachian Basin at December 31, 2008 were 10.9 Bcfe and had a standardized measure of $19.6 million. Our reserves in the Appalachian Basin have an average proved reserve-to-production ratio of 17.5 years (10.7 years for our proved developed properties) as of December 31, 2008. Our typical Marcellus Shale well has a predictable production profile and a standard economic life of approximately 50 years.

 

For 2009, we budgeted $1.4 million for artificial lift equipment, vehicle replacement and purchases and salt water disposal facilities. However, we intend to fund these capital expenditures only to the extent that we have available cash after taking into account our debt service and other obligations. We can give no assurance that any such funds will be available based on current commodity prices and other current conditions.

 

Quest Eastern owns and operates a gas gathering pipeline network of approximately 183 miles that serves our acreage position in the Appalachian Basin. The pipeline delivers both to intrastate gathering and interstate pipeline delivery points. Presently, this system has a maximum daily throughput of approximately 15.0 Mmcf and is operating at about 20% capacity. All of our Appalachian Basin gas production is transported by Quest Eastern’s gas gathering pipeline network.

 

Seminole County, Oklahoma.   We own 55 gross productive oil wells and the development rights to approximately 1,481 net acres in Seminole County, Oklahoma. As of December 31, 2008, the oil producing properties had estimated net proved reserves of 588,800 Bbls, all of which are proved developed producing. During 2008, net production for our Seminole County properties was 148 Bbls/d. Our oil production operations in Seminole County are primarily focused on the development of the Hunton Formation. We believe there are approximately 11 horizontal drilling locations for the Hunton Formation on our acreage. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approval, oil prices, costs and drilling results. There were no proved undeveloped reserves given to these locations as of December 31, 2008. All production from Seminole County is transported via trucks.

 

Recent Developments

 

PetroEdge Acquisition

 

As discussed above under “Overview — Oil and Gas Production — Appalachian Basin,” on July 11, 2008, QRCP acquired PetroEdge and simultaneously sold PetroEdge’s oil and natural gas producing wells to us. We funded our purchase of the PetroEdge wellbores with borrowings under our revolving credit facility, which was

increased from $160 million to $190 million as part of the acquisition, and the proceeds of a $45 million, six-month term loan under our Second Lien Senior Term Loan Agreement (the “Second Lien Loan Agreement”) with Royal Bank of Canada (“RBC”), as administrative agent and collateral agent, KeyBank National Association, as syndication agent, Société Générale, as documentation agent, and the lenders party thereto.

 

The purpose of the PetroEdge acquisition was to expand our operations to another geologic basin with less basis differential, that had significant resource potential. The acquisition closed during the peak month of natural gas pricing in 2008.

 

Internal Investigation; Restatements and Reaudits

 

On August 23, 2008, only six weeks after the PetroEdge transaction closed, Jerry D. Cash, the former chief executive officer, resigned following the discovery of the Transfers. The Transfers were brought to the attention of the boards of directors of each of Quest Energy GP, Quest Midstream GP and QRCP as a result of an inquiry and investigation that had been initiated by the Oklahoma Department of Securities. Quest Energy GP’s board of directors, jointly with the boards of directors of Quest Midstream GP and QRCP, formed a joint special committee to investigate the matter and to consider the effect on our consolidated financial statements. The joint special committee retained numerous professionals to assist with the internal investigation and other matters during the period following the discovery of the Transfers. To conduct the internal investigation, independent legal counsel was retained to report to the joint special committee and to interact with various government agencies, including the Oklahoma Department of Securities, the Federal Bureau of Investigation, the Department of Justice, the SEC and the Internal Revenue Service (“IRS”). We also retained a new independent registered public accounting firm to reaudit our consolidated financial statements and the carve out financial statements of our Predecessor.

 

The investigation is substantially complete. The investigation revealed that the Transfers resulted in a loss of funds totaling approximately $10 million by QRCP. Further, it was determined that David E. Grose directly participated and/or materially aided Jerry D. Cash in connection with the unauthorized Transfers. In addition, the Oklahoma Department of Securities has filed a lawsuit alleging that David E. Grose and Brent Mueller each received kickbacks of approximately $0.9 million from several related suppliers over a two-year period and that during the third quarter of 2008, they also engaged in the direct theft of $1 million for their personal benefit and use. In March 2009, Mr. Mueller pled guilty to one felony count of misprision of justice. Sentencing is pending. We filed lawsuits against all three of these individuals seeking an asset freeze and damages related to the Transfers, kickbacks and thefts and we intend to pursue all remedies available under the law. The lawsuits against Jerry D. Cash were settled on May 19, 2009. See “— Settlement Agreements” below. 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. We received all of Mr. Cash’s equity interest in STP Newco, Inc. (“STP”), which owns certain oil producing properties in Oklahoma, as reimbursement for a portion of the costs of the internal investigation and the costs of the litigation against Mr. Cash that have been paid by us. We are in the process of establishing the value of the interest in STP.

 

We, our general partner, QRCP and certain of the officers and directors of our general partner have been named as defendants in a number of securities class action lawsuits and securityholder derivative lawsuits arising out of or related to the Transfers. See Item 3. “Legal Proceedings.”

 

We experienced significant increased costs in the second half of 2008 and continue to experience such increased costs in the first half of 2009 due to, among other things:

 

 

 

We estimate that our share of the increased costs related to the foregoing will be between approximately $3.5 million and $4.0 million.

 

Global Financial Crisis and Impact on Capital Markets and Commodity Prices

 

At about the same time as the Transfers were discovered, the global economy experienced a significant downturn. The crisis began over concerns related to the U.S. financial system and quickly grew to impact a wide range of industries. There were two significant ramifications to the exploration and production industry as the economy continued to deteriorate. The first was that capital markets essentially froze. Equity, debt and credit markets shut down. Future growth opportunities have been and are expected to continue to be constrained by the lack of access to liquidity in the financial markets.

 

The second impact to the industry was that fear of global recession resulted in a significant decline in oil and gas prices. In addition to the decline in oil and gas prices, the differential from NYMEX pricing to our sales point for our Cherokee Basin gas production has widened and is still at unprecedented levels of volatility.

 

Our operations and financial condition are significantly impacted by these prices. During the year ended December 31, 2008, the NYMEX monthly gas index price (last day) ranged from a high of $13.58 per Mmbtu to a low of $5.29 per Mmbtu. Natural gas prices came under pressure in the second half of the year as a result of lower domestic product demand that was caused by the weakening economy and concerns over excess supply of natural gas. In the Cherokee Basin, where we produce and sell most of our gas, there has been a widening of the historical discount of prices in the area to the NYMEX pricing point at Henry Hub as a result of elevated levels of natural gas drilling activity in the region and a lack of pipeline takeaway capacity. During 2008, this discount (or basis differential) in the Cherokee Basin ranged from $0.67 per Mmbtu to $3.62 per Mmbtu.

 

The spot price for NYMEX crude oil in 2008 ranged from a high of $145.29 per barrel in early July to a low of $33.87 per barrel in late December. The volatility in oil prices during the year was a result of the worldwide recession, geopolitical activities, worldwide supply disruptions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets as well as domestic concerns about refinery utilization and petroleum product inventories pushing prices up during the first half of the year. Due to our relatively low level of oil production relative to gas and our existing commodity hedge positions, the volatility of oil prices had less of an effect on our operations.

 

Overall, as a result, our operating profitability was seriously adversely affected during the second half of 2008 and is expected to continue to be impaired during 2009. While our existing commodity hedge position mitigates the impact of commodity price declines, it does not eliminate the potential effects of changing commodity prices. See Item 1A. “Risk Factors — Risks Related to Our Business — The current financial crisis and economic conditions may have a material adverse impact on our business and financial condition that we cannot predict.”

Management Personnel Changes

 

In connection with the investigation of the Transfers, Jerry D. Cash, the former Chairman of the Board of our general partner and the Chief Executive Officer, resigned on August 23, 2008, and David E. Grose, the former Chief Financial Officer, was placed on administrative leave on August 22, 2008. On August 24, 2008, the Chief Operating Officer, David Lawler, was appointed President, and Jack Collins, Executive Vice President of Investor Relations, was appointed Interim Chief Financial Officer. On September 13, 2008, Mr. Grose was terminated from all positions. After an extensive external search, Eddie LeBlanc became the Chief Financial Officer on January 9, 2009, with Mr. Collins becoming Executive Vice President of Finance/Corporate Development. On May 7, 2009, Mr. Lawler was appointed Chief Executive Officer.

 

NASDAQ Non-compliance

 

Our common units are currently listed on the NASDAQ Global Market. On November 19, 2008, we received a letter from the staff of NASDAQ indicating that, because of our failure to timely file our Form 10-Q for the quarter ended September 30, 2008, we no longer complied with the continued listing requirements set forth in NASDAQ Marketplace Rule 4310(c)(14) (now Rule 5250(c)(1)). As permitted by NASDAQ rules, on January 20, 2009, we timely submitted a plan to NASDAQ staff to regain compliance. Following a review of this plan, NASDAQ staff granted us an extension until May 18, 2009 to file our Form 10-Q. We did not file our Form 10-Q for the quarter ended September 30, 2008 on that date. On May 18, 2009, we received a staff determination notice (the “Staff Determination”) from NASDAQ stating that our common units were subject to delisting since we were not in compliance with the filing requirements for continued listing. A hearing to appeal the Staff Determination was held on June 11, 2009 before the NASDAQ Listing Qualifications Hearing Panel (the “Panel”). On July 15, 2009, we received a letter from NASDAQ advising us that the Panel had granted our request for continued listing on NASDAQ. The terms of the Panel’s decision include a condition that we file our quarterly reports on Form 10-Q for the quarters ended September 30, 2008 and March 31, 2009 by August 15, 2009. If we have not filed all of our delinquent periodic reports by August 15, 2009, there can be no assurances that the Panel will grant a further extension to allow us additional time to file such reports or that our common units will not be delisted.

 

Credit Agreement Amendments

 

In October 2008, we and our operating subsidiary Quest Cherokee entered into amendments to our Second Lien Senior Term Loan Agreement (the “Second Lien Loan Agreement”) and our Amended and Restated Credit Agreement (our “First Lien Credit Agreement”, and collectively our “credit agreements”) that, among other things, amended and/or waived certain of the representations and covenants contained in each credit agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result of (1) the Transfers and (2) not timely settling certain intercompany accounts among us, QRCP and Quest Midstream. The amendment to our Second Lien Loan Agreement also extended the maturity date thereof from January 11, 2009 to September 30, 2009 due to our inability to refinance the Second Lien Loan Agreement as a result of a combination of things including the ongoing investigation and the global financial crisis. The amendments also restricted our ability to pay distributions.

 

In June 2009, we and Quest Cherokee entered into amendments to our credit agreements that, among other things, defer until August 15, 2009 the obligation to deliver unaudited consolidated balance sheets and related statements of income and cash flows for the fiscal quarters ending September 30, 2008 and March 31, 2009.

 

In July 2009, Quest Cherokee received notice from RBC that the borrowing base under the First Lien Credit Agreement had been reduced from $190 million to $160 million, which, following the principal payment discussed below, resulted in the outstanding borrowings under the First Lien Credit Agreement exceeding the new borrowing base by $14 million (the “Borrowing Base Deficiency”). 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. The strike prices on the derivative contracts that Quest Cherokee did not exit were set to market prices at the time. At the same time, Quest Cherokee entered into new natural gas price derivative contracts to increase the total amount of its future proved developed natural gas production hedged to approximately 85% through 2013. On June 30, 2009, using these proceeds, Quest Cherokee made a principal

payment of $15 million on the First Lien Credit Agreement. On July 8, 2009, Quest Cherokee repaid the $14 million Borrowing Base Deficiency.

 

See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreements” for additional information regarding our credit agreements.

 

Suspension of Distributions

 

The board of directors of our general partner suspended distributions on our subordinated units for the third quarter of 2008 and on all units starting with the distribution for the fourth quarter of 2008. Factors significantly impacting the determination that there was no available cash for distribution include the following:

 

 

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. In October of 2008, our credit agreements were amended. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreements.” The amended 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.

 

Intercompany Accounts

 

As part of the investigation, we determined that our former chief financial officer had not been promptly settling intercompany accounts among us, Quest Midstream and QRCP. Intercompany balances as of September 30, 2008 were quantified and have been paid. We paid Quest Midstream $4.0 million, including interest, in February 2009.

 

Cost-cutting Measures

 

In addition to the suspension of distributions discussed above, during the third and fourth quarters of 2008, we took significant actions to reduce our costs and retain cash for our anticipated debt service requirements during 2009. Among other things, we significantly reduced our level of maintenance and expansion capital expenditures, our general partner and QRCP each elected Mr. LeBlanc as the new Chief Financial Officer, which allowed the termination of the consultants that had been hired to assist the interim chief financial officer, and QRCP eliminated 56 field level positions and 3 corporate office positions. We continue to evaluate additional options to further reduce our expenditures.

 

Decrease in Year-End Reserves; Impairment

 

Due to the low price for natural gas as of December 31, 2008 as described above, revisions resulting from further technical analysis (see Note 19 — Supplemental Information on Oil and Gas Producing Activities (Unaudited) to the accompanying consolidated financial statements) and production during the year, 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). As a result of this decrease, we recognized a non-cash impairment of $245.6 million for the year ended December 31, 2008. As a result, the lenders under our revolving credit facility reduced our borrowing base in July 2009. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Sources of Liquidity in 2009 and Capital Requirements.”

 

Seminole County Acreage Acquisition

 

In early February 2008, we purchased certain oil producing properties in Seminole County, Oklahoma from a private company for $9.5 million. In connection with the acquisition, we entered into crude oil swaps for approximately 80% of the estimated production from the property’s proved developed producing reserves at WTI-NYMEX prices per barrel of oil of approximately $96.00 in 2008, $90.00 in 2009, and $87.50 for 2010. The acquisition was financed with borrowings under our First Lien Credit Agreement. As of December 31, 2008, the properties had estimated net proved reserves of 588,800 Bbls, all of which were proved developed producing.

 

Settlement Agreements

 

As discussed above, we and QRCP filed lawsuits against Mr. Cash, the entity controlled by Mr. Cash that was used in connection with the Transfers and two former officers, who are the other owners of this controlled-entity, 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, his controlled-entity and the other owners to settle this litigation. Under the terms of the settlement agreements, QRCP received (1) approximately $2.4 million in cash and (2) 60% of the controlled-entity’s interest in a gas well located in Louisiana and a landfill gas development project located in Texas. While QRCP estimates the value of these assets to be less than the amount of the Transfers and the cost of the internal investigation, they represent the majority of the value of the controlled-entity. QRCP did not take Mr. Cash’s 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. We received all of Mr. Cash’s equity interest in STP, which owns certain oil producing properties in Oklahoma, as reimbursement for a portion of the costs of the internal investigation and the costs of the litigation against Mr. Cash that have been paid by us. We are in the process of establishing the value of the interest in STP.

 

2008 Operating Results

 

Our strategy prior to the events discussed above was to generate stable cash flows allowing us to increase distributable cash flow per unit over time. This strategy was supported by a talented engineering and operating team assembled over the last two years. These teams met or exceeded a number of performance-related goals that were established by management at the beginning of the year. For example, we planned to drill 325 wells in the Cherokee Basin in 2008. We connected 328 wells in eight months, three months ahead of schedule, and delivered the results within our capital budget for the year. We did not drill any wells during the final four months of the year due to limited capital availability and low commodity prices. In addition, we had historically struggled to maintain a low level of wells offline due to well failures. For December 2008, on average less than 2% of our approximately 2,500 Cherokee Basin wells were offline per day. This level of performance was achieved through the implementation of rigorous engineering reviews, statistical failure analysis and the latest de-liquification process control technology. Our net production for 2008 was 21.75 Bcfe, which is a 27.8% increase over our net production in 2007 of 17.02 Bcfe. We have also improved our safety culture by decreasing OSHA recordable incidents by 32% in 2008 as compared to 2007.

