Quest Resource (QRCP)

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K/A

(Amendment No. 1)

 

 

Commission file number: 0-17371

 

 

 

 

QUEST RESOURCE CORPORATION

(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.  o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

(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 voting common equity held by non-affiliates computed by reference to the last reported sale of the registrant’s common stock on June 30, 2008, the last business day of the registrant’s most recently completed second fiscal quarter, at $11.41 per share was $221,824,377. This figure assumes that only the directors and officers of the registrant, their spouses and controlled corporations were affiliates. There were 31,867,527 shares outstanding of the registrant’s common stock as of May 15, 2009.

 

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 3, 2009 (the “Original Filing”), of Quest Resource Corporation (the “Company”) 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 share, stockholders’ equity or the Company’s Consolidated Balance Sheet, Consolidated Statement of Cash Flows or Consolidated Statement of Stockholders’ 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 19 — 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 Company 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 Company’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 Chief Executive Officer and President, who is our principal executive officer, and our Chief Financial Officer, who is our principal financial officer, in Exhibits 31.1, 31.2, 32.1 and 32.2.

TABLE OF CONTENTS

 

 

EXPLANATORY NOTE TO ANNUAL REPORT

 

This Annual Report on Form 10-K/A for the year ended December 31, 2008 includes restated and reaudited consolidated financial statements for Quest Resource Corporation (“QRCP” or the “Company”) as of December 31, 2007 and 2006 and for the periods ended December 31, 2007, 2006 and 2005. QRCP 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.

 

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

 

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

 

As reported on a Current Report on Form 8-K filed on January 2, 2009, on December 31, 2008, the board of directors of QRCP determined that the audited consolidated financial statements of QRCP as of and for the years ended December 31, 2007, 2006 and 2005 and QRCP’s unaudited consolidated financial statements as of and for the three months ended March 31, 2008 and as of and for the three and six months ended June 30, 2008 should no longer be relied upon.

 

Restatement and Reaudit — In October 2008, QRCP’s audit committee engaged a new independent registered public accounting firm to audit the Company’s consolidated financial statements for 2008 and, in January 2009, engaged them to reaudit the Company’s consolidated financial statements as of December 31, 2007 and 2006 and for the years ended December 31, 2007, 2006 and 2005.

 

The restated consolidated financial statements included in this Form 10-K/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 stockholders’ equity, major restatement adjustments and restated stockholders’ equity as well as previously reported net income (loss), major restatement adjustments and restated net income (loss) as of and for the periods indicated (in thousands):

 

 

* Includes minority interest impact.

 

Reconciliations from amounts previously included in QRCP’s consolidated financial statements to restated amounts on a financial statement line item basis are presented in Note 18 to the accompanying consolidated financial statements.

 

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

 

 

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

 

 

All dollar amounts and other data presented in previously filed Annual Reports on Form 10-K for prior years have been revised to reflect the restated amounts throughout this Form 10-K/A, even where such amounts are not labeled as restated.

 

General

 

Quest Resource Corporation is a Nevada corporation. Our principal executive offices are located at 210 Park Avenue, Suite 2750, Oklahoma City, Oklahoma 73102 and our telephone number is (405) 600-7704. Unless the context clearly requires otherwise, references in this report to “we,” “us,” and “our” refer to the Company and its subsidiaries and affiliates, including Quest Energy and Quest Midstream, on a consolidated basis. Quest Energy is a publicly traded limited partnership engaged in oil and gas production operations. Quest Midstream is a private limited partnership engaged in natural gas pipeline operations.

 

We are an integrated independent energy company engaged in the acquisition, exploration, development, production and transportation of oil and natural gas.

 

We divide our operations into two reportable business segments:

 

 

Financial information by segment and revenues from our external customers are located in Item 8. “Financial Statements and Supplementary Data” to this Annual Report on Form 10-K/A.

 

Quest Resource Corporation

 

QRCP’s assets as of May 15, 2009 consist of the following:

 

 

The following chart reflects a simplified version of our organizational structure to better illustrate how we own our assets.

 

 

Since the initial public offering of Quest Energy in November 2007, QRCP’s potential sources of revenue and cash flows consist almost exclusively of distributions on its partnership interests in Quest Energy and Quest Midstream, because its Appalachian Basin assets largely consist of undeveloped acreage. Both Quest Energy and Quest Midstream are required by the terms of their partnership agreements to distribute all cash on hand at the end of each quarter, less reserves established by their general partners in their sole discretion to provide for the proper conduct of their respective businesses or to provide for future distributions.

 

In light of the decline in QELP’s cash flows from operations due to declines in oil and natural gas prices during the last half of 2008, the costs of the investigation and associated remedial actions, including the reaudit and restatement of its financial statements, and concerns about a potential borrowing base redetermination in the second quarter of 2009 and the need to repay or refinance QELP’s term loan by September 30, 2009, the board of directors of Quest Energy GP decided to suspend distributions on QELP’s subordinated units for the third quarter of 2008 and on all units starting with the distribution for the fourth quarter of 2008 in order to conserve cash to properly conduct operations, maintain strategic options and plan for future required principal payments under Quest Energy’s debt instruments. QRCP would have received approximately $20 million from Quest Energy during 2009 if the minimum quarterly distribution of $0.40 was paid on all of Quest Energy’s units for the full year.

 

Quest Midstream did not pay any distributions on any of its units for the third or fourth quarters of 2008 because of a restriction imposed under the terms of an amendment to its credit agreement which provided that no distributions could be paid until the audited financial statements for the year ended December 31, 2008 were delivered to the lenders and thereafter could only be paid if, after the payment of such distributions, the total leverage ratio was not greater than 4.0 to 1.0. The Quest Midstream audited financial statements for the year ended December 31, 2008 were delivered on March 31, 2009.

 

QRCP received cash distributions from Quest Energy of $1.9 million during the first quarter of 2008, $3.8 million during the second quarter of 2008, $4.0 million during the third quarter of 2008 and $0.2 million during the fourth quarter of 2008. QRCP did not receive any cash distributions from Quest Midstream during 2008. No distributions have ever been paid on the Quest Energy or Quest Midstream incentive distribution rights.

QRCP does not expect to receive any distributions from Quest Energy or Quest Midstream in 2009 and is unable to estimate at this time when such distributions may be resumed. In October and November of 2008, QRCP’s credit agreement and the credit agreements for each of Quest Energy and Quest Midstream 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 the credit agreements restrict the ability of Quest Energy and Quest Midstream to pay distributions, among other things. Even if the restrictions on the payment of distributions under Quest Energy’s and Quest Midstream’s credit agreements are removed, both partnerships may continue to not pay distributions in order to conserve cash for the repayment of indebtedness or other business purposes.

 

Arrearages accrue for the unpaid distributions on the common units in Quest Energy and Quest Midstream and the related distributions on the general partner units. Quest Energy and Quest Midstream are not obligated to ever pay these amounts, but they may not make distributions on the subordinated units QRCP owns until all arrearages on the common units and the related general partner units have been paid. The majority of the interests QRCP owns, however, are subordinated units. QRCP owns 8,857,981 subordinated units in Quest Energy and 35,134 Class A subordinated units and 4,900,000 Class B subordinated units in Quest Midstream. QRCP also indirectly owns incentive distribution rights in Quest Energy and Quest Midstream that would entitle it to receive an increasing percentage of cash distributed by each of Quest Energy and Quest Midstream if certain target distribution levels were reached. No incentive distributions can be paid in a quarter until all arrearages on the common units have been paid and the minimum quarterly distribution has been paid for that quarter on all common units and subordinated units. The subordinated units and the incentive distribution rights do not accrue arrearages.

 

Even if Quest Energy and Quest Midstream do not pay distributions, the Company and all other unitholders may be liable for taxes on their share of each of Quest Energy and Quest Midstream’s taxable income.

 

Although QRCP is not currently receiving distributions from Quest Energy or Quest Midstream, QRCP continues to require cash to fund general and administrative expenses, debt service requirements, capital expenditures to develop and maintain its undeveloped acreage, drilling commitments and payments to landowners necessary to maintain its oil and gas leases, which are expected to average $2.7 million per quarter for 2009.

 

As of December 31, 2008, excluding QELP and QMLP, QRCP had cash and cash equivalents of $4.0 million and no ability to borrow under the terms of its credit agreement. QRCP currently estimates that it will not have enough cash to pay its expenses, including capital expenditures and debt service requirements, after August 31, 2009. Our independent registered public accounting firm has expressed doubt about our ability to continue as a going concern. See Item 1A. “Risk Factors — Risks Related to Our Business — Our independent registered public accounting firm has expressed substantial doubt about our ability to continue as a going concern.” The August 31, 2009 date could be extended if QRCP is able to restructure its debt obligations, issue equity securities and/or sell additional assets. If QRCP is not successful in obtaining sufficient additional funds, there is a significant risk that QRCP will be forced to file for bankruptcy protection. See Item 1A. “Risk Factors — Risks Related to Our Business — QRCP’s potential sources of revenue and cash flows consist almost exclusively of distributions from Quest Energy and Quest Midstream, neither of which is expected to pay distributions in 2009 and as a result, we do not expect QRCP to be able to meet its cash disbursement obligations unless it engages in transactions outside the ordinary course of business.”

 

Oil and Gas Production

 

Cherokee Basin.  We currently conduct our oil and gas production operations in the Cherokee Basin through QELP. QELP’s oil and gas production operations are primarily focused on the development of coal bed methane or CBM in a 15-county region in southeastern Kansas and northeastern Oklahoma known as the Cherokee Basin. As of December 31, 2008, QELP had 152.7 Bcfe of estimated net proved reserves in the Cherokee Basin, of which approximately 97.7% were CBM and 81.6% were proved developed. QELP operates approximately 99% of its existing Cherokee Basin wells, with an average net working interest of approximately 99% and an average net revenue interest of approximately 82%. We believe QELP is the largest producer of natural gas in the Cherokee Basin with an average net daily production of 57.3 Mmcfe for the year ended December 31, 2008. QELP’s estimated net proved reserves in the Cherokee Basin at December 31, 2008 had estimated future net revenues discounted at 10%, which we refer to as the “standardized measure,” of $129.8 million. QELP’s Cherokee Basin reserves have an

average proved reserve-to-production ratio of 7.3 years (5.0 years for QELP’s proved developed properties) as of December 31, 2008. QELP’s typical Cherokee Basin CBM well has a predictable production profile and a standard economic life of approximately 15 years.

 

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

 

Seminole County, Oklahoma.  We also currently conduct our oil production operations in Seminole County, Oklahoma through Quest Energy. QELP owns 55 gross productive oil wells and the development rights to approximately 1,481 net acres in Seminole County, Oklahoma. As of December 31, 2008, the oil producing properties had estimated net proved reserves of 588,800 Bbls, all of which are proved developed producing. During 2008, net production for QELP’s Seminole County properties was 148 Bbls/d. QELP’s 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 QELP’s acreage. QELP’s ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approval, oil prices, costs and drilling results. There were no proved undeveloped reserves given to these locations as of December 31, 2008.

 

Appalachian Basin.  Both QELP and QRCP own producing properties in Appalachia that are operated by Quest Eastern, formerly PetroEdge Resources (WV), LLC (“PetroEdge”), which we acquired on July 11, 2008. All production for 2008 was owned by QELP. In February 2009, QRCP began production in the Marcellus Shale in Wetzel County, West Virginia.

 

Our oil and gas production operations in the Appalachian Basin are primarily focused on the development of the Marcellus Shale. We believe there are approximately 334 potential gross vertical well locations and approximately 123 potential gross horizontal well locations for the Marcellus Shale, including significant development opportunities for Devonian Sands and Brown Shales. These potential well locations are located within QRCP’s acreage in West Virginia and New York.

 

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

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

 

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

 

As of December 31, 2008, QRCP owned the development rights to approximately 68,161 net acres throughout the Appalachian Basin and had only developed approximately 12% of its acreage. See “— Recent Developments” below for further information regarding our Appalachian Basin assets. As of December 31, 2008, QRCP’s proved undeveloped acreage contained approximately 22 gross drilling locations.

 

For 2009, QRCP has budgeted approximately $2.4 million of net expenditures to drill one gross vertical well, complete three gross wells and connect four gross wells. This one new well will be drilled on a location that is classified as containing proved reserves in our December 31, 2008 reserve report. QELP has budgeted another $1.4 million for artificial lift equipment, vehicle replacement and purchases and salt water disposal facilities. However, QRCP and QELP intend to fund these capital expenditures only to the extent that they have available cash after taking into account their debt service and other obligations. We can give no assurance that any such funds will be available based on current commodity prices and other current conditions.

 

Natural Gas Pipelines Operations

 

We conduct our natural gas pipelines operations through Quest Midstream and Quest Eastern.

 

Cherokee Basin.  Bluestem Pipeline, LLC, a wholly-owned subsidiary of Quest Midstream (“Bluestem”), owns and operates a natural gas gathering pipeline network of approximately 2,173 miles that serves our acreage position in the Cherokee Basin. Presently, this system has a maximum daily throughput of approximately 85 Mmcf/d and is operating at about 90% capacity. Quest Energy transports 99% of its Cherokee Basin gas production through Bluestem’s gas gathering pipeline network to interstate pipeline delivery points. Approximately 6% of the current throughput on Bluestem’s natural gas gathering pipeline system is for third parties.

 

As of December 31, 2008, QELP had an inventory of approximately 185 gross drilled CBM wells awaiting connection to QMLP’s gas gathering system.

 

Interstate Pipeline System.  Quest Pipelines (KPC), which we refer to as KPC, owns and operates a 1,120 mile interstate natural gas pipeline (the “KPC Pipeline”) which transports natural gas from northern Oklahoma and western

Kansas to the metropolitan Wichita and Kansas City markets. Further, it is one of only three pipeline systems currently capable of delivering gas into the Kansas City metropolitan market. The KPC system includes three compressor stations with a total of 14,680 horsepower and has a throughput capacity of approximately 160 Mmcf/d. KPC has supply interconnections with pipelines owned and/or operated by Enogex Inc., Panhandle Eastern PipeLine Company and ANR Pipeline Company, allowing QMLP to transport natural gas volumes sourced from the Anadarko and Arkoma basins, as well as the western Kansas and Oklahoma panhandle producing regions. KPC’s two primary customers are Kansas Gas Service (KGS) and Missouri Gas Energy (MGE), both of which are served under firm natural gas transportation contracts. KGS, a division of ONEOK, Inc., is the local distribution company in Kansas for Kansas City and Wichita as well as a number of other municipalities. MGE, a division of Southern Union Company, is a natural gas distribution company that serves over a half-million customers in 155 western Missouri communities.

 

Appalachian Basin.  Quest Eastern owns and operates a gas gathering pipeline network of approximately 183 miles that serves our acreage position in the Appalachian Basin. The pipeline delivers both to intrastate gathering and interstate pipeline delivery points. Presently, this system has a maximum daily throughput of approximately 15.0 Mmcf/d and is operating at about 20% capacity. All of QELP’s Appalachian Basin gas production is transported by Quest Eastern’s gas gathering pipeline network. Less than 1% of the current volumes transported on Quest Eastern’s natural gas gathering pipeline system are for third parties.

 

Organizational Structure

 

The following chart reflects our complete organizational structure. The chart excludes 15,000 QELP common units issued, or to be issued, to QELP’s independent directors and 117,877 QMLP common units and 15,000 Class B subordinated units issued, or to be issued, to QMLP’s independent directors and officers.

