UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

Form 10-Q

 

 

Commission file number: 0-17371

 

QUEST RESOURCE CORPORATION
(Exact name of registrant specified in its charter)

 

 

 

 

 

210 Park Avenue, Suite 2750, Oklahoma City, OK 73102

(Address of principal executive offices) (Zip Code)

 

 

 

 

405-600-7704
Registrant’s telephone number, including area code

 

 

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

 

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

 

(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 Exchange Act).  Yes o     No þ

 

As of May 8, 2008, the issuer had 23,522,859 shares of common stock outstanding.

 

 

QUEST RESOURCE CORPORATION
FORM 10-Q
FOR THE QUARTER ENDED MARCH 31, 2008

TABLE OF CONTENTS

 

 

 

Except as otherwise required by the context, references in this quarterly report to “we,” “our,” “us,” “Quest” or “the Company” refer to Quest Resource Corporation and its subsidiaries: Quest Energy Partners, L.P.; Quest Energy GP, LLC; Quest Cherokee, LLC; Quest Cherokee Oilfield Service, LLC; Quest Midstream Partners, L.P.; Quest Midstream GP, LLC; Bluestem Pipeline, LLC; Quest Transmission Company, LLC; Quest Kansas Pipeline, L.L.C; Quest Kansas General Partner, L.L.C.; Quest Pipelines (KPC); Quest Oil & Gas, LLC; and Quest Energy Service, LLC. Our operations are primarily conducted through Quest Cherokee, LLC, Quest Cherokee Oilfield Service, LLC, Bluestem Pipeline, LLC and Quest Energy Service, LLC.

 

Our unaudited interim financial statements, including a consolidated balance sheet as of March 31, 2008, a consolidated statement of operations and comprehensive income, a consolidated statement of cash flows for the three month period ended March 31, 2008 and the comparable period of 2007, and a consolidated statement of stockholders’ equity for the three month period ended March 31, 2008, are attached hereto as Pages F-1 through F-25 and are incorporated herein by this reference.

 

The financial statements included herein have been prepared internally, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission and the Public Company Accounting Oversight Board. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted. However, in our opinion, all adjustments (which include only normal recurring accruals) necessary to fairly present the financial position and results of operations have been made for the periods presented.

 

The financial statements included herein should be read in conjunction with the financial statements and notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2007, as amended (the “2007 Form 10-K”).

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS

 

 

The accompanying notes are an integral part of these consolidated statements.

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

 

 

The accompanying notes are an integral part of these consolidated statements.

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

The accompanying notes are an integral part of these consolidated statements.

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
FOR THE THREE MONTHS ENDED MARCH 31, 2008
(UNAUDITED)

 

 

The accompanying notes are an integral part of these consolidated statements.

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2008

(UNAUDITED)

 

 

Nature of Business

 

Quest Resource Corporation (the “Company”) is a Nevada corporation formed in July 1982. Unless the context requires otherwise, references to “we,” “us,” “our” or the “Company” are intended to mean Quest Resource Corporation and its consolidated subsidiaries.

 

We are an independent energy company with an emphasis on the acquisition, production, transportation, exploration, and development of natural gas (coal bed methane) in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma. Our operations are currently focused on developing coal bed methane gas production through Quest Energy Partners, L.P. (“Quest Energy”) in a fifteen county region that is served by a pipeline network owned through Quest Midstream Partners, L.P. (“Quest Midstream”). Quest Midstream also owns a 1,120-mile interstate natural gas transmission pipeline that runs from Oklahoma to Missouri (the “KPC Pipeline”). In addition, through Quest Oil & Gas, LLC, we have begun developing acreage located in Pennsylvania that is prospective for the Marcellus Shale.

 

We conduct our business through two reportable business segments. These segments and the activities performed to provide services to our customers and create value for our stockholders are as follows:

 

 

Consolidation Policy.  Investee companies in which the Company directly or indirectly owns more than 50% of the outstanding voting securities or those in which the Company has effective control over are generally accounted for under the consolidation method of accounting. Under this method, an Investee company’s balance sheet and results of operations are reflected within the Company’s consolidated financial statements. All significant intercompany accounts and transactions have been eliminated. Minority interests in the net assets and earnings or losses of a consolidated investee are reflected in the caption “Minority interest” in the Company’s consolidated balance sheet and statement of operations. Minority interest adjusts the Company’s consolidated results of operations to reflect only the Company’s share of the earnings or losses of the consolidated investee company. Upon dilution of control below 50% and the loss of effective control, the accounting method is adjusted to the equity or cost method of accounting, as appropriate, for subsequent periods.

 

Financial reporting by the Company’s subsidiaries is consolidated into one set of financial statements with the Company.

 

 

Reference is hereby made to the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2007 (the “2007 Form 10-K”), which contains a summary of significant accounting policies followed by the Company in the preparation of its consolidated financial statements. These policies were also followed in preparing the consolidated financial statements as of March 31, 2008 and for the three months ended March 31, 2008 and 2007.

 

Use of Estimates

 

The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Estimates made in preparing the consolidated financial statements include, among other things, estimates of the proved gas and oil reserve volumes used in calculating depletion, depreciation and amortization expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods.

 

Basis of Accounting

 

The Company’s financial statements are prepared using the accrual method of accounting. Revenues are recognized when earned and expenses when incurred.

 

Revenue Recognition

 

Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties.

 

Cash Equivalents

 

For purposes of the consolidated financial statements, the Company considers investments in all highly liquid instruments with original maturities of three months or less at date of purchase to be cash equivalents.

 

Uninsured Cash Balances

 

The Company maintains its cash balances at several financial institutions. Accounts at the institutions are insured by the Federal Deposit Insurance Corporation up to $100,000. The Company’s cash balances typically are in excess of this amount.

 

Restricted Cash

 

Restricted Cash represents cash pledged to support reimbursement obligations under outstanding letters of credit.

 

Accounts Receivable

 

The Company conducts the majority of its operations in the States of Kansas and Oklahoma and operates exclusively in the natural gas and oil industry. The Company’s receivables are generally unsecured; however, the Company has not experienced any significant losses to date. Receivables are recorded at the estimate of amounts due based upon the terms of the related agreements.

 

Management periodically assesses the Company’s accounts receivable and establishes an allowance for estimated uncollectible amounts. Accounts determined to be uncollectible are charged to operations when that determination is made.

 

Inventory

 

Inventory, which is included in current assets, includes tubular goods and other lease and well equipment which we plan to utilize in our ongoing exploration and development activities and is carried at the lower of cost or market using the specific identification method.

 

Concentration of Credit Risk

 

A significant portion of the Company’s liquidity is concentrated in cash and derivative contracts that enable the Company to hedge a portion of its exposure to price volatility from producing natural gas and oil. These arrangements expose the Company to credit risk from its counterparties. The Company’s accounts receivable are primarily from purchasers of natural gas and oil products. Natural gas sales to one purchaser (ONEOK Energy

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Marketing and Trading Company) accounted for more than 99% of total natural gas and oil revenues for the three months ended March 31, 2008. Natural gas sales to two purchasers (ONEOK and Tenaska Marketing Ventures) accounted for 73% and 27% of total natural gas revenues for the three months ended March 31, 2007.

