KEGS 1812 Brewing Company Inc (PK)

NOTES TO CONDENSED CONSOLIDATED UNAUDITED FINANCIAL STATEMENTS

1.                                       ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The Company

Key Energy Services, Inc. is a Maryland corporation that was organized in April 1977 and commenced operations in July 1978 under the name National Environmental Group, Inc. We emerged from a prepackaged bankruptcy plan in December 1992 as Key Energy Group, Inc. On December 9, 1998, we changed our name to Key Energy Services, Inc. (“Key” or the “Company”). We believe that we are now the leading onshore, rig-based well servicing contractor in the United States. From 1994 through 2002, we grew rapidly through a series of over 100 acquisitions, and today we provide a complete range of well services to major oil companies and independent oil and natural gas production companies, including rig-based well maintenance, workover, well completion and recompletion services, oilfield transportation services, cased-hole electric wireline services and ancillary oilfield services, fishing and rental services and pressure pumping services. During 2006 and through the second quarter of 2007, Key conducted well servicing operations onshore in the continental United States in the following regions: Gulf Coast (including South Texas, Central Gulf Coast of Texas and South Louisiana), Permian Basin of West Texas and Eastern New Mexico, Mid-Continent (including the Anadarko, Hugoton and Arkoma Basins and the ArkLaTex and North Texas regions), Four Corners (including the San Juan, Piceance, Uinta, and Paradox Basins), the Appalachian Basin, Rocky Mountains (including the Denver-Julesberg, Powder River, Wind River, Green River and Williston Basins), and California (the San Joaquin Basin), and internationally in Argentina. During the first quarter of 2007, we were awarded a contract by PEMEX to provide well servicing activities in the Northern region of Mexico.  Operations in Mexico commenced in the second quarter of 2007.  We also provide limited onshore drilling services in the Rocky Mountains, the Appalachian Basin and in Argentina. During 2006 and through the second quarter of 2007, we conducted pressure pumping and cementing operations in a number of major domestic producing basins including California, the Permian Basin, the San Juan Basin, the Mid-Continent region, and in the Barnett Shale of North Texas. Our fishing and rental services are located primarily in the Gulf Coast and Permian Basin regions of Texas, as well as in California and the Mid-Continent region.

Basis of Presentation

The filing of this Quarterly Report on Form 10-Q was delayed due to our restatement and financial reporting process for periods ending December 31, 2003, which began in March 2004. That process was completed on October 19, 2006. Our 2003 Financial and Informational Report on Form 8-K/A, filed with the Securities and Exchange Commission (“SEC”) on October 26, 2006, included an audited 2003 consolidated balance sheet which presented our financial condition as of December 31, 2003 in accordance with Generally Accepted Accounting Principles (“GAAP”). We did not present our other consolidated financial statements in accordance with GAAP as we were unable to determine with sufficient certainty the appropriate period(s) in 2003 or before in which to record certain write offs and write downs that were identified in our restatement process. Our former registered public accounting firm expressed an unqualified opinion that the 2003 balance sheet fairly presented our financial condition on December 31, 2003 in accordance with GAAP. The firm also audited the other financial statements presented in the 2003 Financial and Informational Report. It opined that the financial statements other than the 2003 balance sheet did not fairly present our financial condition or results of operations or cash flows for the periods covered in accordance with GAAP. Investors should refer to the 2003 Financial and Informational Report for a full description of the restatement and financial reporting process for periods prior to 2004.  On August 13, 2007, we filed our Annual Report on Form 10-K for the year ended December 31, 2006, which contained audited financial statements for the years ended December 31, 2004, 2005 and 2006, and our Quarterly Reports on Form 10-Q for 2005 and 2006. Due to the delay in the filing of the Quarterly Report, certain information presented in this report relates to significant events that have occurred subsequent to June 30, 2007.

The accompanying unaudited condensed consolidated financial statements in this report have been prepared in accordance with the instructions for interim financial reporting prescribed by the SEC.  The December 31, 2006 year-end condensed consolidated balance sheet data was derived from audited financial statements but does not include all the disclosures required by GAAP.  These interim financial statements should be read together with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2006.

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The unaudited condensed consolidated financial statements contained in this report include all material adjustments that, in the opinion of management, are necessary for a fair statement of the results of operations for the interim periods presented herein.  The results of operations for the interim periods presented in this report are not necessarily indicative of the results to be expected for the full year or any other interim period due to fluctuations in demand for our services, timing of maintenance and other expenditures, and other factors.