 

Recent Developments

 

PetroEdge Acquisition

 

As discussed above under “— General — Oil and Gas Production — Appalachian Basin”, on July 11, 2008, QRCP acquired PetroEdge and simultaneously transferred PetroEdge’s oil and natural gas producing wells to Quest Energy. This acquisition followed closely after QRCP’s June 4, 2008 acquisition of a one-year option to purchase certain drilling and other rights in and below the Marcellus Shale (the “Deep Rights”) in and to certain oil and gas leases covering approximately 28,700 acres in Potter County, Pennsylvania for $4 million. Certain provisions of the option agreement gave us rights to drill wells in the Deep Rights during the one-year option period.

 

Quest Energy funded its purchase of the PetroEdge wellbores with borrowings under its revolving credit facility, which was increased from $160 million to $190 million as part of the acquisition, and the proceeds of a $45 million, six-month term loan under a Second Lien Senior Term Loan Agreement (the “Second Lien Loan Agreement”) with Royal Bank of Canada (“RBC”), as administrative agent and collateral agent, KeyBank National Association, as syndication agent, Société Générale, as documentation agent, and the lenders party thereto.

 

QRCP funded the balance of the PetroEdge acquisition with proceeds from a public offering of 8,800,000 shares of QRCP common stock at a price of $10.25 per share that closed on July 8, 2008. QRCP received net proceeds from this offering of approximately $85.2 million. Simultaneously with the closing of the PetroEdge acquisition, QRCP entered into an Amended and Restated Credit Agreement (the “Credit Agreement”) to convert its then existing $50 million revolving credit facility to a $35 million term loan with a maturity date of July 11, 2010. The Credit Agreement is among QRCP, as the borrower, RBC, as administrative agent and collateral agent, and the lenders party thereto. RBC required QRCP to use $13 million of the proceeds from the equity offering to reduce the outstanding indebtedness under the Credit Agreement from $48 million to $35 million.

 

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

 

Internal Investigation; Restatements and Reaudits

 

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

 

The investigation is substantially complete. The investigation revealed that the Transfers resulted in a loss of funds totaling approximately $10 million by the Company. Further, it was determined that our former chief financial officer directly participated and/or materially aided our former chief executive officer in connection with the unauthorized Transfers. In addition, the Oklahoma Department of Securities has filed a lawsuit alleging that our former chief financial officer and our former purchasing manager each received kickbacks of approximately $0.9 million from several related suppliers over a two-year period and that during the third quarter of 2008, they also engaged in the direct theft of $1 million for their personal benefit and use. In March 2009, Mr. Mueller, the former purchasing manager, pled guilty to one felony count of misprision of justice. Sentencing is pending. We have filed lawsuits against all three of these individuals seeking an asset freeze and damages related to the Transfers, kickbacks and thefts and we intend to pursue all remedies available under the law. We settled the lawsuits against Mr. Cash on May 19, 2009. See “— Settlement Agreements” below. There can be no assurance that we will be

successful in recovering any additional amounts. Any additional recoveries may consist of assets other than cash and accurately valuing such assets in the current economic climate may be difficult. Any amounts recovered will be recognized by us for financial accounting purposes only in the period in which the recovery occurs.

 

QRCP, Quest Energy, Quest Energy GP and certain of their officers and directors have been named as defendants in a number of securities class action lawsuits and stockholder derivative lawsuits arising out of or related to the Transfers. See Item 3. “Legal Proceedings.”

 

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

 

 

We estimate that the increased costs related to the foregoing will be between approximately $7.0 million and $8.0 million.

 

Global Financial Crisis and Impact on Capital Markets and Commodity Prices

 

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

 

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

 

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

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

 

Overall, as a result, our operating profitability was seriously adversely affected during the second half of 2008 and is expected to continue to be impaired during 2009. While our existing commodity hedge position mitigates the impact of commodity price declines, it does not eliminate the potential effects of changing commodity prices.

 

See Item 1A. “Risk Factors — Risks Related to Our Business — The current financial crisis and economic conditions may have a material adverse impact on our business and financial condition that we cannot predict.”

 

Management Personnel Changes

 

In connection with the investigation of the Transfers, Jerry Cash, our former Chairman of the Board and Chief Executive Officer, resigned on August 23, 2008, and David Grose, our former Chief Financial Officer, was placed on administrative leave on August 22, 2008. On August 24, 2008, our Chief Operating Officer, David Lawler, was appointed President, and Jack Collins, our Executive Vice President of Investor Relations, was appointed Interim Chief Financial Officer. On September 13, 2008, Mr. Grose was terminated from all positions with us. Eddie LeBlanc became our Chief Financial Officer on January 9, 2009, with Mr. Collins becoming our Executive Vice President of Finance/Corporate Development. On May 7, 2009, Mr. Lawler was appointed our Chief Executive Officer. On July 11, 2008, Richard Muncrief resigned as President and Chief Operating Officer of Quest Midstream GP to pursue other opportunities, and on September 30, 2008, Michael Forbau was elected the Chief Operating Officer of Quest Midstream GP.

 

NASDAQ Non-compliance

 

Our common stock is currently listed on the NASDAQ Global Market. On November 19, 2008, we received a letter from the staff of NASDAQ indicating that, because of our failure to timely file our Form 10-Q for the quarter ended September 30, 2008, we no longer complied with the continued listing requirements set forth in NASDAQ Marketplace Rule 4310(c)(14) (now Rule 5250(c)(1)). As permitted by NASDAQ rules, we timely submitted a plan to NASDAQ staff to regain compliance on January 20, 2009. Following a review of this plan, NASDAQ staff granted us an extension until May 11, 2009 to file our Form 10-Q. We did not file our Form 10-Q for the quarter ended September 30, 2008 on that date. On May 12, 2009, we received a staff determination notice (the “Staff Determination”) from NASDAQ stating that our common stock is subject to delisting since we were not in compliance with the filing requirements for continued listing. The NASDAQ Listing Qualifications Hearing Panel (the “Panel”) granted our request for a hearing to appeal the Staff Determination and such 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 stock will not be delisted.

 

Credit Agreement Amendments

 

In October and November 2008, QRCP, Quest Cherokee and Quest Energy, and Quest Midstream and Bluestem entered into amendments to their respective credit agreements that, among other things, amended and/or waived certain of the representations and covenants contained in each credit agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result of (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream. The Quest Cherokee amendment also extended the maturity date of the Second Lien Senior Term Loan Agreement (the “Second Lien Loan Agreement”) from January 11, 2009 to September 30, 2009 due to our inability

to refinance the Second Lien Loan Agreement as a result of a combination of the ongoing investigation and the global financial crisis. The amendments also restricted the ability of Quest Midstream and Quest Energy to pay distributions to QRCP.

 

In May 2009, QRCP entered into an amendment to the Credit Agreement to, among other things, waive certain events of default related to its financial covenants and collateral requirements, extend certain financial reporting deadlines and permit the settlement agreements with Mr. Cash discussed below.

 

In June 2009, QRCP, Quest Cherokee and Quest Energy entered into amendments to their respective 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. The QRCP amendment also waived financial covenant (namely the interest coverage ratio and leverage ratio) events of default for the fiscal quarter ended June 30, 2009, waived any mandatory prepayment due to any collateral deficiency during the fiscal quarter ended September 30, 2009, and deferred until September 30, 2009 the interest payment due on June 30, 2009, which amount was represented by a promissory note bearing interest at the Base Rate (as defined in QRCP’s credit agreement) with a maturity date of September 30, 2009.

 

In July 2009, Quest Cherokee received notice from RBC that the borrowing base under the Quest Cherokee first lien loan 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 loan 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 loan agreement. On July 8, 2009, Quest Cherokee repaid the $14 million Borrowing Base Deficiency.

 

See “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 and Asset Sales

 

As discussed above under “General — Quest Resource Corporation,” distributions were suspended on Quest Energy’s subordinated units beginning with the third quarter of 2008 and distributions were suspended on all of Quest Energy’s units, beginning with the fourth quarter of 2008. Distributions were suspended on all of Quest Midstream’s units beginning with the third quarter of 2008. Since these distributions would have been substantially all of QRCP’s cash flows for 2009, the loss of the distributions was material to QRCP’s financial position.

 

In October 2008, we negotiated an additional $6 million term loan under the Credit Agreement with a maturity date of November 30, 2008. We agreed with our lenders that the additional term loan would be repaid with the net proceeds from asset sales by QRCP and that the first $4.5 million of net proceeds in excess of any additional term loans that were borrowed would be used to repay QRCP’s $35 million term loan.

 

On October 30, 2008, QRCP sold its interest in approximately 22,600 net undeveloped acres and one well in Somerset County, Pennsylvania to a private party for approximately $6.8 million. On November 26, 2008, QRCP sold its interest in the development rights and related purchase option, which it had purchased on June 4, 2008 covering approximately 28,700 acres in Potter County, Pennsylvania, to an undisclosed party for approximately $3.2 million. On February 13, 2009, QRCP sold its interest in approximately 23,076 net undeveloped acres in the Marcellus Shale and one well in Lycoming County, Pennsylvania to a third party for approximately $8.7 million. Management decided that these undeveloped acres were good candidates for disposition in the current environment given the lack of gathering and transportation infrastructure in the immediate area and the cost and time that would be involved in establishing significant flow of natural gas.

 

In addition to these sales, on November 5, 2008, QRCP sold a 50% interest in approximately 4,500 net undeveloped acres, three wells in various stages of completion and existing pipelines and facilities in Wetzel

County, West Virginia to another party for $6.1 million. QRCP will continue to operate the Wetzel County property. All future development costs will be split equally between QRCP and the other party. This joint venture arrangement allows QRCP to retain a significant interest in the Wetzel County property, which we believe is a desirable asset due to established infrastructure, pipeline taps and proved offset production in the area.

 

QRCP borrowed $2 million of the additional $6 million term loan under its Credit Agreement in October 2008. A portion of the net proceeds from the asset sales were used to repay the $2 million additional term loan and to reduce QRCP’s $35 million term loan to $28.3 million as of May 15, 2009.

 

Intercompany Accounts

 

As part of the investigation, we determined that our former chief financial officer had not been promptly settling intercompany accounts among the Company, Quest Midstream and Quest Energy. Intercompany balances as of September 30, 2008 were quantified and have been paid: QRCP paid Quest Midstream $3.6 million in October 2008, $2.0 million in November 2008 and an additional $0.2 million, including interest, in February 2009; and Quest Energy paid Quest Midstream $4.0 million, including interest, in February 2009. The Company’s payments were funded with the proceeds from the asset sales. The remainder of the proceeds from these sales are being used to fund QRCP’s ongoing operations.

 

Cost-cutting Measures

 

In addition to the sales of assets and suspension of distributions discussed above, during the third and fourth quarters of 2008, we took significant actions to reduce our costs and retain cash for anticipated debt service requirements for QRCP and Quest Energy during 2009. Among other things, we renegotiated and postponed drilling commitments related to the PetroEdge properties, we significantly reduced our level of maintenance and expansion capital expenditures, we hired Mr. LeBlanc as our Chief Financial Officer (which allowed us to terminate the consultants that had been hired to assist our interim chief financial officer) and we eliminated 56 field positions and 3 corporate positions. We continue to evaluate additional options to further reduce our expenditures.

 

Decrease in Year-End Reserves; Impairment

 

Due to the low price for natural gas as of December 31, 2008 as described above, revisions resulting from further technical analysis (see Note 21 — Supplemental Information on Oil and Gas Producing Activities (Unaudited) to the accompanying consolidated financial statements) and production during the year, proved reserves decreased 17.2% to 174.8 Bcfe at December 31, 2008 from 211.1 Bcfe at December 31, 2007, and the standardized measure of our proved reserves decreased 42.7% to $164.1 million as of December 31, 2008 from $286.2 million as of December 31, 2007. The December 31, 2008 reserves were calculated using a spot price of $5.71 per Mmbtu (adjusted for basis differential, prices were $5.93 per Mmbtu in the Appalachian Basin and $4.84 per Mmbtu in the Cherokee Basin). As a result of this decrease, we recognized a non-cash impairment of $298.9 million for the year ended December 31, 2008. As a result, the lenders under QELP’s revolving credit facility reduced QELP’s 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 — Quest Energy.”

 

Seminole County Acreage Acquisition

 

In early February 2008, QELP purchased certain oil producing properties in Seminole County, Oklahoma from a private company for $9.5 million. In connection with the acquisition, QELP entered into crude oil swaps for approximately 80% of the estimated production from the 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 Quest Energy’s credit facility. As of December 31, 2008, the properties had estimated net proved reserves of 588,800 Bbls, all of which were proved developed producing.

Settlement Agreements

 

As discussed above, QRCP and QELP filed lawsuits against Mr. Cash, the entity controlled by Mr. Cash that was used in connection with the Transfers and two former officers, who are the other owners of the controlled-entity, seeking, among other things, to recover the funds that were transferred. On May 19, 2009, QRCP, QELP and QMLP entered into settlement agreements with Mr. Cash, the controlled-entity and the other owners to settle this litigation. Under the terms of the settlement agreements, QRCP received (1) approximately $2.4 million in cash and (2) 60% of the controlled-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 cost of the internal investigation, they represent the majority of the value of the controlled-entity. We 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. QELP received all of Mr. Cash’s equity interest in STP Newco, Inc. (“STP”), which owns certain oil producing properties in Oklahoma, and other assets as reimbursement for all of the costs of the internal investigation and the costs of the litigation against Mr. Cash that have been paid by QELP.

 

Pinnacle Merger

 

On October 15, 2007, we and Pinnacle Gas Resources, Inc. (“Pinnacle”) entered into an Agreement and Plan of Merger, pursuant to which we and Pinnacle agreed to combine our operations (the “Merger Agreement”). On May 16, 2008, the Merger Agreement was terminated. Pursuant to the terms of the Merger Agreement, either we or Pinnacle had the right to terminate the Merger Agreement if the proposed merger was not completed by May 16, 2008. No termination fee was payable by either of us as a result of the termination of the Merger Agreement.

 

2008 Operating Results

 

Our strategy prior to the events discussed above was to create value through the growth of the master limited partnerships of Quest Energy and Quest Midstream. This strategy was supported by a talented engineering and operating team assembled over the last two years. This team separated approximately 400 employees at our peak level of activity into discrete, highly focused groups: Capital Development, Production Operations, Well Servicing, Compression and Pipeline. These teams met or exceeded a number of performance-related goals that were established by management at the beginning of the year. For example, Quest Energy planned to drill 325 wells in the Cherokee Basin in 2008. Quest Energy drilled 338 wells in eight months, three months ahead of schedule, and delivered the results within its capital budget for the year. We did not drill any wells during the final four months of the year due to limited capital availability and low commodity prices. In addition, we had historically struggled to maintain a low level of wells offline due to well failures. For December 2008, on average less than 2% of our approximately 2,500 Cherokee Basin wells were offline per day. This level of performance was achieved through the implementation of rigorous engineering reviews, statistical failure analysis and the latest de-liquification process control technology. Our net production for 2008 was 21.75 Bcfe, which is a 23.4% increase over our net production in 2007 of 17.02 Bcfe. With respect to our midstream activities, we connected 328 wells to our Cherokee Basin gathering system and integrated the KPC Pipeline assets into our operations. We have also improved our safety culture by decreasing OSHA recordable incidents by 35% in 2008 as compared to 2007.