 

KPC Pipeline’s two primary customers are Kansas Gas Service (KGS) and Missouri Gas Energy (MGE), both of which are served under long-term natural gas transportation contracts representing 59% and 36% of the gas transported, respectively for the three months ended March 31, 2008.

 

The industry concentration has the potential to impact the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s customers may be similarly affected by changes in economic, industry or other conditions.

 

Natural Gas and Oil Properties

 

The Company follows the full cost method of accounting for natural gas and oil properties, prescribed by the Securities and Exchange Commission (“SEC”). Under the full cost method, all acquisition, exploration, and development costs are capitalized. The Company capitalizes internal costs including: salaries and related fringe benefits of employees directly engaged in the acquisition, exploration and development of natural gas and oil properties, as well as other directly identifiable general and administrative costs associated with such activities.

 

All capitalized costs of natural gas and oil properties, including the estimated future costs to develop proved reserves, are amortized on the units-of-production method using estimates of proved reserves. The costs of unproved properties are excluded from amortization until the properties are evaluated. The Company reviews all of its unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unevaluated properties are assessed individually when individual costs are significant.

 

The Company reviews the carrying value of its oil and natural gas properties under the full-cost accounting rules of the Securities and Exchange Commission on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, plus the cost of properties not being amortized, less any related income tax effects. In calculating future net revenues, current prices and costs used are those as of the end of the appropriate quarterly period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges. Two primary factors impacting this test are reserve levels and current prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. Under SEC regulations, the excess above the ceiling is not expensed (or is reduced) if, subsequent to the end of the period, but prior to the release of the financial statements, oil and natural gas prices increase sufficiently such that an excess above the ceiling would have been eliminated (or reduced) if the increased prices were used in the calculations.

 

Based on the low natural gas prices on December 31, 2007, the Company would have incurred a non-cash impairment loss of approximately $14.9 million for the quarter ended December 31, 2007. However, under the SEC’s accounting guidance in Staff Accounting Bulletin Topic 12(D)(e), if natural gas prices increase sufficiently between the end of a period and the completion of the financial statements for that period to eliminate the need for an impairment charge, an issuer is not required to recognize the non-cash impairment loss in its financial statements for that period. As of March 1, 2008, natural gas prices had improved sufficiently to eliminate the need for an impairment loss at December 31, 2007 and as a result, no impairment loss is reflected in the Company’s financial statements for the year ended December 31, 2007.

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between the capitalized costs and proved reserves of natural gas and oil, in which case the gain or loss is recognized in income.

 

Other Property and Equipment

 

Other property and equipment is reviewed on an annual basis for impairment and as of December 31, 2007, the Company had not identified any such impairment. Repairs and maintenance are charged to operations when incurred and improvements and renewals are capitalized.

 

Other property and equipment are stated at cost. Depreciation is calculated using the straight-line method for financial reporting purposes and accelerated methods for income tax purposes.

 

The estimated useful lives are as follows:

 

 

Debt Issue Costs

 

Included in other assets are costs associated with bank credit facilities. The remaining unamortized debt issue costs at March 31, 2008 and 2007 totaled $8.0 million and $9.7 million, respectively, and are being amortized over the life of the credit facilities.

 

Other Dispositions

 

Upon disposition or retirement of property and equipment other than natural gas and oil properties, the cost and related accumulated depreciation are removed from the accounts and the gain or loss thereon, if any, is credited or charged to income.

 

Marketable Securities

 

In accordance with Statement of Financial Accounting Standards (“SFAS”) 115, Accounting for Certain Investments in Debt and Equity Securities, the Company classifies its investment portfolio according to the provisions of SFAS 115 as either held to maturity, trading, or available for sale. At March 31, 2008 and 2007, the Company did not have any investments in its investment portfolio classified as available for sale and held to maturity.

 

Income Taxes

 

The Company accounts for income taxes pursuant to the provisions of the SFAS 109, Accounting for Income Taxes, which requires an asset and liability approach to calculating deferred income taxes. The asset and liability approach requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax basis of assets and liabilities. The provision for income taxes differ from the amounts currently payable because of temporary differences (primarily intangible drilling costs and the net operating loss carry forward) in the recognition of certain income and expense items for financial reporting and tax reporting purposes.

 

Accounting for Uncertainty in Income Taxes.  In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109 (FIN 48). FIN 48 is intended to clarify the accounting for uncertainty in income taxes recognized

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

in a company’s financial statements and prescribes the recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

 

Under FIN 48, evaluation of a tax position is a two-step process. The first step is to determine whether it is more-likely-than-not that a tax position will be sustained upon examination, including the resolution of any related appeals or litigation based on the technical merits of that position. The second step is to measure a tax position that meets the more-likely-than-not threshold to determine the amount of benefit to be recognized in the financial statements. A tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.

 

Tax positions that previously failed to meet the more-likely-than-not recognition threshold should be recognized in the first subsequent period in which the threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not criteria should be de-recognized in the first subsequent financial reporting period in which the threshold is no longer met.

 

The adoption of FIN 48 at January 1, 2007 did not have a material effect on the Company’s financial position.

 

Earnings Per Common Share

 

SFAS 128, Earnings Per Share, requires presentation of “basic” and “diluted” earnings per share on the face of the statements of operations for all entities with complex capital structures. Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted during the period. Dilutive securities having an anti-dilutive effect on diluted earnings per share are excluded from the calculation. See Note 7 — Earnings Per Share, for a reconciliation of the numerator and denominator of the basic and diluted earnings per share computations.

 

Fair Value of Financial Instruments

 

The Company’s financial instruments consist of cash, receivables, deposits, hedging contracts, accounts payable, accrued expenses and notes payable. The carrying amount of cash, receivables, deposits, accounts payable and accrued expenses approximates fair value because of the short-term nature of those instruments. The hedging contracts are recorded in accordance with the provisions of SFAS 133, Accounting for Derivative Instruments and Hedging Activities. The carrying amounts for notes payable approximate fair value due to the variable nature of the interest rates of the notes payable.

 

Stock-Based Compensation

 

Stock Options.  Effective January 1, 2006, the Company adopted SFAS 123 (Revised 2004), Share-Based Payment, which requires that compensation related to all stock-based awards, including stock options, be recognized in the financial statements based on their estimated grant-date fair value. The Company has previously recorded stock compensation pursuant to the intrinsic value method under APB Opinion No. 25, whereby compensation was recorded related to performance share and unrestricted share awards and no compensation was recognized for most stock option awards. The Company is using the modified prospective application method of adopting SFAS 123R, whereby the estimated fair value of unvested stock awards granted prior to January 1, 2006 will be recognized as compensation expense in periods subsequent to December 31, 2005, based on the same valuation method used in the Company’s prior pro forma disclosures. The Company has estimated expected forfeitures, as required by SFAS 123R, and the Company is recognizing compensation expense only for those awards expected to vest. Compensation expense is amortized over the estimated service period, which is the shorter of the award’s time vesting period or the derived service period as implied by any accelerated vesting provisions

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

when the common stock price reaches specified levels. All compensation must be recognized by the time the award vests. The cumulative effect of initially adopting SFAS 123R was immaterial.