 

Recombination

 

Given the liquidity challenges we are facing, we have undertaken a strategic review of our assets and have evaluated and continue to evaluate transactions to dispose of assets, liquidate derivative contracts, or enter into new derivative contracts in order to raise additional funds for operations and/or to repay indebtedness. In addition, in the

current economic environment we believe the complexity and added overhead costs of QRCP’s corporate structure is negatively affecting our ability to restructure our indebtedness and raise additional equity. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.” On July 2, 2009, we, Quest Midstream, QRCP and other parties thereto entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which the three companies would recombine. The recombination would be effected by forming a new, yet to be named, publicly-traded corporation (“New Quest”) that, through a series of mergers and entity conversions, would wholly-own all three entities. The Merger Agreement follows the execution of a non-binding letter of intent by the three Quest entities that was publicly announced on June 3, 2009. New Quest would continue to develop the unconventional resources of the Cherokee and Appalachian Basins with a clear focus on value creation through efficient operations. While we anticipate 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 New Quest, the approval of the transaction by our unitholders, QRCP stockholders and the unitholders of Quest Midstream, and consents from each entity’s 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 New Quest would be owned approximately 33% by our current common unitholders (other than QRCP), approximately 44% by current Quest Midstream common unitholders, and approximately 23% by current QRCP stockholders.

 

Our Relationship with QRCP and Quest Midstream

 

QRCP is an integrated independent energy company engaged in the acquisition, exploration, development, production and transportation of oil and natural gas. QRCP controls us through its ownership of our general partner, which owns a 2% general partner interest in us as well as all of the incentive distribution rights.

 

Pursuant to a midstream services and gas dedication agreement, all of our natural gas production in the Cherokee Basin is connected into Quest Midstream’s approximately 2,173-mile natural gas gathering pipeline network. Quest Midstream is a privately owned master limited partnership, formed by QRCP to acquire and develop transmission and gathering assets in the midstream oil and natural gas industry. For additional descriptions concerning our relationships with QRCP and our other affiliates, see Item 13. “Certain Relationships and Related Transactions, and Director Independence” in this Annual Report on Form 10-K/A.

Organizational Structure

 

The following chart reflects our complete organizational structure and our relationship with QRCP and Quest Midstream. The chart excludes 15,000 common units issued, or to be issued, to our independent directors.

 

 

In connection with our initial public offering in 2007, we entered into the following agreements with QRCP:

 

Omnibus Agreement.   We, our general partner, and QRCP entered into an Omnibus Agreement, which governs QRCP’s and its affiliates’ relationships with us regarding the following matters:

 

 

QRCP’s maximum liability for its environmental indemnification obligations will not exceed $5 million, and it will not have any indemnification obligation for environmental claims or title defects until our aggregate losses exceed $500,000.

 

Management Agreement.   We, our general partner, and Quest Energy Service entered into a Management Services Agreement, under which Quest Energy Service provides acquisition services and general and administrative services, such as SEC reporting and filings, Sarbanes-Oxley compliance, accounting, audit, finance, tax, benefits, compensation and human resources administration, property management, risk management, land, marketing, legal and engineering to us, as directed by our general partner, for which we reimburse Quest Energy Service on a monthly basis for the reasonable costs of the services provided.

 

Description of Our Properties and Projects

 

Cherokee Basin

 

We produce CBM gas out of our properties located in the Cherokee Basin. The Cherokee Basin is located in southeastern Kansas and northeastern Oklahoma. Geologically, it is situated between the Forest City Basin to the

north, the Arkoma Basin to the south, the Ozark Dome to the east and the Nemaha Ridge to the west. The Cherokee Basin is a mature producing area with respect to conventional reservoirs such as the Bartlesville sandstones and the Mississippian limestones, which were developed beginning in the early 1900s.

 

The Cherokee Basin is part of the Western Interior Coal Region of the central United States. The coal seams we target for development are found at depths of 300 to 1,400 feet. The principal formations we target include the Mulky, Weir-Pittsburgh and the Riverton. These coal seams are blanket type deposits, which extend across large areas of the basin. Each of these seams generally range from two to five feet thick. Additional minor coal seams such as the Summit, Bevier, Fleming and Rowe are found at varying locations throughout the basin. These seams range in thickness from one to two feet.

 

The rock containing conventional gas, referred to as “source rock,” is usually different from reservoir rock, which is the rock through which the conventional gas is produced, while in CBM, the coal seam serves as both the source rock and the reservoir rock. The storage mechanism is also different. Gas is stored in the pore or void space of the rock in conventional gas, but in CBM, most, and frequently all, of the gas is stored by adsorption. This adsorption allows large quantities of gas to be stored at relatively low pressures. A unique characteristic of CBM is that the gas flow can be increased by reducing the reservoir pressure. Frequently, the coal bed pore space, which is in the form of cleats or fractures, is filled with water. The reservoir pressure is reduced by pumping out the water, releasing the methane from the molecular structure, which allows the methane to flow through the cleat structure to the well bore. Because of the necessity to remove water and reduce the pressure within the coal seam, CBM, unlike conventional hydrocarbons, often will not show immediately on initial production testing. Coalbed formations typically require extensive dewatering and depressuring before desorption can occur and the methane begins to flow at commercial rates. Our Cherokee Basin CBM properties typically dewater for a period of 12 months before peak production rates are achieved.

 

CBM and conventional gas both have methane as their major component. While conventional gas often has more complex hydrocarbon gases, CBM rarely has more than 2% of the more complex hydrocarbons. Once coalbed methane has been produced, it is gathered, transported, marketed and priced in the same manner as conventional gas. The CBM produced from our Cherokee Basin properties has an Mmbtu content of approximately 970 Mmbtu, compared to conventional natural gas hydrocarbon production which can typically vary from 1,050-1,300 Mmbtus.

 

The content of gas within a coal seam is measured through gas desorption testing. The ability to flow gas and water to the wellbore in a CBM well is determined by the fracture or cleat network in the coal. While, at shallow depths of less than 500 feet, these fractures are sometimes open enough to produce the fluids naturally, at greater depths the networks are progressively squeezed shut, reducing the ability to flow. It is necessary to provide other avenues of flow such as hydraulically fracturing the coal seam. By pumping fluids at high pressure, fractures are opened in the coal and a slurry of fluid and sand is pumped into the fractures so that the fractures remain open after the release of pressure, thereby enhancing the flow of both water and gas to allow the economic production of gas.

 

Cherokee Basin Projects

 

Historically, we have developed our CBM reserves in the Cherokee Basin on 160-acre spacing. However, during 2008 we developed some areas on 80-acre spacing. We are currently evaluating the results of this 80-acre spacing program. Our wells generally reach total depth in 1.5 days and our average cost in 2008 to drill and complete a well, excluding the related pipeline infrastructure, was approximately $135,000. We estimate that for 2009, our average cost for drilling and completing a well will be between $113,000 and $125,000 excluding the related pipeline infrastructure. For 2009, in the Cherokee Basin, we have budgeted approximately $3.8 million to drill seven new gross wells, connect and complete 49 existing gross wells, and connect and complete three existing salt water disposal wells. All of these new gas wells will be drilled on locations that are classified as containing proved reserves in our December 31, 2008 reserve report. In 2009, we also plan to recomplete an estimated 10 gross wells, and we budgeted another $1.9 million for equipment, vehicle replacement, and other capital purchases, including the replacement of some of our existing pumps with submersible pumps that we believe provide enhanced removal of water from the wells. In addition, we have budgeted $2.4 million related to lease renewals and extensions for acreage that is expiring in 2009. However, we intend to fund these capital expenditures only to the extent that we

have available cash from operations after taking into account our debt service. We can give no assurance that any such funds will be available.

 

We perforate and frac the multiple coal seams present in each well. Our typical Cherokee Basin multi-seam CBM well has net reserves of 130 Mmcf. Our general production profile for a CBM well averages an initial production rate of 5-10 Mcf/d (net), steadily rising for the first twelve months while water is pumped off and the formation pressure is lowered. A period of relatively flat production of 50-55 Mcf/d (net) follows the initial dewatering period for a period of approximately twelve months. After 24 months, production begins to decline. The standard economic life is approximately 15 years. Our completed wells rely on very basic industry technology.

 

Our development activities in the Cherokee Basin also include a program to recomplete CBM wells that produce from a single coal seam to wells that produce from multiple coal seams. During the year ended December 31, 2008, we recompleted approximately 10 wellbores in Kansas and an additional four wellbores in Oklahoma. For 2009, we plan to recomplete an estimated 10 gross wells. However, we intend to fund these recompletions only to the extent that we have available cash from operations after taking into account our debt service obligations. We can give no assurance that such funds will be available. We believe we have approximately 200 additional wellbores that are candidates for recompletion to multi-seam producers. The recompletion strategy is to add four to five additional pay zones to each wellbore, in a two-stage process at an average cost of approximately $16,000 per well. Adding new zones to a well has a brief negative effect on production by first taking the well offline to perform the work and then by introducing a second dewatering phase of the newly completed formations. However, in the long term, we believe the impact of the multi-seam recompletions will be positive as a result of an increase in the rate of production and the ultimate recoverable reserves available per well.

 

Wells are equipped with small pumping units to facilitate the dewatering of the producing coal seams. Generally, upon initial production, a single coal seam will produce 50-60 Bbls of water per day. A multi-seam completion produces about 150 Bbls of water per day. Eventually, water production subsides to 30-50 Bbls per day. Produced water is disposed through injection wells we drill into the underlying Arbuckle formation. One disposal well will generally handle the water produced from 25 CBM wells.

 

Appalachian Basin

 

The Appalachian Basin is one of the largest and oldest producing basins within the United States. It is a northeast to southwest trending, elongated basin that deepens with thicker sections to the east. This basin takes in southern New York, Pennsylvania, eastern Ohio, extreme western Maryland, West Virginia, Kentucky, extreme western/northwestern Virginia, and portions of Tennessee. The basin is bounded on the east by a line of metamorphic rocks known as the Blue Ridge province which is thrusted to the west over the basin margin. Most prospective sedimentary rocks containing hydrocarbons are found at depths of approximately 1,000-9,000 feet with shallowest production in areas where oil and gas are seeping from the outcrop. Most productive horizons are found in sedimentary strata of Pennsylvanian, Mississippian, Devonian, Silurian, and Ordovician age. The Appalachian Basin has been an active area for oil and gas exploration, production and marketing since the mid-1800s. Although deeper zones are of interest, the main exploration and development targets are the Mississippian and Devonian sections.

 

Our main area of interest is within West Virginia, where there are producing formations at depths of 1,500 feet to approximately 8,000 feet. Specifically, our main production targets are the lower Devonian Marcellus Shale, the shallow Mississippian (Big Injun, Maxton, Berea, Pocono, Big Lime), and the Upper Devonian (Riley, Benson, Java, Alexander, Elk, Cashaqua, Middlesex, West River and Genesee, including the Huron Shale members, Rhinestreet Shales). Although deeper targets are of interest (Onondaga and Oriskany), they are of lesser importance. The Mississippian formations are a conventional petroleum reservoir with the Devonian sections being a non-conventional energy resource.

 

The method for exploring and drilling these targets is different in several aspects. The Mississippian and Upper Devonian sections are explored through vertical drilling. The lower Marcellus section is explored by both vertical and horizontal drilling. The Mississippian section is identified by distinct sand and limestone zones with conventional porosity and permeability. Depths range from 1,000-2,500 feet deep. The Upper Devonian sands, siltstones, and shales are identified as multiple stacked pay lenses with depths ranging from 2,500-7,000 feet deep.

The Marcellus Shale ranges in depth from 5,900 feet in portions of West Virginia to 7,100 feet in other portions of West Virginia. In certain areas of our leasehold, vertical wells are drilled with combination completions in the Mississippian, Upper Devonian, and the Marcellus. Occasionally, vertical wells might only complete a single section of the three prospective pay intervals.

 

Appalachian Basin Projects

 

As discussed under “— Recent Developments,” in July 2008, we completed the acquisition of PetroEdge assets, which expanded our position in the Appalachian Basin. At December 31, 2008, our estimated net proved reserves in the Appalachian Basin totaled 10.9 Bcfe and were producing approximately 2.9 Mmcfe/d.

 

For 2009, we budgeted $1.4 million for artificial lift equipment, vehicle replacement and purchases and salt water disposal facilities. However, we intend to fund these capital expenditures only to the extent that we have available cash after taking into account our debt service and other obligations. We can give no assurance that any such funds will be available based on current commodity prices and other current conditions.

 

Seminole County, Oklahoma

 

Our Seminole County, Oklahoma oil producing property is located in south central Oklahoma. This mature oil producing property was originally discovered in 1926 and has undergone several periods of re-development since that time. Two producing horizons include the Hunton Limestone at approximately 4,100 feet and the First Wilcox Sand at approximately 4,300 feet. The Hunton Limestone is the main current producing horizon in the field. Produced water is disposed on-site. Primary oil recovery from the Hunton with vertical wells was limited by discontinuous porosity development in the Hunton reservoir. Early attempts to waterflood this horizon met with poor results. We plan to further develop the Hunton horizon with horizontal drilling.

 

Oil and Gas Data

 

Estimated Net Proved Reserves

 

The following table presents our estimated net proved oil and gas reserves relating to our oil and natural gas properties as of the dates presented based on our reserve reports as of the dates listed below. The data was prepared by the petroleum engineering firm Cawley, Gillespie & Associates, Inc. in Ft. Worth, Texas. We filed estimates of our oil and gas reserves for the calendar years 2008, 2007 and 2006 with the Energy Information Administration of the U.S. Department of Energy on Form EIA-23. The data on Form EIA-23 was presented on a different basis, and included 100% of the oil and gas volumes from our operated properties only, regardless of our net interest. The difference between the oil and gas reserves reported on Form EIA-23 and those reported in this table exceeds 5%. The standardized measure values shown in the table are not intended to represent the current market value of our estimated oil and gas reserves and do not reflect any hedges. Proved reserves at December 31, 2008 were determined using year-end prices of $44.60 per barrel of oil and $5.71 per Mcf of gas, compared to $96.10 per barrel of oil and $6.43 per Mcf of gas at December 31, 2007, and $61.06 per barrel of oil and $6.03 per Mcf of gas at December 31, 2006.

 

 

 

 

The data in the table above represents estimates only. Oil and gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and gas that are ultimately recovered. See Item 1A. “Risk Factors — Risks Related to Our Business — Our estimated proved reserves are based on assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”

Production Volumes, Sales Prices and Production Costs

 

The following table sets forth information regarding the oil and natural gas properties owned by us through our subsidiaries. The oil and gas production figures reflect the net production attributable to our revenue interest and are not indicative of the total volumes produced by the wells. All sales data excludes the effects of our derivative financial instruments.

 

 

Producing Wells and Acreage

 

The following tables set forth information regarding our ownership of productive wells and total acres as of December 31, 2006, 2007 and 2008. For purposes of the table below, productive wells consist of producing wells and wells capable of production.

 

 

 

 

 

 

 

As of December 31, 2008, in the Cherokee Basin, we had 332,401 net developed acres and 225,202 net undeveloped acres. Developed acres are acres spaced or assigned to productive wells/units based upon governmental authority or standard industry practice. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas, regardless of whether such acreage contains proved reserves.

 

Drilling Activities

 

The table below sets forth the number of wells completed at any time during the period, regardless of when drilling was initiated. Our drilling, recompletion, abandonment, and acquisition activities for the periods indicated are shown below (this information is inclusive of all basins and areas):

 

 

 

 

Operations

 

General

 

As the operator of wells in which we have an interest, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Under the management services agreement,

Quest Energy Service manages all of our properties and employs production and reservoir engineers, geologists and other specialists. We employ our Cherokee Basin and Appalachian Basin field personnel through QCOS.