 

Recombination

 

Given the liquidity challenges facing the Company, Quest Midstream and Quest Energy, each entity has undertaken a strategic review of its assets and have evaluated and continue to evaluate transactions to dispose of assets in order to raise additional funds for operations and/or to repay indebtedness. On July 2, 2009, the Company, Quest Midstream, Quest Energy 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 “Recombination”). 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 stockholders and the unitholders of Quest Energy and 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 44% by current Quest Midstream common unitholders, approximately 33% by current QELP common unitholders (other than the Company), and approximately 23% by our current stockholders.

 

Business Strategy

 

Our business strategy for 2009 has been adjusted in response to the recent turmoil in the financial markets and the economy in general, including the reduction in commodity prices which was then exacerbated by the significantly increased general and administrative costs we have incurred as a result of the investigation and the reaudits and restatements of our consolidated financial statements. See “— Recent Developments.” We are focusing on the activities necessary to complete the Recombination while still maintaining a stable asset base, improving the profitability of our assets by increasing their utilization while controlling costs and reducing capital expenditures as discussed elsewhere in this Annual Report on Form 10-K/A, renegotiating with our lenders and possibly raising equity capital.

 

Prior to the events discussed above, our goal was to create stockholder value by growing our two master limited partnerships and investing capital to increase reserves, production and cash flow. In favorable product price markets and credit markets, we would accomplish this goal by focusing on the following key strategies:

 

 

We believe the acquisition of PetroEdge was an opportunity to grow our upstream business just as the acquisition of KPC by QMLP in November 2007 was for the midstream business. However, the significant decline in natural gas prices since the PetroEdge acquisition closed has substantially reduced the opportunity for an economic return on the PetroEdge assets.

 

Additionally, as discussed in more detail under “— Recent Developments”, we have instituted cost control measures, such as work force reductions and other cost savings actions, and have concentrated attention on managing cash flow and planning for future required principal payments. If the Quest entities are not recombined, deployment of any growth strategy will be highly unlikely. Furthermore, should the three individual entities

continue without a significant increase in product prices in the near term, combined with longer term forbearance under their credit facilities, each entity would likely face liquidation or bankruptcy.

 

Description of Our Exploration and Production Properties and Projects

 

Cherokee Basin

 

We produce CBM gas out of Quest Energy’s 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, Quest Energy’s average cost for drilling and completing a well will be between $113,000 and $125,000 excluding the related pipeline infrastructure. For 2009, in the Cherokee Basin, we have budgeted approximately

$3.8 million to drill seven new gross wells, connect and complete 49 existing gross wells, and connect and complete three existing salt water disposal wells. All of these new gas wells will be drilled on locations that are classified as containing proved reserves in our December 31, 2008 reserve report. In 2009, QELP plans to recomplete an estimated 10 gross wells and it has budgeted another $1.9 million for equipment, vehicle replacement, and other capital purchases, including the replacement of some of QELP’s existing pumps with submersible pumps that we believe provide enhanced removal of water from the wells. In addition, QELP has budgeted $2.4 million related to lease renewals and extensions for acreage that is expiring in 2009. However, we intend to fund these capital expenditures only to the extent that QELP has available cash from operations after taking into account its debt service. We can give no assurance that any such funds will be available.

 

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

 

Our development activities in the Cherokee Basin also include a program to recomplete CBM wells that produce from a single coal seam to wells that produce from multiple coal seams. During the year ended December 31, 2008, we recompleted approximately 10 wellbores in Kansas and an additional four wellbores in Oklahoma. For 2009, we plan to recomplete an estimated 10 gross wells. We believe we have approximately 200 additional wellbores that are candidates for recompletion to multi-seam producers. The recompletion strategy is to add four to five additional pay zones to each wellbore, in a two-stage process at an average cost of approximately $16,000 per well. Adding new zones to a well has a brief negative effect on production by first taking the well offline to perform the work and then by introducing a second dewatering phase of the newly completed formations. However, in the long term, we believe the impact of the multi-seam recompletions will be positive as a result of an increase in the rate of production and the ultimate recoverable reserves available per well.

 

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

 

Appalachian Basin

 

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

 

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

The method for exploring and drilling these targets is different in several aspects. The Mississippian and Upper Devonian sections are explored through vertical drilling. The lower Marcellus section is explored by both vertical and horizontal drilling. The Mississippian section is identified by distinct sand and limestone zones with conventional porosity and permeability. Depths range from 1,000-2,500 feet deep. The Upper Devonian sands, siltstones, and shales are identified as multiple stacked pay lenses with depths ranging from 2,500-7,000 feet deep. The Marcellus Shale ranges in depth from 5,900 feet in portions of West Virginia to 7,100 feet in other portions of West Virginia. In certain areas of our leasehold, vertical wells are drilled with combination completions in the Mississippian, Upper Devonian, and the Marcellus. Occasionally, vertical wells might only complete a single section of the three prospective pay intervals.

 

Our technical team has extensive experience in vertical and horizontal exploration, development and production. We have identified areas within the Appalachian Basin that we believe are prospective for both vertical and horizontal targets. Our leases cover approximately eighteen counties within the Appalachian Basin. Certain counties are vertical drilling targets for development and other counties are horizontal development targets. We believe there are over 334 gross vertical locations that would include potential production from one or all three of the Mississippian, Upper Devonian Sands, and Siltstones. We believe there are approximately 123 gross horizontal locations that would include the primary target for the Marcellus formation. We have recently drilled and set production pipe on two horizontal wells located in Wetzel County, West Virginia. This county in particular, along with Lewis County, West Virginia and Steuben County, New York, is prospective for horizontal drilling in the Marcellus. Depths to the Marcellus in Lewis County and Wetzel County range from 6,700 feet to 7,100 feet. The thickness of the Marcellus in these counties ranges from just over fifty feet thick to over ninety feet thick.

 

Appalachian Basin Projects

 

As discussed under “— Recent Developments,” in July 2008, we completed the PetroEdge acquisition, which expanded our position in the Appalachian Basin. At December 31, 2008, the Appalachian estimated net proved reserves totaled 18.6 Bcfe and were producing approximately 2.9 Mmcfe/d. During 2008, QRCP drilled one gross vertical well in Lycoming County, Pennsylvania, completed one gross vertical well in Somerset County, Pennsylvania, drilled one gross vertical well in Ritchie County, West Virginia, and drilled two gross horizontal wells in Wetzel County, West Virginia. The wells in Lycoming and Somerset Counties were subsequently sold as part of the asset sales discussed under “— Recent Developments — Suspension of Distributions and Asset Sales.” Connections to interstate pipelines have recently been installed near the Wetzel County wells and QRCP intends to complete the wells as soon as capital is available. We can give no assurance that any funds will be available prior to the closing of the Recombination or at all.

 

For 2009, QRCP has budgeted net capital expenditures of approximately $2.4 million to drill one gross vertical well and complete three gross wells. The new well will be drilled on a location that is classified as containing proved reserves in our December 31, 2008 reserve report. QRCP expects to connect all four of these gross wells in 2009. Quest Energy has budgeted another $1.4 million for artificial lift equipment, vehicle replacement and purchases and salt water disposal facilities. The expenditure of these funds is subject to capital being available. We can give no assurance that any funds will be available prior to the closing of the Recombination or at all.

 

Seminole County, Oklahoma

 

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

Oil and Gas Data

 

Estimated Net Proved Reserves

 

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

 

Production Volumes, Sales Prices and Production Costs

 

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

 

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. As of December 31, 2008, in the Appalachian Basin, we had 8,798 net developed acres and 59,592 net undeveloped acres. Subsequent to the divestiture of our acreage in Lycoming County, Pennsylvania, as of March 31, 2009, we had 8,758 net developed acres and 36,974 net undeveloped acres in the Appalachian Basin. Developed acres are acres spaced or assigned to productive wells/units based upon governmental authority or standard industry practice. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas, regardless of whether such acreage contains proved reserves.

Drilling Activities

 

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

 

 

 

 

Exploration and Production

 

General

 

As the operator of wells in which we have an interest, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Quest Energy Service, LLC, our wholly-owned subsidiary, manages all of our properties and employs production and reservoir engineers, geologists and other specialists. Quest Cherokee Oilfield Service, LLC, a wholly-owned subsidiary of Quest Energy, employs our Cherokee Basin and Appalachian Basin field personnel.

 

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

 

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

Oil and Gas Leases

 

As of December 31, 2008, we had over 4,500 leases covering approximately 627,244 net acres. The typical oil and gas lease provides for the payment of royalties to the mineral owner for all oil or gas produced from any well drilled on the lease premises. This amount ranges from 12.5% to 18.75% resulting in an 81.25% to 87.5% net revenue interest to us.

 

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

 

As of December 31, 2008, approximately 65% of our oil and gas leases were held by production, which means that for as long as our wells continue to produce oil or gas, we will continue to own those respective leases.

 

Natural Gas Pipelines

 

Gas Gathering Systems

 

QMLP’s approximately 2,173-mile low pressure gas gathering pipeline network is owned by Bluestem, a wholly-owned subsidiary of Quest Midstream. QMLP’s natural gas gathering pipeline network is located in the Cherokee Basin and provides a market outlet for natural gas in a region of approximately 1,000 square miles in size and has connections to both intrastate and interstate delivery pipelines. It is the largest gathering system in the Cherokee Basin with a current throughput capacity of approximately 85 Mmcf/d and delivers virtually all its gathered gas into Southern Star Central Gas Pipeline at multiple interconnects. This gathering system includes 83 field compression units comprising approximately 51,000 horsepower of compression in the field (most of which are currently rented) as well as seven CO₂ amine treating facilities.

 

The pipelines gather all of the natural gas produced by QELP in the Cherokee Basin pursuant to a midstream services and gas dedication agreement (see “— Midstream Services Agreement” below) in addition to some natural gas produced by other companies. The pipeline network is a critical asset for our future growth in the Cherokee Basin because natural gas gathering pipelines are a costly component of the infrastructure required for natural gas production and such pipelines are not easily constructed.

 

We intend to expand our gas gathering pipeline infrastructure through the development of new pipelines and to a lesser extent, through the acquisition of existing pipelines, if the outlook for commodity prices improves to the point where we believe future development in the Cherokee Basin is justified and Quest Midstream has available capital.

 

For 2008, our average cost for pipeline infrastructure to connect a Cherokee Basin well was approximately $65,500 per well. We estimate that our cost for pipeline infrastructure to connect a Cherokee Basin well will be approximately $61,000 per well for 2009. We expect to connect 56 wells in the Cherokee Basin in 2009, if the outlook for commodity prices improves to the point where we believe the connection of these wells is justified and Quest Midstream has available capital.

 

Quest Eastern owns and operates a gas gathering pipeline network of approximately 183 miles that serves our acreage position in the Appalachian Basin. The pipeline delivers both to intrastate gathering and interstate pipeline delivery points. Presently, this system has a maximum daily throughput of approximately 15 Mmcf/d and is operating at about 20% capacity. All of QELP’s Appalachian gas production is transported by Quest Eastern’s gas gathering pipeline network. Less than 1% of the current volumes transported on Quest Eastern’s natural gas gathering pipeline system are for third parties.

The following table sets forth the number of miles of gas gathering pipeline acquired or constructed by Quest Midstream and Quest Eastern during the periods indicated.

 

 

 

 

The table below sets forth the natural gas volumes gathered on our gas gathering pipeline networks during the years ended December 31, 2008 and 2007.

 

 

Midstream Services Agreement

 

Quest Energy and Quest Midstream are parties to a midstream services and gas dedication agreement entered into on December 22, 2006, but effective as of December 1, 2006. Pursuant to the midstream services agreement, Quest Midstream gathers and provides certain midstream services, including dehydration, treating and compression, to Quest Energy for all gas produced from Quest Energy’s 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, Quest Energy agreed to pay Quest Midstream an initial fee equal to $0.50 per Mmbtu of gas for gathering, dehydration and treating services and $1.10 per Mmbtu of gas for compression services, subject to an annual adjustment to be determined by multiplying each of the gathering services fee and the compression services fee by the sum of (i) 0.25 times the percentage change in the producer price index for the prior calendar year and (ii) 0.75 times the percentage change in the Southern Star first of month index for the prior calendar year. Such adjustment will be calculated within 60 days after the beginning of each year, but will be retroactive to the beginning of the year. Such fees will never be reduced below the initial rates described above. For 2008, the fees were $0.51 per Mmbtu of gas for gathering, dehydration and treating services and $1.13 per Mmbtu of gas for compression services. For 2009, the fees are $0.596 per Mmbtu of gas for gathering, dehydration and treating services and $1.319 per Mmbtu of gas for compression services. Such fees are subject to renegotiation in connection with each renewal period. In addition, at any time after each five year anniversary of the date of the midstream services agreement, each party will have a one-time option to elect to renegotiate the fees and/or the basis for the annual adjustment to the fees if the party believes there has been a material change to the economic returns or financial condition of either party. If the parties are unable to agree on the changes, if any, to be made to such terms, then the parties will enter into binding arbitration to resolve any dispute with respect to such terms.

 

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

 

Quest Midstream has an exclusive option for sixty days to connect to its gathering system each of the gas wells that Quest Energy develops in the Cherokee Basin. In addition, Quest Midstream will be required to connect to its gathering system, at its expense, any new gas wells that Quest Energy completes in the Cherokee Basin if Quest

Midstream would earn a specified internal rate of return from those wells. This rate of return is subject to renegotiation once after the fifth anniversary of the agreement and once during each renewal period at the election of either party. Quest Midstream also has the sole discretion to cease providing services on all or any part of its gathering system if it determines that continued operation is not economically justified. If Quest Midstream elects to do so, it must provide Quest Energy with 90 days written notice and will offer Quest Energy the right to purchase that part of the terminated system. If Quest Energy does acquire that part of the system and it remains connected to any other portion of Quest Midstream’s gathering system, then Quest Energy may deliver its 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 Quest Energy’s gas wells connected to Quest Midstream’s gathering system for an initial fee of $1.25 per linear foot and connect such lines to Quest Energy’s saltwater disposal wells for a fee of $1,000 per well, subject to an annual adjustment based on changes in the Employment Cost Index for Natural Resources, Construction, and Maintenance. For 2008, the fees were $1.29 per linear foot to install saltwater disposal lines and $1,030 per well to connect such lines to Quest Energy’s saltwater disposal wells. For 2009, the fees are $1.33 per linear foot to install saltwater disposal lines and $1,061 per well to connect such lines to Quest Energy’s saltwater disposal wells.

 

Appalachian Gathering Agreement

 

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

 

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

 

The gas transportation agreement will continue until terminated upon 90 days written notice by either party. Upon termination of the agreement, Quest Eastern may require Quest Cherokee to resize the compression within Quest 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.

 

Third Party Gas Gathering

 

For services rendered to parties other than Quest Energy, Quest Midstream retains a portion of the gas volumes sold. Approximately 6% of the gas transported on Quest Midstream’s natural gas gathering pipeline system in the Cherokee Basin is for third parties.