The preparation of these consolidated financial statements requires us to develop estimates and to make assumptions that affect our financial position, results of operations and cash flows. These estimates also impact the nature and extent of our disclosure, if any, of our contingent liabilities. Among other things, we use estimates to (1) analyze assets for possible impairment, (2) determine depreciable lives for our assets, (3) assess future tax exposure and realization of deferred tax assets, (4) determine amounts to accrue for contingencies, (5) value tangible and intangible assets, and (6) assess workers’ compensation, vehicular liability, self-insured risk accruals and other insurance reserves. Our actual results may differ materially from these estimates. We believe that our estimates are reasonable.

Due to the delay in the filing of this report as discussed above, additional information regarding certain liabilities and uncertainties that existed as of the date of this report has become available, either through additional facts about, or the ultimate settlement or resolution of, the liability or uncertainty.  We have taken any additional information that has come to light into account in our estimates and disclosure of any potential liabilities or other contingencies as of the date of this report, in accordance with FASB Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies” (“SFAS 5”).  The discussion of our commitments and contingencies (see Note 6) should be read in conjunction with the corresponding disclosures made in our Annual Report on Form 10-K for the year ended December 31, 2006.

Certain reclassifications have been made to prior period amounts to conform to current period financial statement presentation.  These reclassifications primarily relate to the recasting of prior periods to conform to a realignment of certain positions that were previously reported as a component of direct expenses that are now reported as general and administrative.  These reclassifications had no affect on previously reported net income.  The following tables summarize the effects of these reclassifications on previously reported amounts (in thousands):

We apply the provisions of EITF Issue 04-10, “Determining Whether to Aggregate Operating Segments That Do Not Meet Quantitative Thresholds” (“EITF 04-10”) in our segment reporting in Note 8—“Segment Information.” Our contract drilling operations do not meet the quantitative thresholds as described in Statement of Financial Accounting

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Standards No. 131, “Disclosures About Segments of an Enterprise and Related Information” (“SFAS 131”), and, under the provisions of EITF 04-10, since the operating segments meet the aggregation criteria, we have combined information about this segment with other similar segments that individually do not meet the quantitative thresholds in our Well Servicing reportable segment.

Principles of Consolidation

Within our consolidated financial statements, we include our accounts and the accounts of our majority-owned or controlled subsidiaries. We eliminate intercompany accounts and transactions. We account for our interest in entities for which we do not have significant control or influence under the cost method. When we have an interest in an entity and can exert significant influence but not control, we account for that interest using the equity method. See Note 4—“Investment in IROC Energy Services Corp.”

In determining whether we should consolidate an entity within our financial statements, we apply the provisions of FASB Interpretation No. 46 (as amended), “Consolidation of Variable Interest Entities” (“FIN 46R”). FIN 46R requires that an equity investor in a variable interest entity have significant equity at risk and hold a controlling interest, evidenced by voting rights, and absorb a majority of the entity’s expected losses or receive a majority of the entity’s expected returns, or both. If the equity investor is unable to evidence these characteristics, the entity that retains these ownership characteristics is required to consolidate the variable interest entities created or obtained after March 15, 2004.

Revenue Recognition

Well Servicing Rigs.   Well servicing revenue consists primarily of maintenance services, workover services, completion services and plugging and abandonment services. We recognize revenue when services are performed, collection of the relevant receivable is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. These criteria are typically met at the time we complete a job for a customer. Primarily, we price well servicing rig services by the hour of service performed. Depending on the type of job, we may charge by the project or by the day.

Oilfield Transportation.   Oilfield transportation revenue consists primarily of fluid and equipment transportation services and frac tanks which are used in conjunction with fluid hauling services. We recognize revenue when services are performed, collection of the relevant receivable is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. These criteria are typically met at the time we complete a job for a customer. Primarily, we price oilfield trucking services by the hour or by the quantities hauled.

Pressure Pumping and Fishing and Rental Services.   Pressure pumping and fishing and rental services include well stimulation and cementing services and recovering lost or stuck equipment in the wellbore. We recognize revenue when services are performed, collection of the relevant receivable is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. These criteria are typically met at the time we complete a job for a customer. Generally, we price fishing and rental tool services by the day and pressure pumping services by the job.

Ancillary Oilfield Services.   Ancillary oilfield services include services such as wireline operations, wellsite construction, roustabout services, foam units and air drilling services. We recognize revenue when services are performed, collection of the relevant receivable is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable. These criteria are typically met at the time we complete a job for a customer. We price ancillary oilfield services by the hour, day or project depending on the type of services performed.

Cash and Cash Equivalents

We consider short-term investments with an original maturity of less than three months to be cash equivalents. None of our cash is restricted and we have not entered into any compensating balance arrangements. However, at June 30, 2007, all of our obligations under the Senior Secured Credit Facility (hereinafter defined) were secured by most of our assets, including assets held by our subsidiaries, which includes our cash and cash equivalents. We restrict investment of cash to financial institutions with high credit standing and limit the amount of credit exposure to any one financial institution.