 

Field operations conducted by our personnel include duties performed by “pumpers” or employees whose primary responsibility is to operate the wells. Other field personnel are experienced and involved in the activities of well servicing, the development and completion of new wells and the construction of supporting infrastructure for new wells (such as electric service, salt water disposal facilities, and gas feeder lines). The primary equipment categories owned by us are trucks, well service rigs, stimulation assets and construction equipment. We utilize third party contractors on an “as needed” basis to supplement our field personnel.

 

In the Cherokee Basin, we provide, on an in-house basis, many of the services required for the completion and maintenance of our CBM wells. Internally sourcing these functions significantly reduces our reliance on third party contractors, which typically provide these services. We are also able to realize significant cost savings because we can reduce delays in executing our plan of development, avoid paying price markups and are able to purchase our own supplies at bulk discounts. We rely on third party contractors to drill our wells. Once a well is drilled, either we or a third party contractor will run the casing. We will perform the cementing, fracturing, stimulation and complete our own well site construction. We have our own fleet of 24 well service units that we use in the process of completing our wells, and to perform remedial field operations required to maintain production from our existing wells. In the Appalachian Basin, we rely on third party contractors for these services.

 

Oil and Gas Leases

 

As of December 31, 2008, we had approximately 4,000 leases covering approximately 559,084 net acres. The typical oil and gas lease provides for the payment of royalties to the mineral owner for all oil or gas produced from any well drilled on the lease premises. This amount ranges from 12.5% to 18.75% resulting in an 81.25% to 87.5% net revenue interest to us.

 

Because the acquisition of oil and gas leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are sometimes held by other oil and gas operators. In order to gain the right to drill these leases, we may purchase leases from other oil and gas operators. In some cases, the assignor of such leases will reserve an overriding royalty interest, ranging from 3.125% to 16.5% which further reduces the net revenue interest available to us to between 71.0% and 84.375%.

 

As of December 31, 2008, approximately 71% of our oil and gas leases were held by production, which means that for as long as our wells continue to produce oil or gas, we will continue to own those respective leases.

 

Gas Gathering

 

Midstream Services Agreement

 

We and Quest Midstream are parties to a midstream services and gas dedication agreement entered into on December 22, 2006, but effective as of December 1, 2006. Pursuant to the midstream services agreement, Quest Midstream gathers and provides certain midstream services, including dehydration, treating and compression, to us for all gas produced from our wells in the Cherokee Basin that are connected to Quest Midstream’s gathering system.

 

The initial term of the midstream services agreement expires on December 1, 2016, with two additional five-year extension periods that may be exercised by either party upon 180 days’ notice. The fees charged under the midstream services agreement are subject to renegotiation upon the exercise of each five-year extension period.

 

Under the midstream services agreement, we agreed to pay Quest Midstream an initial fee equal to $0.50 per Mmbtu of gas for gathering, dehydration and treating services and $1.10 per Mmbtu of gas for compression services, subject to an annual adjustment to be determined by multiplying each of the gathering services fee and the compression services fee by the sum of (i) 0.25 times the percentage change in the producer price index for the prior calendar year and (ii) 0.75 times the percentage change in the Southern Star first of month index for the prior calendar year. Such adjustment will be calculated within 60 days after the beginning of each year, but will be retroactive to the beginning of the year. Such fees will never be reduced below the initial rates described above. For

2008, the fees were $0.51 per Mmbtu of gas for gathering, dehydration and treating services and $1.13 per Mmbtu of gas for compression services. For 2009, the fees are $0.596 per Mmbtu of gas for gathering, dehydration and treating services and $1.319 per Mmbtu of gas for compression services. Such fees are subject to renegotiation in connection with each renewal period. In addition, at any time after each five year anniversary of the date of the midstream services agreement, each party will have a one-time option to elect to renegotiate the fees and/or the basis for the annual adjustment to the fees if the party believes there has been a material change to the economic returns or financial condition of either party. If the parties are unable to agree on the changes, if any, to be made to such terms, then the parties will enter into binding arbitration to resolve any dispute with respect to such terms.

 

In accordance with the midstream services agreement, we bear the cost to remove and dispose of free water from our gas prior to delivery to Quest Midstream and of all fuel requirements necessary to perform the gathering and midstream services, plus any lost and unaccounted for gas.

 

Quest Midstream has an exclusive option for sixty days to connect to its gathering system each of the gas wells that we develop in the Cherokee Basin. In addition, Quest Midstream will be required to connect to its gathering system, at its expense, any new gas wells that we complete in the Cherokee Basin if Quest Midstream would earn a specified internal rate of return from those wells. This rate of return is subject to renegotiation once after the fifth anniversary of the agreement and once during each renewal period at the election of either party. Quest Midstream also has the sole discretion to cease providing services on all or any part of its gathering system if it determines that continued operation is not economically justified. If Quest Midstream elects to do so, it must provide us with 90 days written notice and will offer us the right to purchase that part of the terminated system. If we do acquire that part of the system and it remains connected to any other portion of Quest Midstream’s gathering system, then we may deliver our gas from the terminated system to Quest Midstream’s system, and a fee for any services provided by Quest Midstream will be negotiated.

 

In addition, Quest Midstream agreed to install the saltwater disposal lines for our gas wells connected to Quest Midstream’s gathering system for an initial fee of $1.25 per linear foot and connect such lines to our saltwater disposal wells for a fee of $1,000 per well, subject to an annual adjustment based on changes in the Employment Cost Index for Natural Resources, Construction, and Maintenance. For 2008, the fees were $1.29 per linear foot to install saltwater disposal lines and $1,030 per well to connect such lines to our saltwater disposal wells. For 2009, the fees are $1.33 per linear foot to install saltwater disposal lines and $1,061 per well to connect such lines to our saltwater disposal wells.

 

Appalachian Gathering Agreement

 

Our subsidiary, Quest Cherokee, and Quest Eastern are parties to a gas transportation agreement effective as of July 1, 2008. Pursuant to the gas transportation agreement, Quest Eastern receives, transports and processes all gas delivered by Quest Cherokee at certain specified receipt points and redelivers to or for the account of Quest Cherokee at the delivery points the thermal equivalent of the gas received from Quest Cherokee.

 

Pursuant to the gas transportation agreement, Quest Cherokee has agreed to pay Quest Eastern a fee equal to $0.70 per Mmbtu. Should Quest Cherokee fail to timely remit the full amount owed to Quest Eastern when due, unless such failure is caused by Quest Cherokee disputing in good faith the amount owed to Quest Eastern, Quest Cherokee must pay interest on the unpaid and undisputed portion, which will accrue at a rate equal to prime plus 1%.

 

The gas transportation agreement will continue until terminated upon 90 days written notice by either party. Upon termination of the agreement, Quest Eastern may require Quest Cherokee to resize the compression within Quest Eastern’s infrastructure and facilities to the capacity necessary without Quest Cherokee’s gas as of the date of termination.

 

In accordance with the gas transportation agreement, Quest Eastern has the right to decrease or halt the receipt of Quest Cherokee’s gas without prior notification if at any time Quest Cherokee’s gas will materially adversely affect the normal operation of Quest Eastern’s facilities due to the failure of gas delivered by Quest Cherokee to meet the quality standards as outlined in the agreement.

Marketing and Major Customers

 

We market our own natural gas. In the Cherokee Basin for 2008, substantially all of our gas production was sold to ONEOK Energy Marketing and Trading Company (“ONEOK”). More than 71% of our natural gas production was sold to ONEOK and 21% was sold to Tenaska Marketing Ventures in 2007. More than 91% of our natural gas production was sold to ONEOK in 2006.

 

Our oil in the Cherokee Basin is currently being sold to Coffeyville Refining. Previously, it had been sold to Plains Marketing, L.P.

 

During the year ended December 31, 2008, we sold 100% of our oil in Seminole County, Oklahoma to Sunoco Partners Marketing & Terminals L.P. under sale and purchase contracts, which have varying terms and cannot be terminated by either party, other than following an event of default.

 

Approximately 73% of our 2008 Appalachian Basin production was sold to Dominion Field Services under contracts with a mix of fixed price and index based sales in place at the time of the PetroEdge acquisition in July 2008. Reliable Wetzel transported and sold approximately 10% of our 2008 Appalachian Basin production under a market sensitive contract that expires in 2010. Another 8% was sold to Hess Corporation under a mix of fixed price and index based sales. The remainder of the Appalachian production was sold to various purchasers under market sensitive pricing arrangements. None of these remaining sales exceeded 4% of total Appalachian Basin production. Due to the history of problematic Northeastern pipeline constraints, we have secured a firm transportation agreement to ensure uninterrupted deliveries of our natural gas production.

 

Under various sale and purchase contracts, 100% of our oil produced in the Appalachian Basin was sold to Appalachian Oil Purchasers, a division of Clearfield Energy.

 

If we were to lose any of these oil or gas purchasers, we believe that we would be able to promptly replace them.

 

Commodity Derivative Activities

 

We sell the majority of our gas in the Cherokee Basin based on the Southern Star first of month index, with the remainder sold on the daily price on the Southern Star index. We sell the majority of our gas in the Appalachian Basin based on the Dominion Southpoint index, with the remainder sold on local basis. We sell the majority of our oil production under a contract priced at a fixed discount to NYMEX oil prices. Due to the historical volatility of oil and natural gas prices, we have implemented a hedging strategy aimed at reducing the variability of prices we receive for the sale of our future production. While we believe that the stabilization of prices and production afforded to us by providing a revenue floor for our production is beneficial, this strategy may result in lower revenues than we would have if we were not a party to derivative instruments in times of rising oil or natural gas prices. As a result of rising commodity prices, we may recognize additional charges to future periods. We hold derivative contracts based on Southern Star and NYMEX natural gas and oil prices and we have fixed price sales contracts with certain customers in the Appalachian Basin. These derivative contracts and fixed price contracts mitigate our risk to fluctuating commodity prices but do not eliminate the potential effects of changing commodity prices. Our derivative contracts limit our exposure to basis differential risk as we generally enter into derivative contracts that are based on the same indices on which the underlying sales contracts are based or by entering into basis swaps for the same volume of hedges that settle based on NYMEX prices.

 

As of December 31, 2008, we held derivative contracts and fixed price sales contracts totaling approximately 39.1 Bcf of natural gas and 66,000 Bbls of oil through 2012. Approximately 14.6 Bcf of our Cherokee Basin natural gas production is hedged utilizing Southern Star contracts at a weighted average price of $7.78/Mmbtu for 2009 and approximately 16.5 Bcf of our Cherokee Basin natural gas production is hedged utilizing Southern Star contracts at a weighted average price of $7.42/Mmbtu for 2010 through 2012. Approximately 0.75 Bcf of our Appalachian Basin natural gas production is hedged utilizing NYMEX contracts at a weighted average price of $11.00/Mmbtu for 2009 and approximately 7.2 Bcf of our Appalachian Basin natural gas is hedged utilizing NYMEX contracts at a weighted average price of $9.77/Mmbtu for 2010 through 2012. Our fixed price sales contracts hedge approximately 0.65 Bcf of our Appalachian Basin natural gas production at a weighted average price of $8.38/Mmbtu in 2009 and 0.1 Bcf of our Appalachian Basin natural gas production at a weighted average price of $8.96/Mmbtu in 2010.

As of December 31, 2008, approximately 36,000 Bbls of our Seminole County crude oil production is hedged utilizing NYMEX contracts at a weighted average price of $90.07/Bbl for 2009 and approximately 30,000 Bbls of our Seminole County crude oil production is hedged utilizing NYMEX contracts for 2010 through 2012 at a weighted average price of $87.50/Bbl. For more information on our derivative contracts, see Note 6 — Derivative Financial Instruments and Note 7 — Financial Instruments, in the notes to the consolidated financial statements in Item 8 of this Form 10-K/A.

 

Competition

 

We operate in a highly competitive environment for acquiring properties, marketing oil and gas and securing trained personnel. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and gas industry.

 

None of QRCP or any of its affiliates is restricted from competing with us outside the Cherokee Basin. QRCP or its affiliates may acquire, invest in or dispose of assets outside the Cherokee Basin in the future without any obligation to offer us the opportunity to purchase or own interests in those assets.

 

We are also affected by competition for drilling rigs, completion rigs and the availability of related equipment. In the past, the oil and gas industry has experienced shortages of drilling and completion rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant increases in the prices for this equipment and personnel. We are unable to predict when, or if, such shortages may occur or how they would affect our exploration and development program.

 

Competition is also strong for attractive oil and gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily when attempting to make further acquisitions.

 

Title to Properties

 

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of development operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence development operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition of producing oil and gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and gas industry.

 

Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or will materially interfere with our use in the operation of our business. In some cases lands over which leases have been obtained are subject to prior liens which have not been subordinated to the leases. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects.

 

On a small percentage of our acreage (less than 1.0%), the landowner in the past transferred the rights to the coal underlying their land to a third party. With respect to those properties, we have obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying those lands. In Kansas, absent a specific conveyance of the CBM in the deed conveying the coal, the law is clear that the coal owner does not own the CBM. In Oklahoma, the

law is unsettled as to whether the owner of the gas rights or the coal rights is entitled to the CBM gas. We are currently involved in litigation with the owner of the coal rights on these lands to determine who has the rights to the CBM gas.

 

Seasonal Nature of Business

 

Seasonal weather conditions and lease stipulations can limit our development activities and other operations and, as a result, we seek to perform a significant percentage of our development during the spring and summer months. These seasonal anomalies can pose challenges for meeting our well development objectives and increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

 

In addition, freezing weather, winter storms and flooding in the spring and summer have in the past resulted in a number of our wells being off-line for a short period of time, which adversely affects our production volumes and revenues and increases our lease operating costs due to the time spent by field employees to bring the wells back on-line.

 

Generally, but not always, the demand for gas decreases during the summer months and increases during the winter months thereby affecting the price we receive for gas. Seasonal anomalies such as mild winters and hot summers sometimes lessen this fluctuation.

 

Environmental Matters and Regulation

 

General

 

Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

 

 

These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on our operating costs.

 

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

 

Waste Handling

 

The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous solid wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development and production of oil and gas are currently excluded from regulation as hazardous wastes under RCRA. However, 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. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils, which may be regulated as hazardous wastes.

 

Comprehensive Environmental Response, Compensation and Liability Act

 

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, imposes joint and several liabilities, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain environmental studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

 

We currently own, lease or operate numerous properties that have been used for oil and gas exploration and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. In fact, there is evidence that petroleum spills or releases have occurred in the past at some of the properties owned or leased by us. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform plugging or pit closure operations to prevent future contamination.

 

Water Discharges

 

The Clean Water Act (“CWA”) and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants in waste water and storm water, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The CWA regulates storm water run-off from oil and gas production operations and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of the CWA may require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. Federal and state regulatory agencies can also impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

 

Our operations also produce wastewaters that are disposed via underground injection wells. These activities are regulated by the Safe Drinking Water Act (“SDWA”) and analogous state and local laws. The underground injection well program under the SDWA classifies produced wastewaters and imposes controls relating to the drilling and operation of the wells as well as the quality of the injected wastewaters. This program is designed to protect drinking water sources and requires a permit from the EPA or the designated state agency. Currently, our operations comply with all applicable requirements and have a sufficient number of operating injection wells. However, a change in the regulations or the inability to obtain new injection well permits in the future may affect our ability to dispose of the produced waters and ultimately affect the results of operations.

The primary federal law for oil spill liability is the Oil Pollution Act, or OPA, which addresses three principal areas of oil pollution: prevention, containment, and cleanup. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.