 

On March 5, 2008, the Company’s board of directors approved the cancellation of each of the independent directors’ unvested stock options. Replacement bonus shares were awarded such that for every two shares subject to the original options, the director would be entitled to receive one bonus share. The bonus shares will become vested on the dates respective to the dates the original stock options would have become exercisable.

 

Partnership Unit Awards.  Quest Energy GP, LLC, the general partner of Quest Energy, granted bonus units to certain members of its Board of Directors during the three months ended March 31, 2008. The units are subject to vesting with 25% of the units immediately vested and one-third of the remaining units vesting equally on each of the first three anniversaries of the date of the grant. The fair value of the unit awards granted is recognized over the applicable vesting period as compensation expense. Compensation expense amounts are recognized in general and administrative expenses or capitalized to oil and gas properties. For the three months ended March 31, 2008, Quest Energy did not capitalize any of the value associated with the bonus unit grants. The value of the bonus unit grants included in general and administrative expenses for the three months ended March 31, 2008 was $203,000.

 

Quest Midstream GP, LLC, the general partner of Quest Midstream, granted bonus units to certain employees and certain members of its Board of Directors during the year ended December 31, 2007. The units are subject to a three-year vesting schedule. The fair value of the unit awards granted is recognized over the applicable vesting period as compensation expense. To the extent the compensation expense relates to employees directly involved in acquisition and development of pipeline activities, such amounts are capitalized to the pipeline. Amounts not capitalized to the pipeline are recognized in general and administrative expenses. For the three months ended March 31, 2008, Quest Midstream did not capitalize any of the value associated with the bonus unit grants. The value of the bonus unit grants included in general and administrative expenses for the three months ended March 31, 2008 was $472,000.

 

Stock Awards.  The Company granted shares of common stock to certain employees in February 2008 and February, March, April, September and December 2007. The shares are subject to three-year and four-year vesting schedules. In March 2008, the Company granted bonus units to its independent directors in exchange for the cancellation of their unvested stock options. See “−Stock Options” above. The fair value of the stock awards granted is recognized over the applicable vesting period as compensation expense. To the extent the compensation expense relates to employees directly involved in acquisition, exploration and development activities, such amounts are capitalized to oil and gas properties. Amounts not capitalized to oil and gas properties are recognized in general and administrative expenses.

 

The 1,065,714 shares issued during the three months ended March 31, 2008 includes 22,634 shares issued for previously granted bonus shares and the issuance of 1,043,080 shares of restricted stock that had been previously granted but not yet issued.

 

Accounting for Derivative Instruments and Hedging Activities

 

The Company seeks to reduce its exposure to unfavorable changes in natural gas and oil prices by utilizing energy swaps and collars (collectively, “fixed-price contracts”). The Company also enters into interest rate swaps and caps to reduce its exposure to adverse interest rate fluctuations. The Company has adopted SFAS 133, as amended by SFAS 138, Accounting for Derivative Instruments and Hedging Activities, which contains accounting and reporting guidelines for derivative instruments and hedging activities. It requires that all derivative instruments be recognized as assets or liabilities in the statement of financial position, measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Designation is established at the inception of a derivative, but re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS 133, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings.

 

Pursuant to the provisions of SFAS 133, all hedging designations and the methodology for determining hedge ineffectiveness must be documented at the inception of the hedge, and, upon the initial adoption of the standard, hedging relationships must be designated anew. Based on the interpretation of these guidelines by the Company, the changes in fair value of all of its derivatives entered into during the period from June 1, 2003 to December 22, 2003 are required to be reported in results of operations, rather than in other comprehensive income. Also, all changes in fair value of the Company’s interest rate swaps and caps were reported in results of operations rather than in other comprehensive income because the critical terms of the interest rate swaps and caps did not comply with certain requirements set forth in SFAS 133.

 

Although the Company’s fixed-price contracts may not qualify for special hedge accounting treatment from time to time under the specific guidelines of SFAS 133, the Company has continued to refer to these contracts in this document as hedges inasmuch as this was the intent when such contracts were executed, the characterization is consistent with the actual economic performance of the contracts, and the Company expects the contracts to continue to mitigate its commodity price and interest rate risks in the future. The specific accounting for these contracts, however, is consistent with the requirements of SFAS 133. See Note 6 — Financial Instruments and Hedging Activities.

 

The Company has established the fair value of all derivative instruments using estimates determined by its counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility, and time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

 

Asset Retirement Obligations

 

The Company has adopted SFAS 143, Accounting for Asset Retirement Obligations. SFAS 143 requires companies to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement.

 

The Company’s asset retirement obligations relate to the plugging and abandonment of natural gas and oil properties and its interstate pipeline assets. The Company is unable to predict if and when its intrastate pipelines would become completely obsolete and require decommissioning. Accordingly, the Company has recorded no liability or corresponding asset for the intrastate pipelines in conjunction with the adoption of SFAS 143 because the future dismantlement and removal dates of the Company’s assets and the amount of any associated costs are indeterminable.

 

Reclassification

 

Certain reclassifications have been made to the prior year’s financial statements in order to conform to the current presentation. These reclassifications had no effect on previously reported results of operations or stockholders’ equity.

 

Recently Issued Accounting Standards

 

The Financial Accounting Standards Board recently issued the following standards which the Company reviewed to determine the potential impact on our financial statements upon adoption.

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

On February 6, 2008, the FASB issued Financial Staff Position FAS 157-2, “Effective Date of FASB Statement No. 157.” This Staff Position delays the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The delay is intended to allow the FASB and constituents additional time to consider the effect of various implementation issues that have arisen, or that may arise, from the application of SFAS 157.

 

The remainder of SFAS 157 was adopted by us effective for fiscal years beginning after November 15, 2007. The adoption of SFAS 157 did not have an impact on the Company’s financial position, results of operations, or cash flows.

 

In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities”, an amendment of FASB SFAS 115. SFAS 159 addresses how companies should measure many financial instruments and certain other items at fair value. The objective is to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS 159 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. SFAS 159 had been adopted and did not have a material impact on the Company’s financial position, results of operations, or cash flows.

 

In December 2007, the FASB issued SFAS 141R (revised 2007), “Business Combinations.” Although this statement amends and replaces SFAS 141, it retains the fundamental requirements in SFAS 141 that (i) the purchase method of accounting be used for all business combinations; and (ii) an acquirer be identified for each business combination. SFAS 141R defines the acquirer as the entity that obtains control of one or more businesses in the business combination and establishes the acquisition date as the date that the acquirer achieves control. This Statement applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree), including combinations achieved without the transfer of consideration; however, this Statement does not apply to a combination between entities or businesses under common control. Significant provisions of SFAS 141R concern principles and requirements for how an acquirer (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 with early adoption not permitted. Management is assessing the impact of the adoption of SFAS 141R.