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Investment in Debt and Equity Securities

We account for investments in debt and equity securities under the provisions of Statement of Financial Accounting Standards No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (“SFAS 115”). Under SFAS 115, investments are classified as either “trading,” “available for sale,” or “held to maturity,” depending on management’s intent regarding the investment.

Securities classified as “trading” are carried at fair value on the Company’s Consolidated Balance Sheets, with any unrealized holding gains or losses reported currently in earnings on our Consolidated Statements of Operations. Securities classified as “available for sale” are carried at fair value on the Company’s Consolidated Balance Sheets, with any unrealized holding gains or losses, net of tax, reported as a separate component of shareholders’ equity in Accumulated Other Comprehensive Income.

As of June 30, 2007 and December 31, 2006, the Company had no investments in debt or equity securities that were classified as “trading” or “held to maturity.” In the third quarter of 2006, the Company began investing in Auction-Rate Securities (“ARS”) and Variable-Rate Demand Notes (“VRDN”). These are investments in long-term bonds whose returns are tied to short-term interest rates that are periodically reset, with periods ranging from 7 days to 6 months. As a result of the long-term nature of the underlying security (bonds with contractual lives ranging from 20 to 30 years), the Company accounts for ARS and VRDN investments as “available for sale” securities.  Because the Company can liquidate its position in an ARS or VRDN investment on an interest reset date, and because management does not intend to hold these investments beyond one year, they are classified as current assets in our consolidated balance sheets.

In addition to the ARS and VRDN investments, in the third quarter of 2006 the Company began to invest in 270-day commercial paper and certain other bond investments. These instruments are treated as “available for sale” securities and are carried at fair value as short-term investments on the Company’s Consolidated Balance Sheets, because their maturity dates are within one year of the date of investment. Any unrealized holding gains or losses on these securities are recorded net of tax as a separate component of stockholders’ equity in Accumulated Other Comprehensive Income until the date of maturity, at which point any gains or losses are reclassified into earnings. We use the specific identification method when determining the amount of realized gain or loss upon the date of maturity. The aggregate fair value of our available for sale investments as of June 30, 2007 was approximately $115.0 million.

Inventories

Inventories, which consist primarily of equipment parts for use in our well servicing operations, sand and chemicals for our pressure pumping operations, and supplies held for consumption, are valued at the lower of average cost or market.

Property and Equipment

Asset Retirement Obligations.   In connection with our well servicing activities, we operate a number of Salt Water Disposal (“SWD”) facilities. Our operations involve the transportation, handling and disposal of fluids in our SWD facilities that have been determined to be harmful to the environment. SWD facilities used in connection with our fluid hauling operations are subject to future costs associated with the abandonment of these properties. As a result, we have incurred costs associated with the proper storage and disposal of these materials. In accordance with Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), we recognize a liability for the fair value of all legal obligations associated with the retirement of tangible long-lived assets and capitalize an equal amount as a cost of the asset. We depreciate the additional cost over the estimated useful life of the assets. Significant judgment is involved in estimating future cash flows associated with such obligations, as well as the ultimate timing of those cash flows. If our estimates of the amount or timing of the cash flows change, such changes may have a material impact on our results of operations.  Amortization of the assets associated with the asset retirement obligations was $0.1 million and $0.1 million for the quarters ended June 30, 2007, and 2006, respectively.  Amortization of the assets associated with the asset retirement obligations was $0.3 million and $0.2 million for the six months ended June 30, 2007, and 2006, respectively.

Asset and Investment Impairments.   We apply Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”) in reviewing our long-lived assets and investments for possible impairment. This statement requires that long-lived assets held and used by us, including certain identifiable intangibles, be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. For purposes of applying this statement, we group our long-lived assets on a division-by-division basis and compare the estimated future cash flows of each division to the division’s net carrying value. The division level represents the lowest level for which identifiable cash flows are available. We would record an impairment charge,

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reducing the division’s net carrying value to an estimated fair value, if its estimated future cash flows were less than the division’s net carrying value. “Trigger events,” as defined in SFAS 144, that cause us to evaluate our fixed assets for recoverability and possible impairment may include market conditions, such as adverse changes in the prices of oil and natural gas, which could reduce the fair value of certain of our property and equipment. The development of future cash flows and the determination of fair value for a division involves significant judgment and estimates. As of June 30, 2007 and December 31, 2006, no trigger events had been identified by management.

Change in Useful Lives.   In the first quarter of 2007, management reassessed the estimated useful lives assigned to all of its equipment due to the higher activity and utilization levels experienced under recent market conditions. As a result, the maximum estimated useful lives of certain assets were adjusted to reflect higher utilization. Included in this change is a reduction in the useful life expected for a well service rig, which was reduced from an average expected life of 17 years to 15 years. Management also determined that the life assigned to a self-remanufactured well service rig should be the same as the 15-year life assigned to a well service rig acquired from third parties.