 

Air Emissions

 

The Federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain or strictly comply with air permits containing various emissions and operational limitations or utilize specific emission control technologies to limit emissions. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Moreover, depending on the state-specific statutory authority, states may be able to impose air emissions limitations that are more stringent than the federal standards imposed by EPA. Federal and state regulatory agencies can also impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations.

 

Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas, may require oil and gas exploration and production operations to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some oil and gas facilities may be included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the CAA. Failure to comply with these requirements could subject a regulated entity to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions. Oil and gas exploration and production facilities may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

 

Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or use specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. Historically, air pollution control has become more stringent over time. This trend is expected to continue. The cost of technology and systems to control air pollution to meet regulatory requirements is significant today. These costs are expected to increase as air pollution control requirements increase. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

 

Legislative and regulatory measures to address concerns that emissions of certain gases, commonly referred to as “greenhouse gases” (“GHGs”), may be contributing to warming of the Earth’s atmosphere are in various phases of discussions or implementation at the international, national, regional, and state levels. The oil and gas industry is a direct source of certain GHG emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. In the United States, federal legislation requiring GHG controls may be enacted by the end of 2009. In addition, the EPA is considering initiating a rulemaking to regulate GHGs as a pollutant under the CAA. Furthermore, the EPA recently issued proposed regulations that would require the economy-wide monitoring and reporting of GHG emissions on an annual basis, including extensive GHG monitoring and reporting requirements. The rule as proposed does not cover onshore petroleum and natural gas production, but the EPA has asked for comment on whether onshore petroleum and natural gas production should be subject to the rule in the future. Although this proposed rule would not control GHG emission levels from any facilities, if it applied to us, it would still cause us to incur monitoring and reporting costs. The EPA has also recently proposed findings that GHGs in the atmosphere endanger public health and welfare, and that emissions from mobile sources cause or contribute to GHGs in the atmosphere. These proposed findings, if finalized as proposed, would not immediately affect our operations, but standards eventually promulgated pursuant to these findings could affect our operations and ability to obtain air permits for new or modified

facilities. Legislation and regulations are also in various stages of discussions or implementation in many of the states in which we operate. Lawsuits have been filed seeking to force the federal government to regulate GHG emissions under the CAA and to require individual companies to reduce GHG emissions from their operations. These and other lawsuits may result in decisions by state and federal courts and agencies that could impact our operations and ability to obtain certifications and permits to construct future projects.

 

Passage of climate change legislation or other federal or state legislative or regulatory initiatives that regulate or restrict GHG emissions in areas in which we conduct business could adversely affect the demand for oil and gas, and depending on the particular program adopted, could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions and/or administer and manage a GHG emissions program. At this time, it is not possible to accurately estimate how laws or regulations addressing GHG emissions would impact our business, but we do not believe that the impact on us will be any more burdensome to us that to any other similarly situated companies.

 

Hydrogen Sulfide

 

Hydrogen sulfide gas is a byproduct of sour gas treatment. Exposure to unacceptable levels of hydrogen sulfide (known as sour gas) is harmful to humans, and prolonged exposure can result in death. We employ numerous safety precautions to ensure the safety of our employees. There are various federal and state environmental and safety requirements that apply to facilities using or producing hydrogen sulfide gas. Notwithstanding compliance with such requirements, common law causes of action are available to persons damaged by exposure to hydrogen sulfide gas.

 

National Environmental Policy Act

 

Oil and gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. If we were to conduct any exploration and production activities on federal lands in the future, those activities would need to obtain governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and gas projects.

 

Endangered Species Act

 

The Endangered Species Act (“ESA”) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Although we believe that our current operations do not affect endangered or threatened species or their habitats, the existence of endangered or threatened species in areas of future operations and development could cause us to incur additional mitigation costs or become subject to construction or operating restrictions or bans in the affected areas.

 

OSHA and Other Laws and Regulation

 

We are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The Occupational Safety and Health Administration’s hazard communication standard, EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other comparable laws.

 

We believe that we are in substantial compliance with all existing environmental and safety laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. For instance, we did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2008. Additionally, as of the date of this report, we are not aware of any environmental issues or claims that will require material capital expenditures

during 2009. However, accidental spills or releases may occur in the course of our operations, and we cannot assure you that we will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. Moreover, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our business, financial condition, or results of operations.

 

Other Regulation of the Oil and Gas Industry

 

The oil and gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

 

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

 

Drilling and Production

 

Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

 

 

Some state laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, some state conservation laws establish maximum rates of production from oil and gas wells. These laws generally prohibit the venting or flaring of gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, some states impose a production or severance tax with respect to the production and sale of oil, gas and gas liquids within its jurisdiction.

 

The Cherokee Basin has been an active oil and gas producing region for a number of years. Many of our properties had abandoned oil and conventional gas wells on them at the time the current lease was entered into with the landowner. A number of these wells remain unplugged or were improperly plugged by a prior landowner or operator. Many of the former operators of these wells have ceased operations and cannot be located or do not have the financial resources to plug these wells. We believe that we are not responsible for plugging an abandoned well on one of our leases, unless we have used, attempted to use or invaded the abandoned well bore in our operations on the land or have otherwise agreed to assume responsibility for plugging the wells. The Kansas Corporation Commission’s current interpretation of Kansas law is consistent with our position.

State Regulation

 

The various states regulate the drilling for, and the production and sale of, oil and gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Kansas currently imposes a severance tax on the gross value of oil and gas produced from wells having an average daily production during a calendar month with a gross value of more than $87 per day. Kansas also imposes oil and gas conservation assessments per barrel of oil and per 1,000 cubic feet of gas produced. In general, oil and gas leases and oil and gas wells (producing or capable of producing), including all equipment associated with such leases and wells, are subject to an ad valorem property tax.

 

Oklahoma imposes a monthly gross production tax and excise tax based on the gross value of the oil and gas produced. Oklahoma also imposes an excise tax based on the gross value of oil and gas produced. All property used in the production of oil and gas is exempt from ad valorem taxation if gross production taxes are paid. Lastly, the rate of taxation of locally assessed property varies from county to county and is based on the fair cash value of personal property and the fair cash value of real property.

 

West Virginia imposes a severance tax equal to five percent of the gross value of oil and gas produced and a similar severance tax on CBM produced. West Virginia also imposes an additional annual privilege tax equal to 4.7 cents per Mcf of natural gas produced. New York imposes an annual oil and gas charge based on the amount of oil or natural gas produced each year.

 

States may regulate rates of production and may establish maximum daily production allowables from oil and gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may limit the amounts of oil and gas that may be produced from our wells and may limit the number of wells or locations drilled.

 

Gas Marketing

 

The availability, terms and cost of transportation significantly affect sales of gas. The interstate transportation and sale for resale of gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission or FERC. Federal and state regulations govern the price and terms for access to gas pipeline transportation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the gas industry, most notably interstate gas transmission companies that remain subject to the FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the gas industry, and these initiatives generally reflect more light handed regulation. We cannot predict the ultimate impact of these regulatory changes to our gas marketing operations, and we note that some of the FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other gas marketers with which we compete.

 

The Energy Policy Act of 2005, or EP Act 2005, gave the FERC increased oversight and penalty authority regarding market manipulation and enforcement. EP Act 2005 amended the Natural Gas Act of 1938, or NGA, to prohibit market manipulation and also amended the Natural Gas Policy Act of 1978, or NGPA, to increase civil and criminal penalties for any violations of the NGA, NGPA and any rules, regulations or orders of the FERC to up to $1,000,000 per day, per violation. In addition, the FERC issued a final rule effective January 26, 2006 regarding market manipulation, which makes it unlawful for any entity, in connection with the purchase or sale of gas or transportation service subject to the FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud. This final rule works together with the FERC’s enhanced penalty authority to provide increased oversight of the gas marketplace.

 

Although gas prices are currently unregulated, FERC promulgated regulations in December 2007 requiring natural gas sellers to submit an annual report, beginning in July 2009, reporting certain information regarding natural gas purchases and sales (e.g., total volumes bought and sold, volumes bought and sold and index prices,

etc.). Additionally, Congress historically has been active in the area of gas regulation. We cannot predict whether new legislation to regulate gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and gas liquids are not currently regulated and are made at market prices.

 

Sales of Natural Gas

 

The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry, and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines.

 

Other

 

In addition to existing laws and regulations, the possibility exists that new legislation or regulations may be adopted which would have a significant impact on our operations or our customers’ ability to use gas and may require us or our customers to change their operations significantly or incur substantial costs. Additional proposals and proceedings that might affect the gas industry are pending before Congress, FERC, the Minerals Management Service, state commissions and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely.

 

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of injunctive relief or both. Moreover, changes in any of these laws and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

 

Management believes that our operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on our method of operations than on other similar companies in the energy industry. We have internal procedures and policies to ensure that our operations are conducted in substantial regulatory compliance.

 

Employees

 

At December 31, 2008, we employed approximately 177 field employees that perform development and maintenance services on our wells in offices located in Kansas, Oklahoma, Pennsylvania, and West Virginia. We entered into a management services agreement with Quest Energy Service pursuant to which it performs general and administrative services for us such as SEC reporting and filings, Sarbanes-Oxley compliance, accounting, audit, finance, tax, land, legal and engineering. We also have access to Quest Energy Service’s personnel and senior management team and access to its operational, commercial, technical, risk management and administrative infrastructure. Quest Energy Service has a staff of approximately 59 executive and administrative personnel. None of these employees are represented by labor unions or covered by any collective bargaining agreement. Quest Energy Service and our general partner believe that relations with these employees are satisfactory.

 

Administrative Facilities

 

Our principal executive offices are located at 210 Park Avenue, Suite 2750, Oklahoma City, Oklahoma 73102 which is also where QRCP’s principal executive offices are located. QRCP leases this office space. The office lease

is for 10 years expiring August 31, 2017 covering approximately 35,000 square feet with annual rental costs of approximately $631,000. We own three buildings located in Chanute, Kansas that are used for administrative offices, a geological laboratory, an operations terminal and a repair facility. We own an additional building and storage yard in Lenapah, Oklahoma.

 

Where To Find Additional Information

 

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, or Exchange Act, are made available free of charge on our website at www.qelp.net as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC. These documents are also available at the SEC’s website at www.sec.gov or you may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC 20549. Our website also includes our Code of Business Conduct and Ethics and the charter of the audit committee of the board of directors of our general partner. No information from either the SEC’s website or our website is incorporated herein by reference.

GLOSSARY OF SELECTED TERMS

 

The following is a description of the meanings of some of the oil and natural gas industry terms used in this Form 10-K/A.

 

Appalachian Basin.   One of the United States’ oldest oil and natural gas producing regions that extends from Alabama to Maine.

 

Bbl.   One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

 

Bcf.   One billion cubic feet of gas.

 

Bcfe.   One billion cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.

 

Btu or British Thermal Unit.   The quantity of heat required to raise the temperature of a one pound mass of water by one degree Fahrenheit.

 

CBM.   Coal bed methane.

 

Cherokee Basin.   A fifteen-county region in southeastern Kansas and northeastern Oklahoma.

 

Completion.   The installation of permanent equipment for the production of oil or gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

 

Developed acreage.   The number of acres that are allocated or assignable to productive wells or wells capable of production.

 

Development well.   A well drilled within the proved boundaries of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

Devonian Sands.   Sands generally younger and shallower than the Marcellus Shale that occur in portions of Ohio, New York, Pennsylvania, West Virginia, Kentucky and Tennessee and generally located at depths of less than 5,000 feet.

 

Dry hole.   A well found to be incapable of producing hydrocarbons in paying quantities.

 

Exploitation.   A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

 

Exploratory well.   A well drilled: a) to find and produce oil or gas in an area previously considered unproductive; b) to find a new reservoir in a known field, i.e., one previously producing oil and gas from another reservoir, or c) to extend the limit of a known oil or gas reservoir.

 

Field.   An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

 

Frac/fracturing.   The method used to increase the deliverability of a well by pumping a liquid or other substance into a well under pressure to crack and prop open the hydrocarbon formation.

 

Gas.   Hydrocarbon gas found in the earth, composed of methane, ethane, butane, propane and other gases.

 

Gathering system.   Pipelines and other equipment used to move gas from the wellhead to the trunk or the main transmission lines of a pipeline system.

 

Gross acres or gross wells.   The total acres or wells, as the case may be, in which we have a working interest.

 

Horizon or formation.   The section of rock, from which gas is expected to be produced.

 

Marcellus Shale.   A black, organic-rich shale formation in the Appalachian Basin that occurs in much of Ohio, West Virginia, Pennsylvania and New York and portions of Maryland, Kentucky, Tennessee and Virginia. The fairway of the Marcellus Shale is generally located at depths between 3,500 and 8,000 feet and ranges in thickness from 50 to 150 feet.

Mcf.   One thousand cubic feet of gas.

 

Mcf/d.   One Mcf per day.

 

Mcfe.   One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.

 

Mmbtu.   One million British thermal units.

 

Mmcf.   One million cubic feet of gas.

 

Mmcf/d.   One Mmcf per day.

 

Mmcfe.   One million cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.

 

Mmcfe/d.   One million cubic feet equivalent per day.

 

Net acres or net wells.   The sum of the fractional working interests owned in gross acres or wells, as the case may be.

 

Net production.   Production that is owned by us less royalties and production due others.

 

Net revenue interest.   The percentage of revenues due an interest holder in a property, net of royalties or other burdens on the property.

 

NGLs.   Natural gas liquids being the combination of ethane, propane, butane and natural gasoline that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

 

NYMEX.   The New York Mercantile Exchange.

 

Oil.   Crude oil, condensate and NGLs.

 

Permeability.   The ability, or measurement of a rock’s ability, to transmit fluids, typically measured in darcies or millidarcies.

 

Perforation.   The making of holes in casing and cement (if present) to allow formation fluids to enter the well bore.

 

Productive well.   A well that produces commercial quantities of hydrocarbons exclusive of its capacity to produce at a reasonable rate of return.

 

Proved developed non-producing reserves.   Proved developed reserves expected to be recovered from zones behind casings in existing wells.

 

Proved developed reserves.   Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. This definition of proved developed reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

 

Proved reserves.   The estimated quantities of crude oil, natural gas and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. This definition of proved reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

 

Proved undeveloped reserves.   Proved reserves that are expected to be recovered from new wells drilled to known reservoirs on acreage yet to be drilled for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

 

Recompletion.   The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reserve.   That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.

 

Reserve-to-production ratio.   This ratio is calculated by dividing estimated net proved reserves by the production from the previous year to estimate the number of years of remaining production.

 

Reservoir.   A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

 

Royalty Interest.   A real property interest entitling the owner to receive a specified portion of the gross proceeds of the sale of oil and natural gas production or, if the conveyance creating the interest provides, a specific portion of oil or natural gas produced, without any deduction for the costs to explore for, develop or produce the oil and gas. A royalty interest owner has no right to consent to or approve the operation and development of the property, while the owners of the working interests have the exclusive right to exploit the mineral on the land.

 

Shut in.   To close down a well temporarily.

 

Standardized measure.   The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Our standardized measure does not reflect any future income tax expenses, for the successor period, because we are not subject to federal income taxes. Standardized measure does not give effect to derivative transactions.

 

Unconventional resource development.   A development in which the targeted reservoirs generally fall into three categories: (1) tight sands, (2) coal beds, and (3) gas shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require stimulation treatments or other special recovery processes in order to produce economic flow rate.

 

Undeveloped acreage.   Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas regardless of whether or not such acreage contains proved reserves.

 

Working interest.   The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

 

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. The following risk factors should be carefully considered together with all of the other information included in this report. If any of the following risks and uncertainties described below or elsewhere in this report were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we may not be able to restart paying distributions on our common units, the trading price of our common units could decline, and unitholders could lose all or part of their investment.