 

In December 2007, the FASB issued SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”. The objective of this statement is to improve the relevant, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements related to noncontrolling or minority interests. The effective date for this Statement is for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 with earlier adoption being prohibited. Adoption of this Statement will change the method in which minority interests are reflected on the Company’s consolidated financial statements and will add some additional disclosures related to the reporting of minority interests. Management is assessing the impact of the adoption of SFAS 160.

 

In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities”. The objective of this statement is to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity’s financial position, financial performance, and cash flows. The effective date for this statement is for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. Management is assessing the impact of the adoption of SFAS 161.

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

KPC Pipeline

 

On November 1, 2007, Quest Midstream completed the purchase of the KPC Pipeline pursuant to a Purchase and Sale Agreement (the “Purchase Agreement”), dated as of October 9, 2007, by and among Quest Midstream, Enbridge Midcoast Energy, L.P. and Midcoast Holdings No. One, L.L.C., whereby Quest Midstream purchased all of the membership interests in the two general partners of Enbridge Pipelines (KPC), the owner of the KPC Pipeline for a purchase price of approximately $133 million in cash, subject to adjustment for working capital at closing.

 

In accordance with the terms of the Purchase Agreement, the purchase price, current assets and certain assumed liabilities were allocated as follows (dollars in thousands):

 

 

Pro Forma Summary Data (unaudited)

 

The following pro forma summary data for the three months ending March 31, 2007 presents the consolidated results of operations as if the KPC Pipeline acquisition made on November 1, 2007 had occurred on January 1, 2007. These pro forma results have been prepared for comparative purposes only and do not purport to be indicative of what would have occurred had the acquisitions been made at January 1, 2007 or of results that may occur in the future.

 

 

Searight

 

Quest Energy purchased certain oil producing properties in Seminole County, Oklahoma from a private company for $9.5 million in a transaction that closed in early February 2008. The properties have estimated proved reserves of 712,000 barrels, all of which are proved developed producing. In addition, Quest Energy 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.

 

 

The Company has adopted SFAS 143, Accounting for Asset Retirement Obligations. The following table provides a roll forward of the asset retirement obligations for the three months ended March 31, 2008 and 2007:

 

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

 

Long-term debt consists of the following:

 

 

The aggregate scheduled maturities of notes payable and long-term debt for the period ending December 31, 2013 and thereafter were as follows as of March 31, 2008 (assuming no payments were made on the revolving credit facilities prior to their maturity) (dollars in thousands):

 

 

Credit Facilities

 

The Company and its subsidiaries are parties to three credit facilities. See Note 3 to the consolidated financial statements included in the 2007 Form 10-K for descriptions of the material terms of the credit facilities.

 

Quest Energy Partners, L.P. and Quest Cherokee, LLC.  Quest Cherokee, LLC is a party to an Amended and Restated Credit Agreement dated as of November 15, 2007 with Royal Bank of Canada, as administrative agent and collateral agent (“RBC”), KeyBank National Association, as documentation agent, and the lenders party thereto. Quest Energy is a guarantor of the credit agreement. As of March 31, 2008, the borrowing base under this credit agreement was $160 million and the amount borrowed under the credit agreement was $123 million. The weighted average interest rate under this credit agreement for the three months ended March 31, 2008 was 6.88%. See Note 11 — Subsequent Events for a description of amendments to this credit agreement.

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Quest Resource Corporation.  The Company is a party to a Credit Agreement dated as of November 15, 2007 with RBC, as administrative agent and collateral agent, and the lenders party thereto. As of March 31, 2008, the borrowing base under this credit agreement was $50 million and the amount borrowed under the credit agreement was $44 million. The weighted average interest rate under this credit agreement for the three months ended March 31, 2008 was 8.25%.

 

Quest Midstream Partners, L.P. and Bluestem Pipeline, LLC.  Quest Midstream and Bluestem are parties to an Amended and Restated Credit Agreement dated as of November 1, 2007 with RBC, as administrative agent and collateral agent, and the lenders party thereto. As of March 31, 2008, the amount borrowed under the credit agreement was $106 million and the total amount available was $135 million. The weighted average interest rate under this credit agreement for the three months ended March 31, 2008 was 7.23%.

 

Other Long-Term Indebtedness

 

$613,000 of notes payable to banks and finance companies were outstanding at March 31, 2008 and are secured by equipment and vehicles, with payments due in monthly installments through October 2013 with interest ranging from 5.5% to 11.5% per annum.

 

 

Natural Gas and Oil Hedging Activities

 

The Company seeks to reduce its exposure to unfavorable changes in natural gas and oil prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. The fixed-price contracts are comprised of energy swaps and collars. These contracts allow the Company to predict with greater certainty the effective natural gas and oil prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Collar structures provide for participation in price increases and decreases to the extent of the ceiling and floor prices provided in those contracts. For the three months ended March 31, 2008 and 2007, fixed-price contracts hedged approximately 59.05% and 71.6%, respectively, of the Company’s natural gas production. As of March 31, 2008, fixed-price contracts are in place to hedge 38.2 Bcf of estimated future natural gas production. Of this total volume, 9.0 Bcf are hedged for 2008 and 29.1 Bcf thereafter. As of March 31, 2008, fixed-price contracts are in place to hedge 93,000 Bbls of estimated future oil production. Of this total volume, 27,000 Bbls are hedged for 2008 and 66,000 Bbls thereafter.

 

For energy swap contracts, the Company receives a fixed price for the respective commodity and pays a floating market price, as defined in each contract (generally a regional spot market index or in some cases, NYMEX future prices), to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. Natural gas and oil collars contain a fixed floor price (put) and ceiling price (call) (generally a regional spot market index or in some cases, NYMEX future prices). If the market price of natural gas or oil exceeds the call strike price or falls below the put strike price, then the Company receives the fixed price and pays the market price. If the market price of natural gas or oil is between the call and the put strike price, then no payments are due from either party.

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of March 31, 2008.

 

 

 

 

The estimates of fair value of the fixed-price contracts are computed based on the difference between the prices provided by the fixed-price contracts and forward market prices as of the specified date, as adjusted for basis. Forward market prices for natural gas are dependent upon supply and demand factors in such forward market and

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

are subject to significant volatility. The fair value estimates shown above are subject to change as forward market prices and basis change.

 

All fixed-price contracts have been approved by the Company’s board of directors. The differential between the fixed price and the floating price for each contract settlement period multiplied by the associated contract volume is the contract profit or loss. For fixed-price contracts qualifying as cash flow hedges pursuant to SFAS 133, the realized contract profit or loss is included in oil and gas sales in the period for which the underlying production was hedged. For the three months ended March 31, 2008 and 2007, oil and gas sales included $1.2 million and $996,000, respectively, of net losses associated with realized losses under fixed-price contracts.

 

For contracts that did not qualify as cash flow hedges, the realized contract profit and loss is included in other revenue and expense in the period for which the underlying production was hedged. For the three months ended March 31, 2008 and 2007, other revenue and expense included $0 and $0, respectively, of net losses associated with realized losses under fixed-price contracts.