 

Interstate Pipelines

 

KPC, an indirect subsidiary of Quest Midstream, owns and operates an approximately 1,120-mile interstate gas pipeline, which transports natural gas from Oklahoma and western Kansas to the metropolitan Wichita and Kansas City markets. Further, it is one of only three pipeline systems currently capable of delivering gas into the Kansas City metropolitan market. The KPC system includes three compressor stations with a total of 14,680 horsepower and has a throughput capacity of approximately 160 Mmcf/d. KPC has supply interconnections with pipelines owned and/or operated by Enogex Inc., Panhandle Eastern PipeLine Company and ANR Pipeline

Company, allowing QMLP to transport natural gas volumes sourced from the Anadarko and Arkoma basins, as well as the western Kansas and Oklahoma panhandle producing regions.

 

Marketing and Major Customers

 

Exploration and Production

 

We market our own natural gas. In the Cherokee Basin for 2008, 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.

 

Gas Gathering

 

Approximately 94% of the throughput on Quest Midstream’s gas gathering pipeline system is attributable to Quest Energy production with the balance being other third party customers. Approximately 99% of the throughput on Quest Eastern’s gas gathering pipeline system in the Appalachian Basin is attributable to Quest Energy production.

 

Interstate Pipelines

 

KPC’s two primary customers are Kansas Gas Service (KGS) and Missouri Gas Energy (MGE), both of which are served under firm natural gas transportation contracts. For the period from November 1, 2007, the date of the KPC Pipeline acquisition, through December 31, 2007, approximately 60% of KPC’s revenue was from KGS and 36% was from MGE. During 2008, approximately 58% and 36% of KPC’s revenue was from KGS and MGE, respectively. KGS, a division of ONEOK, Inc., is the local distribution company in Kansas for Kansas City and Wichita as well as a number of other municipalities; while MGE, a division of Southern Union Company, is a natural gas distribution company that serves over one-half million customers in 155 western Missouri communities.

 

Commodity Derivative Activities

 

Quest Energy sells the majority of its gas in the Cherokee Basin based on the Southern Star first of month index, with the remainder sold on the daily price on the Southern Star index. Quest Energy sells the majority of its gas in the Appalachian Basin based on the Dominion Southpoint index, with the remainder sold on local basis. Quest Energy sells the majority of its oil production under a contract priced at a fixed discount to NYMEX oil prices. Due to the historical volatility of oil and natural gas prices, Quest Energy has implemented a hedging

strategy aimed at reducing the variability of prices it receives for the sale of its future production. While we believe that the stabilization of prices and production afforded Quest Energy by providing a revenue floor for its production is beneficial, this strategy may result in lower revenues than Quest Energy would have if it was not a party to derivative instruments in times of rising oil or natural gas prices. As a result of rising commodity prices, Quest Energy may recognize additional charges to future periods. Quest Energy holds derivative contracts based on Southern Star and NYMEX natural gas and oil prices and it has fixed price sales contracts with certain customers in the Appalachian Basin. These derivative contracts and fixed price contracts mitigate Quest Energy’s risk to fluctuating commodity prices but do not eliminate the potential effects of changing commodity prices. Quest Energy’s derivative contracts limit its exposure to basis differential risk as it generally enters into derivative contracts that are based on the same indices on which the underlying sales contracts are based or by entering into basis swaps for the same volume of hedges that settle based on NYMEX prices.

 

As of December 31, 2008, Quest Energy held derivative contracts and fixed price sales contracts totaling approximately 39.8 Bcf of natural gas and 66,000 Bbls of oil through 2012. Approximately 14.6 Bcf of Quest Energy’s Cherokee Basin natural gas production is hedged utilizing Southern Star contracts at a weighted average price of $7.78/Mmbtu for 2009 and approximately 22.5 Bcf of its Cherokee Basin natural gas production is hedged utilizing Southern Star contracts at a weighted average price of $7.42/Mmbtu for 2010 through 2012. Approximately 0.75 Bcf of Quest Energy’s Appalachian Basin natural gas production is hedged utilizing NYMEX contracts at a weighted average price of $11.00/Mmbtu for 2009 and approximately 1.2 Bcf of its Appalachian Basin natural gas is hedged utilizing NYMEX contracts at a weighted average price of $9.77/Mmbtu for 2010 through 2012. Quest Energy’s fixed price sales contracts hedge approximately 0.65 Bcf of its Appalachian Basin natural gas production at a weighted average price of $8.38/Mmbtu in 2009 and 0.1 Bcf of its Appalachian Basin natural gas production at a weighted average price of $8.96/Mmbtu in 2010.

 

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

 

Competition

 

Exploration and Production

 

We operate in a highly competitive environment for acquiring properties, marketing oil and gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive oil and gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and gas industry.

 

Gas Gathering

 

Quest Midstream’s and Quest Eastern’s gas gathering systems experience minimal competition because approximately 94% and 99%, respectively, of these systems’ throughput is attributable to Quest Energy production.

 

Interstate Pipelines

 

We compete with other interstate and intrastate pipelines in the transportation of natural gas for transportation customers primarily on the basis of transportation rates, access to competitively priced supplies of natural gas, markets served by the pipelines, and the quality and reliability of transportation services. Major competitors include Southern Star Central Gas Pipeline, Kinder Morgan Interstate Gas Transmission’s Pony Express Pipeline and

Panhandle Eastern Pipeline Company in the Kansas City market, and Southern Star Central Gas Pipeline, Peoples Natural Gas and Mid-Continent Market Center in the Wichita market.

 

Title to Properties

 

Oil and Gas Properties

 

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

 

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

 

On a small percentage of our acreage (less than 1.0%), the landowner in the past transferred the rights to the coal underlying their land to a third party. With respect to those properties, we have obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying those lands. In Oklahoma and Kansas, the law is unsettled as to whether the owner of the gas rights or the coal rights is entitled to the CBM gas. We are currently involved in litigation with the owner of the coal rights on these lands to determine who has the rights to the CBM gas.

 

Pipeline Rights-of-Way

 

Substantially all of our gathering systems and our transmission pipeline are constructed within rights-of-way granted by property owners named in the appropriate land records. All of our compressor stations are located on property owned in fee or on property obtained via long-term leases or surface easements.

 

Our property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not interfered, and we do not expect that they will materially interfere, with the conduct of our business. In many instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants. In some cases, not all of the owners named in the appropriate land records have joined in the right-of-way grants, but in substantially all such cases signatures of the owners of majority interests have been obtained. Substantially all permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets, and state highways, where necessary. Substantially all permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election.

 

Certain of our rights to lay and maintain pipelines are derived from recorded oil and gas leases, for wells that are currently in production; however, the leases are subject to termination if the wells cease to produce. In most cases, the right to maintain existing pipelines continues in perpetuity, even if the well associated with the lease ceases to be productive. In addition, because some of these leases affect wells at the end of lines, these rights-of-way will not be used for any other purpose once the related wells cease to produce.

Seasonal Nature of Business

 

Exploration and Production and Gas Gathering

 

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

 

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

 

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

 

Interstate Pipelines

 

Due to the nature of the markets served by the KPC Pipeline, primarily the metropolitan Wichita and Kansas City markets’ heating load, the utilization rate of the KPC Pipeline has traditionally been much higher in the winter months (December through April) than in the remainder of the year. However, due to the nature of the firm transportation agreements under which the vast majority of the KPC Pipeline revenue is derived, we are, to a material degree, profit neutral to these seasonal fluctuations.

 

Environmental Matters and Regulation

 

General

 

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

 

 

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

 

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

Waste Handling

 

The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous solid wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, production and transportation of oil and gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils, which may be regulated as hazardous wastes. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.

 

Comprehensive Environmental Response, Compensation and Liability Act

 

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

 

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

 

Water Discharges

 

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

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

 

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

 

Air Emissions

 

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

 

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

 

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

 

The Kyoto Protocol to the United Nations Framework Convention on Climate Change, or the Protocol, became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as “greenhouse gases”, that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol; however, Congress has recently considered proposed legislation directed at reducing “greenhouse gas emissions”, and certain states have adopted legislation, regulations and/or initiatives addressing greenhouse gas emissions from various sources, primarily

power plants. Additionally, on April 2, 2007, the U.S. Supreme Court ruled in Massachusetts v. EPA that the EPA has authority under the CAA to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks). The Court also held that greenhouse gases fall within the CAA’s definition of “air pollutant”, which could result in future regulation of greenhouse gas emissions from stationary sources, including those used in oil and gas exploration, production and transportation operations. The oil and gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations are not adversely impacted by the current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

 

Hydrogen Sulfide

 

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

 

National Environmental Policy Act

 

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

 

Endangered Species Act

 

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

 

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.

 

Exploration and Production

 

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

 

 

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.

Interstate Pipelines

 

The availability, terms and cost of transportation significantly affect sales of gas. The interstate transportation of gas and sale for resale of gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to gas pipeline transportation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the gas industry, most notably interstate gas transmission companies that remain subject to 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. We cannot predict the ultimate impact of these regulatory changes to our 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. We do not believe that we will be affected by any such FERC action materially differently than other interstate pipelines with which we compete.

 

The Energy Policy Act of 2005, or EP Act 2005, gave FERC increased oversight and penalty authority regarding market manipulation and enforcement. EP Act 2005 amended the Natural Gas Act of 1938, or NGA, to prohibit market manipulation and also amended the NGA and the Natural Gas Policy Act of 1978, or NGPA, to increase civil and criminal penalties for any violations of the NGA, NGPA and any rules, regulations or orders of FERC to up to $1,000,000 per day, per violation. In addition, FERC issued a final rule effective January 26, 2006 regarding market manipulation, which makes it unlawful for any entity, in connection with the purchase or sale of gas or transportation service subject to 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 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.

 

State Regulation

 

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

 

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

 

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

 

States may regulate rates of production and may establish maximum daily production allowables from oil and gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or

engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may limit the amounts of oil and gas that may be produced from our wells and may limit the number of wells or locations drilled.

 

Federal Regulation of Transportation of Gas

 

FERC regulates interstate natural gas pipelines pursuant to the NGA, NGPA and EP Act 2005. Generally, FERC’s authority over interstate natural gas pipelines extends to:

 

 

Rates charged by interstate natural gas pipelines may generally not exceed the just and reasonable rates approved by FERC, unless they are filed as “negotiated rates” and accepted by the FERC. In addition, interstate natural gas pipelines are prohibited from granting any undue preference to any person, or maintaining any unreasonable difference in their rates, terms, or conditions of service. Consistent with these requirements, the rates, terms, and conditions of the natural gas transportation services provided by interstate pipelines are governed by tariffs approved by FERC.

 

We own and operate one interstate natural gas pipeline system that is subject to these regulatory requirements. KPC owns and operates a 1,120-mile interstate natural gas pipeline system, which transports natural gas from Oklahoma and western Kansas to the metropolitan markets of Wichita and Kansas City. As an interstate natural gas pipeline, KPC is subject to FERC’s jurisdiction and the regulatory requirements summarized above. Maintaining compliance with these requirements on a continuing basis requires KPC to incur various expenses. Additional compliance expenses could be incurred if new or amended laws or regulations are enacted or existing laws or regulations are reinterpreted. KPC’s customers, the state commissions that regulate certain of those customers, and other interested parties also have the right to file complaints seeking changes in the KPC tariff, including with respect to the transportation rates stated therein.

 

Our remaining natural gas pipeline facilities are generally exempt from FERC’s jurisdiction and regulation pursuant to Section 1(b) of the NGA, which exempts pipeline facilities that perform primarily a gathering function, rather than a transportation function. We believe our pipeline facilities (other than the KPC system) meet the traditional tests used by FERC to distinguish gathering facilities from transportation facilities. However, if FERC were to determine that the facilities perform primarily a transportation function, rather than a gathering function, these facilities may become subject to regulation as interstate natural gas pipeline facilities. We believe the expenses associated with seeking certificate authority for construction, service and abandonment, establishing rates and a tariff for these other facilities, and meeting the detailed regulatory accounting and reporting requirements would substantially increase our operating costs and would adversely affect our profitability.

 

Additionally, while generally exempt from FERC’s jurisdiction, FERC adopted new internet posting requirements in November 2008 that are applicable to certain gathering facilities and other non-interstate pipelines meeting size and other thresholds. Various parties have requested rehearing of the FERC rule adopting the new posting requirements and the FERC has granted an extension of time to comply with the new requirements until 150 days following the issuance of an order addressing the requests for rehearing. If the rules are upheld on

rehearing and become applicable to our gathering facilities, they would likely require us to post certain pipeline operational information on a daily basis, which could require us to incur additional compliance expenses.

 

State Regulation of Natural Gas Gathering Pipelines

 

Our natural gas gathering pipeline operations are currently limited to the States of Kansas, Oklahoma, New York, and West Virginia. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and compliant-based rate regulation. Bluestem is licensed as an operator of a natural gas gathering system with the KCC and is required to file periodic information reports with the KCC. We are not required to be licensed as an operator or to file reports in Oklahoma, New York or West Virginia.

 

On those portions of our gas gathering system that are open to third party producers, the producers have the ability to file complaints challenging our gathering rates, terms of services and practice. Our fees, terms and practice must be just, reasonable, not unjustly discriminatory and not unduly preferential. If the KCC or the Oklahoma Corporation Commission (OCC), as applicable, were to determine that the rates charged to a complainant did not meet this standard, the KCC or the OCC, as applicable, would have the ability to adjust our rates with respect to the wells that were the subject of the complaint. We are not aware of any instance in which either the KCC or the OCC has made such a determination in the past.

 

These regulatory burdens may affect profitability, and management is unable to predict the future cost or impact of complying with such regulations. While state regulation of pipeline transportation does not materially affect our operations, we do own several small, discrete delivery laterals in Kansas that are subject to a limited jurisdiction certificate issued by the KCC. As with FERC regulation described above, state regulation of pipeline transportation may influence certain aspects of our business and the market price for our products.

 

Sales of Natural Gas

 

The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to 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.

 

Pipeline Safety

 

Our pipelines are subject to regulation by the U.S. Department of Transportation, or the DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended, or the NGPSA, pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The NGPSA covers the pipeline transportation of natural gas and other gases and requires any entity that owns or operates pipeline facilities to comply with the regulations under the NGPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our pipeline operations are in substantial compliance with applicable NGPSA requirements; however, if new or amended laws and regulations are enacted or existing laws and regulations are reinterpreted, future compliance with the NGPSA could result in increased costs.

 

Other

 

In addition to existing laws and regulations, the possibility exists that new legislation or regulations may be adopted which would have a significant impact on our operations or our customers’ ability to use gas and may

require us or our customers to change their operations significantly or incur substantial costs. Additional proposals and proceedings that might affect the gas industry are pending before Congress, FERC, the Minerals Management Service, state commissions and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely.

 

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

 

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

 

Employees

 

At December 31, 2008, we had a staff of 177 field employees in offices located in Kansas, Oklahoma, Pennsylvania, and West Virginia. We have 61 pipeline operations employees. Our staff consists of 72 executive and administrative personnel at the headquarters office in Oklahoma City and the Quest Midstream office in Houston, Texas. None of our employees are covered by a collective bargaining agreement. Management considers its relations with our employees to be satisfactory.

 

Administrative Facilities

 

The office space for the corporate headquarters for us and our subsidiaries and affiliates is leased and is located at 210 Park Avenue, Suite 2750, Oklahoma City, Oklahoma 73102. The office lease is for 10 years expiring August 31, 2017 covering approximately 35,000 square feet. We own three buildings located in Chanute, Kansas that are used for administrative offices, a geological laboratory, an operations terminal and a repair facility. We own an additional building and storage yard in Lenapah, Oklahoma.