 

Risks Related to Our Business

 

Our independent registered public accounting firm has expressed substantial doubt about our ability to continue as a going concern.

 

The independent auditor’s report accompanying the audited consolidated financial statements included herein contains a statement expressing substantial doubt as to our ability to continue as a going concern. 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, to a lesser degree, the cash expenditures resulting from the investigation related to the Transfers. Please read Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.” Unless we are able to reprice our existing derivative contracts or enter into new derivative contracts, restructure our indebtedness, or complete some other strategic transaction including the Recombination, 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. Furthermore, the presence of this concern may have an adverse impact on our relationship with third parties with whom we do business, including our customers, vendors and employees and could make it more challenging for us to raise additional financing or refinance our existing indebtedness.

 

The board of directors of our general partner suspended quarterly distributions and we are unable to estimate when distributions may be resumed.

 

Factors significantly impacting the determination that there was no available cash for distribution included the following:

 

 

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 be resumed.

 

Further, our credit agreements contain, and future debt agreements may contain, restrictions on our ability to pay distributions.

We have identified significant and pervasive material weaknesses in our internal controls, which have and could continue to affect our ability to ensure timely and reliable financial reports and the ability of our auditors to attest to the effectiveness of our internal controls.

 

During management’s review of our internal controls as of December 31, 2008, control deficiencies that constituted material weaknesses related to the following items were identified:

 

 

These material weaknesses resulted in the misstatement of our audited consolidated financial statements as of December 31, 2007 and for the period from November 15, 2007 to December 31, 2007, and our 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 and the Predecessor’s audited consolidated financial statements as of and for the years ended December 31, 2005 and 2006 and for the period from January 1, 2007 to November 14, 2007, and the Predecessor’s unaudited consolidated financial statements as of and for the three months ended March 31, 2007 and as of and for the three and six months ended June 30, 2007 and as of and for the three and nine months ended September 30, 2007.

 

Based on management’s evaluation, because of the material weaknesses described above, management has concluded that our internal control over financial reporting was not effective as of December 31, 2008. Our independent registered public accounting firm, UHY LLP, has audited management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2008, and their report appears in this Annual Report on Form 10-K/A.

 

Under the management services agreement between us and Quest Energy Service, all of our financial reporting services are provided by Quest Energy Service. The measures taken to address the deficiencies identified, along with other measures we expect to be taken to improve our internal controls over financial reporting, may not be sufficient to address the deficiencies identified or ensure that our internal control over financial reporting is effective. If we are unable to provide reliable and timely financial external reports, our business and prospects could suffer material adverse effects. In addition, we may in the future identify further material weaknesses or significant deficiencies in our internal control over financial reporting.

 

Events of default are anticipated under our credit agreements, which could expose our assets to foreclosure or other collection efforts.

 

Under the terms of our Second Lien Loan Agreement, we are required to make quarterly payments of $3.8 million. The next payment is due August 15, 2009. The balance remaining after the August 15, 2009 payment

is $29.8 million and is due on September 30, 2009. No assurance can be given that we will be able to repay such amount in accordance with the terms of the agreement.

 

If a default occurs and we are unable to obtain the necessary waivers from our lenders, our assets will be subject to foreclosure or other collection efforts and we may be forced to sell assets, issue additional equity securities or refinance our credit agreements at unfavorable prices.

 

Our borrowing base under our First Lien Credit Agreement could be redetermined to an amount that creates a deficiency that we do not have the ability to pay.

 

Our First Lien Credit Agreement limits the amount we can borrow to a borrowing base amount, determined by the lenders in their sole discretion. Outstanding borrowings in excess of the borrowing base will be required to be repaid (1) in four equal monthly installments following receipt of notice of the new borrowing base or (2) immediately if the borrowing base is reduced in connection with a sale or disposition of certain properties in excess of 5% of the borrowing base. Additionally, if the lenders’ exposure under the letters of credit exceeds this amount after all borrowings under the credit agreements have been repaid, Quest Energy will be required to provide additional collateral.

 

In July 2009, Quest Energy received notice from RBC that the borrowing base under the First Lien Credit Agreement had been reduced from $190 million to $160 million. There can be no assurance that the borrowing base will not be further reduced in the future.

 

Our credit agreements contain cross default provisions so a default under either of our credit agreements can cause a default under the other credit agreement, resulting in payment acceleration of both loans.

 

A default under either of our credit agreements would also cause a default under the other credit agreement, resulting in payment acceleration of both loans, which would lead to foreclosure on our assets, other collection efforts or our bankruptcy.

 

The Merger Agreement for the Recombination is subject to closing conditions that could result in the completion of the Recombination being delayed or not consummated, which could lead to liquidation or bankruptcy.

 

Under the Merger Agreement, completion of the Recombination is subject to the satisfaction of a number of closing conditions, including, among others, the arrangement of one or more satisfactory credit facilities for New Quest, the approval of the transaction by our unitholders, QRCP’s stockholders and the unitholders of Quest Midstream, and consents from each entity’s existing lenders. The required conditions to closing may not be satisfied in a timely manner, if at all, or, if permissible, waived, and the Recombination may not occur. Failure to consummate the Recombination could negatively impact our unit price, future business and operations, and financial condition. Any delay in the consummation of the Recombination or any uncertainty about the consummation of the Recombination may lead to liquidation or bankruptcy and may adversely affect our future business, growth, revenue and results of operations.

 

Failure to complete the proposed Recombination could negatively impact the market price of 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.

 

QRCP’s stockholders, our unitholders and Quest Midstream’s unitholders may not approve the matters relating to the Recombination if presented to them. If the Merger Agreement for the Recombination is not agreed to or if the Recombination is not completed for any reason, we could be subject to several risks that we would not otherwise face including the following:

 

 

 

The realization of any of these risks may materially adversely affect our business, financial results, and financial condition.

 

A default by QRCP under its credit agreement could result in a change of control of our general partner, which would be an event of default under our credit agreements and could adversely affect our operating results.

 

QRCP has pledged its ownership interest in our general partner to secure its term loan credit agreement. If QRCP were to default under its credit agreement, the lenders under QRCP’s credit agreement 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 agreements.

 

A change of control of our general partner would be an event of default under our credit agreements, which could result in a significant portion of our indebtedness becoming immediately due and payable. In addition, our ability to make distributions would be further restricted and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make accelerated repayments of our debt. In addition, our obligations under our credit agreements are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit agreements, the lenders could seek to foreclose on our assets.

 

In addition, a new owner of our general partner may replace our existing management with new management that is not familiar with our existing assets and operations, which could adversely affect our results of operations and the amount of cash available for distributions. Furthermore, it is possible that different persons could end up with control of our general partner and the general partner of Quest Midstream. In such an event, the advantages that we have from being under common control with Quest Midstream would be lost, which could adversely affect our results of operations and the amount of cash available for distributions.

 

The economic terms of the midstream services agreement may become unfavorable to us.

 

Under the midstream services agreement, we pay Quest Midstream a fee per MMBtu for gathering, dehydration and treating services and a compression fee. These fees are subject to an annual upward adjustment based on increases in the producer price index and the market price for gas for the prior calendar year. If these fees increase at a faster rate than the realized prices that we receive from sale of our gas, our results of operations and our ability to make cash distributions to our unitholders may be adversely affected. Such fees are subject to renegotiation in connection with each of the two five year renewal terms, beginning after the initial term expires on December 1, 2016. In addition, at any time after each five year anniversary of the date of the midstream services agreement, each party will have a one-time option to elect to renegotiate the fees and/or the basis for the annual adjustment to the fees if the party believes there has been a material change to the economic returns or financial condition of either party. If the parties are unable to agree on the changes, if any, to be made to such terms, then the parties will enter into binding arbitration to resolve any dispute with respect to such terms. The renegotiated fees may not be as favorable to us as the initial fees. For 2009, the fees are $0.596 per MMBtu of gas for gathering, dehydration and treating services and $1.319 per MMBtu of gas for compression services. For additional information regarding the midstream services agreement, please read “Business and Properties — Gas Gathering — Midstream Services Agreement” under Items 1 and 2 of this Form 10-K/A.

The gathering fees payable to Quest Midstream under the midstream services agreement in some cases could exceed the amount we are able to charge to royalty owners under our gas leases for gathering and compression.

 

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 fees to the royalty owners under the leases. We currently have leases covering approximately 97,000 net acres that generally permit only deductions for compression expenses, subject to certain exceptions. With respect to our remaining leases, we believe that we have the right to charge our royalty owners their proportionate share of the full amount of the fees due under the midstream services agreement. However, on August 3, 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. To the extent that we are unable to charge the full amount of these fees to our royalty owners, it will reduce our net income and the cash available for distribution to our unitholders.

 

The current financial crisis and economic conditions may have a material adverse impact on our business and financial condition that we cannot predict.

 

The economic conditions in the United States and throughout the world have deteriorated. Since the second half of 2008, global financial markets have been experiencing a period of unprecedented turmoil and upheaval characterized by extreme volatility and declines in prices of securities, diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse or sale of financial institutions and an unprecedented level of intervention from the U.S. federal government and other governments. In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide any new funding.

 

A continuation of the economic crisis could result in further reduced demand for oil and natural gas and keep downward pressure on the prices for oil and natural gas, which have fallen dramatically since reaching historic highs in July 2008. These price declines have negatively impacted our revenues and cash flows. Although we cannot predict the impacts on us of the deteriorating economic conditions, they could materially adversely affect our business and financial condition. For example:

 

 

Due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or if funding is available only on unfavorable terms, we may be unable to meet our obligations as they come due or be required to post collateral to support our obligations, or we may be unable to implement our development plans, enhance our existing business, complete acquisitions or

otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues, results of operations, or financial condition.

 

Energy prices are very volatile, and if commodity prices remain low or continue to decline for a temporary or prolonged period, our revenues, profitability and cash flows will decline. A sustained or further decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations.

 

The current global credit and economic environment has resulted in significantly lower oil and natural gas prices. The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities, and therefore their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on a variety of additional factors that are beyond our control, such as:

 

 

In the past, the prices of gas have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2008, the near month NYMEX natural gas futures price ranged from a high of $13.58 per Mmbtu to a low of $5.29 per Mmbtu.

 

Our revenue, profitability and cash flow depend upon the prices and demand for oil and gas, and a drop in prices can significantly affect our financial results and impede our growth. In particular, declines in commodity prices will:

 

 

Future price declines may result in a write-down of our asset carrying values.

 

Lower gas prices may not only decrease our revenues, profitability and cash flows, but also reduce the amount of oil and gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. Substantial decreases in oil and gas prices would render a significant

number of our planned exploration and development projects uneconomic. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil or gas properties for impairments. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and may, therefore, require a write-down of such carrying value. For example, for the year ended December 31, 2008, we had an impairment charge of $245.6 million. Due to a further decline in natural gas prices between December 31, 2008 and March 31, 2009, we expect to incur an additional impairment charge of approximately $85.0 million to $105.0 million for the quarter ended March 31, 2009. We may incur further impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our credit agreements which in turn may adversely affect our ability to resume and sustain cash distributions.

 

Unless we replace the reserves that we produce, our existing reserves and production will decline, which would adversely affect our cash from operations and have a material adverse effect on our financial condition and results of operation.

 

Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. CBM production generally declines at a shallow rate after initial increases in production as a consequence of the dewatering process. Our future oil and gas reserves, production, cash flow and ability to make distributions depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability to acquire additional reserves include competition, access to capital, prevailing gas prices and attractiveness of properties for sale. Because of our financial condition, we will not be able to replace in 2009 the reserves we expect to produce in 2009.

 

As of December 31, 2008, our proved reserve-to-production ratio was 7.4 years. Because this ratio includes our proved undeveloped reserves, we expect that this ratio will not increase even if those proved undeveloped reserves are developed and the wells produce as expected. The proved reserve-to-production ratio reflected in our reserve report as of December 31, 2008 will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances.

 

If QRCP fails to present us with, or successfully competes against us for, attractive acquisition opportunities, we may not be able to replace or increase our reserves, which would have a material adverse effect on our financial condition and results of operation.

 

We rely upon QRCP and its affiliates to identify and evaluate for us prospective oil and natural gas properties for acquisition. QRCP and its affiliates are not obligated to present us with potential acquisitions, and are not restricted from competing with us for potential acquisitions outside the Cherokee Basin. Because QRCP controls our general partner, we will not be able to pursue or consummate any acquisition opportunity unless QRCP causes us to do so. Further, we may be unable to make acquisitions because:

 

 

If QRCP and its affiliates fail to present us with, or successfully compete against us for, potential acquisitions, we may not be able to adequately maintain our asset base, which would have a material adverse effect on our financial condition and results of operation.

 

We face the risks of leverage.

 

As of December 31, 2008, we had borrowed $230.2 million under our credit agreements. We anticipate that we may in the future incur additional debt for financing our growth. Our ability to borrow funds will depend upon a number of factors, including the condition of the financial markets. In fact, during 2008, availability of credit became severely restricted. Under certain circumstances, the use of leverage may provide a higher return to you on your investment, but will also create a greater risk of loss to you than if we did not borrow. The risk of loss in such circumstances is increased because we would be obligated to meet fixed payment obligations on specified dates regardless of our revenue. If we do not make our debt service payments when due, we may sustain the loss of our equity investment in any of our assets securing such debt, upon the foreclosure on such debt by a secured lender. The interest payable on our debt varies with the movement of interest rates charged by financial institutions. An increase in our borrowing costs due to a rise in interest rates in the market may reduce the amount of income and cash available for the payment of dividends to the holders of our common units.

 

Our future level of debt could have important consequences to us, including the following:

 

 

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, 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.

 

The credit agreements of our operating subsidiary, Quest Cherokee, (to which we are a guarantor) have substantial restrictions and financial covenants that may restrict our business and financing activities.

 

Quest Cherokee is party to the First Lien Credit Agreement and a Second Lien Loan Agreement. The operating and financial restrictions and covenants in Quest Cherokee’s credit agreements and any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions. The credit agreements and any future financing agreements may restrict our ability to:

 

 

 

We also are required to comply with certain financial covenants and ratios. Our credit agreements require us to maintain a leverage ratio (the ratio of our consolidated funded debt to our adjusted consolidated EBITDA, as defined by the credit agreements) of less than 3.5 to 1.0 determined as of the last day of each quarter for the four-quarter period ending on the date of determination. The credit agreements require us to maintain an interest coverage ratio (the ratio of our adjusted consolidated EBITDA to our consolidated interest charges, as defined in our credit agreements) of not less than 2.5 to 1.0 determined as of the last day of each quarter for the four-quarter period ending on the date of determination. The credit agreements require us to maintain a current ratio (the ratio of our consolidated current assets plus unused availability under our First Lien Credit Agreement to our consolidated current liabilities excluding non-cash obligations, asset and asset retirement obligations and current maturities of indebtedness) of not less than 1.0 to 1.0. The Second Lien Loan Agreement contains an additional covenant that prohibits us from permitting the total reserve leverage ratio (ratio of total proved reserves to consolidated funded debt) at any fiscal quarter-end (calculated based on the most recently delivered compliance certificate) to be less that 1.5 to 1.0. Our credit agreements generally permit us to pay distributions of available cash so long as we are in compliance with the provisions of the credit agreements. A default under either credit agreement would preclude us from making any distributions during the periods in which such defaults occurred. In addition, the credit agreements restrict the amount of quarterly distributions we may declare and pay to our unitholders to not exceed $0.40 per common unit per quarter as long as the term loan has not been paid in full. Further, after giving effect to each quarterly distribution, we and Quest Cherokee must be in compliance with a financial covenant that prohibits each of us, Quest Cherokee or any of our respective subsidiaries from permitting Available Liquidity (as defined in the credit agreements) to be less than $14 million at March 31, 2009 and to be less than $20 million at June 30, 2009.