 

For fixed-price contracts qualifying as cash flow hedges, changes in fair value for volumes not yet settled are shown as adjustments to other comprehensive income. For those contracts not qualifying as cash flow hedges, changes in fair value for volumes not yet settled are recognized in change in derivative fair value in the statement of operations. The fair value of all fixed-price contracts are recorded as assets or liabilities in the balance sheet.

 

Based upon market prices at March 31, 2008, the estimated amount of unrealized gains for fixed-price contracts shown as adjustments to other comprehensive income that are expected to be reclassified into earnings as actual contract cash settlements are realized within the next 12 months is $28.6 million.

 

Interest Rate Hedging Activities

 

At March 31, 2008, the Company had no outstanding interest rate cap or swap agreements.

 

Change in Derivative Fair Value

 

Change in derivative fair value in the statements of operations for the three months ended March 31, 2008 and 2007 is comprised of the following:

 

 

The amounts recorded in change in derivative fair value do not represent cash gains or losses. Rather, they are temporary valuation swings in the fair value of the contracts. All amounts initially recorded in this caption are ultimately reversed within this same caption over the respective contract terms.

 

Credit Risk

 

Energy swaps and collars and interest rate swaps and caps provide for a net settlement due to or from the respective party as discussed previously. The counterparties to the derivative contracts are financial institutions. Should a counterparty default on a contract, there can be no assurance that we would be able to enter into a new contract with a third party on terms comparable to the original contract. The Company has not experienced non-performance by its counterparties.

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Cancellation or termination of a fixed-price contract would subject a greater portion of the Company’s natural gas or oil production to market prices, which, in a low price environment, could have an adverse effect on its future operating results. Cancellation or termination of an interest rate swap or cap would subject a greater portion of the Company’s long-term debt to market interest rates, which, in an inflationary environment, could have an adverse effect on its future net income. In addition, the associated carrying value of the derivative contract would be removed from the balance sheet.

 

Market Risk

 

The differential between the floating price paid under each energy swap or collar contract and the price received at the wellhead for our production is termed “basis” and is the result of differences in location, quality, contract terms, timing and other variables. For instance, some of our fixed price contracts are tied to commodity prices on the New York Mercantile Exchange (“NYMEX”), that is, we receive the fixed price amount stated in the contract and pay to our counterparty the current market price for gas as listed on the NYMEX. However, due to the geographic location of our natural gas assets and the cost of transporting the natural gas to another market, the amount that we receive when we actually sell our natural gas is based on the Southern Star Central TX/KS/OK (“Southern Star”) first of month index, with a small portion being sold based on the daily price on the Southern Star index. The difference between natural gas prices on the NYMEX and the price actually received by the Company is referred to as a basis differential. Typically, the price for natural gas on the Southern Star first of the month index is less than the price on the NYMEX due to the more limited demand for natural gas on the Southern Star first of the month index. The crude oil production for which we have entered into swap agreements is sold at a contract price based on the average daily settling price of NYMEX less $1.10/bbl, which eliminates our exposure to changing differentials on this production. This contract runs through March 2009 with automatic extensions thereafter unless terminated by either party. Recently, the basis differential has been increasingly volatile and has on occasion resulted in us receiving a net price for our natural gas and oil that is significantly below the price stated in the fixed price contract.

 

The effective price realizations that result from the fixed-price contracts are affected by movements in this basis differential. Basis movements can result from a number of variables, including regional supply and demand factors, changes in the portfolio of the Company’s fixed-price contracts and the composition of its producing property base. Basis movements are generally considerably less than the price movements affecting the underlying commodity, but their effect can be significant. Recently, the basis differential has been increasingly volatile and has on occasion resulted in the Company receiving a net price for its natural gas and oil that is significantly below the price stated in the fixed price contract.

 

Changes in future gains and losses to be realized in natural gas and oil sales upon cash settlements of fixed-price contracts as a result of changes in market prices for natural gas and oil are expected to be offset by changes in the price received for hedged natural gas and oil production.

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Fair Value of Financial Instruments

 

The following information is provided regarding the estimated fair value of the financial instruments, including derivative assets and liabilities as defined by SFAS 133 that the Company held as of March 31, 2008 and December 31, 2007 and the methods and assumptions used to estimate their fair value:

 

 

The Company’s financial instruments consist of cash, receivables, deposits, hedging contracts, accounts payable, accrued expenses and notes payable. The carrying amount of cash, receivables, deposits, accounts payable and accrued expenses approximates fair value because of the short-term nature of those instruments. The hedging contracts are recorded in accordance with the provisions of SFAS 133, Accounting for Derivative Instruments and Hedging Activities. The carrying amounts for notes payable approximate fair value due to the variable nature of the interest rates of the notes payable.

 

 

SFAS 128 requires a reconciliation of the numerator and denominator of the basic and diluted earnings per share (EPS) computations. The following securities were not included in the calculation of diluted earnings per share because their effect was antidilutive.

 

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

The following reconciles the components of the EPS computation (dollars in thousands, except per share):

 

 

 

Quest Energy Distributions to Unit Holders

 

Minimum Quarterly Distribution.  Quest Energy will distribute to the holders of its common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.40 per unit, or $1.60 per year, to the extent Quest Energy has sufficient cash from its operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner. However, there is no guarantee that Quest Energy will pay the minimum quarterly distribution on the units in any quarter. Even if Quest Energy’s cash distribution policy is not modified or revoked, the amount of distributions paid under its policy and the decision to make any distribution is determined by its general partner, taking into consideration the terms of Quest Energy’s partnership agreement. Quest Energy will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under its credit facility. Please read Note 3 to the consolidated financial statements included in the 2007 Form 10-K for a discussion of the restrictions included in Quest Energy’s credit facility that may restrict its ability to make distributions.

 

General Partner Interest and Incentive Distribution Rights.  Initially, Quest Energy’s general partner will be entitled to 2% of all quarterly distributions since inception that Quest Energy makes prior to its liquidation. The 2% general partner interest in the distributions may be reduced if Quest Energy issues additional units in the future and its general partner does not contribute a proportionate amount of capital to Quest Energy to maintain its 2% general partner interest. See Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities — Cash Distributions to Unitholders” in Quest Energy’s Annual Report on Form 10-K for the year ended December 31, 2007 for further discussion of its cash distributions.

 

As of March 31, 2008, Quest Energy has accrued cash distributions for the quarter ended March 31, 2008 to all of its unit holders totaling $8.0 million or $0.41 per unit on all of its units.

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Quest Midstream Distributions to Unit Holders

 

Minimum Quarterly Distribution.  Quest Midstream will distribute to the holders of its common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.425 per unit, or $1.70 per year, plus any arrearages in payment of the minimum quarterly distribution on common units from prior quarters, to the extent Quest Midstream has sufficient cash from its operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner. However, there is no guarantee that Quest Midstream will pay the minimum quarterly distribution on the units in any quarter. Even if Quest Midstream’s cash distribution policy is not modified or revoked, the amount of distributions paid under its policy and the decision to make any distribution is determined by its general partner, taking into consideration the terms of Quest Midstream’s partnership agreement. Quest Midstream will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under its credit facility. Please read Note 3 to the consolidated financial statements included in the 2007 Form 10-K for a discussion of the restrictions included in Quest Midstream’s credit facility that may restrict its ability to make distributions.