The following table identifies the impact of this change in depreciation and amortization expense for the three and six months ended June 30, 2007 (in thousands):

As a result of the change, the estimated useful lives of the Company’s asset classes are as follows:

Goodwill and Other Intangible Assets

Goodwill results from business acquisitions and represents the excess of acquisition costs over the fair value of the net assets acquired. We account for goodwill and other intangible assets under the provisions of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). SFAS 142 eliminates amortization for goodwill and other intangible assets with indefinite lives. Intangible assets with lives restricted by contractual, legal, or other means will continue to be amortized over their expected useful lives. Goodwill and other intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. SFAS 142 requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. If impairment is indicated, then the fair value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination. The amount of impairment for goodwill is measured as the excess of its carrying value over its fair value. We conduct annual impairment assessments, the most recent affecting this report as of December 31, 2006. The assessments did not result in an indication of goodwill impairment.

Our intangible assets subject to amortization under SFAS 142 consist of noncompete agreements and patents and trademarks. Amortization expense for noncompete agreements is calculated using the straight-line method over the period of

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the agreement, ranging from three to seven years. The cost and accumulated amortization are retired when the noncompete agreement is fully amortized and no longer enforceable. Amortization expense for patents and trademarks is calculated using the straight-line method over the useful life of the patent or trademark, ranging from five to seven years.  Amortization of noncompete agreements for the quarters ended June 30, 2007 and 2006 was $0.3 million and $0.6 million, respectively.  Amortization of patents and trademarks for the quarters ended June 30, 2007 and 2006 was $0.2 million and $0.1 million, respectively.  Amortization of noncompete agreements for the six months ended June 30, 2007 and 2006 was $0.8 million and $1.2 million, respectively.  Amortization of patents and trademarks for the six months ended June 30, 2007 and 2006 was $0.4 million and $0.3 million, respectively.  During the six months ended June 30, 2007, the Company capitalized approximately $0.3 million of costs associated with patents and trademarks.  No costs associated with noncompete agreements were capitalized during the six months ended June 30, 2007.

Derivative Instruments and Hedging Activities

The Company applies Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”) as amended by Statement of Financial Accounting Standards No. 137, No. 138 and No. 149 (“SFAS 137,” “SFAS 138,” and “SFAS 149,” respectively; collectively, “SFAS 133, as amended”) in accounting for derivative instruments. SFAS 133, as amended establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. It requires the recognition of all derivative instruments as assets and liabilities on the balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge, and if so, the type of hedge. For derivatives designated as cash flow hedges, the effective portion of the change in the fair value of the hedging instrument is recognized in other comprehensive income until the hedged item is recognized in earnings. Any ineffective portion of changes in the fair value of the hedging instrument is recognized currently in earnings.

To account for a financial instrument as a hedge, the contract must meet the following criteria: the underlying asset or liability must expose the Company to risk that is not offset in another asset or liability, the hedging contract must reduce that risk, and the instrument must be properly designated as a hedge at the inception of the contract and throughout the contract period. To be an effective hedge, there must be a high correlation between changes in the fair value of the financial instrument and the fair value of the underlying asset or liability, such that changes in the market value of the financial instrument and the anticipated future cash flows would be offset by the effect of price changes on the exposed items.

In March 2006, under the terms of our Senior Secured Credit Facility, the Company was required to mitigate the risk of changes in future cash flows posed by changes in interest rates associated with the variable-rate interest term loan portion of our Senior Secured Credit Facility. We entered into two interest rate swap arrangements in order to offset this risk. The swaps are classified as derivative instruments and were designated at inception as cash flow hedges. Management believes that these instruments were highly effective at inception to offset changes in the future cash flows of the underlying liabilities and will continue to be highly effective throughout the life of the hedge. See Note 3—“Derivative Financial Instruments” for further discussion.

Earnings Per Share

We present earnings per share information in accordance with the provisions of Statement of Financial Accounting Standards No. 128, “Earnings Per Share” (“SFAS 128”). Under SFAS 128, basic earnings per common share is determined by dividing net earnings applicable to common stock by the weighted average number of common shares actually outstanding during the period. Diluted earnings per common share is based on the increased number of shares that would be outstanding assuming conversion of dilutive outstanding convertible securities using the “as if converted” method.