 

Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations 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 the credit agreements, a significant portion of our indebtedness may become immediately due and payable, our ability to resume or continue distributions will be inhibited and our lenders’ commitment 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 addition, our obligations under the credit agreements are secured by substantially all of our assets, and if we are unable to repay the indebtedness under the credit agreements, the lenders could seek to foreclose on our assets.

 

Our future debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

 

We have the ability to incur debt, subject to borrowing base limitations in our First Lien Credit Agreement. Our future indebtedness could have important consequences to us, including:

 

 

 

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, 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 effect any of these remedies on satisfactory terms or at all.

 

An increase in interest rates will cause our debt service obligations to increase.

 

Borrowings under our credit agreements bear interest at floating rates. The rates are subject to adjustment based on fluctuations in the London Interbank Offered Rate (“LIBOR”) and RBC’s base rate. An increase in the interest rates associated with our floating-rate debt would increase our debt service costs and affect our results of operations and cash flow. In addition, an increase in our interest expense could adversely affect our future ability to obtain financing or materially increase the cost of any additional financing.

 

We are exposed to trade credit risk in the ordinary course of our business activities.

 

We are exposed to risks of loss in the event of nonperformance by our customers and by counterparties to our derivative contracts. Some of our customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our customers and/or counterparties could adversely affect our results of operations and financial condition.

 

U.S. government and internal investigations could affect our results of operations.

 

We are currently involved in government and internal investigations involving various of our operations. As discussed in the Explanatory Note to Annual Report immediately preceding Part I of this Annual Report on Form 10-K/A, an inquiry and investigation initiated by the Oklahoma Department of Securities revealed questionable Transfers of funds by QRCP’s subsidiaries to an entity controlled by Jerry D. Cash. The Oklahoma Department of Securities has filed lawsuits against Jerry D. Cash, David E. Grose and Brent Mueller, and the Oklahoma Department of Securities, the Federal Bureau of Investigation, the Department of Justice, the SEC, and the IRS are currently conducting investigations related to the Transfers and these individuals.

 

These investigations are ongoing, and we cannot anticipate the timing, outcome or possible impact of these investigations, financial or otherwise. The governmental agencies involved in these investigations have a broad range of civil and criminal penalties they may seek to impose against business entities and individuals for violations of securities laws, and other federal and state statutes, including, but not limited to, injunctive relief, disgorgement, fines, penalties and modifications to business practices and compliance programs. In recent years, these agencies and authorities have entered into agreements with, and obtained a broad range of penalties against, several public corporations and individuals in similar investigations, under which civil and criminal penalties were imposed, including in some cases multi-million dollar fines and other penalties and sanctions. Any injunctive relief, disgorgement, fines, penalties, sanctions or imposed modifications to business practices resulting from these investigations could adversely affect our results of operations and our ability to continue as a going concern.

There is a significant delay between the time 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 expend 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 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:

 

 

If these assumptions prove to be incorrect, our estimates of proved reserves, the economically recoverable quantities of oil and gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly.

 

Our standardized measure is calculated using unhedged oil and gas prices and is determined in accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual drilling and production.

 

The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the current market value of our estimated proved reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from our oil and gas properties also will be affected by factors such as:

 

 

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves, and

thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with the FASB’s Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities , may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

 

Drilling for and producing oil and gas is a costly and high-risk activity with many uncertainties that could adversely affect our financial condition or results of operations, and as a result.

 

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:

 

 

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, which may adversely affect our liquidity, financial condition and borrowing base.

 

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of gas, we currently and may in the future enter into derivative arrangements for a significant portion of our gas production. We have entered into derivative contracts and fixed price sales contracts totaling approximately 39.1 Bcf of natural gas and 66,000 Bbls of oil through 2012. Our derivative instruments are subject to mark-to-market accounting treatment, and the change in fair market value of the instrument is reported in our statement of operations each quarter, which has resulted in and may in the future result in significant net 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 will be dependent upon commodity prices at the time we enter into these transactions, which may be substantially lower than current oil and gas prices. Accordingly, our commodity price risk management strategy will not protect us from significant and sustained declines in oil and 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 direct commodity price exposure on the unhedged portion of our production volumes. Please read “Quantitative and Qualitative Disclosures about Market Risk” under Item 7A of this report.

 

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:

 

 

Because of our lack of asset and geographic diversification, adverse developments in our operating area would adversely affect our results of operations.

 

Substantially all of our assets are currently located in the Cherokee Basin and Appalachian Basin. As a result, our business is disproportionately exposed to adverse developments affecting these regions. These potential adverse developments could result from, among other things, changes in governmental regulation, capacity constraints with respect to the pipelines connected to our wells, curtailment of production, natural disasters or adverse weather conditions in or affecting these regions. Due to our lack of diversification in asset type and location, an adverse development in our business or these operating areas would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.

 

We may be unable to compete effectively with larger companies, which may adversely affect our results of operations.

 

The oil and gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and gas and securing equipment and trained personnel, and we compete with other companies that have greater resources. Many of our competitors are major and large independent oil and gas companies, and they not only drill for and produce oil and gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. Our larger competitors also possess and employ financial, technical and personnel resources substantially greater than ours. These companies may be able to pay more for oil and gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, there is substantial competition for investment capital in the oil and gas industry. These larger companies may have a greater ability to continue drilling activities during periods of low oil and gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material impact on our business activities, results of operations and financial condition.

 

We may have difficulty managing growth in our business.

 

Because of the relatively small size of our business, growth in accordance with our long-term business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we

increase our activities and the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of required personnel could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

 

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs that is not fully insured, our operations and financial results could be adversely affected.

 

There are a variety of risks inherent in our operations that may generate liabilities, including contingent liabilities, and financial losses to us, such as:

 

 

Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial revenue losses.

 

In accordance with typical industry practice, we currently possess property, business interruption and general liability insurance at levels we believe are appropriate; however, insurance against all operational risk is not available to us. We are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets subsequent to the terrorist attacks on September 11, 2001 and the hurricanes in 2005 have made it more difficult for us to obtain certain types of coverage. There can be no assurance that we will be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations, and ability to resume and sustain the payment of cash distributions to our unitholders.

 

We have recently been named a defendant in a number of securities class action lawsuits and securityholder derivative lawsuits and we are a party to pending litigation arising out of the conduct of our business. These, and potential similar or related litigation, could result in significant expenses, monetary damages, penalties or injunctive relief against us.

 

As discussed in Items 1 and 2. “Business and Properties — Recent Developments — Internal Investigation; Restatements and Reaudits,” the joint special committee conducted an internal investigation into the Transfers of funds effected by Jerry D. Cash that totaled approximately $10 million. During the course of the investigation, management identified material errors in our and our Predecessor’s previously issued consolidated financial statements and has restated our and our Predecessor’s previously filed consolidated financial statements. The investigation and restatement have exposed us to risks and expenses associated with litigation and government investigations. Certain putative class action lawsuits and securityholder derivative lawsuits have been asserted

against us, our general partner, QRCP, and current and former officers and directors. See Item 3. “Legal Proceedings” for a discussion of these lawsuits and other material legal proceedings. No assurance can be given regarding the outcome of such litigation, and additional claims may arise. The investigation and restatement and any settlements, payment of claims and other costs could lead to substantial expenses, may materially affect our cash balance and cash flows from operations and may divert management’s attention from our business. In addition, there are indemnification provisions in our partnership agreement and the operating agreement of our general partner under which we are required to indemnify and advance defense costs to our current and certain of our former directors and officers. Furthermore, considerable legal, accounting and other professional services expenses related to these matters have been incurred to date and significant expenditures may continue to be incurred in the future. We could be required to pay damages and might face remedies that could harm our business, financial condition and results of operations. While we maintain directors and officers liability insurance, there can be no assurance that the proceeds of this insurance will be available with respect to all or part of any damages, costs or expenses that we may incur in connection with the class action and derivative securityholder lawsuits.

 

We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental and operational safety regulations or an accidental release of hazardous substances into the environment.

 

We may incur significant costs and liabilities as a result of new or existing environmental, health and safety requirements applicable to our oil and gas exploration, development and production activities. These costs and liabilities could arise under a wide range of federal, state and local environmental, health and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations.

 

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example, (1) the federal CAA and comparable state laws and regulations that impose obligations related to air emissions, (2) federal and state laws and regulations currently under development to address GHG emissions, (3) the federal RCRA and comparable state laws that impose requirements for the handling, storage, treatment or discharge of waste from our facilities, (4) the federal CERCLA, also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent waste for disposal and (5) the federal CWA and analogous state laws and regulations that impose detailed permit requirements and strict controls regarding the discharge of pollutants into waters of the United States and state waters. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Certain environmental regulations, including CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

 

There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of oil and natural gas, air emissions related to our operations, and historical industry operations and waste disposal practices. 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 disposal costs.

 

We are subject to regulation that restricts our ability to discharge water produced as part of our gas production operations. Productive zones frequently contain water that must be removed in order for the gas to detach and

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 fail to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

 

 

Shortages of crews could delay our operations, adversely affect our ability to increase our reserves and production.

 

Higher oil and gas prices generally stimulate increased demand and result in increased wages for crews and personnel in our production operations. These types of shortages or wage increases in the future could increase our costs and/or restrict or delay our ability to drill wells and conduct our operations. Any delay in the drilling of new wells or significant increase in labor costs could adversely affect our ability to increase our reserves and production and reduce our revenue and cash available for distribution. Additionally, higher labor costs could cause certain of our projects to become uneconomic and therefore not be implemented or for existing wells to become shut-in, reducing our production.

 

We depend on one customer to purchase our natural gas.

 

During the year ended December 31, 2008, substantially all of our natural gas produced in the Cherokee Basin was sold to ONEOK under a sale and purchase contract, which has an indefinite term but may be terminated by either party on 30 days’ notice, other than with respect to pending transactions, or less following an event of default. If ONEOK was to reduce the volume of gas it purchases under this agreement, our revenue and cash available for distribution will decline to the extent we are not able to find new customers for the natural gas we produce and sell.

 

The credit and risk profile of QRCP could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.

 

The credit and business risk profiles of QRCP may be factors considered in our credit evaluations because our general partner controls our business activities, including our cash distribution policy and acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of QRCP including the degree of its financial leverage and any dependence on cash flow from us to service its indebtedness.

 

In QRCP’s Annual Report on Form 10-K for 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 in the next few months. 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.

 

If we were to seek a credit rating in the future, our credit rating may be adversely affected by the financial condition of QRCP, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the financial condition and credit profile of QRCP and its affiliates because of their ownership

interest in and control of us and the strong operational links between QRCP and us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and resume and continue the payment of distributions to unitholders.

 

Certain of our undeveloped leasehold acreage is subject to leases that may expire in the near future.

 

In the Cherokee Basin, as of December 31, 2008, we held oil and gas leases on approximately 557,603 net acres, of which 150,922 net acres are undeveloped and not currently held by production. Unless we establish commercial production on the properties subject to these leases during their term, these leases will expire. Leases covering approximately 29,760 net acres are scheduled to expire before December 31, 2009 and an additional 77,149 net acres are scheduled to expire before December 31, 2010. If our leases expire, we will lose our right to develop the related properties. We typically acquire a three-year primary term when the original lease is acquired, with an option to extend the term for up to three additional years, if the primary three-year term reaches expiration without a well being drilled to establish production for holding the lease.

 

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, which could have an adverse effect on our financial condition and results of operation.

 

Our management has specifically identified drilling locations for our future multi-year drilling activities on our existing acreage. We have identified, as of December 31, 2008, approximately 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. 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 may exist greater uncertainty with respect to the likelihood of drilling and completing successful commercial wells at these potential drilling locations. Our final determination of whether to drill any of these drilling locations will be dependent upon the factors described above, our current financial condition, our ability to obtain additional capital as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, it is unlikely that all of the numerous drilling locations we have identified will be drilled within the timeframe specified in the reserve report or will ever be drilled, and we do not know if we will be able to produce gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could have a significant adverse effect on our financial condition and results of operations.

 

We may incur losses as a result of title deficiencies in the properties in which we invest.

 

If an examination of the title history of a property reveals that an oil or gas lease has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would be worthless. In such an instance, the amount paid for such oil or gas lease or leases would be lost. It is our practice, in acquiring oil and gas leases, or undivided interests in oil and gas leases, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.

 

Prior to drilling an oil or gas well, however, it is the normal practice in the oil and gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil or gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. The work might include obtaining affidavits of heirship or causing an estate to be administered. Our failure to obtain these rights may adversely impact its ability in the future to increase production and reserves.

On a small percentage of our acreage (less than 1.0%), the land owner in the past transferred the rights to the coal underlying their land to a third party. With respect to those properties we have obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying those lands. In Kansas, absent a specific conveyance of the CBM in the deed conveying the coal, the law is clear that the coal owner does not own the CBM. In Oklahoma, the law is unsettled as to whether the owner of the gas rights or the coal rights is entitled to the CBM gas. We are currently involved in litigation with the owner of the coal rights on these lands to determine who has the rights to the CBM gas. In the event that the courts were to determine that the owner of the coal rights is entitled to extract the CBM gas, we would lose these leases and the associated wells and reserves. In addition, we may be required to reimburse the owner of the coal rights for some of the gas produced from those wells. For additional information regarding these legal proceedings, please read “Business and Properties — Environmental Matters and Regulation” under Items 1 and 2. of this report and “Legal Proceedings” under Item 3 of this report.

 

We depend on a limited number of key management personnel, who would be difficult to replace.

 

Our operations and activities are dependent to a significant extent on the efforts and abilities of management and key employees of QRCP, including David Lawler, President and Chief Executive Officer, Eddie LeBlanc, Chief Financial Officer, Richard Marlin, Executive Vice President — Engineering, David Bolton, Executive Vice President — Land, Thomas A. Lopus, Executive Vice President — Appalachia and Jack Collins, Executive Vice President — Finance/Corporate Development. We maintain no key person insurance for any of our management or key employees. The loss of any member of our management or other key employees could negatively impact our ability to execute our strategy.

 

We rely on our general partner and Quest Energy Service for our management. If our general partner or Quest Energy Service fails to or inadequately performs, our costs will increase which will reduce our cash from operations and have a material adverse effect on our financial condition and results of operation.

 

We rely on our general partner and Quest Energy Service for our management. We also expect that our general partner will provide us with assistance in hedging our production and acquisition services in respect of opportunities for us to acquire long-lived, stable and proved oil and gas reserves. QRCP and its affiliates have no obligation to present us with potential acquisitions outside the Cherokee Basin, and, if they fail to do so, we will need to either seek acquisitions on our own or retain a third party to seek acquisitions on our behalf. In the long term, without further acquisitions, we will not be able to replace or grow our reserves, which would reduce our cash from operations and have a material adverse effect on our financial condition and results of operation.

 

Any acquisitions we complete are subject to substantial risks that could have a material adverse effect on our financial condition and results of operation.

 

Our ability to grow, increase our profitability and resume the payment of distributions as well as increase distributions over time depends in part on our ability to make acquisitions that result in an increase in our net income. We may be unable to make such acquisitions because we are: (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms or (3) outbid by competitors. If we are unable to acquire properties containing proved reserves, our total level of proved reserves will decline as a result of our production, which will adversely affect our results of operations. Even if we do make acquisitions that we believe will increase our net income and cash flows, these acquisitions may nevertheless result in a decrease in available cash per unit. Any acquisition involves potential risks, including, among other things:

 

 

 

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and investors will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

 

In addition, we may pursue acquisitions outside the Cherokee and Appalachian Basins. Because we currently operate substantially in the Cherokee and Appalachian Basins, we do not have the same level of experience in other basins. Consequently acquisitions in areas outside the Cherokee and Appalachian Basins may not allow us the same operational efficiencies we benefit from in those basins. In addition, acquisitions outside the Cherokee and Appalachian Basins will expose us to different operational risks due to potential differences, among others, in:

 

 

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume environmental and other risks and liabilities in connection with acquired properties.