 

General Partner Interest and Incentive Distribution Rights.  Initially, Quest Midstream’s general partner will be entitled to 2% of all quarterly distributions since inception that Quest Midstream makes prior to its liquidation. The 2% general partner interest in the distributions may be reduced if Quest Midstream issues additional units in the future and its general partner does not contribute a proportionate amount of capital to Quest Midstream to maintain its 2% general partner interest.

 

During the three months ended March 31, 2008, Quest Midstream accrued cash distributions for the quarter ended March 31, 2008 to its unit holders totaling $3.8 million or $0.425 per unit on its common units.

 

 

Quest Resource Corporation, Bluestem Pipeline, LLC, STP, Inc., Quest Cherokee, LLC, Quest Energy Service, LLC, Quest Midstream Partners, LP, Quest Midstream GP, LLC, and STP Cherokee, Inc. (now STP Cherokee, LLC) have been named Defendants in a lawsuit filed by Plaintiffs, Eddie R. Hill, et al. in the District Court for Craig County, Oklahoma (Case No. CJ-2003-30). Plaintiffs are royalty owners who are alleging underpayment of royalties owed to them. Plaintiffs also allege, among other things, that Defendants have engaged in self-dealing and breached fiduciary duties owed to Plaintiffs, and that Defendants have acted fraudulently toward the Plaintiffs. Plaintiffs also allege that the gathering fees and related charges should not be deducted in paying royalties. Plaintiffs’ claims relate to a total of 84 wells located in Oklahoma and Kansas. Plaintiffs are seeking unspecified actual and punitive damages. Defendants intend to defend vigorously against Plaintiffs’ claims.

 

STP, Inc., STP Cherokee, Inc. (now STP Cherokee, LLC), Bluestem Pipeline, LLC, Quest Cherokee, LLC, and Quest Energy Service, LLC (improperly named Quest Energy Services, LLC) have been named defendants in a lawsuit by Plaintiffs John C. Kirkpatrick and Suzan M. Kirkpatrick in the District Court for Craig County (Case No. CJ-2005-143). Plaintiffs allege that STP, Inc., et al., sold natural gas from wells owned by the Plaintiffs without providing the requisite notice to Plaintiffs. Plaintiffs further allege that Defendants failed to include deductions on the check stubs of Plaintiffs in violation of state law and that Defendants deducted for items other than compression in violation of the lease terms. Plaintiffs assert claims of actual and constructive fraud and further seek an accounting stating that if Plaintiffs have suffered any damages for failure to properly pay royalties, Plaintiffs have a right to recover those damages. Plaintiffs have not quantified their alleged damages. Discovery is ongoing and Defendants intend to defend vigorously against Plaintiffs’ claims.

 

Quest Cherokee Oilfield Services, LLC has been named in this lawsuit filed by Plaintiffs Segundo Francisco Trigoso and Dana Jara De Trigoso in the District Court of Oklahoma County, Oklahoma (Case No. CJ-2007-11079). Plaintiffs allege that Plaintiff Segundo Trigoso was injured while working for Defendant on September 29, 2006 and that such injuries were intentionally caused by Defendant. Plaintiffs seek unspecified damages for physical injuries,

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

emotional injuries, loss of consortium and pain and suffering. Plaintiffs also seek punitive damages. Defendant intends to defend vigorously against Plaintiffs’ claims.

 

Quest Cherokee and Bluestem were named as defendants in a lawsuit (Case No. 04-C-100-PA) filed by plaintiff Central Natural Resources, Inc. on September 1, 2004 in the District Court of Labette County, Kansas. Central Natural Resources owns the coal underlying numerous tracts of land in Labette County, Kansas. Quest Cherokee has obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying some of that land and has drilled wells that produce coal bed methane gas on that land. Bluestem purchases and gathers the gas produced by Quest Cherokee. Plaintiff alleges that it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser. Plaintiff is seeking quiet title and an equitable accounting for the revenues from the coal bed methane gas produced. Plaintiff has alleged that Bluestem converted the gas and seeks an accounting for all gas purchased by Bluestem from the wells in issue. Quest Cherokee contends it has valid leases with the owners of the coal bed methane gas rights. The issue is whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. If Quest Cherokee prevails on that issue, then the 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 were filed by Quest Cherokee and the plaintiff, with summary judgment being awarded in Quest Cherokee’s favor. The plaintiff has appealed the summary judgment and that appeal is pending. Quest Cherokee and Bluestem intend to defend vigorously against these claims.

 

Quest Cherokee was named as a defendant in a lawsuit (Case No. CJ-06-07) filed by plaintiff Central Natural Resources, Inc. on January 17, 2006, in the District Court of Craig County, Oklahoma. Bluestem is not a party to this lawsuit. Central Natural Resources owns the coal underlying approximately 2,250 acres of land in Craig County, Oklahoma. Quest Cherokee has obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying those lands, and has drilled and completed 20 wells that produce coal bed methane gas on those lands. Plaintiff alleges that it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser. Plaintiff seeks to quiet its alleged title to the coal bed methane and an accounting of the revenues from the coal bed methane gas produced by Quest Cherokee. Quest Cherokee contends it has valid leases from the owners of the coal bed methane gas rights. The issue is whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. Quest Cherokee has answered the petition and discovery is ongoing. Quest Cherokee intends to defend vigorously against these claims.

 

Quest Cherokee was named as a defendant in a lawsuit (Case No. 05 CV 41) filed by Labette Energy, LLC in the district court of Labette County, Kansas. Plaintiff claims to own a 3.2 mile gas gathering pipeline in Labette County, Kansas, and that Quest Cherokee used that pipeline without plaintiff’s consent. Plaintiff also contends that the defendants slandered its alleged title to that pipeline and suffered damages from the cancellation of their proposed sale of that pipeline. Plaintiff claims that they were damaged in the amount of $202,375. Discovery in that case is ongoing and Quest Cherokee intend to defend vigorously against the plaintiff’s claims.

 

Quest Cherokee was named as a defendant in a putative class action lawsuit (Case No. 07-1225-MLB) filed by several royalty owners in the U.S. District Court for the District of Kansas. The plaintiffs have not yet filed a motion asking the court to certify the class and the court has not determined that the case may properly proceed as a class action. The case was filed by the named plaintiffs on behalf of a putative class consisting of all Quest 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.