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The diluted earnings per share calculation for the quarters ended June 30, 2007 and 2006 excludes the potential exercise of 20,000 and zero stock options, respectively, because the effects of such exercises on earnings per share in those periods would be anti-dilutive.  The diluted earnings per share calculation for the six months ended June 30, 2007 and 2006 excludes the potential exercise of 19,000 and zero stock options, respectively, because the effects of such exercises on earnings per share in those periods would be anti-dilutive.

Stock-Based Compensation

We account for stock-based compensation under the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123(R)”), which we adopted on January 1, 2006. Prior to January 1, 2006, we accounted for share-based payments under the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”), which was permitted by Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”). We adopted the provisions of SFAS 123(R) using the modified prospective transition method.

Beginning in June 2005 we began making grants of restricted shares of common stock to certain of our employees and non-employee directors.  These shares have vesting periods ranging from zero to three years. Subject to the provisions of SFAS 123(R), the Company recognizes expense in earnings equal to the fair value of the shares vesting during the period, net of actual and estimated forfeitures.

In December 2006, the Company began granting “Phantom Shares” to certain of its employees, which vest ratably over a four-year period from the date of grant.  The Phantom Shares convey the right to the grantee to receive a cash payment on each anniversary date of the grant equal to the fair market value of the Phantom Shares vesting on that date.  Grantees are not permitted to defer the payout to a later date.  The Phantom Shares qualify as a “liability” type award under SFAS 123(R); as such, the Company accounts for the Phantom Shares at fair value, with an offsetting liability recorded on our Consolidated Balance Sheets.  Changes in the fair value of the liability, net of estimated and actual forfeitures, are recorded currently in earnings as compensation expense.

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Foreign Currency Gains and Losses

The local currency is the functional currency for our foreign operations in Argentina and Mexico. The cumulative translation gains and losses, resulting from translating each foreign subsidiary’s financial statements from the functional currency to U.S. dollars, are included as a separate component of stockholders’ equity in other comprehensive income until a partial or complete sale or liquidation of our net investment in the foreign entity.

New Accounting Pronouncements

FIN No. 48 and FSP FIN 48-1. On July 12, 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109” (“FIN 48”), which provides clarification of SFAS 109, “Accounting for Income Taxes” with respect to the recognition of income tax benefits of uncertain tax positions in the financial statements. FIN 48 requires that uncertain tax positions be reviewed and assessed, with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard.

In May 2007, the FASB issued FASB Staff Position No. FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48” (“FSP FIN 48-1”).  FSP FIN 48-1 provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits.  In determining whether a tax position has been effectively settled, entities must evaluate (i) whether taxing authorities have completed their examination procedures; (ii) whether the entity intends to appeal or litigate any aspect of a tax position included in a completed evaluation; and (iii) whether it is remote that a taxing authority would examine or re-examine any aspect of a taxing position.  FSP FIN 48-1 is to be applied upon the initial adoption of FIN 48.

We adopted the provisions of FIN 48 and FSP FIN 48-1 on January 1, 2007 and recorded a $1.3 million decrease to the balance of our retained earnings as of January 1, 2007 to reflect the cumulative effect of adopting these standards.  See Note 2—“Income Taxes” for further discussion of the impact of the adoption of these standards.

FSP EITF 00-19-2.     In December 2006, the FASB issued FASB Staff Position No. EITF 00-19-2, “Accounting for Registration Payment Arrangements” (“FSP EITF 00-19-2”). FSP EITF 00-19-2 addresses accounting for Registration Payment Arrangements (“RPAs”), which are provisions within financial instruments such as equity shares, warrants or debt instruments in which the issuer agrees to file a registration statement and to have that registration statement declared effective by the SEC within a specified grace period. If the registration statement is not declared effective within the grace period or its effectiveness is not maintained for the period of time specified in the RPA, the issuer must compensate its counterparty. The FASB Staff concluded that the contingent obligation to make future payments or otherwise transfer consideration under a RPA should be recognized as a liability and measured in accordance with SFAS 5 and FASB Interpretation No. 14, “Reasonable Estimation of the Amount of a Loss,” and that the RPA should be recognized and measured separately from the instrument to which the RPA is attached.

In January 1999, the Company completed the private placement of 150,000 units (the “Units”) consisting of $150.0 million of 14% Senior Subordinated Notes due January 25, 2009 (the “14% Senior Subordinated Notes”) and 150,000 warrants to purchase an aggregate of approximately 2.2 million shares of the Company’s common stock at an exercise price of $4.88125 per share (the “Warrants”). As of June 30, 2007, 63,500 Warrants had been exercised, leaving 86,500 Warrants outstanding that were exercisable for an aggregate of approximately 1.3 million shares.