 

The office space for Quest Eastern is leased and is located at 2200 Georgetowne Drive, Suite 301, Sewickley, Pennsylvania 15143. The office lease is for five years expiring August 1, 2013 covering approximately 4,744 square feet. Quest Eastern owns a 50% interest in a nine acre lot with building improvements in Wetzel County, West Virginia that is used for equipment storage and office space.

 

Quest Midstream has 9,801 square feet of office space for some of its management personnel that is leased and is located at 3 Allen Center, 333 Clay Street, Suite 4060, Houston, Texas 77002. The office lease expires on May 6, 2015. Quest Midstream also owns an operational office that is located east of Chanute, Kansas. KPC has leased facilities at Olathe, Wichita, and Medicine Lodge, Kansas for the operations of its interstate pipeline. The Olathe office consists of approximately 7,650 square feet for a lease term of five years expiring October 31, 2011. The Wichita office consists of approximately 1,240 square feet on a one year lease, with an extension expiring December 31, 2009. The Medicine Lodge field office is leased on a month to month basis.

 

Where To Find Additional Information

 

Additional information about us can be found on our website at www.questresourcecorp.com. We also provide free of charge on our website our filings with the SEC, including our annual reports, quarterly reports, and current reports along with any amendments thereto, as soon as reasonably practicable after we have electronically filed such material with, or furnished it to, the SEC.

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.

 

Brown Shales.  Fine grained rocks composed largely of clay minerals that contain little organic matter. Some of these shales immediately overlay the Marcellus Shale.

 

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

 

CBM.  Coal bed methane.

 

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

 

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

 

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

 

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

 

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

 

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

 

Dth.  One dekatherm, equivalent to one million British Thermal Units.

 

Earned acreage.  The number of acres that has been assigned as a result of fulfilling conditions or requirements of an agreement.

 

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

 

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

 

Farm-in or farm-out.  An agreement under which the owner of a working interest in an oil or gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.” Acreage is considered to be unearned, until the conditions of the agreement are met, and an assignment of interest has been made.

 

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

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. Standardized measure does not give effect to derivative transactions.

 

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

 

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

 

Unearned acreage.  The number of acres that has not yet been assigned, but may be developed per the terms of an agreement.

 

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

ITEM 1A.  RISK FACTORS

 

Risks Related to Our Business

 

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

 

The independent 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. The factors contributing to this concern include our recurring losses from operations, stockholders’ (deficit) equity, and inability to generate sufficient cash flow to meet our obligations and sustain our operations. Please read Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.” Unless QRCP is able to sell additional assets, restructure its indebtedness, issue equity securities and/or complete some other strategic transaction, we may be forced to make a bankruptcy filing or take other actions that could have a material adverse effect on our business, the price of our common stock and our results of operations. Furthermore, the presence of this concern may have an adverse impact on our relationship with third parties with whom we do business, including our customers, vendors and employees and could make it more challenging for us to raise additional financing or refinance our existing indebtedness.

 

QRCP’s potential sources of revenue and cash flows consist almost exclusively of distributions from Quest Energy and Quest Midstream, neither of which is expected to pay distributions in 2009 and as a result, we do not expect QRCP to be able to meet its cash disbursement obligations unless it engages in transactions outside the ordinary course of business.

 

QRCP’s potential sources of revenue and cash flows consist almost exclusively of distributions from Quest Energy and Quest Midstream on the partnership interests it owns. We do not expect either Quest Energy or Quest Midstream to pay any distributions to their unitholders in 2009 and are unable to estimate at this time when such distributions may be resumed.

 

In October and November of 2008, QRCP’s credit agreement and the credit agreement for each of Quest Energy and Quest Midstream 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 the credit agreements restrict the ability of Quest Energy and Quest Midstream to pay distributions, among other things. Even if they do not pay distributions, the Company and all other unitholders may be liable for taxes on their share of each of Quest Energy and Quest Midstream’s taxable income. As a result, we currently anticipate that QRCP will not be able to meet its cash disbursement obligations after August 31, 2009, unless QRCP is able to restructure its debt obligations, issue equity securities and/or sell additional assets, in which case there can still be no assurances that QRCP will be able to avoid bankruptcy or the liquidation of its assets.

 

Quest Energy’s credit agreements allow the payment of distributions only on its common units and the general partner units and only up to $0.40 per unit per quarter as long as the Second Lien Loan Agreement has not been paid in full. Since the majority of the units the Company owns in Quest Energy are subordinated units, Quest Energy is only permitted to pay distributions on approximately one-third of the interests the Company owns, which significantly reduces what was previously anticipated in cash flows. Furthermore, after giving effect to each quarterly distribution, Quest Energy must be in compliance with certain financial covenants which require its Available Liquidity (as defined in each of its credit agreements) to be no less than $14 million at March 31, 2009 and no less than $20 million at June 30, 2009.

 

Quest Midstream’s credit agreement prohibits the payment of distributions to its unitholders until the total leverage ratio is not greater than 4.0 to 1.0 after giving effect to each quarterly distribution.

 

Quest Midstream did not pay any distributions on any of its units for the third or fourth quarter of 2008 or the first quarter of 2009 and Quest Energy only paid distributions on its common units and the general partner interest for the third quarter of 2008 and did not pay any distributions on any of its units for the fourth quarter of 2008 or the first quarter of 2009. There is no assurance that unpaid distributions on QRCP’s common units and general partner units will be paid or that any future distributions will be declared and paid on any units.

In addition, even if the credit agreements did not restrict the payment of distributions, Quest Energy and Quest Midstream may not have sufficient available cash each quarter to pay distributions to their unitholders. The amount of cash each of Quest Energy and Quest Midstream can distribute to its unitholders each quarter depends upon the amount of cash it generates from its operations, which fluctuate from quarter to quarter based on, among other things:

 

 

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 annual and interim consolidated financial statements as of and for the years ended December 31, 2007, 2006 and 2005, the seven months ended December 31, 2004 and the fiscal year ended May 31, 2004 (including the interim periods within those periods) and as of and for the three months ended March 31, 2008 and as of and for the three and six months ended June 30, 2008.

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.

 

While we have taken certain actions to address the deficiencies identified, additional measures will be necessary and these measures, along with other measures we expect to take to improve our internal controls over financial reporting, may not be sufficient to address the deficiencies identified or ensure that our internal control over financial reporting is effective. If we are unable to provide reliable and timely financial external reports, our business and prospects could suffer material adverse effects. In addition, we may in the future identify further material weaknesses or significant deficiencies in our internal control over financial reporting.

 

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

 

Events of default have recently occurred under our QRCP credit agreement. The QRCP credit agreement contains both financial and ratio covenants. Due to the cancellation of distributions by QELP and QMLP, the decline in oil and gas prices and the decline in the fair market value of the units in QELP and QMLP that it owns, QRCP was not in compliance with all of its financial and ratio covenants as of December 31, 2008, and does not anticipate that it will be in compliance at any time in the foreseeable future. On May 29, 2009, QRCP obtained a waiver of these defaults from its lender for the quarters ended December 31, 2008 and March 31, 2009 and on June 30, 2009, QRCP obtained a waiver of these defaults from its lender for the fiscal quarter ended June 30, 2009. We do not expect that QRCP will be in compliance with all of its financial and ratio covenants for the remainder of 2009, therefore it may be required to obtain additional waivers or its lender may foreclose on its assets.

 

QRCP is required to maintain as of the end of each quarter, an Interest Coverage Ratio of not less than 2.5 to 1.0 and a Leverage Ratio of no more than 2.0 to 1.0. As a result of the suspension of the distributions to QRCP from Quest Energy and Quest Midstream discussed above, QRCP was not in compliance with these financial covenants as of December 31, 2008, March 31, 2009 and June 30, 2009. On May 29, 2009 and June 30, 2009, QRCP obtained waivers of these defaults from QRCP’s lenders. QRCP does not anticipate that it will be in compliance with these financial covenants and ratios at any time in the foreseeable future. On June 30, 2009, the lender under the QRCP credit agreement agreed to defer until September 30, 2009 the interest payment due on June 30, 2009, which amount is represented by a promissory note bearing interest at the Base Rate (as defined in QRCP’s credit agreement) with a maturity date of September 30, 2009. QRCP is also required to make quarterly principal payments of $1.5 million. QRCP has prepaid the quarterly principal payments through and including June 30, 2009 and its next quarterly principal payment is due September 30, 2009. QRCP currently does anticipate being able to make this payment. QRCP’s credit agreement limits the amount that can be outstanding under its term loan to an amount that is equal to (i) 50% of the market value of the common and subordinated units of Quest Energy and Quest Midstream that QRCP has pledged to the lenders and (ii) the value of the oil and gas properties that QRCP has pledged to the lenders. QRCP is required to make a mandatory prepayment equal to any such excess amount outstanding. On May 29, 2009, QRCP obtained a waiver of this mandatory prepayment for the quarters ended December 31, 2008, March 31, 2009 and June 30, 2009. If a deficiency exists after June 30, 2009 that is not waived by QRCP’s lenders, QRCP will be required to sell assets, issue additional equity securities or refinance its credit agreement in order to cure such deficiency, none of which may be possible. Additionally, if the lenders’ exposure under letters of credit exceeds this amount after all borrowings under the credit agreements have been repaid, QRCP will be required to provide additional cash collateral which it may not have.

 

The QELP borrowing base under its first lien credit agreement could be redetermined to an amount that creates a deficiency that QELP does not have the ability to pay.

 

Quest Energy’s credit facility limits the amount it can borrow to a borrowing base amount, determined by the lenders in their sole discretion. Outstanding borrowings in excess of the borrowing base will be required to be repaid (1) in four equal monthly installments following receipt of notice of the new borrowing base or (2) immediately if

the borrowing base is reduced in connection with a sale or disposition of certain properties in excess of 5% of the borrowing base.

 

Additionally, if the lenders’ exposure under letters of credit exceeds this amount after all borrowings under the credit agreements have been repaid, Quest Energy will be required to provide additional cash collateral.

 

In July 2009, Quest Energy received notice from RBC that the borrowing base under the Quest Cherokee first lien loan 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.

 

A default under the QELP first lien credit agreement would cause a cross default under the QELP second lien credit agreement.

 

Under the terms of Quest Energy’s second lien credit agreement, Quest Energy is required to make quarterly payments of $3.8 million. The next payment is due August 15, 2009. The balance remaining, after such payment of $29.8 million, is due on September 30, 2009. No assurance can be given that Quest Energy will be able to repay such amount in accordance with the terms of its second lien credit agreement.

 

A default under QELP’s first lien credit agreement would cause a default under the second lien credit agreement, which could cause payment acceleration. If payment under the second lien credit agreement were accelerated, payment under the first lien credit agreement would be accelerated. Such acceleration of payments could lead to foreclosure, other collection efforts, or bankruptcy of QELP.

 

The 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 conditioned upon the satisfaction 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 stockholders and the unitholders of Quest Energy and 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 the Company’s stock 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 the Company’s common stock and our future business and financial results because of, among other things, the disruption that would occur as a result of uncertainties relating to a failure to complete the Recombination.

 

The Company’s stockholders and Quest Energy’s 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 including the following:

 

 

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

 

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

 

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

 

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

 

 

Due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or if funding is available only on unfavorable terms, we may be unable to meet our obligations as they come due or be required to post collateral to support our obligations, or we may be unable to implement our development plans, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues, results of operations, or financial condition.

 

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

 

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

 

 

 

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 $298.9 million. Due to a further decline in natural gas prices between December 31, 2008 and March 31, 2009, we will incur an additional impairment charge of approximately $95 million to $115  million for the quarter ended March 31, 2009. We may incur further impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our credit agreements.

Unless we replace the reserves that we produce, our existing reserves and production will decline, which would adversely affect our revenues, profitability and cash flows.

 

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

 

As of December 31, 2008, our proved reserve-to-production ratio was 7.8 years. Because this ratio includes our proved undeveloped reserves, we expect that this ratio will not increase even if those proved undeveloped reserves are developed and the wells produce as expected. The proved reserve-to-production ratio reflected in our reserve report as of December 31, 2008 will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances.

 

We may not be able to replace our reserves or generate cash flows if we are unable to raise capital.

 

In order to increase our asset base, we will need to make substantial capital expenditures for the exploration, development, production and acquisition of oil and gas reserves and the construction of additional gas gathering pipelines and related facilities. These maintenance capital expenditures may include capital expenditures associated with drilling and completion of additional wells to offset the production decline from our producing properties or additions to our inventory of unproved properties or our proved reserves to the extent such additions maintain our asset base. These expenditures could increase as a result of:

 

 

Our cash flow from operations and access to capital is subject to a number of variables, including:

 

 

Historically, we have financed these expenditures primarily with cash generated by operations and proceeds from bank borrowings and equity financings. If our revenues or borrowing base further decreases as a result of lower oil and natural gas prices, operating difficulties or declines in reserves, we may have limited ability to expend the capital necessary to undertake or complete future drilling programs. Additional debt or equity financing or cash generated by operations may not be available to meet these requirements. Due to the current low prices for oil and gas and the restrictions in the capital markets due to the global financial crisis, we anticipate that we will not have any significant amounts available during 2009 for capital expenditures.

We face the risks of leverage.

 

As of December 31, 2008, QRCP had borrowed $29 million, Quest Energy had borrowed $230.2 million, and Quest Midstream had borrowed $128 million under their respective credit agreements. We anticipate that we may in the future incur additional debt for financing our growth. Our ability to borrow funds will depend upon a number of factors, including the condition of the financial markets. In fact, during 2008, availability of credit became severely restricted. Under certain circumstances, the use of leverage may provide a higher return to you on your investment, but will also create a greater risk of loss to you than if we did not borrow. The risk of loss in such circumstances is increased because we would be obligated to meet fixed payment obligations on specified dates regardless of our revenue. If we do not make our debt service payments when due, we may sustain the loss of our equity investment in any of our assets securing such debt, upon the foreclosure on such debt by a secured lender. The interest payable on our debt varies with the movement of interest rates charged by financial institutions. An increase in our borrowing costs due to a rise in interest rates in the market may reduce the amount of income and cash available for the payment of dividends to the holders of our common stock.

 

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

 

 

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.

 

Our credit agreements have substantial restrictions and financial covenants that may restrict our business and financing activities.