Risks Inherent in an Investment in Our Common Units

 

We currently are not in compliance with NASDAQ’s continued listing requirements, and if our common units are delisted, it could negatively impact the price of our common units, our ability to access the capital markets and the liquidity of our common units.

 

On November 19, 2008, we received a letter from the staff of NASDAQ indicating that, because of our failure to timely file our Form 10-Q for the quarter ended September 30, 2008, we no longer complied with the continued listing requirements set forth in NASDAQ Marketplace Rule 4310(c)(14) (now Rule 5250(c)(1)). As permitted by NASDAQ rules, we timely submitted a plan to NASDAQ staff to regain compliance on January 20, 2009. Following a review of this plan, NASDAQ staff granted us an extension until May 18, 2009 to file our Form 10-Q.

 

We did not file our Form 10-Q for the quarter ended September 30, 2008 on that date and on May 18, 2009, we received a Staff Determination from NASDAQ stating that our common units are subject to delisting since we were not in compliance with the filing requirements for continued listing. We requested and were granted a hearing before the NASDAQ Listing Panel to appeal the Staff Determination. The hearing was held on June 11, 2009. On July 15, 2009, we received a letter from NASDAQ advising us that the Panel had granted our request for continued listing on NASDAQ. The terms of the Panel’s decision include a condition that we file our quarterly reports on Form 10-Q for the quarters ended September 30, 2008 and March 31, 2009 by August 15, 2009. If we have not filed all of our delinquent periodic reports by August 15, 2009, there can be no assurances that the Panel will grant a further extension to allow us additional time to file such reports or that our common units will not be delisted.

 

Any potential delisting of our common units from the NASDAQ Global Market would make it more difficult for our unitholders to sell our units in the public market. Additionally, the delisting of our common units could materially adversely affect our ability to raise capital that may be needed for future operations. Delisting could also have other negative results, including the potential loss of confidence by customers and employees, the loss of institutional investor interest, and fewer business development opportunities and would likely result in decreased liquidity and increased volatility for our common units.

 

Our unit price may be volatile.

 

The following factors could affect our unit price:

 

 

 

Our common units are unsecured equity interests.

 

Just like any equity interest, our common units will not be secured by any of our assets. Therefore, in the event of our liquidation, the holders of our common units will receive distributions only after all of our secured and unsecured creditors have been paid in full. There can be no assurance that we will have sufficient assets after paying its secured and unsecured creditors to make any distribution to the holders of our common units.

 

QRCP controls our general partner, which conducts our business and manages our operations. QRCP and its affiliates have conflicts of interest with us and limited fiduciary duties to us, which may permit them to favor their own interests to your detriment.

 

QRCP owns and controls our general partner. The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to QRCP. Some of our general partner’s directors and executive officers are directors or officers of QRCP and Quest Midstream. Therefore, conflicts of interest may arise between QRCP and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

 

 

Our partnership agreement limits our general partner’s 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.

 

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held under state law and restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:

 

 

Each common unitholder is bound by the provisions in the partnership agreement, including the provisions discussed above.

 

We do not have any officers and rely solely on officers of our general partner and employees of QRCP and its affiliates for the management of our business.

 

None of the officers of our general partner are employees of our general partner. We have entered into a management services agreement with Quest Energy Service pursuant to which Quest Energy Service operates our assets and performs other administrative services for us such as SEC reporting and filings, Sarbanes-Oxley compliance, accounting, audit, finance, tax, benefits, compensation and human resource administration, property management, risk management, land, marketing, legal and engineering. The terms of the management services agreement and our partnership agreement significantly limit our remedies in the event Quest Energy Service fails to perform. Affiliates of QRCP conduct businesses and activities of their own in which we have no economic interest, including businesses and activities relating to QRCP and Quest Midstream. As a result, there could be material competition for the time and effort of the officers and employees who provide services to our general partner, QRCP and its affiliates. As a result of the PetroEdge acquisition, QRCP increased its operations, which could result in increased competition for the time and effort of such officers and employees. If the officers of our general partner and the employees of QRCP and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer.

Unitholders have limited voting rights and are not entitled to elect our general partner or the directors of our general partner.

 

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or our general partner’s board of directors, and will have no right to elect our general partner or our general partner’s board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, will be chosen by QRCP. Since QRCP also holds 57% of our aggregate outstanding common and subordinated units, the public unitholders will not have an ability to influence any operating decisions or to prevent us from entering into any transactions. Furthermore, the goals and objectives of QRCP and our general partner relating to us may not be consistent with those of a majority of the public unitholders.

 

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

 

Unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2 / 3 % of all outstanding units (including units held by our general partner and its affiliates) voting together as a single class is required to remove the general partner. Our general partner and its affiliates own 57% of our aggregate outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

 

Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholder’s dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

 

As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

 

QRCP may engage in competition with us.

 

QRCP and its affiliates may engage in competition with us outside the Cherokee Basin. Pursuant to the omnibus agreement, QRCP and its subsidiaries agreed to give us a right to purchase any oil or natural gas wells or other oil or natural gas rights and related equipment and facilities that they acquire within the Cherokee Basin, but not including any midstream or downstream assets. QRCP may acquire, develop or dispose of additional oil or gas properties or other assets outside of the Cherokee Basin in the future, without any obligation to offer us the opportunity to acquire any of those assets.

 

If QRCP does engage in competition with us it could have an adverse impact on our results of operations and ability to make distributions to our unitholders. For a description of the non-competition provisions of the omnibus agreement, please read “Certain Relationships and Related Party Transactions, and Director Independence — Agreements Governing the Transactions — Omnibus Agreement” and “Certain Relationships and Related Party Transactions, and Director Independence — Agreements Governing the Transactions — Management Services Agreement,” in each case, under Item 13 of this report.

We are restricted from engaging in businesses other than the exploration and development of oil and gas.

 

We are subject to the Omnibus Agreement dated as of December 22, 2006, but effective as of December 1, 2006, among Quest Midstream, Quest Midstream’s general partner, Quest Midstream’s operating subsidiary and QRCP and will continue to be subject to it so long as we are an affiliate of QRCP and QRCP or any of its affiliates controls Quest Midstream. Except for certain limited exceptions, the Omnibus Agreement restricts us from engaging in the following businesses:

 

 

These provisions will limit our flexibility to diversify into businesses other than the exploration and development of oil and gas, which may limit our ability to enter into different and potentially more profitable lines of business, and thus, adversely affect our ability to resume and continue to make distributions to our unitholders.

 

Our general partner has incentive distribution rights, which may incentivize it to cause us to distribute cash needed to develop our properties.

 

Our general partner has all of the incentive distribution rights entitling it to receive up to 23% of our cash distributions above certain target distribution levels in addition to its 2% general partner interest. This increased sharing in our distributions creates a conflict of interest for the general partner in determining whether to distribute cash to our unitholders or reserve it for reinvestment in the business and whether to borrow to pay distributions to our unitholders. Our general partner may have an incentive to distribute more cash than it would if its only economic interest in us were its 2% general partner interest. Furthermore, because of the commodity price sensitivity of our business, the general partner may receive incentive distributions due solely to increases in commodity prices as opposed to growth through development drilling or acquisitions.

 

Each quarter our general partner is required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available to unitholders than if actual maintenance capital expenditures were deducted.

 

Our partnership agreement requires our general partner to deduct our estimated, rather than actual, maintenance capital expenditures from operating surplus each quarter in an effort to reduce fluctuations in operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the conflicts committee at least once a year. In years when estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from operating surplus. On the other hand, if our general partner underestimates the appropriate level of estimated maintenance capital expenditures, we will have more cash available for distribution from operating surplus in the short term, including on the general partner’s incentive distribution rights, but will have less cash available for distribution from operating surplus in future periods when we have to increase our estimated maintenance capital expenditures to account for our previous underestimation.

Cost reimbursements due our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution to you.

 

Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf, as determined by our general partner. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. Payments for these services will reduce the amount of cash available for distribution to unitholders. Please read “Certain Relationships and Related Party Transactions, and Director Independence — Agreements Governing the Transactions — Omnibus Agreement” and “Certain Relationships and Related Party Transactions, and Director Independence — Agreements Governing the Transactions — Management Services Agreement,” in each case, under Item 13 of this report.

 

Our general partner’s interest in us and control of our general partner may be transferred to a third party without unitholder consent.

 

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our general partner from transferring all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions taken by the board of directors and officers of our general partner.

 

We may issue additional units, including units that are senior to the common units, without approval of our unitholders, which would dilute the existing ownership interests of our unitholders.

 

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

 

Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of our general partner or holders of our common units and subordinated units. This may result in lower distributions to holders of our common units in certain situations.

 

Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount.

In connection with resetting these target distribution levels, our general partner will be entitled to receive Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B units to be issued will be equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B units, which are entitled to receive cash distributions from us on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights.

 

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

 

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

 

The NASDAQ Global Market does not require a listed limited partnership like us to comply with some of its listing requirements with respect to corporate governance requirements.

 

Because we are a limited partnership, the NASDAQ Global Market does not require us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, you will not have the same protections afforded to shareholders of companies that are subject to all of the NASDAQ Global Market corporate governance requirements.

 

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

 

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their units. Our general partner and its affiliates own approximately 26% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own approximately 57% of our aggregate outstanding common units.

 

The liability of our unitholders may not be limited if a court finds that unitholder action constitutes control of our business.

 

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in Kansas, Oklahoma, West Virginia and New York. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we may do business. Our

unitholders could be liable for any and all of our obligations as if they were a general partner if a court or government agency determined that:

 

 

Unitholders may have liability to repay distributions.

 

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Sections 17-607 and 17-804 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are not liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

 

Common units held by persons who are not Eligible Holders will be subject to the possibility of redemption.

 

If we become subject to U.S. laws with respect to the ownership interests in oil and gas leases on federal lands, our general partner has the right under our partnership agreement to institute procedures, by giving notice to each of our unitholders, that would require transferees of common units and, upon the request of our general partner, existing holders of our common units to certify that they are Eligible Holders. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and gas leases on federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the United States, (2) a corporation organized under the laws of the United States or of any state thereof, (3) a public body, including a municipality or (4) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. Onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof. If these certification procedures are implemented, unitholders who are not persons or entities who meet the requirements to be an Eligible Holder will not receive distributions or allocations of income and loss on their units, and we will have the right to redeem the common units held by persons or entities who are not Eligible Holders at the then-current market price of the units. The redemption price would be paid in cash or by delivery of a promissory note, as determined by our general partner.

 

An increase in interest rates may cause the market price of our common units to decline.

 

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

Tax Risks to Common Unitholders

 

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.

 

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

 

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

 

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. For example, at the federal level, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner that does apply to us. We are unable to predict whether any of these changes, or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such a tax on us by any state will reduce the cash available for distribution to unitholders. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

 

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

 

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

 

Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

 

Our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute. As a result, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely affected, and the cost of any contest will reduce our cash available for distribution to unitholders.

 

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this report or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will reduce our cash available for distribution and thus will be borne indirectly by our unitholders and our general partner.

 

Tax gain or loss on disposition of our common units could be more or less than expected.

 

If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to our unitholders in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to them if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. If our unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale. If the IRS successfully contests some tax positions we take, unitholders could recognize more gain on the sale of units than would be the case if those positions were sustained, without the benefit of decreased income in prior years.

 

Tax-exempt entities and foreign persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

 

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a foreign person, you should consult your tax advisor before investing in our common units.

 

We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

 

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audits of, and adjustments to, unitholders’ tax returns.

 

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

 

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For example, an exchange of 50% of our capital and profits could occur if, in any twelve-month period, holders of our subordinated and common units sell at least 50% of the interests in our capital and profits. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which could result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one fiscal year. Our termination could also result in a

deferral of depreciation deductions allowable in computing our taxable income. If this occurs, you will be allocated an increased amount of federal taxable income for the year in which we are considered to be terminated and for future years as a percentage of the cash distributed to you with respect to such periods. Although the amount of the increase cannot be estimated because it depends upon numerous factors including the timing of the termination, the amount could be material. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred.

 

We may adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the holders of incentive distribution rights and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

 

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and the holders of the incentive distribution rights. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the holders of the incentive distribution rights, which may be unfavorable to such unitholders. Moreover, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the holders of the incentive distribution rights and certain of our unitholders.

 

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

 

Unitholders likely will be subject to state and local taxes and return filing requirements.

 

In addition to federal income taxes, unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property, now or in the future, even if they do not live in any of those jurisdictions. Unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, they may be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business in Kansas, Oklahoma, West Virginia and New York. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is the unitholder’s responsibility to file all United States federal, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

 

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

 

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Stinson Morrison Hecker LLP has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

 

None.

 

 

We are subject, from time to time, to certain legal proceedings and claims in the ordinary course of conducting our business. As of December 31, 2008, 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. We will record a liability related to our legal proceedings and claims when we have determined that it is probable that we will be obligated to pay and the related amount can be reasonably estimated, and we will disclose the related facts in the footnotes to our financial statements, if material. If we determine that an obligation is reasonably possible, we will, if material, disclose the nature of the loss contingency and the estimated range of possible loss, or include a statement that no estimate of loss can be made. Except for those legal proceedings listed below, we believe there are no pending legal proceedings in which we are currently involved which, if adversely determined, could have a material adverse effect on our financial position, results of operations or cash flow. We are currently a defendant in the following litigation. We intend to defend vigorously against the claims described below. We are unable to predict the outcome of these proceedings or reasonably estimate a range of possible loss that may result. Like other oil and natural gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. Therefore it is extremely difficult to reasonably quantify future environmental related expenditures.

 

Federal Securities Class Actions

 

Michael Friedman, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David E. Grose , Case No. 08-cv-936-M U.S., District Court for the Western District of Oklahoma, filed September 5, 2008

 

James Jents, individually and on behalf of all others similarly situated v. Quest Resource Corporation, Jerry Cash, David E. Grose, and John Garrison , Case No. 08-cv-968-M, U.S. District Court for the Western District of Oklahoma, filed September 12, 2008

 

J. Braxton Kyzer and Bapui Rao, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation and David E. Grose , Case No. 08-cv-1066-M, U.S. District Court for the Western District of Oklahoma, filed October 6, 2008

 

Paul Rosen, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David E. Grose , Case No. 08-cv-978-M, U.S. District Court for the Western District of Oklahoma, filed September 17, 2008

 

Four putative class action complaints were filed in the United States District Court for the Western District of Oklahoma against Quest Energy GP et al. The complaints were filed by certain unitholders on behalf of themselves and other unitholders who purchased our common units between November 7, 2007 and August 25, 2008 and by certain stockholders on behalf of themselves and other stockholders who purchased QRCP’s common stock between May 2, 2005 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 our former chief executive officer, Jerry D. Cash. The complaints also allege that, as a result of these actions, our unit price and the stock price of QRCP was artificially inflated during the class period. On December 29, 2008 the court consolidated these complaints as Michael Friedman, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David E. Grose , Case No. 08-cv-936-M, in the Western District of Oklahoma. Various individual plaintiffs have filed multiple rounds of motions seeking appointment as lead plaintiff, however the court has not yet ruled on these motions and appointed a lead plaintiff. Once a lead plaintiff is appointed, the lead plaintiff must file a consolidated amended complaint within 60 days after being appointed. No further activity is expected in

the purported class action until a lead plaintiff is appointed and an amended consolidated complaint is filed. We intend to defend vigorously against 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. Phillip 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 our behalf, which names certain of our 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 of contract against the external auditors. The complaint seeks monetary damages, disgorgement, costs and expenses and equitable and/or injunctive relief. It also seeks us to take all necessary actions to reform and improve our corporate governance and internal procedures. We intend to defend vigorously against these claims.