Under the terms of the Warrants, we are required to maintain an effective registration statement covering the shares of common stock issuable upon exercise. If we are unable to maintain an effective registration statement, we are required to make semiannual liquidated damages payments for periods in which an effective registration statement is not maintained. Due to our failure to file our SEC reports in a timely manner, we have been unable to maintain an effective registration statement covering the Warrants. The requirement to make liquidated damages payments under the terms of the Warrant agreement constitutes a RPA under the provisions of FSP EITF 00-19-2. As prescribed by the transition provisions of FSP EITF 00-19-2, on January 1, 2007, the Company recorded a current liability of approximately $1.0 million on its balance sheet, which is equivalent to the payments for the Warrant RPA for one year, and we recorded an offsetting adjustment to the opening balance of retained earnings.  This amount represents the low end of a range of possible outcomes. If we continue to be unable to maintain an effective registration statement with the SEC, the total amount of liquidated damages payable under the Warrant RPA during 2007 could be as high as $1.4 million. Any subsequent changes in the carrying value of the RPA liability will be recorded in earnings as other income and expense.

SFAS 157.   In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 establishes a framework for measuring fair value and requires expanded disclosure about the information used to measure fair value. The statement applies whenever other statements require or permit assets or

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liabilities to be measured at fair value. SFAS 157 does not expand the use of fair value accounting in any new circumstances and is effective for the Company for the year ended December 31, 2008 and for interim periods included in that year, with early adoption encouraged. The Company is evaluating the effect of adoption of SFAS 157 on its financial position, results of operations and cash flows.

SFAS 158.   In September 2006, the FASB issued Statement of Financial Accounting Standards No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 123(R)” (“SFAS 158”). SFAS 158 requires an entity that is the sponsor of a plan within the scope of the statement to (a) recognize on its balance sheet as an asset a plan’s over-funded status or as a liability such plan’s under-funded status; (b) measure a plan’s assets and obligations as of the end of the entity’s fiscal year; and (c) recognize changes in the funded status of its plans in the year in which changes occur through adjustments to other comprehensive income. We adopted the provisions of this standard on December 31, 2006. Because the Company is not a sponsor of a defined postretirement benefit plan as defined by SFAS 158, the adoption of this standard did not have a material impact on the Company’s financial position, results of operations, or cash flows.

FSP AUG AIR-1.   In September 2006, the FASB issued FASB Staff Position No. AUG AIR-1 (“FSP AUG AIR-1”), which addresses the accounting for planned major maintenance activities. FSP AUG AIR-1 prohibits the use of the “accrue-in-advance” method of accounting for planned major maintenance activities in annual and interim financial reporting periods. We adopted FSP AUG AIR-1 on January 1, 2007.  The adoption of this standard did not materially impact our financial position, results of operations, or cash flows.

SFAS 159.   In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Liabilities, including an amendment of FASB Statement No. 115” (“SFAS 159”). SFAS 159 permits companies to choose, at specified election dates, to measure eligible items at fair value (the “Fair Value Option”). Companies choosing such an election would report unrealized gains and losses on items for which the Fair Value Option has been elected in earnings at each subsequent reporting period. This standard is effective as of the beginning of the first fiscal year that begins after November 15, 2007. The adoption of this standard is not anticipated to have a material impact on our financial position, results of operations, or cash flows.

2.                                       INCOME TAXES

The Company’s effective tax rate for the six months ended June 30, 2007 and 2006 was 38.5% and 38.0%, respectively.  The primary difference between the statutory rate of 35% and our effective tax rate relates to state taxes, which increased during 2007 primarily due to the new Texas Margins Tax, which took effect on January 1, 2007.

FIN No. 48 and FSP FIN 48-1. On July 12, 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109” (“FIN 48”), which provides clarification of SFAS 109, “Accounting for Income Taxes” with respect to the recognition of income tax benefits of uncertain tax positions in the financial statements. FIN 48 requires that uncertain tax positions be reviewed and assessed, with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard.

In May 2007, the FASB issued FASB Staff Position No. FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48” (“FSP FIN 48-1”).  FSP FIN 48-1 provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits.  In determining whether a tax position has been effectively settled, entities must evaluate (i) whether taxing authorities have completed their examination procedures; (ii) whether the entity intends to appeal or litigate any aspect of a tax position included in a completed evaluation; and (iii) whether it is remote that a taxing authority would examine or re-examine any aspect of a taxing position.  FSP FIN 48-1 is to be applied upon the initial adoption of FIN 48.

We adopted the provisions of FIN 48 and FSP FIN 48-1 on January 1, 2007 and recorded a $1.3 million decrease to the balance of our retained earnings as of January 1, 2007 to reflect the cumulative effect of adopting these standards.  As of January 1, 2007, we had approximately $3.9 million of unrecognized tax benefits, which, if recognized, would impact our effective tax rate. We are subject to U.S. Federal Income Tax as well as income taxes in multiple state jurisdictions.  We have substantially concluded all U.S. federal and state income tax matters through the year ended December 31, 2002.