 

The operating and financial restrictions and covenants in our credit agreements and any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions. Our credit agreements and any future financings agreements may restrict our ability to:

 

 

 

We are also required to comply with certain financial covenants and ratios. In the past, we have not satisfied all of the financial covenants and ratios contained in our credit facilities. In January 2005, we determined that we were not in compliance with the leverage and interest coverage ratios under a prior secured credit agreement and, in connection with a February 2005 amendment to such credit agreement, we were unable to drill any additional wells until our gross daily production reached certain levels. We were unable to reach these production goals without the drilling of additional wells and, in the fourth quarter of 2005, we undertook a significant recapitalization that included a private placement of our common stock and the refinancing of our credit facilities. For the quarter ended March 31, 2007, QRCP’s total debt to EBITDA ratio was 4.77 to 1.0, which exceeded the permitted maximum total debt to EBITDA ratio of 4.5 to 1.0 under its credit facilities. We obtained a waiver of this default from QRCP’s lenders. We refinanced QRCP’s credit facilities in November 2007. In October 2008, we obtained waivers of any defaults or potential defaults under the credit agreements of QRCP, Quest Energy and Quest Midstream related to or arising out of the internal investigation and our not promptly settling intercompany accounts. The current credit agreements for QRCP, Quest Midstream and Quest Energy each contain financial covenants. QRCP was not in compliance with all of these covenants as of December 31, 2008 and we do not expect that QRCP and Quest Energy will be in compliance with all of these covenants for the remainder of 2009. See “— Risks Related to Our Business — Events of default are anticipated under the QRCP credit agreement, which could expose our assets to foreclosure or other collection efforts.” QRCP has obtained waivers of these defaults from its lenders for the quarters ended December 31, 2008, March 31, 2009 and June 30, 2009 and we are currently in the process of seeking waivers from QRCP’s and QELP’s lenders with respect to anticipated defaults and to restructure their required principal payments; however, there can be no assurance that we will be successful in obtaining such waivers or restructuring such principal payments.

 

Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by our results of operations and financial conditions and events or circumstances beyond our control. If market or other economic conditions do not improve, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit agreements, a significant portion of our indebtedness may become immediately due and payable, the interest rates on our credit agreements may increase and the lenders’ commitment, if any, to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments.

 

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

 

Borrowings under our credit agreements bear interest at floating rates. The rates are subject to adjustment based on fluctuations in the London Interbank Offered Rate (“LIBOR”) and 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 belonging to the Company to an entity controlled by our former chief executive officer. The Oklahoma Department of Securities has filed lawsuits against our former chief executive officer, former chief financial officer and former purchasing manager, and the Oklahoma Department of Securities, the Federal Bureau of Investigation, the Department of Justice, the Securities and Exchange Commission, the Internal Revenue Service and other government agencies are currently conducting investigations related to the Transfers and these individuals.

 

The joint special committee retained independent legal counsel to conduct the investigation and to interact with various government agencies, including the Oklahoma Department of Securities, the Federal Bureau of Investigation, the Department of Justice, the Securities and Exchange Commission, the Internal Revenue Service and other government agencies.

 

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

 

There is a significant delay between the time QELP drills and completes a CBM well and when the well reaches peak production. As a result, there will be a significant lag time between when QELP expends capital expenditures and when QELP will begin to recognize significant cash flow from those expenditures.

 

Our general production profile for a CBM well averages an initial 5-10 Mcf/d (net), steadily rising for the first twelve months while water is pumped off and the formation pressure is lowered until the wells reach peak production (an average of 50-55 Mcf/d (net)). In addition, there could be significant delays between the time a well is drilled and completed and when the well is connected to a gas gathering system. This delay between the time when QELP expends capital expenditures to drill and complete a well and when QELP will begin to recognize significant cash flow from those expenditures may adversely affect QELP’s 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.

 

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.

 

We have limited experience in drilling wells to the Marcellus Shale and less information regarding reserves and decline rates in the Marcellus Shale than in the Cherokee Basin. Wells drilled to the Marcellus Shale are deeper, more expensive and more susceptible to mechanical problems in drilling and completing than wells in the Cherokee Basin.

 

We have limited experience in drilling wells in the Marcellus Shale reservoir. As of May 1, 2009, we have drilled two vertical and two horizontal gross wells to the Marcellus Shale. Other operators in the Appalachian Basin also have limited experience in the drilling of Marcellus Shale wells. As a result, we have much less information with respect to the ultimate recoverable reserves and the production decline rate in the Marcellus Shale than we have in the Cherokee Basin. The wells to be drilled in the Marcellus Shale will be drilled deeper than in the Cherokee Basin and some may be horizontal wells, which makes the Marcellus Shale wells more expensive to drill and complete. The wells, especially any horizontal wells, will also be more susceptible than those in the Cherokee Basin to mechanical problems associated with the drilling and completion of the wells, such as casing collapse and lost equipment in the wellbore. The fracturing of the Marcellus Shale will be more extensive and complicated than fracturing the geological formations in the Cherokee Basin and requires greater volumes of water than conventional gas wells. The management of water and treatment of produced water from Marcellus Shale wells may be more costly than the management of produced water from other geologic formations.

 

Our hedging activities could result in financial losses or reduce our income.

 

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and gas, we currently and may in the future enter into derivative arrangements for a significant portion of our oil and gas production that could result in both realized and unrealized hedging losses. The extent of our commodity price exposure is related largely to the effectiveness and scope of our hedging activities.

 

Our actual future production may be significantly higher or lower than we estimate at the time we enter into hedging transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our hedging activities are subject to the following risks:

 

 

 

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. We do not have property insurance on any of Quest Midstream’s underground pipeline systems that would cover damage to the pipelines. Pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets subsequent to the terrorist attacks on September 11, 2001 and the hurricanes in 2005 have made it more difficult for us to obtain certain types of coverage. There can be no assurance that we will be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition and results of operations.

 

We have been named a defendant in a number of securities class action lawsuits and stockholder derivative lawsuits. These, and potential similar or related litigation, could result in significant expenses, monetary damages, penalties or injunctive relief against us that could significantly reduce our earnings and cash flows and harm our business.

 

As discussed in Items 1. and 2. “Business and Properties — Recent Developments — Internal Investigation; Restatements and Reaudits,” we conducted an internal investigation into the Transfers of funds effected by our former chief executive officer that totaled approximately $10 million. During the course of the investigation, management identified material errors in our previously issued consolidated financial statements and has restated our previously filed consolidated financial statements. The investigation and restatement have exposed us to risks and expenses associated with litigation and government investigations. Certain putative class action lawsuits and stockholder derivative lawsuits have been asserted against QRCP, Quest Energy, Quest Energy GP and certain of their current and former officers and directors. See Item 3. “Legal Proceedings” for a discussion of the lawsuits. No assurance can be given regarding the outcome of such litigation, and additional claims may arise. The investigation 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, we are a party to indemnification agreements under which we are required to indemnify and advance defense costs to our current and certain of our former directors and officers. Furthermore, considerable legal, accounting and other professional services expenses related to these matters have been incurred to date and significant expenditures may continue to be incurred in the future. We could be required to pay damages and might face remedies that could harm our business, financial condition and results of operations. While we maintain directors and officers liability insurance, there can be no assurance that the proceeds of this insurance will be available with respect to all or part of any damages, costs or expenses that we may incur in connection with the class action and derivative stockholder lawsuits.

 

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

 

We may incur significant costs and liabilities as a result of environmental, health and safety requirements applicable to our oil and gas exploration, development and production activities. These costs and liabilities could

arise under a wide range of federal, state and local environmental, health and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations.

 

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

 

There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of oil and natural gas, air emissions related to our operations, and historical industry operations and waste disposal practices. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover these costs from insurance.

 

We may face unanticipated water disposal costs.

 

We are subject to regulation that restricts our ability to discharge water produced as part of our gas production operations. Productive zones frequently contain water that must be removed in order for the gas to detach produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether 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 and adversely affect our results of operations.

 

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

 

Quest Energy depends on one customer for sales of its natural gas. A reduction by this customer in the volumes of gas it purchases from Quest Energy could indirectly result in a substantial decline in our revenues and net income.

 

During the year ended December 31, 2008, Quest Energy sold substantially all of its natural gas produced in the Cherokee Basin to ONEOK Energy Marketing and Trading Company (“ONEOK”) under a sale and purchase contract, which has an indefinite term but may be terminated by either party on 30 days’ notice, other than with respect to pending transactions, or less following an event of default. If ONEOK was to reduce the volume of gas it purchases under this agreement, Quest Energy’s revenue and cash flow will decline to the extent it is not able to find new customers for the natural gas it sells.

 

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

 

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

 

Subsequent to the divestiture of the Lycoming County, Pennsylvania properties on February 13, 2009, we held oil and gas leases and development rights, by virtue of farm-out agreements or similar mechanisms, on 31,490 net acres in the Appalachian Basin that are still within their original lease or agreement term and are not earned or are not held by production. Unless we establish commercial production on the properties, or fulfill the requirements specified by the various agreements, during the prescribed time periods, these leases or agreements will expire. Leases or agreements covering approximately 3,600 net acres are scheduled to expire before December 31, 2009 and an additional approximately 6,000 net acres are scheduled to expire before December 31, 2010. Of this acreage, approximately 8,200 net acres can be maintained and held beyond December 31, 2010 by drilling five wells before December 31, 2009 and an additional six wells before December 31, 2010.

 

Because of our financial condition, we do not expect to be able to meet the drilling and payment obligations to earn or maintain all of this leasehold acreage.

 

Our identified drilling location inventories will be developed over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, resulting in temporarily lower cash from operations, which may impact our results of operations.

 

Our management has specifically identified drilling locations for our future multi-year drilling activities on our existing acreage. We have identified, as of December 31, 2008, approximately 292 gross proved undeveloped

drilling locations and approximately 2,034 additional gross potential drilling locations in the Cherokee Basin and approximately 22 gross proved undeveloped drilling locations and approximately 435 additional gross potential drilling locations in the Appalachian Basin. These identified drilling locations represent a significant part of our future long-term development drilling program. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, gas prices, costs and drilling results. In addition, no proved reserves are assigned to any of the approximately 2,034 Cherokee Basin and 435 Appalachian Basin potential drilling locations we have identified and therefore, there may exist greater uncertainty with respect to the likelihood of drilling and completing successful commercial wells at these potential drilling locations. Our final determination of whether to drill any of these drilling locations will be dependent upon the factors described above, our current financial condition, our ability to obtain additional capital as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, it is unlikely that all of the numerous drilling locations we have identified will be drilled within the timeframe specified in the reserve report or will ever be drilled, and we do not know if we will be able to produce gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could have a significant adverse effect on our financial condition and results of operations.

 

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

 

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

 

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

 

On a small percentage of our acreage (less than 1.0%), the land owner in the past transferred the rights to the coal underlying their land to a third party. With respect to those properties we have obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying those lands. In Oklahoma and Kansas, the law is unsettled as to whether the owner of the gas rights or the coal rights is entitled to the CBM gas. We are currently involved in litigation with the owner of the coal rights on these lands to determine who has the rights to the CBM gas. In the event that the courts were to determine that the owner of the coal rights is entitled to extract the CBM gas, we would lose these leases and the associated wells and reserves. In addition, we may be required to reimburse the owner of the coal rights for some of the gas produced from those wells.

 

A change in the jurisdictional characterization of some of Quest Midstream’s gathering assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its gathering assets, which may indirectly cause our revenues to decline and operating expenses to increase.

 

Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities from FERC jurisdiction. We believe that the facilities comprising Quest Midstream’s gathering system meet the traditional tests used by FERC to distinguish nonjurisdictional gathering facilities from jurisdictional transportation facilities, and that, as a result, the gathering system is not subject to FERC’s jurisdiction. However, FERC regulation still affects Quest Midstream’s gathering business and the markets for its natural gas. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation,

ratemaking, capacity release and market center promotion, indirectly affect Quest Midstream’s gathering business. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of regular litigation. The classification and regulation of some of Quest Midstream’s gathering facilities may be subject to change based on future determinations by FERC, the courts or Congress.

 

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and complaint-based rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. Quest Midstream’s gathering operations are currently limited to the States of Kansas and Oklahoma. Bluestem, a wholly owned subsidiary of Quest Midstream and the owner of the gathering system, is licensed as an operator of a natural gas gathering system with the KCC and is required to file periodic information reports with the KCC. Quest Midstream is not required to be licensed as an operator or to file reports in Oklahoma.

 

Third party producers on our Cherokee Basin gathering system have the ability to file complaints challenging the rates that Quest Midstream charges. The rates must be just, reasonable, not unjustly discriminatory and not duly preferential. If the KCC or the OCC, as applicable, were to determine that the rates charged to a complainant did not meet this standard, the KCC or the OCC, as applicable, would have the ability to adjust the rates with respect to the wells that were the subject of the complaint. Quest Midstream’s gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on Quest Midstream’s operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

 

The KPC Pipeline is subject to regulation by FERC, which could have an adverse impact on Quest Midstream’s ability to establish transportation rates that would allow it to recover the full cost of operating the KPC pipeline, including a reasonable return, which may affect Quest Midstream’s business and results of operations.

 

As an interstate natural gas pipeline, the KPC Pipeline is subject to regulation by FERC under the NGA. FERC’s regulation of interstate natural gas pipelines extends to such matters as:

 

 

KPC may only charge transportation rates that it has been authorized to charge by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

 

The maximum recourse rates that it may charge for transportation services are established through FERC’s ratemaking process, and those recourse rates, as well as the terms and conditions of service, are set forth in KPC’s FERC-approved interstate tariff. Pipelines may also negotiate rates that are higher than the maximum recourse rates

stated in their tariffs, provided such rates are filed with, and approved by, FERC. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint, proposed rate increases may be challenged by protest, and either may be challenged sua sponte by FERC. Any successful challenge against KPC’s rates could have an adverse impact on Quest Midstream’s revenues and ability to pay distributions.

 

Generally and absent settlement, the maximum filed recourse rates for interstate pipelines are based on the cost of service plus an approved return on equity, which may be determined through the use of a proxy group of similarly situated companies. Specifically, FERC uses a discounted cash flow model that incorporates the use of proxy groups to develop a range of reasonable returns earned on equity interests in companies with corresponding risks. FERC then assigns a rate of return on equity within that range to reflect specific risks of that pipeline when compared to the proxy group companies. Other key determinants in the ratemaking process are capital costs and costs of providing service, including an income tax allowance, and volume throughput and contractual capacity commitment assumptions.

 

We cannot give any assurance regarding the likely future regulations under which KPC will operate the KPC Pipeline or the effect such regulation could have on its business, financial condition, and results of operations. FERC periodically revises and refines its ratemaking and other policies in the context of rulemakings, generic proceedings, and pipeline-specific cases. FERC’s policies may also be modified when FERC decisions are subjected to judicial review. Changes to ratemaking policies may in turn affect the rates we may charge for transportation service. For example, on April 17, 2008, FERC issued a policy statement that, among other things, provides for the inclusion of master limited partnerships in the proxy groups it will use to decide the return on equity of natural gas pipelines. Once this policy is applied in individual rate cases, it may be subject to further review (including judicial review) and potential modification. The final resolution of this issue may reduce the rate of return KPC is allowed in future rate cases.

 

The outcome of certain rate cases involving FERC policy statements is uncertain and could affect KPC’s ability to include an income tax allowance in its cost of service based rates, which would in turn impact Quest Midstream’s revenues and ability to pay distributions.

 

In May 2005, FERC issued a policy statement permitting the inclusion of an income tax allowance in the cost of service-based rates of a pipeline organized as a tax pass-through entity to reflect actual or potential income tax liability on public utility income, if the pipeline proves that the ultimate owner of its interests has an actual or potential income tax liability on such income. In May 2007, the U.S. Court of Appeals for the D.C. Circuit issued a decision upholding the policy statement as applied to an individual pipeline. More recent proceedings at FERC have addressed a variety of implementation and application issues, for example, whether the recovery of an income tax allowance by a pipeline should be taken into consideration when establishing return on equity rates for the pipeline. The ultimate outcome of these proceedings, as well as future proceedings in which these types of issues will be adjudicated, could result in changes to FERC’s treatment of income tax allowances or related cost of service components. Depending upon how the policy statement on income tax allowances is applied in practice to pipelines organized as pass through entities, these decisions might adversely affect Quest Midstream. Under FERC’s current income tax allowance policy, if the KPC Pipeline was to file a rate case or its rates were to otherwise become subject to review for justness and reasonableness before FERC, Quest Midstream would be required to demonstrate that the equity interest owners in the pipeline incur actual or potential income tax liability on their respective shares of partnership public utility income. If Quest Midstream is unable to do so, FERC could decide to reduce its rates from current levels. We can give no assurance that in the future FERC’s current income tax allowance policy or its application will not be changed.