 

Royalty Owner Class Action

 

Hugo Spieker, et al. v. Quest Cherokee, LLC Case No. 07-1225-MLB in the U.S. District Court, District of Kansas, filed August 6, 2007

 

Quest Cherokee was named as a defendant in a class action lawsuit filed by several royalty owners in the U.S. District Court for the District of Kansas. The case was filed by the named plaintiffs on behalf of a putative class consisting of all Quest Cherokee’s royalty and overriding royalty owners in the Kansas portion of the Cherokee Basin. Plaintiffs contend that Quest Cherokee failed to properly make royalty payments to them and the putative class by, among other things, paying royalties based on reduced volumes instead of volumes measured at the wellheads, by allocating expenses in excess of the actual costs of the services represented, by allocating production costs to the royalty owners, by improperly allocating marketing costs to the royalty owners, and by making the royalty payments after the statutorily proscribed time for doing so without providing the required interest. Quest Cherokee has answered the complaint and denied plaintiffs’ claims. Discovery in that case is ongoing. Quest Cherokee intends to defend vigorously against these claims.

 

Personal Injury Litigation

 

Segundo Francisco Trigoso and Dana Jara De Trigoso v. Quest Cherokee Oilfield Service, LLC, CJ-2007-11079, in the District Court of Oklahoma County, State of Oklahoma, filed December 27, 2007

 

Quest Cherokee Oilfield Service, LLC (“QCOS”) 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 Fall 2009. QCOS intends to defend vigorously against plaintiffs’ claims.

 

St. Paul Surplus Lines Insurance Company v. Quest Cherokee Oilfield Service, LLC, et al, CJ-2009-1078, in the District Court of Tulsa County, State of Oklahoma, filed February 11, 2009

 

QCOS was named as a defendant in this declaratory action. This action arises out of the Trigoso matter discussed above. Plaintiff alleges that no coverage is owed QCOS under the excess insurance policy issued by plaintiff. The contentions of plaintiff primarily rest on their position that the allegations made in Trigoso are intentional in nature and that the excess insurance policy does not cover such claims. QCOS will vigorously defend the declaratory action.

Billy Bob Willis, et al. v. Quest Resource Corporation, et al., Case No. CJ-09-00063, District Court of Nowata County, State of Oklahoma, filed April 28, 2009

 

Quest Resource Corporation, et al. were named in the above-referenced lawsuit. The lawsuit has not been served. At this time and due to the recent filing of the lawsuit, QRCP is unable to provide further detail.

 

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 is 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.

 

Juana Huerter v. Quest Cherokee Oilfield Services, LLC, et al., Case No. 2008 CV-50, District Court of Neosho County, State of Kansas, filed May 5, 2008

 

QCOS, et al. were named in this personal injury lawsuit arising out of an automobile collision. Initial written discovery is being conducted. There is no pending trial date. QCOS intends to defend vigorously against this claim.

 

Bradley Haviland, Jr., v. Quest Cherokee Oilfield Services, LLC, et al., Case No. 2008 CV-78, District Court of Neosho County, State of Kansas, filed July 25, 2008

 

QCOS, et al. were named in this personal injury lawsuit arising out of an automobile collision. There is no pending trial date. QCOS intends to defend vigorously against this claim.

 

Litigation Related to Oil and Gas Leases

 

Quest Cherokee was 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 March 1, 2009, the total amount of acreage covered by the leases at issue in these lawsuits was approximately 4,808 acres. Quest Cherokee intends to vigorously defend against those claims. Following is a list of those cases:

 

Roger Dean Daniels v. Quest Cherokee, LLC, Case No. 06-CV-61, in the District Court of Montgomery County, State of Kansas, filed May 5, 2006 (currently on appeal)

 

Carol R. Knisely, et al. v. Quest Cherokee, LLC, Case No. 07-CV-58-I, in the District Court of Montgomery County, State of Kansas, filed April 16, 2007

 

Quest Cherokee, LLC v. David W. Hinkle, et al., Case No. 2006-CV-74, in the District Court of Labette County, State of Kansas, filed September 5, 2006

 

Scott Tomlinson, et al. v. Quest Cherokee, LLC, Case No. 2007-CV-45, in the District Court of Wilson County, State of Kansas, filed August 29, 2007

 

Ilene T. Bussman et al. v. Quest Cherokee, LLC, Case No. 07-CV-106-PA, in the District Court of Labette County, State of Kansas, filed November 26, 2007

 

Gary Dale Palmer, et al. v. Quest Cherokee, LLC, Case No. 07-CV-107-PA, in the District Court of Labette County, State of Kansas, filed November 26, 2007

 

Richard L. Bradford, et al. v. Quest Cherokee, LLC, Case No. 2008-CV-67, in the District Court of Wilson County, Kansas, filed September 18, 2008 (Quest Cherokee has resolved these claims as part of a settlement)

 

Richard Winder v. Quest Cherokee, LLC, Case Nos. 07-CV-141 and 08-CV-20, in the District Court of Wilson County, Kansas, filed December 7, 2007, and February 27, 2008

Housel v. Quest Cherokee, LLC , 06-CV-26-I, in the District Court of Montgomery County, State of Kansas, filed March 2, 2006

 

Quest Cherokee was named as a defendant in a lawsuit filed by Charles Housel and Meredith Housel on March 2, 2006. Plaintiffs allege that the primary term of the lease at issue has expired and that based upon non-production, plaintiffs are entitled to cancellation of said lease. A judgment was entered against Quest Cherokee on May 15, 2006. Quest Cherokee, however, was never properly served with this lawsuit and did not learn of this lawsuit until on or about April 23, 2007. Quest Cherokee filed a Motion to Set Aside Default Judgment and the parties have since agreed to set aside the default judgment that was entered. Quest Cherokee has answered the complaint. On April 1, 2008, Quest Cherokee sought leave from the court to bring a third party claim against Layne Energy Operating, LLC (“Layne”) on the basis that it, among other things, has committed a trespass and has converted the well and gas and/or proceeds at issue. Quest Cherokee was granted leave to file its claim against Layne. Layne has moved to dismiss the Third Party Petition and Quest Cherokee has objected. Quest Cherokee intends to defend vigorously against plaintiffs’ claims and pursue vigorously its claims against Layne.

 

Central Natural Resources, Inc. v. Quest Cherokee, LLC, et al., Case No. 04-C-100-PA in the District Court of Labette County, State of Kansas, filed on September 1, 2004

 

Quest Cherokee and Bluestem were named as defendants in a lawsuit filed by Central Natural Resources, Inc. (“Central Natural Resources”) on September 1, 2004 in the District Court of Labette County, Kansas. Central Natural Resources owns the coal underlying numerous tracts of land in Labette County, Kansas. Quest Cherokee has obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying some of that land and has drilled wells that produce coal bed methane gas on that land. Bluestem purchases and gathers the gas produced by Quest Cherokee. Plaintiff alleges that it is entitled to the coal bed methane gas produced and revenues 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 Plaintiff’s 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 Cherokee’s favor. Plaintiff appealed the summary judgment and the Kansas Supreme Court has issued an opinion affirming the District Court’s decision and has remanded the case to the District Court for further proceedings consistent with that decision. Quest Cherokee and Bluestem intend to defend vigorously against these claims.

 

Central Natural Resources, Inc. v. Quest Cherokee, LLC, et al ., Case No. CJ-06-07 in the District Court of Craig County, State of Oklahoma, filed January 17, 2006

 

Quest Cherokee was named as a defendant in a lawsuit filed by Central Natural Resources, Inc. on January 17, 2006, in the District Court of Craig County, Oklahoma. Central Natural Resources owns the coal underlying approximately 2,250 acres of land in Craig County, Oklahoma. Quest Cherokee has obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying those lands, and has drilled and completed 20 wells that produce coal bed methane gas on those lands. Plaintiff alleges that it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser. Plaintiff seeks to quiet its alleged title to the coal bed methane and an accounting of the revenues from the coal bed methane gas produced by Quest Cherokee. Quest Cherokee contends it has valid leases from the owners of the coal bed methane gas rights. The issue is whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. Quest Cherokee has answered the petition and discovery has been stayed by agreement of the parties. Quest Cherokee intends to defend vigorously against these claims.

 

Edward E. Birk, et ux., and Brian L. Birk, et ux., v. Quest Cherokee, LLC , Case No. 09-CV-27, in the District Court of Neosho County, State of Kansas, filed April 23, 2009

 

Quest Cherokee was named as a defendant in a lawsuit filed by Edward E. Birk, et ux., and Brian L. Birk, et ux., on April 23, 2009. In that case, the plaintiffs claim that they are entitled to an overriding royalty interest (1/16th 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’s answer date is June 15, 2009. We are investigating the factual and legal basis for these claims and intend to defend against them vigorously based upon the results of the investigation.

 

Robert C. Aker, et al. v. Quest Cherokee, LLC, et al., U.S. District Court for the Western District of Pennsylvania, Case No. 3-09CV101, filed April 16, 2009

 

Quest Cherokee, et al. were named as defendants in this action where plaintiffs seek a ruling invalidating certain oil and gas leases. Quest Cherokee has not answered and no discovery has taken place. Quest Cherokee is investigating whether it is a proper party to this lawsuit and intends to vigorously defend against this claim.

 

Other

 

Well Refined Drilling Co. v. Quest Cherokee, LLC, Case No. 2007-CV-91, in the District Court of Neosho County, State of Kansas, filed July 19, 2007; and Well Refined Drilling Co. v. Quest Cherokee, LLC, Case No. 2007-CV-46, in the District Court of Wilson County, State of Kansas, filed September 4, 2007

 

Quest Cherokee 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 contends that Quest Cherokee owes certain sums for services provided by the plaintiff in connection with drilling wells for Quest Cherokee. Plaintiff has also filed mechanics liens against the oil and gas leases on which those wells are located and also seeks foreclosure of those liens. Quest Cherokee has answered those petitions and has denied plaintiff’s claims. Quest Cherokee has resolved these claims as well as the Neosho Natural matter described below as part of a global settlement.

 

Neosho Natural, LLC, Jeffrey D. Kephart and Randall L. Cox v. Quest Cherokee, LLC, Case No. 2008-CV-23, in the District Court of Neosho County, State of Kansas, filed March 7, 2008.

 

Quest Cherokee was named as a defendant in a lawsuit filed in the District Court of Neosho County, Kansas on March 7, 2008 alleging that Quest Cherokee’s taking of a new oil and gas lease with the landowners did not eliminate the overriding royalty interest (“ORRI”) that had been granted to Plaintiffs and, accordingly, seeking declaratory judgment that their ORRI is enforceable as to the subsequent oil and gas lease purchased by QC. Quest denied that the ORRI was enforceable due to a new lease that was granted by the landowners. Quest Cherokee agreed to resolve this matter as part of a global settlement in the Well Refined Drilling Litigation identified above.

 

Barbara Cox v. Quest Cherokee, LLC , U.S. District Court for the District of New Mexico, Case No. CIV-08-0546, filed April 18, 2008

 

Quest Cherokee 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 alleges that Quest Cherokee violated the New Mexico Surface Owner Protection Act and has committed a trespass and nuisance in the drilling and maintenance of the well. Quest Cherokee denies the allegations of plaintiff. Plaintiff has not articulated any firm damage numbers. Quest Cherokee intends to defend vigorously against plaintiff’s claims.

 

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. were 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.

Quest Resource Corporation, et al. v. David E. Grose, et al., Case No. CJ-2009-2078, in the District Court of Oklahoma County, State of Oklahoma, filed March 3, 2009

 

QRCP, et al. filed this action against defendants alleging that defendants engaged in a fraudulent kick-back scheme. In particular plaintiffs contend that defendants conspired to place orders for pipe at marked up prices and would split the price of the markup. The amount of kick-backs is estimated to be approximately $1,700,000. Further, plaintiffs allege that defendants Grose and Mueller conspired to cause an invoice for $1,000,000 to be paid for pipe that plaintiffs never received and, instead, Grose and Mueller converted the funds. No deadlines have been set by the court and no discovery has taken place. Plaintiffs are currently attempting service of process on defendants. Plaintiffs will pursue their claims against defendants vigorously.

 

 

No matters were submitted to a vote of security holders during the fourth quarter of 2008.

PART II

 

 

Market Information

 

Our common units trade on The NASDAQ Global Market under the symbol “QELP.” The table set forth below presents the range of high and low last reported sales prices of our common units on NASDAQ for each quarter since our initial public offering on November 9, 2007. In addition, distributions declared during each quarter are presented.

 

 

 

 

Record Holders

 

At the close of business on June 9, 2009, based upon information received from our transfer agent, we had 11 common unitholders of record. This number does not include owners for whom common units may be held in “street” names.

 

Cash Distributions to Unitholders

 

In light of the decline in our cash flows from operations due to declines in oil and natural gas prices during the last half of 2008, the costs of the investigation and associated remedial actions, including the reaudit and restatement of our financial statements, and concerns about a potential borrowing base redetermination in the second quarter of 2009 and the need to repay or refinance our term loan by September 30, 2009, the board of directors of our general partner decided to suspend distributions on all units starting with the distribution for the fourth quarter of 2008 in order to conserve cash to properly conduct operations, maintain strategic options and plan for future required principal payments under our debt instruments.

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 be resumed, if ever. In October of 2008, our credit agreements were amended. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreements.” The amended 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. Future cash distributions are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. We are currently focusing on negotiating documentation to complete the Recombination and there is no present intent to resume the payment of distributions or to pay any arrearages.

 

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. Our general partner has determined and is expected to continue to conclude for the remainder of 2009, if not longer, that we do not have any available cash. The amount of available cash generally is all cash on hand at the end of the quarter:

 

 

 

 

Our general partner is entitled to 2% of all quarterly distributions that we make prior to our liquidation. The general partner’s 2% interest in these distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. The following discussion assumes our general partner maintains its 2% general partner interest. Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 25%, of the cash we distribute from operating surplus (as defined in our partnership agreement) in excess of $0.46 per unit per quarter.

 

During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to the minimum quarterly distribution of $0.40 per common unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

 

The subordination period will extend until the first day of any quarter beginning after December 31, 2012 that each of the following tests are met:

 

 

 

When the subordination period expires, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:

 

 

If the tests for ending the subordination period are satisfied for any three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2010, 25% of the subordinated units will convert into an equal number of common units. Similarly, if those tests are also satisfied for any three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2011, an additional 25% of the subordinated units will convert into an equal number of common units. The second early conversion of subordinated units may not occur, however, until at least one year following the end of the period for the first early conversion of subordinated units.

 

In addition to the early conversion of subordinated units described above, all of the subordinated units will convert into an equal number of common units on the first day of any quarter beginning after December 31, 2010 that each of the following tests are met:

 

 

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

 

 

 

 

Recent Sales of Unregistered Securities

 

None.

 

Purchases of Equity Securities

 

None.

 

The following table sets forth selected consolidated financial data of us and the Predecessor for the periods and as of the dates indicated. The selected financial data as of December 31, 2008, 2007, 2006 and 2005 and for the year ended December 31, 2008, the periods from November 15, 2007 to December 31, 2007 and January 1, 2007 to November 14, 2007, and the years ended December 31, 2006 and 2005 are derived from our audited consolidated/carve out financial statements. The selected financial data for the seven month transition period ended December 31, 2004 and the fiscal year ended May 31, 2004 are derived from the unaudited management accounts of the Predecessor for such periods, not from the Predecessor’s previously filed audited financial statements. All periods prior to 2008 have been restated from previously filed amounts. See Note 16 — Restatement to the consolidated financial statements for a discussion of the restatements.