We recognize accrued interest expense and penalties related to unrecognized tax benefits as income tax expense.  We have accrued approximately $1.3 million and $1.0 million for the payment of interest and penalties as of June 30, 2007 and January 1, 2007, respectively.  We do not expect any substantial changes within the next 12 months related to uncertain tax positions.

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3.                                       DERIVATIVE FINANCIAL INSTRUMENTS

We are exposed to risks due to potential changes in interest rates associated with the variable-rate interest term loan of our Senior Secured Credit Facility. As of June 30, 2007, our variable-rate interest debt instruments comprised 100% of our total debt, excluding our capital lease obligations. Based on this exposure, and because of provisions contained in our Senior Secured Credit Facility, on March 10, 2006 we entered into two $100.0 million notional amount interest rate swaps to effectively fix the interest rate on a portion of our variable-rate debt. These swaps meet the criteria of derivative instruments.

We account for derivative instruments using the guidance provided by SFAS 133, as amended. SFAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. It requires the recognition of all derivative instruments as assets and liabilities on the balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge, and if so, the type of hedge. For derivatives designated as cash flow hedges, the effective portion of a change in the fair value of the hedging instrument is recognized in other comprehensive income until the settlement of the forecasted hedged transaction. Any ineffective portion of changes in the fair value of the hedging instrument is recognized currently in earnings.

The Company uses a historic simulation based on regression analysis to assess the effectiveness of the swaps as a hedge of the future cash flows of the forecasted transaction, both on a historical and prospective basis. The simulation regresses the monthly changes in the cash flows associated with the hedging instrument and the hedged item. The results of the regression indicated that the swaps were highly effective in offsetting the future cash flows of the items being hedged and could be reasonably assumed to be highly effective on an ongoing basis. Based on the results of this analysis and the Company’s intent to use the instruments to reduce exposure to changes in future cash flows attributable to interest payments, the Company elected to account for the swaps as cash flow hedges.

The measurement of hedge ineffectiveness is based on a comparison of the cumulative change in the fair value of the actual swap designated as the hedging instrument and the cumulative change in fair value of a perfectly effective hypothetical derivative (“Perfect Hypothetical Derivative”) (as defined in Derivatives Implementation Group Issue G7). The perfectly effective hypothetical swap mimics the terms of the debt with a fixed interest rate assumed to be the same as the hedge instrument. This method of measuring ineffectiveness is known as the “Hypothetical Derivative Method.” Under this method, the actual swap is recorded at fair value on the Company’s Consolidated Balance Sheets and Accumulated Other Comprehensive Income is adjusted to a balance that reflects the lesser of either the cumulative change in the fair value of the actual swap or the cumulative change in the fair value of the Perfect Hypothetical Derivative. The amount of ineffectiveness, if any, is equal to the excess of the cumulative change in the fair value of the actual swap over the cumulative change in the fair value of the Perfect Hypothetical Derivative, and is recorded currently in earnings as a component of other income and expense on the Company’s Consolidated Statements of Income.

As of June 30, 2007, we recorded $0.3 million in current assets and $0.2 million in long-term assets in our Consolidated Balance Sheets, based on the fair value of our derivative instruments on that date. During the six months ended June 30, 2007, amounts recorded related to the ineffective portion of our cash flow hedges were less than $0.1 million. No amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows in any of the periods.  During the three and six months ended June 30, 2007, no amounts were reclassified to earnings in connection with forecasted transactions whose occurrence was no longer considered probable.

4.                                       INVESTMENT IN IROC ENERGY SERVICES CORP.

As of June 30, 2007 and December 31, 2006, we owned 8,734,469 shares of   IROC Energy Services Corp., formerly known as IROC Systems Corp. (“IROC”), an Alberta-based oilfield services company. This represented approximately 19.7% and 23.0% of IROC’s outstanding common stock on June 30, 2007 and December 31, 2006, respectively. IROC shares trade on the Toronto Venture Stock Exchange and had a closing price of $1.98 and $2.10 CDN per share on June 30, 2007 and December 31, 2006, respectively.  Mr. William Austin, our Chief Financial Officer, and Mr. Newton W. Wilson III, our General Counsel, serve on the board of directors of IROC.

We have significant influence over the operations of IROC through our ownership interest and representation on IROCs board of directors, but do not control it.  We account for our investment in IROC using the equity method.  Our ownership interest percentage in IROC declined as a result of IROC issuing additional common stock during the six months ended June 30, 2007. Our investment in IROC totaled $10.9 million and $10.7 million as of June 30, 2007 and December 31,

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2006, respectively, and is recorded in our Condensed Consolidated Balance Sheets as a component of other non-current assets.  The pro-rata share of IROC’s earnings and losses to which we are entitled are recorded in our Condensed Consolidated Statements of Operations as a component of other income and expense, with an offsetting increase or decrease to the value of our investment, as appropriate.  Any earnings distributed back to us from IROC in the form of dividends would result in a decrease in the value of our equity investment.