 

We lack experience with and could be subject to penalties and fines if we fail to comply with FERC regulations.

 

Quest Midstream acquired the KPC Pipeline, which is its only FERC regulated asset, in November 2007. Given Quest Midstream’s limited experience with FERC regulated pipeline operations, and the complex and evolving nature of FERC regulation, it may incur significant costs related to compliance with FERC regulations. Should Quest Midstream fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. Under the EP Act 2005, FERC has civil penalty

authority under the NGA to impose penalties for current violations of up to $1,000,000 per day for each violation, to revoke existing certificate authority, and to order disgorgement of profits associated with any violation. Since enactment of the EP Act 2005, FERC has initiated a number of enforcement proceedings and issued penalties to various regulated entities, including other interstate natural gas pipelines.

 

Pipeline integrity programs and repairs may impose significant costs and liabilities.

 

Pursuant to the Pipeline Safety Improvement Act of 2002, the DOT has adopted regulations requiring pipeline operators to develop integrity management programs for intrastate and interstate natural gas and natural gas liquids pipelines located near high consequence areas, where a leak or rupture could do the most harm. The regulations require operators to:

 

 

We currently estimate that Quest Midstream will incur costs of approximately $1.0 million through 2009 to complete the last year of the initial high consequence area integrity testing and $1.5 million in 2012 to implement pipeline integrity management program testing along certain segments of natural gas pipelines. We also estimate that Quest Midstream will incur costs of approximately $0.5 million through 2009 to complete the last year of a Stray Current Survey resulting from a 2004 DOT audit. These costs may be significantly higher and Quest Midstream’s cash available for distribution correspondingly reduced due to the following factors:

 

 

Growing our business by constructing new assets is subject to regulatory, political, legal and economic risks.

 

One of the ways Quest Midstream intends to grow its business in the long term is through the construction of new midstream assets.

 

The construction of additions or modifications to the Cherokee Basin gathering system and/or the KPC Pipeline, and the construction of new midstream assets, involve numerous operational, regulatory, environmental, political and legal risks beyond our control and may require the expenditure of significant amounts of capital. These potential risks include, among other things:

 

 

 

If third party pipelines and other facilities interconnected to Quest Midstream’s natural gas pipelines become unavailable to transport or produce natural gas, its revenues and cash available for distribution could be adversely affected.

 

Quest Midstream depends upon third party pipelines and other facilities that provide delivery options to and from its pipelines and facilities for the benefit of its customers. Since Quest Midstream does not own or operate any of these pipelines or other facilities, their continuing operation is not within its control. If any of these third party pipelines and other facilities become unavailable to transport or produce natural gas, Quest Midstream’s revenues and cash available for distribution could be adversely affected.

 

Failure of the natural gas that Quest Midstream gathers on its gas gathering system to meet the specifications of interconnecting interstate pipelines could result in curtailments by the interstate pipelines.

 

Natural gas gathered on Quest Midstream’s gathering system is delivered into interstate pipelines. These interstate pipelines establish specifications for the natural gas that they are willing to accept, which include requirements such as hydrocarbon dewpoint, temperature, and foreign content including water, sulfur, carbon dioxide and hydrogen sulfide. These specifications vary by interstate pipeline. If the natural gas delivered from the gathering system fails to meet the specifications of a particular interstate pipeline that pipeline may refuse to accept all or a part of the natural gas scheduled for delivery to it. In those circumstances, Quest Midstream may be required to find alternative markets for that natural gas or to shut-in the producers of the non-conforming natural gas, potentially reducing its throughput volumes or revenues.

 

Quest Midstream’s interstate natural gas pipeline has recorded certain assets that may not be recoverable from its customers.

 

Accounting policies for FERC-regulated companies permit certain assets that result from the regulated ratemaking process to be recorded on our balance sheet that could not be recorded under GAAP for nonregulated entities. We consider factors such as regulatory changes and the impact of competition to determine the probability of future recovery of these assets. If Quest Midstream determines future recovery is no longer probable, it would be required to write off the regulatory assets at that time, potentially reducing its revenues and cash available for distribution.

 

Reduction in firm reservation agreements and the demand for interruptible services could cause significant reductions in Quest Midstream’s revenues and operating results.

 

For the year ended December 31, 2008, approximately 63% of Quest Midstream’s firm contracted capacity on our KPC pipeline system was under long-term contracts (i.e., contracts with remaining terms longer than one year). A decision by customers upon the expiration of long-term agreements to substantially reduce or cease to ship volumes of natural gas on Quest Midstream’s KPC pipeline system could cause a significant decline in its revenues. Quest Midstream’s results of operations and cash available for distribution could also be adversely affected by decreased demand for interruptible services.

Operational limitations of the pipeline system could cause a significant decrease in Quest Midstream’s revenues and operating results.

 

During peak demand periods, failures of compression equipment or pipelines could limit KPC’s ability to meet firm commitments, which may limit its ability to collect reservation charges from its customers and, if so, could negatively impact Quest Midstream’s revenues and ability to make cash distributions.

 

Quest Midstream’s industry is highly competitive, and increased competitive pressures could adversely affect its business and operating results.

 

With respect to its Cherokee Basin gathering system, Quest Midstream may face competition in its efforts to obtain additional natural gas volumes from parties other than Quest Energy. Quest Midstream competes principally against other producers in the Cherokee Basin with natural gas gathering services. Its competitors may expand or construct gathering systems in the Cherokee Basin that would create additional competition for the services Quest Midstream provides to its customers.

 

With respect to the KPC Pipeline, Quest Midstream competes with other interstate and intrastate pipelines in the transportation of natural gas for transportation customers primarily on the basis of transportation rates, access to competitively priced supplies of natural gas, markets served by the pipelines, and the quality and reliability of transportation services. Major competitors include Southern Star Central Gas Pipeline, Kinder Morgan Interstate Gas Transmission’s Pony Express Pipeline and Panhandle Eastern Pipeline Company in the Kansas City market and Southern Star Pipeline, Peoples Natural Gas and Mid-Continent Market Center in the Wichita market.

 

Natural gas also competes with other forms of energy available to Quest Midstream’s customers, including electricity, coal, hydroelectric power, nuclear power and fuel oil. The impact of competition could be significantly increased as a result of factors that have the effect of significantly decreasing demand for natural gas in the markets served by Quest Midstream’s pipelines, such as competing or alternative forms of energy, adverse economic conditions, weather, higher fuel costs, and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.

 

Quest Midstream does not own all of the land on which its pipelines are located or on which it may seek to locate pipelines in the future, which could disrupt its operations and growth.

 

Quest Midstream does not own the land on which its pipelines have been constructed, but does have right-of-way and easement agreements from landowners and governmental agencies, some of which require annual payments to maintain the agreements and most of which have a perpetual term. New pipeline infrastructure construction may subject Quest Midstream to more onerous terms or to increased costs if the design of a pipeline requires redirecting. Such costs could have a material adverse effect on Quest Midstream’s business, results of operations and financial condition and ability to make cash distributions.

 

In addition, the construction of additions to the KPC Pipeline may require Quest Midstream to obtain new rights-of-way prior to constructing new pipelines. Quest Midstream may be unable to obtain such rights-of-way to expand the KPC Pipeline or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive to obtain new rights-of-way. If the cost of obtaining new rights-of-way increases, then Quest Midstream’s cash flows and its ability to make distributions could be adversely affected.

 

The revenues of Quest Midstream’s interstate pipeline business are generated under contracts that must be renegotiated periodically.

 

Substantially all of KPC Pipeline’s revenues are generated under contracts which expire periodically and must be renegotiated and extended or replaced. Quest Midstream’s contracts with Kansas Gas Service and Missouri Gas Energy represent commitments in the amount of approximately 144,000 Dth/d, of which approximately 55,000 Dth/d extend through October 2009, approximately 12,000 Dth/d extend through 2013, approximately 63,000 Dth/d extend through 2014, and approximately 14,000 Dth/d extend through 2017. If Quest Midstream is unable to extend or replace these contracts when they expire or renegotiate contract terms as favorable as the existing contracts, Quest Midstream could suffer a material reduction in revenues, earnings and cash flows. In

particular, Quest Midstream’s ability to extend and replace contracts could be adversely affected by factors it cannot control, including:

 

 

Fluctuations in energy commodity prices could adversely affect Quest Midstream’s pipeline businesses.

 

Revenues generated by Quest Midstream’s transmission contracts depend, in part, on volumes and rates, both of which can be affected by the prices of natural gas. Increased prices could result in a reduction of the volumes transported by customers. Increased prices could also result in industrial plant shutdowns or load losses to competitive fuels as well as local distribution companies’ loss of customer base. The success of Quest Midstream’s transmission operations is subject to continued development of additional gas supplies to offset the natural decline from existing wells connected to its systems, which requires the development of additional oil and natural gas reserves and obtaining additional supplies from interconnecting pipelines on or near our systems. A decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of reserves available for transmission through Quest Midstream’s systems. Pricing volatility may impact the value of under or over recoveries of retained natural gas and imbalances. If natural gas prices in the supply basins connected to Quest Midstream’s pipeline systems are higher than prices in other natural gas producing regions, its ability to compete with other transporters may be negatively impacted on a short-term basis, as well as with respect to long-term recontracting activities. Furthermore, fluctuations in pricing between supply sources and market areas could negatively impact Quest Midstream’s transportation revenues.

 

Our success, and the success of Quest Energy and Quest Midstream, depends on our key management personnel, the loss of any of whom could disrupt our respective businesses.

 

The success of our operations and activities is dependent to a significant extent on the efforts and abilities of our management. We share a large majority of our management and operational personnel with Quest Energy and Quest Midstream, which are similarly dependent on these management and personnel for their continued success. We have not obtained, and do not anticipate that we will obtain, “key man” insurance for any of our management. The loss of services of any of our key management personnel could have a material adverse effect on our business. These key management personnel provide services to two public companies (Quest Energy and QRCP), and a private company (Quest Midstream). As a result, there could be material competition for their time and effort. If the key personnel do not devote significant time and effort to the management and operation of each of these businesses, our financial results may suffer.

 

If we do not make acquisitions on economically acceptable terms, our future growth and profitability will be limited.

 

Our ability to grow and to increase our profitability depends in part on our ability to make acquisitions that result in an increase in our net income. We may be unable to make such acquisitions because we are: (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms or (3) outbid by competitors. If we are unable to acquire properties containing proved reserves, our total level of proved reserves will decline as a result of our production, which will adversely affect our results of operations.

Even if we do make acquisitions that we believe will increase our net income and cash flows, these acquisitions may nevertheless result in a decrease in net income and/or cash flows. Any acquisition involves potential risks, including, among other things:

 

 

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 Relating to Our Common Stock

 

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

 

Our common stock is currently listed on the NASDAQ Global Market. To maintain our listing, we are required to maintain a minimum closing bid price of at least $1.00 per share for our common stock for 30 consecutive business days. Since October 2008, the bid price for our common stock has continuously closed below the minimum $1.00 per share; however, given the current extraordinary market conditions, NASDAQ has suspended enforcement of the minimum bid price requirement through July 19, 2009. As a result, if the closing bid price for our common stock is less than $1.00 for a period of 30 consecutive days after July 19, 2009, we may receive notification from NASDAQ that our common stock will be delisted from the NASDAQ Global Market, unless the stock closes at or above $1.00 per share for at least 10 consecutive days during the 180-day period following such notification.

 

Additionally, on November 19, 2008, we received a letter from the staff of NASDAQ indicating that, because of our failure to timely file our Form 10-Q for the quarter ended September 30, 2008, we no longer complied with the continued listing requirements set forth in NASDAQ Marketplace Rule 4310(c)(14) (now Rule 5250(c)(1)). As permitted by NASDAQ rules, we timely submitted a plan to NASDAQ staff to regain compliance on January 20, 2009. Following a review of this plan, NASDAQ staff granted us an extension until May 11, 2009 to file our Form 10-Q.

 

We did not file our Form 10-Q for the quarter ended September 30, 2008 on that date and on May 12, 2009, we received a Staff Determination from NASDAQ stating that our common stock is subject to delisting since we were not in compliance with the filing requirements for continued listing. We requested and were granted a hearing before the NASDAQ Panel to appeal the Staff Determination, which took place 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 stock will not be delisted.

 

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

 

Our stock price may be volatile.

 

The following factors could affect our stock price:

 

 

 

It is unlikely that we will be able to pay dividends on our common stock.

 

We have never paid dividends on our common stock. We cannot predict with certainty that our operations will result in sufficient revenues to enable us to operate profitably and with sufficient positive cash flow so as to enable us to pay dividends to the holders of common stock. In addition, QRCP’s credit agreement prohibits it from paying any dividend to the holders of our common stock without the consent of the lenders under the credit agreement, other than dividends payable solely in equity interests of the Company.

 

The percentage ownership evidenced by the common stock is subject to dilution.

 

We are authorized to issue up to 200,000,000 shares of common stock and are not prohibited from issuing additional shares of such common stock. Moreover, to the extent that we issue any additional common stock, a holder of the common stock is not necessarily entitled to purchase any part of such issuance of stock. The holders of the common stock do not have statutory “preemptive rights” and therefore are not entitled to maintain a proportionate share of ownership by buying additional shares of any new issuance of common stock before others are given the opportunity to purchase the same. Accordingly, you must be willing to assume the risk that your percentage ownership, as a holder of the common stock, is subject to change as a result of the sale of any additional common stock, or other equity interests in the Company.

 

Our common stock is an unsecured equity interest.

 

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

Provisions in Nevada law could delay or prevent a change in control, even if that change would be beneficial to our stockholders.

 

Certain provisions of Nevada law may delay, discourage, prevent or render more difficult an attempt to obtain control of us, whether through a tender offer, business combination, proxy contest or otherwise. The provisions of Nevada law are designed to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with our board of directors.

 

Specifically, the Nevada Revised Statutes contain a provision prohibiting certain “combinations” (generally defined to include certain mergers, disposition of assets transactions, and share issuance or transfer transactions) between a resident domestic corporation and an “interested stockholder” (generally defined to be the beneficial owner of 10% or more of the voting power of the outstanding shares of the corporation), except those combinations which are approved by the board of directors before the interested stockholder first obtained a 10% interest in the corporation’s stock. There are additional exceptions to the prohibition, which apply to combinations if they occur more than three years after the interested stockholder’s date of acquiring shares. This provision applies unless the corporation elects against its application in its original articles of incorporation or an amendment thereto. Our restated articles of incorporation, as amended, do not currently contain a provision rendering this provision inapplicable.

 

We have various mechanisms in place to discourage takeover attempts, which may reduce or eliminate our stockholders’ ability to sell their shares for a premium in a change of control transaction.