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Quest Cherokee has been named as a defendant in several lawsuits in which the plaintiff claims that an oil and gas lease owned and operated by Quest Cherokee has either expired by their terms or, for various reasons, have been forfeited by Quest Cherokee. Those lawsuits are pending in the district courts of Labette, Montgomery, and Wilson Counties, Kansas. Quest Cherokee has drilled wells on some of the oil and gas leases in issue and some of those oil and gas leases do not have a well located thereon but have been unitized with other oil and gas leases upon which a well has been drilled. The plaintiffs in those cases are generally seeking statutory damages of $100 per lease, attorneys’ fees, and a judicial declaration that Quest Cherokee’s leases have terminated. As of May 7, 2008, the total amount of acreage covered by the leases at issue in these lawsuits was approximately 7,481 acres. Discovery in those cases is ongoing. Quest Cherokee intends to vigorously defend against those claims.

 

Quest Cherokee was named in an Order to Show Cause issued by the Kansas Corporation Commission (the “KCC”) (KCC Docket No. 07-CONS-155-CSHO) filed on February 23, 2007. The KCC has ordered Quest Cherokee to demonstrate why it should not be held responsible for plugging 22 abandoned oil wells on a gas lease owned and operated by Quest Cherokee in Wilson County, Kansas. Quest Cherokee denies that it is legally responsible for plugging the wells in issue and intends to vigorously defend against the KCC’s claims.

 

Quest Cherokee was named as a defendant in two lawsuits (Case No. 07-CV-141 and Case No. 08-CV-20) filed in Neosho County District Court by Richard Winder, d/b/a Winder Oil Company. Plaintiff claims to own an oil and gas lease covering lands upon which Quest Cherokee also claims to own an oil and gas lease and upon which Quest Cherokee has drilled two producing wells. Plaintiff claims that his lease is prior and superior to Quest Cherokee’s leases and seeks damages for trespass and conversion. Quest Cherokee contends that plaintiffs leases have expired by their terms and that Quest Cherokee’s leases are valid. Discovery in that case is ongoing. Quest Cherokee intends to vigorously defend against the Plaintiff’s claims.

 

The Company, from time to time, may be subject to legal proceedings and claims that arise in the ordinary course of its business. Although no assurance can be given, management believes, based on its experiences to date, that the ultimate resolution of such items will not have a material adverse impact on the Company’s business, financial position or results of operations. Like other natural gas and oil producers and marketers, the Company’s 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.

 

 

We divide our operations into two reportable business segments:

 

 

Each segment uses the same accounting policies as those described in the summary of significant accounting policies (see Note 2). Our reportable segments are strategic business units that offer different products and services. Each segment is managed separately because each segment involves different products and marketing strategies. The Company does not allocate income taxes to its operating segments.

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Operating segment data for the three months ended March 31, 2008 and 2007 follows (in thousands):

 

 

 

Operating profit per segment represents total revenues less costs and expenses attributable thereto, excluding general corporate expenses.

 

 

On April 17, 2008, Quest Energy and Quest Cherokee entered into an amendment to the Amended and Restated Credit Agreement with the Royal Bank of Canada, as administrative agent and collateral agent, Keybank National Association, as documentation agent, and the lenders party thereto (the “Amendment”). The Amendment changed the maturity date from November 15, 2012 to November 15, 2010, and increased the applicable rate at

 

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

 

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

which interest will accrue by 1% to either LIBOR plus a margin ranging from 2.25% to 2.875% (depending on the utilization percentage) or the base rate plus a margin ranging from 1.25% to 1.875% (depending on the utilization percentage). The Amendment also eliminated the “accordion” feature in the credit agreement, which gave Quest Cherokee the option to request an increase in the aggregate revolving commitment from $250 million to $350 million. There was no commitment on the part of the lenders to agree to such a request.

 

We are an independent energy company with an emphasis on the acquisition, exploration, development, production, and transportation of natural gas (coal bed methane) in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma. We also own and operate a gas gathering pipeline network of approximately 2,000 miles in length within this basin. Additionally, we own a 1,120-mile interstate natural gas transmission pipeline that runs from Oklahoma to Missouri (the “KPC Pipeline”). Our main focus is upon the development of our coal bed methane gas reserves in our pipeline network region and upon the continued enhancement of the pipeline system, and supporting infrastructure. Unless otherwise indicated, references to “us”, “we”, the “Company” or “Quest” include our operating subsidiaries.

 

Significant Developments During the Three Months Ended March 31, 2008

 

During the first quarter of 2008, we continued to be focused on drilling and completing new wells. We drilled 118 gross wells and completed the connection of 101 gross wells during this period. As of March 31, 2008, we had approximately 130 additional gas wells (gross) that we were in the process of completing and connecting to our gas gathering pipeline system.

 

We completed approximately 70 miles of pipeline infrastructure expansion and acquired additional natural gas leases covering approximately 16,000 acres (gross).

 

We are also evaluating the operation of our natural gas gathering system to determine whether changes in compression or other alterations in the operation of the pipeline system might improve production.

 

For the three months ended March 31, 2008, our average net daily production was 55.6 Mmcfe/d.

 

Quest Energy purchased certain oil producing properties in Seminole County, Oklahoma from a private company for $9.5 million in a transaction that closed in early February 2008. The properties have estimated net proved reserves of 712,000 barrels, all of which are proved developed producing. In addition, Quest Energy entered into crude oil swaps for approximately 80% of the estimated net 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.

 

Part of our business strategy is to expand our exploration, development and production activities beyond the Cherokee Basin. We currently own approximately 23,000 net undeveloped acres in Pennsylvania, Maryland, Texas and New Mexico. We expect our first vertical well in Pennsylvania to be completed and tested by the end of the second quarter of 2008. We plan to drill and complete additional wells during 2008 if the first well is successful. Our test well in New Mexico was unsuccessful and was plugged and abandoned in May 2008. We currently do not plan any additional activity in New Mexico. Overall, we plan to spend between $2 million and $3 million on drilling and completion of exploratory wells in 2008.

 

Results of Operations

 

As a result of the acquisition of KPC Pipeline in November 2007 we have begun reporting our results of operations as two segments: Quest Energy (natural gas and oil production) and Quest Midstream (natural gas pipelines). Previously reported amounts have been adjusted to reflect this change, which did not impact our consolidated financial statements.

 

The following discussion is based on the consolidated operations of all our subsidiaries and should be read in conjunction with the financial statements included in this report; and should further be read in conjunction with the audited financial statements and notes thereto included in our 2007 Form 10-K. Comparisons made between reporting periods herein are for the three month periods ended March 31, 2008 as compared to the same period in 2007.

Quest Energy (Gas and Oil Production Segment)

 

Overview.  The following discussion of results of operations will compare balances for the three months ended March 31, 2008 and 2007, as follows:

 

 

Production.  The following table presents the primary components of revenues of our Gas and Oil Production Segment (gas and oil production and average gas and oil prices), as well as the average costs per Mcfe, for the three months ended March 31, 2008 and 2007.