We recorded $0.2 million of income and $0.2 million of loss, respectively, related to our investment in IROC for the six months ended June 30, 2007 and 2006.  During those time periods, no earnings were distributed back to us by IROC in the form of dividends.

Senior Secured Credit Facility

On July 29, 2005, we entered into a Credit Agreement (the “Senior Secured Credit Facility”). The Senior Secured Credit Facility consists of (i) a revolving credit facility of up to an aggregate principal amount of $65.0 million, which will mature on July 29, 2010, (ii) a senior term loan facility in the original aggregate amount of $400.0 million, which will mature on June 30, 2012, and (iii) a prefunded letter of credit facility in the aggregate amount of $82.3 million, which will mature on July 29, 2010. The revolving credit facility includes a $25.0 million sub-facility for additional letters of credit. The proceeds from the term loan facility, along with cash on hand were used to refinance our then-existing 8.375% Senior Notes and our then-existing 6.375% Senior Notes. The revolving credit facility may be used for general corporate purposes.

Borrowings under the Senior Secured Credit Facility through December 31, 2005 bore interest upon the outstanding principal balance, at the Company’s option, at the prime rate plus a margin of 1.75% or a Eurodollar rate plus a margin of 2.75%. These margins were increased on December 31, 2005 by 0.50% and again on March 31, 2006 by 0.50% because the Company did not meet certain filing targets for our 2003 Annual Report on Form 10-K. We were also required to pay certain fees in connection with the credit facilities, including a commitment fee as a percentage of aggregate commitments.

The Senior Secured Credit Facility contains certain covenants, which, among other things, require us to maintain a consolidated leverage ratio (defined generally as the ratio of consolidated total debt to consolidated EBITDA) as follows:

The Senior Secured Credit Facility also requires that we maintain a consolidated interest coverage ratio (defined generally as the ratio of consolidated EBITDA to consolidated interest expense) as of the last day of any fiscal quarter, beginning with the fourth fiscal quarter of 2005, of not less than 3.0 to 1.0. Upon the occurrence of certain events of default, such as payment default, our obligations under the Senior Secured Credit Facility may be accelerated.

All obligations under the Senior Secured Credit Facility are guaranteed by most of our subsidiaries and are secured by most of our assets, including our accounts receivable, inventory and equipment.

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First Amendment to Senior Secured Credit Facility

On November 3, 2005, we amended the Senior Secured Credit Facility (the “First Amendment”) to increase the amount of capital expenditures allowed under the facility during 2005 and 2006. Under the terms of the First Amendment, we were allowed to make annual capital expenditures of $175.0 million for 2005 and $200.0 million for 2006. Additionally, under certain conditions, up to $25.0 million of the capital expenditure limit, if not spent in the permitted fiscal year, could be carried over for expenditures in the next succeeding fiscal year. Previously under the Senior Secured Credit Facility, we were limited to annual capital expenditures of $150.0 million.

Second Amendment to Senior Secured Credit Facility

On November 21, 2006, we again amended the Senior Secured Credit Facility (the “Second Amendment”) to (i) allow the Company until July 31, 2007 to file its 2006 Annual Report on Form 10-K, quarterly reports for 2005 and 2006, and quarterly reports for 2007 that were then due, and to waive any defaults due to the failure to file compliant SEC reports for prior periods; (ii) reduce the Eurodollar interest rate spread from 3.75% to 2.50% and commitment fees from 0.50% to 0.375%; (iii) increase the limitation on annual capital expenditures through 2009 to $225.0 million; (iv) increase the permitted stock repurchase basket from $50.0 million to $250.0 million and permit repurchases before the Company has made all required SEC filings; (v) increase the permitted acquisitions basket from $50.0 million to $100.0 million; and (vi) eliminate the provision requiring the Company to prepay the term loan with excess cash flow. We paid a total of $0.5 million in fees and other expenses in connection with the Second Amendment.

As of June 30, 2007, the Company had no borrowings under the revolving credit facility of the Senior Secured Credit Facility and had $394.0 million borrowed at three-month Eurodollar rates, plus a margin of 2.50%. As described above, the Company has interest rate swaps that hedge a portion of the interest rate expense on the term loan.

On July 27, 2007, we entered into a third amendment with respect to the Senior Secured Credit Facility.  See Note 9—“Subsequent Events,” for a discussion of the third amendment.

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