 

Various provisions of our articles of incorporation and bylaws may discourage, delay or prevent a change in control or takeover attempt of our company by a third party that is opposed to by our management and board of directors. Public stockholders who might desire to participate in such a transaction may not have the opportunity to do so. These anti-takeover provisions could substantially impede the ability of public stockholders to benefit from a change of control or change in our management and board of directors. These provisions include:

 

 

We have also approved a stockholders’ rights agreement (the “Rights Agreement”) between us and UMB Bank, N.A., (subsequently acquired by Computershare Limited) as Rights Agent. Pursuant to the Rights Agreement, holders of our common stock are entitled to purchase one one-thousandth (1/1,000) of a share (a “Unit”) of Series B Junior Participating Preferred Stock at a price of $75.00 per Unit upon certain events. The purchase price is subject to appropriate adjustment upon the happening of certain events. Generally, in the event a person or entity acquires, or initiates a tender offer to acquire, at least 15% of our then outstanding common stock, the Rights will become exercisable for shares of common stock equal to (i) the number of Units held by a stockholder multiplied by the then-current purchase price, and (ii) divided by one-half of our then-current stock price. The existence of the Rights Agreement may discourage, delay or prevent a change of control or takeover attempt of us by a third party that is opposed to by our management and board of directors.

 

None.

ITEM 3.  LEGAL PROCEEDINGS.

 

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

 

Federal Securities Class Actions

 

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

 

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

 

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

 

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

 

Four putative class action complaints were filed in the United States District Court for the Western District of Oklahoma against the Company, Quest Energy Partners, L.P., and Quest Energy GP, LLC and certain of our current and former officers and directors. The complaints were filed by certain stockholders on behalf of themselves and other stockholders who purchased our common stock between May 2, 2005 and August 25, 2008 and Quest Energy common units between November 7, 2007 and August 25, 2008. The complaints assert claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and Sections 11 and 15 of the Securities Act of 1933. The complaints allege that the defendants violated the federal securities laws by issuing false and misleading statements and/or concealing material facts concerning certain unauthorized transfers of funds from subsidiaries of the Company to entities controlled by the Company’s former chief executive officer, Mr. Jerry D. Cash. The complaints also allege that, as a result of these actions, our stock price and the unit price of Quest Energy was artificially inflated during the class period. On December 29, 2008 the court consolidated these complaints as Michael Friedman, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David E. Grose, Case No. 08-cv-936-M, in the Western District of Oklahoma. Various individual plaintiffs have filed multiple rounds of motions seeking appointment as lead plaintiff, however the court has not yet ruled on these motions and appointed a lead plaintiff. Once a lead plaintiff is appointed, the lead plaintiff must file a consolidated amended complaint within 60 days after being appointed. No further activity is expected in the purported class action until a lead plaintiff is appointed and an amended consolidated complaint is filed. The Company, Quest Energy and Quest Energy GP intend to defend vigorously against plaintiffs’ claims.

Federal Derivative Cases

 

James Stephens, derivatively on behalf of nominal defendant Quest Resource Corporation. v. William H. Damon III, Jerry Cash, David Lawler, David E. Grose, James B. Kite Jr., John C. Garrison and Jon H. Rateau, Case No. 08-cv-1025-M, U.S. District Court for the Western District of Oklahoma, filed September 25, 2008

 

On September 25, 2008 a complaint was filed in the United States District Court for the Western District of Oklahoma, purportedly on our behalf, entitled James Stephens, derivatively on behalf on nominal defendant Quest Resource Corporation v. William H. Damon III, Jerry Cash, David Lawler, David E. Grose, James B. Kite Jr., John C. Garrison and Jon H. Rateau, Case No. 08-cv-1025-M. The complaint names certain of our current and former officers and directors as defendants. The factual allegations mirror those in the purported class actions described above, and the complaint asserts claims for breach of fiduciary duty, abuse of control, gross mismanagement, waste of corporate assets, and unjust enrichment. The complaint seeks disgorgement, costs, expenses, and equitable and/or injunctive relief. On October 16, 2008, the court stayed this case pending the court’s ruling on any motions to dismiss the class action claims. The Company intends to defend vigorously against these claims.

 

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 Quest Energy’s behalf, which names certain of its current and former officers and directors, external auditors and vendors. The factual allegations relate to, among other things, the Transfers and lack of effective internal controls. The complaint asserts claims for breach of fiduciary duty, waste of corporate assets, unjust enrichment, conversion, disgorgement under the Sarbanes-Oxley Act of 2002, and aiding and abetting breaches of fiduciary duties against the individual defendants and vendors and professional negligence and breach of contract against the external auditors. The complaint seeks monetary damages, disgorgement, costs and expenses and equitable and/or injunctive relief. It also seeks Quest Energy to take all necessary actions to reform and improve its corporate governance and internal procedures. Quest Energy intends to defend vigorously against these claims.

 

State Court Derivative Cases

 

Tim Bodeker, derivatively on behalf of nominal defendant Quest Resource Corporation v. Jerry Cash, David E. Grose, Bob G. Alexander, David C. Lawler, James B. Kite, John C. Garrison, Jon H. Rateau and William H. Damon III, Case No. CJ-2008-9042, in the District Court of Oklahoma County, State of Oklahoma, filed October 8, 2008

 

William H. Jacobson, derivatively on behalf of nominal defendant Quest Resource Corporation v. Jerry Cash, David E. Grose, David C. Lawler, James B. Kite, Jon H. Rateau, Bob G. Alexander, William H. Damon III, John C. Garrison, Murrell, Hall, McIntosh & Co., LLP, and Eide Bailly, LLP, Case No. CJ-2008-9657, in the District Court of Oklahoma County, State of Oklahoma, filed October 27, 2008

 

Amy Wulfert, derivatively on behalf of nominal defendant Quest Resource Corporation, v. Jerry D. Cash, David C. Lawler, Jon C. Garrison, John H. Rateau, James B. Kite Jr., William H. Damon III, David E. Grose, N. Malone Mitchell III, and Bryan Simmons, Case No. CJ-2008-9042 — consolidated December 30, 2008, in the District Court of Oklahoma County, State of Oklahoma (Original Case No. CJ-2008-9624, filed October 24, 2008)

 

The factual allegations in these petitions mirror those in the purported class actions discussed above. All three petitions assert claims for breach of fiduciary duty, abuse of control, gross mismanagement, and unjust enrichment. The Jacobson petition also asserts claims against the two auditing firms named in that suit for professional negligence and aiding and abetting the director defendants’ breaches of fiduciary duties. The Wulfert petition also asserts a claim against Mr. Bryan Simmons for aiding and abetting Messrs. Cash’s and Grose’s breaches of fiduciary duties. The petitions seek damages, costs, expenses, and equitable relief. On November 12, 2008, the parties to these lawsuits filed a motion to consolidate the actions and appoint lead counsel. The court has not yet ruled on this

motion. Under the proposed order, the defendants need not respond to the individual petitions. Once the actions are consolidated, the proposed order provides that counsel for the parties shall meet and confer, within thirty days from the date of the entry of the order, regarding the scheduling of the filing of a consolidated derivative petition and the defendants’ responses to that petition. The Company intends to defend vigorously against plaintiffs’ claims.

 

Royalty Owner Class Action

 

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

 

Quest Cherokee was named as a defendant in a class action lawsuit filed by several royalty owners in the U.S. District Court for the District of Kansas. The case was filed by the named plaintiffs on behalf of a putative class consisting of all Quest 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”) has been named in this lawsuit filed by plaintiffs Segundo Francisco Trigoso and Dana Jara De Trigoso. Plaintiffs allege that Segundo Francisco Trigoso was seriously injured while working for QCOS on September 29, 2006 and that the conduct of QCOS was substantially certain to cause injury to Segundo Francisco Trigoso. Plaintiffs seek unspecified damages for physical injuries, emotional injuries, loss of consortium and pain and suffering. Plaintiffs also seek punitive damages. Various motions for summary judgment have been filed and denied by the court. It is expected that the court will set this matter for trial in Fall 2009. QCOS intends to defend vigorously against plaintiffs’ claims.

 

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

 

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

 

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

 

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

 

Larry Reitz, et al. v. Quest Resource Corporation, et al., Case No. CJ-09-00076, District Court of Nowata County, State of Oklahoma, filed May 15, 2009

 

Quest Resource Corporation, et al. have been named in the above-referenced lawsuit. The lawsuit was served on May 22, 2009. Defendants have not answered and no discovery has taken place. Plaintiffs allege that defendants have wrongfully deducted costs from the royalties of plaintiffs and have engaged in self-dealing contracts and agreements resulting in a less than market price for production. Plaintiffs seek unspecified actual and punitive damages. Defendants intend to defend vigorously against this claim.

 

Berenice Urias v. Quest Cherokee, LLC, et al., CV-2008-238C in the Fifth Judicial District, County of Lea, State of New Mexico (Second Amended Complaint filed September 24, 2008)

Quest Cherokee was named in this wrongful death lawsuit filed by Berenice Urias. Plaintiff was the surviving fiancée of the decedent Montano Moreno. The decedent was killed while working for United Drilling, Inc. United Drilling was transporting a drilling rig between locations when the decedent was electrocuted. All claims against Quest Cherokee have been dismissed with prejudice.

 

Litigation Related to Oil and Gas Leases

 

Quest Cherokee has been named as a defendant or counterclaim defendant in several lawsuits in which the plaintiff claims that oil and gas leases owned and operated by Quest Cherokee have either expired by their terms or, for various reasons, have been forfeited by Quest Cherokee. Those lawsuits were originally filed in the district courts of Labette, Montgomery, Wilson, and Neosho Counties, Kansas. Quest Cherokee has drilled wells on some of the oil and gas leases in issue and some of those oil and gas leases do not have a well located thereon but have been unitized with other oil and gas leases upon which a well has been drilled. As of 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 (1/16^th in some leases, and 1/32^nd in some leases) in 14 oil and gas leases owned and operated by Quest Cherokee. Plaintiffs contend that Quest Cherokee has produced oil and/or gas from wells located on or unitized with those leases, and that Quest Cherokee has failed to pay plaintiffs their overriding royalty interest in that production. Quest 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 has been named as a defendant in two lawsuits filed by Well Refined Drilling Company in the District Court of Neosho County, Kansas (Case No. 2007 CV 91) and in the District Court of Wilson County, Kansas (Case No. 2007 CV 46). In both cases, plaintiff contends that Quest Cherokee owes certain sums for services provided by the plaintiff in connection with drilling wells for Quest Cherokee. Plaintiff has also filed mechanics liens against the oil and gas leases on which those wells are located and also seeks foreclosure of those liens. Quest Cherokee has answered those petitions and has denied plaintiff’s claims. Discovery in those cases is ongoing. Quest Cherokee intends to defend vigorously against these claims.

 

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

 

Quest Cherokee has been named in this lawsuit by Barbara Cox. Plaintiff is a landowner in Hobbs, New Mexico and owns the property where the Quest State 9-4 Well was drilled and plugged. Plaintiff alleges that Quest Cherokee violated the New Mexico Surface Owner Protection Act and has committed a trespass and nuisance in the drilling and maintenance of the well. Quest Cherokee denies the allegations of plaintiff. Plaintiff has not articulated any firm damage numbers. Quest Cherokee intends to defend vigorously against plaintiff’s claims.

 

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

 

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

 

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

 

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

 

 

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

 

 

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

 

Market Information

 

The Company’s common stock trades on The NASDAQ Global Market under the symbol “QRCP”. The table set forth below lists the range of high and low prices of the Company’s common stock on NASDAQ for each quarter of the last two years.

 

The closing price for QRCP stock on May 15, 2009 was $0.49.

 

Record Holders

 

As of May 15, 2009, there were 31,867,527 shares of common stock outstanding held of record by approximately 646 stockholders.

 

Dividends

 

The payment of dividends on QRCP’s common stock is within the discretion of the board of directors and will depend on our earnings, capital requirements, financial condition and other relevant factors. We have not declared any cash dividends on QRCP’s common stock and do not anticipate paying any dividends on QRCP’s common stock in the foreseeable future.

 

Our ability to pay dividends on QRCP’s common stock is subject to restrictions contained in its credit agreement. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreements” for a discussion of these restrictions.

 

In addition, the partnership agreements for Quest Energy and Quest Midstream restrict the ability of Quest Energy and Quest Midstream to pay distributions on the subordinated units of such partnerships that QRCP owns if the minimum quarterly distribution has not been paid on all of the common units of such partnerships. The credit agreements for Quest Energy and Quest Midstream also restrict the ability of Quest Energy and Quest Midstream to pay any distributions. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreements.” The third and fourth quarter 2008 distributions for Quest Midstream were not paid, the third quarter 2008 distribution on Quest Energy’s subordinated units was not paid and the fourth quarter 2008 distribution on all of Quest Energy’s units, including common units, for Quest Energy was not paid. There can be no assurance that minimum quarterly distributions on the common units for those quarters will be paid or that any future distributions will be paid.

 

Recent Sales of Unregistered Securities

 

None.

 

Purchases of Equity Securities

 

We have reacquired shares of stock from employees upon the vesting of restricted stock that was granted under our 2005 Omnibus Stock Award Plan. These shares were surrendered by the employees and reacquired by us to satisfy a portion of the minimum statutory tax withholding obligations arising from the lapse of restrictions on the shares. The following table provides information with respect to these purchases during the year ended December 31, 2008.

 

STOCK PRICE PERFORMANCE GRAPH

 

The following graph compares the performance of our common stock to a published industry index (AMEX Natural Resources) and a market index (Nasdaq Composite Index) for the past five years. We have also included a peer group in our SIC code index that was included in our Stock Price Performance Graph last year. The peer group consists of the following companies: Abraxas Petroleum Corporation; Credo Petroleum Corporation; Double Eagle Petroleum Company; Dune Energy Inc; Edge Petroleum Corporation; Evolution Petroleum Corporation; FX Energy Inc.; Georesources Inc.; Houston American Energy Corporation; Kodiak Oil & Gas Corporation; Meridian Resource Corporation; Ngas Resources Inc.; Northern Oil & Gas Inc.; Pinnacle Gas Resources Inc.; Platinum Energy Resources Inc.; Primeenergy Corporation; South Texas Oil Company; Toreador Resources Corporation; and Tri Valley Corporation.

 

The peer group was chosen last year to reflect a comparison of companies closely aligned with our market capitalization value. Beginning this year, we have decided to switch from a self-selected peer group to a published industry index (AMEX Natural Resources) because we believe the broader index provides more meaningful stockholder return information.

 

The graph assumes the investment of $100 on December 31, 2003 and the reinvestment of all dividends. The graph shows the value of the investment at the end of each year.

 

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN

Among Quest Resource Corporation, AMEX Natural Resources, Nasdaq Composite Index and a Peer Group

 

ITEM 6.  SELECTED FINANCIAL DATA.

 

The following table sets forth selected financial information. The data for the years ended December 31, 2008, 2007, 2006 and 2005 are derived from our audited and, for 2007, 2006 and 2005, restated consolidated financial statements included elsewhere in this report. The data for the seven month transition period ended December 31, 2004 and the fiscal year ended May 31, 2004 are derived from unaudited management accounts for such periods, not from our previously filed audited financial statements, which have been restated. See Note 18 — Restatement to the consolidated financial statements for a discussion of the restatements.