 

 

Oil and Gas Sales.  The $11.8 million (46.2%) increase in oil and gas sales from $25.5 million for the quarter ended March 31, 2007 to $37.4 million for the quarter ended March 31, 2008 was primarily attributable to the increase in production volumes and sales prices reflected in the table above. The increase in production volumes was achieved by the addition of more producing wells, which was partially offset by the natural decline in production from some of our older gas wells. The additional wells contributed to the production of 4,991,000 Mcf of net gas for the quarter ended March 31, 2008, as compared to 3,716,000 net Mcf produced in the same quarter last

year. Our product prices on an equivalent basis (Mcfe) increased from an average of $6.99 per Mcfe for the quarter ended March 31, 2007 to an average of $7.62 per Mcfe for the quarter ended March 31, 2008. For the quarter ended March 31, 2008, the net product price, after accounting for the loss on hedging settlements of $1.2 million during the quarter, averaged $7.38 per Mcfe. For the quarter ended March 31, 2007, the net product price, after accounting for the gain on hedging settlements of $996,000 during the quarter, averaged $7.12 per Mcfe.

 

Other revenue/(expense).  Other revenue for the three months ended March 31, 2008 was $50,000 as compared to other expense of $13,000 for the three-month period ended March 31, 2007, that was due to a reduction in overhead fees.

 

Operating Expenses.  Operating expenses, which consist of oil and gas production costs and transportation expense, totaling $16.9 million for the three months ended March 31, 2008, were comprised of lease operating costs of $5.6 million, production taxes of $1.7 million, ad valorem taxes of $804,000, and transportation expenses of $8.6 million. The current operating expenses compared to $13.6 million for the three months ended March 31, 2007, comprised of lease operating costs of $5.5 million, production taxes of $1.1 million, ad valorem taxes of $888,000, and transportation expenses of $6.1 million, a total increase of $3.3 million, or 24%.

 

During the three months ended March 31, 2008, management implemented cost controls which have kept lease operating costs relatively flat, while connecting approximately 600 new wells since the same quarter of 2007. Unit production costs, excluding gross production and ad valorem taxes, were $1.12 per Mcfe for the three months ended March 31, 2008 compared to $1.47 per Mcfe for the three months ended March 31, 2007 representing a 23.8% decrease. Unit production costs, inclusive of gross production and ad valorem taxes, were $1.94 per Mcfe for the 2007 period as compared to $1.62 per Mcfe for the three months ended March 31, 2008 period, representing a 16.5% decrease.

 

Transportation expense increased $2.3 million from $6.4 million for the three months ended March 31,2007 compared to $8.7 million for the three months ended March 31,2008, resulting in $1.72 per Mcfe for 2008. This increase primarily resulted from the annual increase in the fees charged under the midstream services agreement with Quest Midstream and increased production.

 

Depreciation, Depletion and Amortization.  We are subject to variances in our depletion rates from period to period, including the periods described below. These variances result from changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our gas and oil properties. Our depletion of gas and oil properties as a percentage of gas and oil revenues was 25% in the three months ended March 31, 2008 compared to 26% in 2007. Depreciation, depletion and amortization expense was $1.88 per Mcfe in March 31, 2008 compared to $1.80 per Mcfe in 2007. Increases in our depletable basis and production volumes caused depletion expense to increase $2.8 million to $9.5 million in 2008 compared to $6.7 million in 2007.

 

General and Administrative Expense.  General and administrative expenses increased from $1.8 million for the quarter ended March 31, 2007 to $2.5 million for the quarter ended March 31, 2008. This increase resulted from a non-cash charge for amortization of stock and unit awards. The remainder of the increase is due to an increase in staff personnel, legal, accounting and professional fees, travel expenses for presentations to increase our visibility with investors, increased staffing to support the higher levels of development and operational activity and the added resources to enhance our internal controls.

 

Change in Derivative Fair Value.  Change in derivative fair value was a non-cash loss of $23.8 million for the three months ended March 31, 2008, which included a $23.5 million loss attributable to the change in fair value for certain derivative contracts that did not qualify as cash flow hedges pursuant to SFAS 133 and a loss of $283,000 relating to hedge ineffectiveness. Change in derivative fair value was a non-cash loss of $464,000 for the three months ended March 31, 2007, which included a $1.04 million loss attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133 and a gain of $572,000 relating to hedge ineffectiveness. Amounts recorded in this caption represent non-cash gains and losses created by valuation changes in derivatives that are not entitled to receive hedge accounting. All amounts recorded in this caption are ultimately reversed in this caption over the respective contract term.

 

Interest Expense.  Interest expense decreased to $2.1 million for the quarter ended March 31, 2008 from $7.0 million for the quarter ended March 31, 2007, due to refinancing of our credit facilities attributable to the

segment during 2007 resulting in lower average interest rates and lower outstanding borrowings attributable to the segment.

 

Quest Midstream (Natural Gas Pipelines Segment)

 

 

Pipeline Revenue.  Our third party transmission and gathering revenues were $6.9 million for the three months ended March 31, 2008, an increase of $5.4 million (348%) from $1.5 million for the three months ended March 31, 2007. 91% of the increase was attributable to revenue contributions from Quest Pipelines (KPC), which was acquired November 1, 2007, totaling $4.9 million. The remaining increase was due to additional third party volumes on our gathering system.

 

The intercompany gas pipeline revenues were $8.7 million for the three months ended March 31, 2008 as compared to $6.4 million for the three months ended March 31, 2007, an increase of $2.3 million, or 36%. The increase is due to the 31% increase in throughput volumes from our Cherokee Basin properties and the increase in gathering and compression fees resulting from the annual price adjustment under the midstream services agreement that became effective January 1, 2008, which provided for a fixed transportation fee that was higher than the fees in the year earlier period.

 

Pipeline Operating Expense.  Pipeline operating costs for the three months ended March 31, 2008 totaled approximately $7.2 million ($1.04 per Mcf) as compared to pipeline operating costs of $4.9 million ($0.92 per Mcf) for the three months ended March 31, 2007. This increase in operating costs was due to the delivery of additional compressors in anticipation of increased pipeline volumes, the number of wells completed and operated during the year, the increased miles of pipeline in service, the increase in property taxes and the operations of the KPC Pipeline.

 

Depreciation and Amortization.  Depreciation and amortization expense was $3.2 million for the three months ended March 31, 2008 compared to $1.1 million in 2007. The increase is due to the acquisition of the KPC Pipeline on November 1, 2007 and the additional natural gas gathering pipeline installed during the year ended December 31, 2007 and the three months ended March 31, 2008.

General and Administrative Expense.  General and administrative expenses increased from $886,000 for the quarter ended March 31, 2007 to $1.8 million for the quarter ended March 31, 2008. This increase resulted from a non-cash charge of approximately $450,000 for amortization of stock and unit awards. The remainder of the increase is due to an increase in staff personnel, legal, accounting and professional fees, travel expenses for presentations to increase our visibility with investors, costs for establishing a Houston office and staffing requirements, increased staffing to support the higher levels of development and operational activity and the added resources to enhance our internal controls.

 

Interest Expense.  Interest expense increased to $2.0 million for the quarter ended March 31, 2008 from $142,000 for the quarter ended March 31, 2007, due to additional borrowings under of our credit facility to finance the KPC Pipeline acquisition during 2007 and the construction of additional gas gathering pipeline.

 

Corporate Unallocated Items

 

Overview.  The following discussion of results of operations will compare balances for the three months ended March 31, 2008 and 2007, as follows: