Edgar Filing: KEY ENERGY SERVICES INC

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)
x		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the Quarterly Period Ended June 30, 2007

		or

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 1-8038

KEY ENERGY SERVICES, INC.

(Exact Name of Registrant as Specified in Its Charter)

Maryland		04-2648081
(State or Other Jurisdiction of		(I.R.S. Employer
Incorporation or Organization)		Identification No.)

1301 McKinney Street, Suite 1800, Houston, Texas 77010

(Address of Principal Executive Offices) (Zip Code)

713/651-4300

(Registrant’s Telephone Number, Including Area Code)

None

(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x

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

Large Accelerated Filer x

Accelerated Filer o

Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes o

As of August 31, 2007, the number of outstanding shares of common stock of the Registrant was 131,890,373.

KEY ENERGY SERVICES, INC.

INDEX TO FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2007

Part I — Financial Information
Note Regarding Our Financial Reporting Process
Item 1.	Unaudited Condensed Consolidated Financial Statements
	Unaudited Condensed Consolidated Balance Sheets as of June 30, 2007 and December 31, 2006
	Unaudited Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2007 and 2006
	Unaudited Condensed Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2007 and 2006
	Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2007 and 2006
	Notes to Condensed Consolidated Unaudited Financial Statements
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.	Quantitative and Qualitative Disclosures About Market Risks
Item 4.	Controls and Procedures

Part II — Other Information

Item 1.	Legal Proceedings
Item 1A.	Risk Factors
Item 2.	Unregistered Sales Of Equity Securities And Use Of Proceeds
Item 3.	Defaults Upon Senior Securities
Item 4.	Submission Of Matters To A Vote Of Security Holders
Item 5.	Other Information
Item 6.	Exhibits

FORWARD-LOOKING STATEMENTS

In addition to statements of historical fact, this report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Statements that are not historical in nature or that relate to future events and conditions are, or may be deemed to be, forward-looking statements. These “forward-looking statements” are based on our current expectations, estimates and projections about the Company, our industry and management’s beliefs and assumptions concerning future events and financial trends affecting our financial condition and results of operations. In some cases, you can identify these statements by terminology such as “may,” “will,” “predicts,” “projects,” “potential” or “continue” or the negative of such terms and other comparable terminology. These statements are only predictions and are subject to substantial risks and uncertainties. Actual performance or results may differ materially and adversely.

We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date of this report except as required by law. All of our written and oral forward-looking statements are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements. The reasons for these differences include changes that occur in our business environment as well as differences stemming from the delay in our financial reports, such as the following factors:

· Possible adverse consequences of failure to file past SEC reports;

· Limitations on access to public capital markets;

· Inability of common stock to trade on a recognized exchange and potential inability to re-list on a recognized exchange;

· Impact of material weaknesses in internal control over financial reporting;

· Potential changes in tax liabilities; and

· Civil litigation.

PART I — FINANCIAL INFORMATION

NOTE REGARDING OUR FINANCIAL REPORTING PROCESS

This report has been 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 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. 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. Investors are strongly cautioned not to rely on any of the financial statements contained in the 2003 Financial and Informational Report, other than the 2003 balance sheet, as fairly presenting, for the periods covered, our financial condition or our results of operations or cash flows, in accordance with GAAP. Any information set forth in the 2003 Financial and Informational Report that incorporates or discusses information contained in the financial statements is subject to the same caution. You also should not rely on any of our previously-filed Annual Reports on Form 10-K or Quarterly Reports on Form 10-Q for the periods that ended prior to and including September 30, 2003.

We have completed our financial statements for the years ended December 31, 2004, 2005 and 2006. On August 13, 2007, we filed our Annual Report on Form 10-K for the year ended December 31, 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.

Item 1. CONDESNSED CONSOLIDATED UNAUDITED FINANCIAL STATEMENTS

Key Energy Services, Inc.

Condensed Consolidated Balance Sheets

(In thousands)

	June 30,			December 31,
	2007			2006
	(Unaudited)
*ASSETS*
Current assets:
Cash and cash equivalents	$	60,087		$	88,375
Marketable securities	114,975			61,767
Accounts receivable, net of allowance for doubtful accounts of $14,035 and $12,998 at June 30, 2007 and December 31, 2006, respectively	287,941			272,382
Inventories	21,192			19,505
Prepaid expenses	7,395			4,810
Deferred tax assets	36,220			35,968
Other current assets	6,625			5,799

Total current assets	534,435			488,606

Property, plant and equipment	1,397,748			1,279,980
Accumulated depreciation	(639,493		)	(585,689		)

Net property, plant and equipment	758,255			694,291

Goodwill	320,905			320,912
Deferred costs, net	9,094			9,952
Notes and accounts receivable - related parties	182			287
Other assets	26,379			27,350

TOTAL ASSETS	$	1,649,250		$	1,541,398

*LIABILITIES AND STOCKHOLDERS’ EQUITY*
Current liabilities:
Accounts payable	$	17,883		$	15,294
Accrued severance	458			631
Other accrued liabilities	190,618			188,939
Accrued interest	4,970			2,530
Current portion of capital lease obligations	10,627			11,714
Current portion of long-term debt	4,000			4,000

Total current liabilities	228,556			223,108

Capital lease obligations, less current portion	14,435			14,080
Long-term debt, less current portion	390,000			392,000
Workers’ compensation, vehicular, health and other insurance claims	40,884			44,617
Deferred tax liability	121,798			115,826
Other non-current accrued expenses	21,889			21,256

Commitments and contingencies	—			—

Stockholders’ equity:
Common stock, $0.10 par value; 200,000,000 shares authorized, 131,593,695 and 131,624,038 shares issued and outstanding at June 30, 2007 and December 31, 2006, respectively	13,213			13,212
Additional paid-in capital	726,200			722,610
Treasury stock, at cost; 533,466 and 497,501 shares at June 30, 2007 and December 31, 2006, respectively	(11,564		)	(10,862		)
Accumulated other comprehensive loss	(36,415		)	(36,284		)
Retained earnings	140,254			41,835

Total stockholders’ equity	831,688			730,511
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,649,250		$	1,541,398

See the accompanying notes which are an integral part of these condensed consolidated unaudited financial statements

Key Energy Services, Inc.

Condensed Consolidated Statements of Operations

(In thousands, except per share data)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006

*REVENUES:*
Well servicing	$	308,825		$	288,392		$	619,985		$	561,307
Pressure pumping	77,289			60,199			151,366			111,997
Fishing and rental services	24,397			23,445			48,079			46,689

Total revenues	410,511			372,036			819,430			719,993

*COSTS AND EXPENSES:*
Well servicing	177,304			173,449			352,832			350,514
Pressure pumping	47,410			33,032			93,943			60,459
Fishing and rental services	13,509			13,580			26,960			27,708
Depreciation and amortization	30,684			28,924			60,298			55,738
General and administrative	56,154			49,285			108,217			98,418
Interest expense	8,968			10,030			18,317			18,608
Gain on sale of assets, net	(703		)	(309		)	(453		)	(2,244		)
Interest income	(1,798		)	(828		)	(3,737		)	(2,028		)
Other, net	512			953			(112		)	472

Total costs and expenses, net	332,040			308,116			656,265			607,645

Income before income taxes	78,471			63,920			163,165			112,348
Income tax expense	(30,335		)	(24,338		)	(62,838		)	(42,704		)

*NET INCOME*	$	48,136		$	39,582		$	100,327		$	69,644

*EARNINGS PER SHARE:*
Basic	$	0.37		$	0.30		$	0.76		$	0.53
Diluted	$	0.36		$	0.29		$	0.75		$	0.52

*WEIGHTED AVERAGE SHARES OUTSTANDING:*
Basic	131,627			131,335			131,628			131,337
Diluted	134,140			134,979			134,028			134,752

See the accompanying notes which are an integral part of these condensed consolidated unaudited financial statements

Key Energy Services, Inc.

Condensed Consolidated Statement of Comprehensive Income

(In thousands)

(Unaudited)

	Three Months Ended June 30,					Six Months Ended June 30,
	2007			2006		2007			2006

*NET INCOME*	$	48,136		$	39,582	$	100,327		$	69,644
*OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:*
Foreign currency translation gain (loss)	160			176		—			(102		)
Deferred gain from cash flow hedges	198			1,171		75			1,094
Deferred loss from available for sale securities	(8		)	—		(206		)	—
*COMPREHENSIVE INCOME, NET OF TAX*	$	48,486		$	40,929	$	100,196		$	70,636

See the accompanying notes which are an integral part of these condensed consolidated unaudited financial statements

Key Energy Services, Inc.

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

	Six Months Ended June 30,
	2007			2006

*CASH FLOWS FROM OPERATING ACTIVITIES:*

Net income	$	100,327		$	69,644

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	60,298			55,738
Accretion expense	262			252
(Income) loss from equity investment	(243		)	161
Amortization of deferred debt issuance costs	858			803
Deferred income tax expense	5,720			3,888
Capitalized interest	(1,998		)	(1,615		)
Gain on sale of assets	(453		)	(2,244		)
Stock-based compensation	5,633			3,424

Changes in working capital:
Accounts receivable	(15,745		)	(29,543		)
Other current assets	(5,156		)	2,247
Accounts payable, accrued interest and accrued expenses	4,119			32,794

Other assets and liabilities	(4,982		)	(17,545		)

Net cash provided by operating activities	148,640			118,004

*CASH FLOWS FROM INVESTING ACTIVITIES:*

Capital expenditures - Well Servicing	(67,674		)	(74,385		)
Capital expenditures - Pressure Pumping	(35,794		)	(18,530		)
Capital expenditures - Fishing and Rental	(10,919		)	(4,755		)
Capital expenditures - Other	(4,458		)	(521		)
Proceeds from sale of fixed assets	2,826			9,651
Investment in available for sale securities	(85,147		)	—
Proceeds from the sale of available for sale securities	31,900			—

Net cash used in investing activities	(169,266		)	(88,540		)

*CASH FLOWS FROM FINANCING ACTIVITIES:*

Repayment of long-term debt	(2,000		)	(2,000		)
Repayments under capital lease obligations	(5,357		)	(6,286		)
Purchase of Treasury Stock	—			(1,180		)

Net cash used in financing activities	(7,357		)	(9,466		)

Effect of exchange rates on cash	(305		)	(399		)

Net (decrease) increase in cash and cash equivalents	(28,288		)	19,599
Cash and cash equivalents, beginning of period	88,375			94,170
Cash and cash equivalents, end of period	$	60,087		$	113,769

See the accompanying notes which are an integral part of these condensed consolidated unaudited financial statements

Key Energy Services, Inc.

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.

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):

	Three Months Ended June 30, 2006
	Amounts as Previously Reported		Effect of Reclassifications			Amounts as Currently Reported

Well servicing costs	$	177,172	$	(3,723	)	$	173,449
Pressure pumping costs	34,020		(988		)	33,032
Fishing and rental costs	14,415		(835		)	13,580
General and administrative	43,739		5,546			49,285
Total	$	269,346	$	—		$	269,346

	Six Months Ended June 30, 2006
	Amounts as Previously Reported		Effect of Reclassifications			Amounts as Currently Reported

Well servicing costs	$	357,928	$	(7,414	)	$	350,514
Pressure pumping costs	62,589		(2,130		)	60,459
Fishing and rental costs	29,502		(1,794		)	27,708
General and administrative	87,080		11,338			98,418
Total	$	537,099	$	—		$	537,099

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

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.

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,

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):

	Three Months Ended June 30, 2007			Six Months Ended June 30, 2007
Depreciation and amortization expense using prior lives	$	28,737		$	56,186
Impact of change	1,947			4,112
Depreciation and amortization expense, as reported	$	30,684		$	60,298

Diluted earnings per share using prior lives	$	0.37		$	0.77
Impact of change on diluted earnings per share	(0.01		)	(0.02		)
Diluted earnings per share, as reported	$	0.36		$	0.75

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

Description		Years
Well service rigs and components		3 - 15
Oilfield trucks, trailers and related equipment		7 - 12
Motor vehicles		3 - 5
Fishing and rental tools		4 - 10
Disposal wells		15 - 30
Furniture and equipment		3 - 7
Buildings and improvements		15 - 30

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

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.

	Three Months Ended June 30,				Six Months Ended June 30,
	2007		2006		2007		2006
	(in thousands, except per share data)

Basic EPS Computation:
Numerator
Net income	$	48,136	$	39,582	$	100,327	$	69,644

Denominator
Weighted average shares outstanding	131,627		131,335		131,628		131,337

Basic earnings per share	$	0.37	$	0.30	$	0.76	$	0.53


Diluted EPS Computation:
Numerator
Net income	$	48,136	$	39,582	$	100,327	$	69,644

Denominator
Weighted average shares outstanding	131,627		131,335		131,628		131,337
Stock options	1,912		3,072		1,815		2,853
Warrants	601		572		585		562
	134,140		134,979		134,028		134,752

Diluted earnings per share	$	0.36	$	0.29	$	0.75	$	0.52

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.

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

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.

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.

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,

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.

5. LONG-TERM DEBT

The components of our long-term debt are as follows:

	June 30, 2007			December 31, 2006
	(in thousands)
Senior Credit Facility Term Loans	$	394,000		$	396,000
Capital lease obligations	25,062			25,794
	419,062			421,794
Less: current portion	(14,627		)	(15,714		)
Total long-term debt	$	404,435		$	406,080

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:

Fiscal Quarter		Consolidated Leverage Ratio
Fourth Fiscal Quarter, 2005		3.5 : 1.0
First Fiscal Quarter, 2006		3.0 : 1.0
Second Fiscal Quarter, 2006		3.0 : 1.0
Third Fiscal Quarter, 2006 and thereafter		2.75 : 1.0

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.

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.

Interest Expense

Interest expense for the three and six months ended June 30, 2007 and 2006 consisted of the following:

	Three Months Ended June 30,
	2007			2006
	(in thousands)
Cash payments	$	8,199		$	7,801
Commitment and agency fees paid	704			1,532
Amortization of debt issuance costs	430			402
Net change in accrued interest	789			1,172
Capitalized interest	(1,154		)	(877		)
Total interest expense	$	8,968		$	10,030

	Six Months Ended June 30,
	2007			2006
	(in thousands)
Cash payments	$	15,035		$	16,065
Commitment and agency fees paid	1,982			2,243
Amortization of debt issuance costs	858			803
Net change in accrued interest	2,440			1,112
Capitalized interest	(1,998		)	(1,615		)
Total interest expense	$	18,317		$	18,608

6. COMMITMENTS AND CONTINGENCIES

As discussed in Note 1—“Organization and Summary of Significant Accounting Policies—Basis of Presentation,” due to the delay in the filing of this report, this note includes information regarding certain liabilities and uncertainties that became available after the end of the period covered by this report, but has been taken into consideration in the preparation of this report.

Litigation. Various suits and claims arising in the ordinary course of business are pending against us. Due to locations where we conduct business in the continental United States, we are often subject to jury verdicts and arbitration hearings that result in favor of the plaintiffs. We do not believe that the disposition of any of these items will result in a material adverse impact on our consolidated financial position, results of operations or cash flows.

Gonzales Matter. In September 2005 a class action lawsuit, Gonzales v. Key Energy Services, Inc., was filed in Ventura County, California Superior Court alleging that Key did not pay its hourly employees for travel time between the yard and the wellhead and that certain employees were denied meal and rest periods between shifts. We have recorded a liability for this matter and do not expect that the conclusion of this matter will have a material impact on our results of operations, cash flows or financial position.

Litigation with Former Officers and Employees. On April 7, 2006, we delivered a notice to our former chief executive officer, Francis D. John, of our intention to treat his termination of employment effective May 1, 2004, as “for Cause” under his employment agreement with us. In response to the notice, Mr. John filed a lawsuit against us in the U.S. District Court for the Southern District of Texas, Houston Division, on May 19, 2006, in which he alleged, among other things, that we breached stock option agreements and his employment agreement. On June 13, 2006, we filed an answer and counterclaim denying Mr. John’s claims and asserting claims against Mr. John for breach of contract and declaratory judgment including, among other things, a declaration that “Cause” exists under Mr. John’s employment agreement. On June 20, 2007 we settled our litigation with Mr. John for $23 million.

We have also been named in a lawsuit by our former general counsel, Jack D. Loftis, Jr., filed in the U.S. District Court, District of New Jersey on April 21, 2006, in which he alleges a “whistle-blower” claim under the Sarbanes-Oxley Act, breach of contract, breach of good faith and fair dealing, breach of fiduciary duty, and wrongful termination. Mr. Loftis previously filed his “whistle-blower” claim with the Department of Labor (“DOL”), which found that there was no reasonable cause to believe that we violated the Sarbanes-Oxley Act when we terminated Mr. Loftis and dismissed the complaint. On July 28, and October 2, 2006, Key moved to dismiss the lawsuit for lack of jurisdiction over Key Energy or for lack of venue. On June 28, 2007, the Court denied our motions but on its own motion transferred the case to the U.S. District Court for the Eastern District of Pennsylvania.

On July 6, 2007, we delivered a notice to Mr. Loftis, through his counsel, of our intention to treat his termination of employment effective July 8, 2004 as “for cause” under his employment agreement. On August 17, 2007, the Company filed counterclaims against Mr. Loftis alleging attorney malpractice, breach of contract, and breach of fiduciary duties. In its counterclaims, the Company seeks repayment of all severance paid to Mr. Loftis to date (approximately $815,000) plus benefits paid during the period July 8, 2004 to September 21, 2004, as well as damages relating to the allegations of malpractice and breach of fiduciary duties. On September 21, 2007, the Company’s Board of Directors determined that Mr. Loftis should be terminated “for cause” effective July 8, 2004, and further found that his vested and unvested stock options should be deemed expired.

Additionally, on August 21, 2006, our former chief financial officer, Royce W. Mitchell, filed a suit against the Company in 385th District Court, Midland County, Texas alleging breach of contract with regard to alleged bonuses, benefits and expense reimbursements, conditional stock grants and stock options, to which he believes himself entitled; as well as relief under theories of quantum meruit, promissory estoppel, and specific performance. Although there is no scheduling order in the case, discovery is underway. Further, our former controller and assistant controller filed a joint complaint against the Company on September 3, 2006 in 133rd District Court, Harris County, Texas alleging constructive termination and breach of contract. Following Key’s removal of the case to the federal court, Plaintiff dismissed his constructive termination allegation and the parties agreed to a remand of the case back to the state court. Discovery is now ongoing.

We are vigorously defending against these claims; however, we cannot predict the outcome of the lawsuits.

Class Action Suits and Derivative Actions. Since June 2004, we have been named as a defendant in six class action complaints for alleged violations of federal securities laws, which have been filed in federal district court in Texas. These six actions

have been consolidated into one action. On November 1, 2005, the plaintiffs filed a consolidated amended class action complaint. The complaint generally alleges that we made false and misleading statements and omitted material information from our public statements and SEC reports during the class period in violation of the Securities Exchange Act of 1934, including alleged: (i) overstatement of revenues, net income, and earnings per share, (ii) failure to take write-downs of assets, consisting of primarily idle equipment, (iii) failure to amortize the Company’s goodwill, (iv) failure to disclose that the Company lacked adequate internal controls and therefore was unable to ascertain the true financial condition of the Company, (v) material inflation of the Company’s financial results at all relevant times, (vi) misrepresentation of the value of acquired businesses, and (vii) failure to disclose misappropriation of funds by employees.

Four shareholder derivative actions have been filed by certain of our shareholders. Those actions are filed by individual shareholders purporting to act on our behalf, asserting various claims against the named officer and director defendants. The derivative actions generally allege the same facts as those in the shareholder class action suits. Those suits also allege breach of fiduciary duty, abuse of control, waste of corporate assets, and unjust enrichment by these defendants.

On September 7, 2007, the Company reached agreements in principle to settle all pending securities class action and derivative lawsuits in consideration of payments totaling $16.6 million in exchange for full and complete releases for all defendants. The Company’s contribution to the settlement, net of payments by its insurers and contributions from other defendants, will amount to $1.0 million. The Company has recorded a liability in this amount for the quarter ended March 31, 2007. The settlement is subject to completion of documentation and court approval following notices to all potential claimants eligible for class participation. A preliminary approval hearing is scheduled for October 24, 2007, with a final hearing scheduled on March 25, 2008.

Tax Audits. We are routinely the subject of audits by tax authorities and have received some material assessments from tax auditors. As of June 30, 2007, we have recorded reserves for future potential liabilities as a result of these audits that management feels are appropriate. While we have fully reserved for these assessments, the ultimate amount of settlement can vary from this estimate. In connection with our Egyptian operations, we are undergoing income tax audits for all periods in which we had operations. Based on information as of the period covered by this report, we have determined that additional income taxes will be owed and have recorded a liability of approximately $1.1 million.

Self-Insurance Reserves. We maintain insurance policies for workers’ compensation, vehicle liability and general liability claims. These insurance policies carry self-insured retention limits or deductibles on a per occurrence basis. The retention limits or deductibles are accounted for in our accrual process for all workers’ compensation, vehicular liability and general liability claims. We maintain reserves for workers’ compensation and vehicle liability on our balance sheet based on our judgment and estimates using an actuarial method based on claims incurred. We estimate general liability claims on a case-by-case basis. As of June 30, 2007 and December 31, 2006, we have recorded $61.5 million and $69.0 million, respectively, of self-insurance reserves related to worker’s compensation, vehicular liabilities and general liability claims.

Environmental Remediation Liabilities. For environmental reserve matters, including remediation efforts for current locations and those relating to previously-disposed properties, we record liabilities when our remediation efforts are probable and the costs to conduct such remediation efforts are reasonably estimated. Environmental reserves do not reflect management’s assessment of the insurance coverage that may apply to these matters at issue, whereas our litigation reserves do reflect the application of our insurance coverage. As of June 30, 2007 and December 31, 2006, we have recorded $3.6 million and $4.6 million, respectively, for our environmental remediation liabilities.

Guarantees. We provide performance bonds to provide financial surety assurances for the remediation and maintenance of our SWD properties to comply with environmental protection standards. Costs for SWD properties may be mandatory (to comply with applicable laws and regulations), in the future (required to divest or cease operations), or for optimization (to improve operations, but not for safety or regulatory compliance).

Argentina Payroll Matters. Our Argentinean subsidiary, Key Energy Services S.A., had previously underpaid our social security contributions to the Administración Federal de Ingressos Públicos (“AFIP”) as a result of applying an incorrect rate in the calculation of our obligation. Additionally, we also underpaid AFIP as a result of our incorrect use of food stamp equivalents provided to employees as compensation. The correct amounts have been reflected in these financial statements. On May 31, 2007 we paid AFIP $3.5 million, representing the cumulative amount of underpayment and interest. As a result of our underpayment, AFIP has imposed fines and penalties against us and has begun an audit of our filings made to them in prior years. We have recorded an appropriate liability for this matter, and do not expect the ultimate resolution of this matter to have a material impact to our results of operations, cash flows or financial position.

Well Service Rig Purchase Contract. In October 2005, we entered into a purchase and sale agreement to acquire 30 well service rigs, with the option to acquire more under the terms of the agreement. Through June 30, 2007 we have ordered five additional rigs under this option and have received delivery of 26 rigs. We also reduced our total order of rigs to 26 total rigs. The purchase and sale agreement is cancelable at our option at any time. Should we cancel the agreement prior to taking delivery of the 30 well service rigs, we may be required to refund to the seller the amount of the contractual discount provided by the seller on the previously delivered well service rigs.

7. STOCKHOLDERS’ EQUITY

Common Stock

On June 30, 2007, we had 200,000,000 shares of common stock authorized with a $0.10 par value, of which 131,593,695 shares were issued and outstanding, net of 533,466 shares held in treasury, and no dividends were declared or paid. On December 31, 2006, we had 200,000,000 shares of common stock authorized with a $0.10 par value, of which 131,624,038 shares were issued and outstanding, net of 497,501 shares held in treasury, and no dividends had been declared or paid.

Common Stock Warrants

On January 22, 1999, in connection with a private placement offering, we issued 150,000 Warrants to purchase approximately 2.2 million shares of the Company’s common stock at an exercise price of $4.88125 per share. Through June 30, 2007, 63,500 Warrants had been exercised, providing $4.2 million of proceeds to us and leaving 86,500 Warrants outstanding, which are potentially convertible into an aggregate of approximately 1.3 million shares of the Company’s common stock. On the date of issuance, the value of the Warrants was estimated at $7.4 million and was classified as equity. Under the terms of the Warrants, we are required to maintain an effective registration statement with the SEC 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. We have been unable to maintain an effective registration statement due to our failure to timely file our SEC reports. As a result, we paid liquidated damages starting at $0.05 per Warrant per week and escalating to $0.20 per Warrant per week. The total amounts paid to the holders of the Warrants were $0.5 million and $0.5 million during the six months ended June 30, 2007 and 2006, respectively.

Treasury Stock

In June 2007 and 2006, the Company purchased 35,965 and 80,835 shares, respectively, of restricted common stock that had been previously granted to certain of the Company’s officers, pursuant to an agreement under which those individuals were permitted to sell shares back to the Company in order to satisfy the income tax withholding requirements related to the vesting of these grants. We account for treasury stock under the cost method, and as such recorded $0.7 million and $1.2 million, respectively, in treasury stock on the date of purchase, which represented the fair market value of the shares based on the price of the Company’s stock on the date of purchase.

Stock Incentive Plans

On January 13, 1998, Key’s shareholders approved the Key Energy Group, Inc. 1997 Incentive Plan, as amended (the “1997 Incentive Plan”). The 1997 Incentive Plan is an amendment and restatement of the plans formerly known as the Key Energy Group, Inc. 1995 Stock Option Plan and the Key Energy Group, Inc. 1995 Outside Directors Stock Option Plan (collectively, the “Prior Plans”).

All options previously granted under the Prior Plans and outstanding as of November 17, 1997 (the date on which our board of directors adopted the 1997 Incentive Plan) were assumed and continued, without modification, under the 1997 Incentive Plan.

Under the 1997 Incentive Plan, Key may grant the following awards to certain key employees, directors who are not employees (“Outside Directors”) and consultants of Key, our controlled subsidiaries, and our parent corporation, if any: (i) incentive stock options (“ISOs”) as defined in Section 422 of the Internal Revenue Code of 1986, as amended (the “Code”), (ii) “nonstatutory” stock options (“NSOs”), (iii) stock appreciation rights (“SARs”), (iv) shares of restricted stock, (v) performance shares and performance units, (vi) other stock-based awards and (vii) supplemental tax bonuses (collectively,

“Incentive Awards”). ISOs and NSOs are sometimes referred to collectively herein as “Options.” All Options granted have a maximum contractual life of ten years.

Key may grant Incentive Awards covering an aggregate of the greater of (i) 3.0 million shares of our common stock or (ii) 10% of the shares of our common stock issued and outstanding on the last day of each calendar quarter, provided, however, that a decrease in the number of issued and outstanding shares of our common stock from the previous calendar quarter shall not result in a decrease in the number of shares available for issuance under the 1997 Incentive Plan. As of June 30, 2007, the number of shares of our common stock that may be covered by Incentive Awards was approximately 13.2 million shares. As of that date, approximately 2.2 million Incentive Awards could still be issued under the 1997 Incentive Plan.

The following table summarizes the stock option activity related to the plans for the six months ended June 30, 2007 (options in thousands):

	Options		Weighted Average Exercise Price		Weighted Average Fair Value

Outstanding at beginning of year	5,829		$	9.46	$	4.94
Granted	28		$	18.16	$	7.88
Exercised	—		$	—	$	—
Cancelled or expired	(247	)	$	12.90	$	5.06
Outstanding at end of period	5,610		$	9.35	$	4.95

Exercisable at end of period	4,693		$	8.29	$	4.53

The following tables summarize information about the stock options outstanding at June 30, 2007 (options in thousands):

	Weighted Average Remaining Contractual Life (Years)	Number of Options Outstanding, June 30, 2007	Weighted Average Exercise Price		Weighted Average Fair Value

Range of Exercise Prices:
$3.00 - $7.44	2.01	961	$	4.85	$	3.44
$7.45 - $8.43	4.24	1,257	$	8.16	$	4.46
$8.44 - $9.75	3.28	1,175	$	8.63	$	5.44
$9.76 - $11.75	6.16	1,039	$	10.29	$	4.21
$11.76 - $16.25	8.53	1,178	$	14.18	$	6.86
	4.92	5,610	$	9.35	$	4.95

	Number of Options Exercisable, June 30, 2007	Weighted Average Exercise Price		Weighted Average Fair Value

Range of Exercise Prices:
$3.00 - $7.44	961	$	4.85	$	3.44
$7.45 - $8.43	1,257	$	8.16	$	4.46
$8.44 - $9.75	1,175	$	8.63	$	5.44
$9.76 - $11.75	1,023	$	10.28	$	4.19
$11.76 - $16.25	277	$	12.04	$	6.01
	4,693	$	8.29	$	4.53

The total fair value of stock options granted during the six months ended June 30, 2007 was $0.2 million. The fair value of each stock option granted during the six months ended June 30, 2007 was estimated on the date of grant using the Black-Scholes option-pricing model, based on the following weighted-average assumptions:

Risk-free interest rate	4.9	%
Expected life of options, years	6
Expected volatility of the Company’s stock price	41.4	%
Expected dividends	none

During the three months ended June 30, 2007 and 2006, we recognized approximately $0.7 million and $0.9 million, respectively, in compensation expense associated with options.

Common Stock Awards

In June 2005, we began granting shares of common stock to our outside directors and certain employees. These shares are restricted as to exercisability and transferability, have required service periods in certain cases before they are vested, and are subject to forfeiture. The vesting periods on these grants range from zero (immediately vested) to three years. The total fair market value of all common stock awards granted during the three months ended June 30, 2007 and 2006 was $0.1 million and $0.1 million, respectively.

In June 2006, pursuant to the agreement under which they were issued restricted stock, certain of the Company’s officers had a number of common shares withheld in order to satisfy those individuals’ income tax obligations associated with the vesting of the first tranche of shares that were conveyed to them in June 2005. In this transaction, the Company purchased 80,835 shares from the officers, which had a fair market value of approximately $1.2 million on the purchase date. We accounted for this as a treasury stock transaction. One of the officers was permitted to have an amount withheld that was in excess of the required minimum required withholding under current tax law. Under SFAS 123(R), we are required to account for this grant as a liability award. Compensation expense for this award for the six months ended June 30, 2007 and 2006 was $0.1 million and $0.1 million, respectively. Compensation expense recognized for this award during the quarter ended June 30, 2007 and 2006 was $0.1 million and less than $0.1 million, respectively.

We issued a total of 5,622 common shares to an outside director during the six months ended June 30, 2006 at an issuance price of $15.12 per share. This award vested immediately. At June 30, 2007, 469,157 common share awards were vested, at a weighted average issuance price of $12.22 per share. At December 31, 2006, 338,534 common share awards were vested, at a weighted-average issuance price of $12.30 per share.

As of June 30, 2007, there were approximately 450,000 unvested common stock awards outstanding, at a weighted-average issuance price of $14.91 per share.

For common stock grants that vest immediately upon issuance, we record expense equal to the fair market value of the shares on the date of grant. For common stock grants that do not immediately vest, we recognize compensation cost ratably over the vesting period of the grant, net of actual and estimated forfeitures. For the three months ended June 30, 2007 and 2006, we recognized $1.2 million and $0.5 million, respectively, of pre-tax expense related to common stock awards, net of estimated and actual forfeitures. For the six months ended June 30, 2007

and 2006, we recognized $2.2 million and $2.3 million, respectively, of pre-tax expense related to common stock awards, net of estimated and actual forfeitures. In connection with the expense related to common stock awards recognized during the three and six months ended June 30, 2007, we recognized tax benefits of $0.5 million and $0.8 million.

Phantom Share Awards

In December 2006, the Company announced the implementation of a “Phantom Share Plan,” pursuant to which certain of the Company’s employees were granted “Phantom Shares.” The Phantom Shares vest ratably over a four-year period and convey the right to the grantee to receive a cash payment on the 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 payment to a later date. The Phantom Shares qualify as a “liability” type award under SFAS 123(R), and as such, we account for these awards at fair value. We recognize compensation expense related to the Phantom Shares based on the change in the fair value of the awards during the period and the percentage of service requirement that has been performed, net of estimated and actual forfeitures, with an offsetting liability recorded on our Consolidated Balance Sheets. During the three and six months ended June 30, 2007, we recognized approximately $1.1 million and $2.0 million of pre-tax compensation expense, respectively, associated with the Phantom Shares, and have recorded a current liability of approximately $1.0 million and a long-term liability of approximately $1.0 million as of June 30, 2007. Associated with the Phantom Shares, we recognized $0.4 million and $0.7 million, respectively, of tax benefits for the three and six months ended June 30, 2007.

8. SEGMENT INFORMATION

For 2007, our reportable business segments are well servicing, pressure pumping and fishing and rental.

Well Servicing. These operations provide a full range of well services, including rig-based services, oilfield transportation services and other ancillary oilfield services necessary to complete, maintain and workover oil and natural gas producing wells. Our Argentina operations are included in our well servicing segment. We aggregate our operating divisions engaged in well servicing activities into our well servicing reportable segment.

Pressure Pumping. These operations provide well stimulation and cementing services. Stimulation includes fracturing, nitrogen services and acidizing services and is used to enhance the production of oil and natural gas wells from formations which exhibit a restricted flow of oil and / or natural gas. Cementing services include pumping cement into a well between the casing and the wellbore.

Fishing and Rental. These operations provide services that include “fishing” to recover lost or stuck equipment in a wellbore through the use of “fishing tools.” In addition, this segment offers a full line of services and rental equipment designed for use both on land and offshore for drilling and workover services and includes an inventory consisting of tubulars, handling tools, pressure-control equipment and power swivels.

We evaluate the performance of our operating segments based on revenue and EBITDA, which is a non-GAAP measure and not disclosed below. Corporate expenses include general corporate expenses associated with managing all reportable operating segments. Corporate assets consist principally of cash and cash equivalents, short-term investments, deferred debt financing costs and deferred income tax assets.

The following table sets forth our segment information as of and for the periods ended June 30, 2007 and June 30, 2006, respectively:

	Well Servicing			Pressure Pumping			Fishing and Rental			Corporate / Other			Eliminations		Total
	(in thousands)
As of and for the three months ended June 30, 2007:
Operating revenues	$	308,825		$	77,289		$	24,397		$	—		$	—	$	410,511
Gross margin	131,522			29,879			10,887			—			—		172,288
Depreciation and amortization	21,305			4,056			2,048			3,275			—		30,684
Interest expense	(270		)	(225		)	(108		)	9,571			—		8,968
Net income (loss)	93,601			23,503			6,899			(75,867		)	—		48,136
Propery, plant and equipment, net	550,045			125,787			43,120			39,303			—		758,255
Total assets	1,032,513			232,103			85,894			85,741			212,999		1,649,250
Capital expenditures, excluding acquisitions	(40,833		)	(22,218		)	(6,913		)	(2,456		)	—		(72,374		)

	Well Servicing			Pressure Pumping			Fishing and Rental			Corporate / Other			Eliminations			Total
	(in thousands)
As of and for the three months ended June 30, 2006:
Operating revenues	$	288,392		$	60,199		$	23,445		$	—		$	—		$	372,036
Gross margin	114,943			27,167			9,865			—			—			151,975
Depreciation and amortization	21,689			2,810			1,705			2,720			—			28,924
Interest expense	(152		)	(173		)	(9		)	10,364			—			10,030
Net income (loss)	72,225			22,356			5,173			(60,172		)	—			39,582
Propery, plant and equipment, net	510,456			86,394			29,486			32,215			—			658,551
Total assets	975,625			172,823			72,648			352,267			(140,247		)	1,433,116
Capital expenditures, excluding acquisitions	(43,082		)	(12,129		)	(3,399		)	—			—			(58,610		)

	Well Servicing			Pressure Pumping			Fishing and Rental			Corporate / Other			Eliminations		Total
	(in thousands)
As of and for the six months ended June 30, 2007:
Operating revenues	$	619,985		$	151,366		$	48,079		$	—		$	—	$	819,430
Gross margin	267,153			57,423			21,119			—			—		345,695
Depreciation and amortization	41,072			7,992			4,394			6,840			—		60,298
Interest expense	(435		)	(369		)	(179		)	19,300			—		18,317
Net income (loss)	191,636			44,521			12,332			(148,162		)	—		100,327
Propery, plant and equipment, net	550,045			125,787			43,120			39,303			—		758,255
Total assets	1,032,513			232,103			85,894			85,741			212,999		1,649,250
Capital expenditures, excluding acquisitions	(67,674		)	(35,794		)	(10,919		)	(4,458		)	—		(118,694		)

	Well Servicing			Pressure Pumping			Fishing and Rental			Corporate / Other			Eliminations			Total
	(in thousands)
As of and for the six months ended June 30, 2006:
Operating revenues	$	561,307		$	111,997		$	46,689		$	—		$	—		$	719,993
Gross margin	210,793			51,538			18,981			—			—			281,312
Depreciation and amortization	41,764			5,172			3,295			5,507			—			55,738
Interest expense	(292		)	(382		)	(6		)	19,288			—			18,608
Net income (loss)	131,335			42,290			10,007			(113,988		)	—			69,644
Propery, plant and equipment, net	510,456			86,394			29,486			32,215			—			658,551
Total assets	975,625			172,823			72,648			352,267			(140,247		)	1,433,116
Capital expenditures, excluding acquisitions	(74,385		)	(18,530		)	(4,755		)	(521		)	—			(98,191		)

Operating revenues for our foreign operations were $19.7 million and $18.0 million for the three months ended June 30, 2007 and 2006, respectively. Operating revenues for our foreign operations were $40.1 million and $35.2 million for the six months ended June 30, 2007 and 2006, respectively. Gross margins for our foreign operations were $1.4 million and $3.5 million for the quarters ended June 30, 2007 and 2006, respectively. Gross margins for our foreign operations were $5.6 million and $8.3 million for the six months ended June 30, 2007 and 2006, respectively.

We had $40.3 million and $29.7 million of identifiable assets related to our foreign operations as of June 30, 2007 and December 31, 2006, respectively. Capital expenditures for our foreign operations were $4.6 million and $6.3 million for the six months ended June 30, 2007 and 2006, respectively.

9. SUBSEQUENT EVENTS

Third Amendment to Senior Secured Credit Facility

On July 27, 2007, the Company entered into a Third Amendment to our Senior Secured Credit Facility. The amendment (i) eliminated the $100 million limitation on permitted acquisitions; (ii) increased the permitted stock repurchase basket from $250.0 million to $300.0 million; (iii) extended until August 31, 2007, the date by which we were required to file our Annual Report on Form 10-K for the year ended December 31, 2006, and the date by which we were required to file our quarterly reports on Form 10-Q for 2005 and 2006; and (iv) extended until October 31, 2007, the date by which we must file this quarterly report and our quarterly report for the period ending March 31, 2007.

Stock Acquisition

On September 5, 2007, the Company, through its wholly-owned Canadian subsidiaries, purchased all of the shares of Advanced Measurements Inc. and Formsoft Inc, two privately-held Canadian technology entities focused on oilfield service equipment controls, data acquisition, and digital information work flow. Contemporaneous with the acquisition, the acquired entities were merged with Key’s Alberta subsidiary and will be known as Advanced Measurements Inc., or AMI. The purchase price was $8.39 million in cash, which includes deferred cash payments up to a maximum of $1.78 million. Key also assumed approximately $3.0 million in debt. In addition, in connection with the acquisition, the Company acquired a 48% ownership interest, with the right to acquire an additional 3% interest, in Advanced Flow Technologies, Inc., a privately-held Canadian technology company focused on low cost wireless gas well production monitoring.

Execution of Moncla Stock Purchase Agreement

On September 19, 2007, Key Energy Services, LLC, a Delaware limited liability company and wholly-owned subsidiary of the Company, entered into a stock purchase agreement to acquire Moncla Well Service, Inc. and related entities (“Moncla”). Collectively, the Moncla assets include 53 rigs, of which 37 are daylight rigs for well servicing and workovers and eight are twenty-four hour rigs for shallow drilling, sidetracking and deep workovers. In addition, the Moncla companies operate eight barge rigs, and own rig-up, swab, hot oil and anchor trucks, tubing testing units and rental equipment. The Moncla companies currently operate in Texas, Louisiana, Mississippi, Alabama and Florida.

The purchase price for Moncla is $145.0 million, of which $112.5 million will be paid in cash at closing, with the balance consisting of $22.5 million notes payable to the sellers, and the assumption of approximately $10.0 million in long-term debt. The closing of the stock purchase agreement is subject to the expiration or early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvement Act of 1976, as amended, and the satisfaction of other customary closing conditions.

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes as of June 30, 2007 and for the three and six months ended June 30, 2007 and 2006, included elsewhere herein.

Overview

We believe that we are the leading onshore, rig-based well servicing contractor in the United States. Since 1994, we have grown 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; fishing and rental services; pressure pumping services; and ancillary oilfield services.

We operate in most major oil and natural gas producing regions of the United States as well as internationally in Argentina and Mexico.

We operate in three business segments:

Well Servicing:

We provide a broad range of well services, including rig-based services, oilfield transportation services and ancillary oilfield services. Our well service rig fleet is used to perform four major categories of rig services for our customers: (i) maintenance, (ii) workover, (iii) completion, and (iv) plugging and abandonment services. Our fluid transportation services include: (i) vacuum truck services, (ii) fluid transportation services, and (iii) disposal services for operators whose oil or natural gas wells produce saltwater and other fluids. In addition, we are a supplier of frac tanks which are used for temporary storage of fluids used in conjunction with fluid hauling operations and we also provide cased-hole electric wireline services.

Pressure Pumping Services:

We provide a broad range of stimulation and completion services, also known as pressure pumping services. Our primary services include well stimulation and cementing services. Well stimulation includes fracturing, nitrogen and acidizing services. These services (which may be used in completion and workover services) are used to enhance the production of oil and natural gas wells from formations which exhibit restricted flow of oil and natural gas. In the fracturing process, we typically pump fluid and sized sand, or proppants, into a well at high pressure in order to fracture the formation and thereby increase the flow of oil and natural gas. With our cementing services, we pump cement into a well between the casing and the wellbore. We provide pressure pumping services in the Permian Basin of Texas, the Barnett Shale of North Texas, the Mid-Continent region of Oklahoma and in the San Juan Basin. In addition, we provide cementing services in California.

Fishing & Rental Services:

We provide fishing and rental services in the Gulf Coast, Mid-Continent and Permian Basin regions of the United States, as well as in the Rockies and California. Fishing services involve recovering lost or stuck equipment in the wellbore and a “fishing tool” is a downhole tool designed to recover any such equipment lost in the wellbore. We also offer a full line of services and rental equipment designed for use both on land and offshore for drilling and workover services. Our rental tool inventory consists of tubulars, handling tools, pressure-controlled equipment, power swivels and foam air units.

Performance Measures

In determining the overall health of the oilfield service industry, we believe that the Baker Hughes U.S. land drilling rig count is the best barometer of capital spending and activity levels, since this data is made publicly available on a weekly basis. Historically, our activity levels have correlated well with the capital spending by oil and natural gas producers. When commodity prices are strong, capital spending tends to be high, as illustrated by the Baker Hughes land drilling rig count. As the following table indicates, the land drilling rig count increased significantly over the past several quarters as commodity prices, both oil and natural gas, generally increased.

	WTI Cushing Crude Oil		NYMEX Henry Hub Natural Gas		Average Baker Hughes Land Drilling Rigs

2006:
First Quarter	$	63.27	$	7.84	1,440
Second Quarter	$	70.41	$	6.65	1,539
Third Quarter	$	70.42	$	6.17	1,626
Fourth Quarter	$	59.98	$	7.24	1,634

2007:
First Quarter	$	58.08	$	7.18	1,651
Second Quarter	$	64.97	$	7.66	1,680

Internally, we measure activity levels primarily through our rig and trucking hours. As capital spending by oil and natural gas producers increases, demand for our services also rises, resulting in increased rig and trucking services and more hours worked. Conversely, when activity levels decline due to lower spending by oil and natural gas producers, we provide fewer rig and trucking services, which results in lower hours worked. We publicly release our monthly rig and trucking hours. The following table presents our quarterly rig and trucking hours from 2006 through the second quarter of 2007.

	Rig Hours	Trucking Hours
2006:
First Quarter	663,819	609,317
Second Quarter	679,545	602,118
Third Quarter	677,271	587,129
Fourth Quarter	637,994	578,471
Total 2006:	2,658,629	2,377,035

2007:
First Quarter	625,748	571,777
Second Quarter	611,890	583,074

Market Conditions

Industry fundamentals in the U.S. marketplace remain strong as crude oil prices averaged $64.97 per barrel during the June 2007 quarter and averaged approximately $72.36 per barrel during the month of August. While natural gas prices averaged $7.66 per MMbtu during the June 2007 quarter, natural gas prices have since fallen and averaged approximately $6.14 per MMbtu during the month of August. Industry activity levels, as measured by the Baker Hughes land drilling rig count, stabilized during the June 2007 quarter as the rig count averaged 1,680 rigs compared to 1,651 rigs in the March 2007 quarter. The drilling rig count totaled 1,754 on August 31, 2007.

According to the Energy Information Association, there was approximately 3.0 Tcf of natural gas in storage as of August 31, 2007. This is 11.9% higher than the five-year average and the current high levels of natural gas storage have led to decline in natural gas prices from the June 2007 quarter through the month of August. Although natural gas prices have declined significantly from earlier this year, the NYMEX 12-month strip averaged over $7.00 per MMbtu as of August 31, 2007, a level which is still strong for oil and natural gas producers.

Despite the recent declines in natural gas prices, there does not appear to be an impact to U.S. natural gas-directed drilling. In fact, the Baker Hughes land drilling rig count totaled 1,754 on August 31, 2007, which is a 20-year high. While there is typically a lag between the time commodity prices change and when drilling levels are impacted, recent oilfield service industry reports show a rise in the level of land drilling permits, and this is often a leading indicator of future drilling activity. The rise in drilling permits suggests that drilling activity should remain strong.

We believe that industry activity levels should remain stable despite the recent softness in natural gas prices. We remain positive about long term industry fundamentals. Our positive outlook is based on (i) strength of today’s oil price; (ii) a healthy 12-month strip for both oil and natural gas prices; (iii) our belief that capital spending by our customers should remain strong; (iv) preliminary evidence that the U.S. drilling rig count permit is rising, which we believe will result in higher drilling activity; and (v) our belief that natural gas wells drilled today are experiencing faster decline rates which should require more drilling to maintain natural gas production. We are, however, cognizant that a material decline in natural

gas prices from today’s levels could result in further erosion of our rig and trucking hours while additional capacity in all of our segments could reduce demand for our services or result in additional price pressure for our services.

Results of Operations

Key Energy Services, Inc.

Condensed Consolidated Statements of Operations

(In thousands, except per share data)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006

*REVENUES:*
Well servicing	$	308,825		$	288,392		$	619,985		$	561,307
Pressure pumping	77,289			60,199			151,366			111,997
Fishing and rental services	24,397			23,445			48,079			46,689

Total revenues	410,511			372,036			819,430			719,993

*COSTS AND EXPENSES:*
Well servicing	177,304			173,449			352,832			350,514
Pressure pumping	47,410			33,032			93,943			60,459
Fishing and rental services	13,509			13,580			26,960			27,708
Depreciation and amortization	30,684			28,924			60,298			55,738
General and administrative	56,154			49,285			108,217			98,418
Interest expense	8,968			10,030			18,317			18,608
Gain on sale of assets, net	(703		)	(309		)	(453		)	(2,244		)
Interest income	(1,798		)	(828		)	(3,737		)	(2,028		)
Other, net	512			953			(112		)	472

Total costs and expenses, net	332,040			308,116			656,265			607,645

Income before income taxes	78,471			63,920			163,165			112,348
Income tax expense	(30,335		)	(24,338		)	(62,838		)	(42,704		)

*NET INCOME*	$	48,136		$	39,582		$	100,327		$	69,644

Three Months Ended June 30, 2007 Compared to Three Months Ended June 30, 2006

Revenue:

Well Servicing: Well servicing revenues increased 7.1% to $308.8 million for the quarter ended June 30, 2007 compared to revenue of $288.4 million for the quarter ended June 30, 2006. The increase in revenue is largely attributable to higher pricing for the Company’s services, offset somewhat by lower rig and trucking hours. For the June 2007 quarter, the Company’s composite segment revenue to total hours was approximately $258 per hour compared to approximately $225 per hour for the June 2006 quarter. (Total hours is defined as rig plus trucking hours; note that the composite segment revenue to total hours can be affected by changes in the mix between rig and trucking hours.) Rig hours for the Company decreased 11.1% to 611,890 in the June 2007 quarter from 679,545 in the June 2006 quarter while the Company’s trucking hours decreased 3.3% to 583,074 in the June 2007 quarter from 602,118 in the June 2006 quarter. The decrease in rig hours and trucking hours is due primarily to lost market share and the impact of heavy rains in Texas and Oklahoma during May and June of 2007.

Pressure Pumping Services: Pressure pumping services (“PPS”) segment revenues increased 28.4% to $77.3 million for the quarter ended June 30, 2007 compared to revenue of $60.2 million for the quarter ended June 30, 2006. The increase in revenue is attributable to incremental pressure pumping equipment, higher activity levels and higher pricing for the Company’s services. At June 30, 2007, the Company had approximately 196,000 horsepower of pumping equipment as compared to approximately 162,000 at June 30, 2006. The Company’s pressure pumping segment performs several different services including fracturing, cementing, acidizing, nitrogen services, abandonment and other miscellaneous jobs. Generally, the fracturing and cementing jobs represent the substantial majority of the segment’s revenue. Fracturing jobs totaled 531 in

the June 2007 quarter compared to 399 the June 2006 quarter while cementing jobs totaled 468 in the June 2007 quarter compared to 505 the June 2006 quarter.

Fishing and Rental Services: Fishing and rental services (“FRS”) segment revenues for the quarter ended June 30, 2007 increased 4.1% to $24.4 million compared to revenue of $23.4 million for the quarter ended June 30, 2006. The increase in revenue is attributable to higher pricing and continued strong activity levels.

Direct Costs:

Well Servicing: Well servicing direct costs increased $3.9 million, or 2.2%, to $177.3 million for the quarter ended June 30, 2007 compared to $173.5 million for the quarter ended June 30, 2006. Although workers’ compensation costs declined by nearly $7.1 million, this decrease was offset by higher insurance premiums ($4.2 million), higher salaries expense ($6.9 million) and higher repair and maintenance expense ($1.6 million). The decrease in workers’ compensation expense is due to a reduction in incurred claims history, which resulted from fewer reportable claims during 2007 than in prior periods. Direct costs as a percent of total well servicing segment revenue improved to 57.4% for the quarter ended June 30, 2007 compared to 60.1% for the quarter ended June 30, 2006.

Pressure Pumping Services: PPS direct costs increased 43.5% to $47.4 million for the quarter ended June 30, 2007 compared to $33.0 million for the quarter ended June 30, 2006. The increase in direct costs is largely attributable to increased sand and chemical purchases as well as higher trucking and freight costs, higher labor costs and higher repair and maintenance expense. The increase in direct costs is primarily the result of increased demand for the Company’s services. Direct costs as a percent of total PPS segment revenue increased to 61.3% for the quarter ended June 30, 2007 compared to 54.9% for the quarter ended June 30, 2006.

Fishing and Rental Services: FRS direct costs were essentially flat at $13.5 million for the quarter ended June 30, 2007 compared to $13.6 million for the quarter ended June 30, 2006. Decreased labor and repairs and maintenance costs during the June 2007 quarter were offset by increased supply costs and insurance premiums. Direct costs as a percent of total FRS segment revenue improved to 55.4% for the quarter ended June 30, 2007 compared to 57.9% for the quarter ended June 30, 2006.

General and Administrative Expense

General and administrative (“G&A”) expenses increased $6.7 million, or 13.9%, to $56.2 million for the quarter ended June 30, 2007 compared to $49.3 million for the quarter ended June 30, 2006. G&A expenses increased primarily due to higher professional fees ($4.7 million) related to the Company’s accounting and internal controls processes. G&A expense as a percent of revenue for the quarter ended June 30, 2007 totaled 13.7% compared to 13.2% for the quarter ended June 30, 2006.

Interest Expense

Interest expense declined 10.6% to $9.0 million for the quarter ended June 30, 2007 compared to $10.0 million for the quarter ended June 30, 2006. The decline is primarily attributable to higher capitalized interest expense. Interest expense as a percent of revenue for the quarter ended June 30, 2007 totaled 2.2% compared to 2.7% for the quarter ended June 30, 2006.

Depreciation Expense

Depreciation expense increased 6.1% to $30.7 million for the quarter ended June 30, 2007 compared to $28.9 million for the quarter ended June 30, 2006. The increase is primarily attributable to a greater fixed asset base which is due to increased capital expenditures and the decrease of the estimated useful lives of certain of our well servicing assets, which contributed an additional $2.0 million in depreciation expense during the June 2007 quarter. For the quarter ended June 30, 2007, the Company spent approximately $72.5 million on capital expenditures as compared to $58.6 million for the quarter ended June 30, 2006. Depreciation expense as a percent of revenue for the quarter ended June 30, 2007 totaled 7.5% compared to 7.8% for the quarter ended June 30, 2006.

Income Taxes

Our income tax expense was $30.3 million and $24.3 million for the three months ended June 30, 2007 and 2006, respectively. Our effective tax rate for those same periods was 38.7% and 38.1%, respectively. The differences between the rates between periods relate largely to nondeductible expense for executive compensation and other nondeductible items. Differences between the statutory rate and the effective rate are due primarily to state and foreign income taxes and nondeductible expenditures.

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

Revenue

Well Servicing: Well servicing revenues increased 10.5% to $620.0 million for the six months ended June 30, 2007 compared to revenue of $561.3 million for the six months ended June 30, 2006. The increase in revenue is largely attributable to higher pricing for the Company’s services and higher rig hours, offset somewhat by lower trucking hours. For the six months ended June 30, 2007, the Company’s composite segment revenue to total hours was approximately $259 per hour compared to approximately $220 per hour for the six months ended June 30, 2006. Rig hours for the Company decreased 7.9% to 1,237,638 in the first six months of 2007 from 1,343,364 in the first six months of 2006 while the Company’s trucking hours decreased 4.7% to 1,154,851 in the first six months of 2007 from 1,211,435 in the first six months of 2006. The decrease in rig hours and trucking hours is due primarily to lost market share and to a lesser extent, inclement weather in 2007.

Pressure Pumping Services: PPS segment revenues increased 35.2% to $151.4 million for the six months ended June 30, 2007 compared to revenue of $112.0 million for the six months ended June 30, 2006. The increase in revenue is attributable to incremental pressure pumping equipment, higher activity levels and higher pricing for the Company’s services. At June 30, 2007, the Company had approximately 196,000 horsepower of pumping equipment as compared to approximately 162,000 horsepower at June 30, 2006. The Company’s pressure pumping segment performs several different services including fracturing, cementing, acidizing, nitrogen services, abandonment and other miscellaneous jobs. Generally, the fracturing and cementing jobs represent the substantial majority of the segments revenue. Fracturing jobs totaled 1,011 during the first six months of 2007 compared to 752 the first six months of 2006 while cementing jobs totaled 943 during the first six months of 2007 compared to 950 the first six months of 2006.

Fishing and Rental Services: FRS segment revenues for the six months ended June 30, 2007 increased 3.0% to $48.1 million compared to revenue of $46.7 million for the six months ended June 30, 2006. The increase in revenue is primarily attributable to higher pricing and continued strong market conditions.

Direct Costs

Well Servicing: Well serving direct costs increased $2.3 million to $352.8 million for the six months ended June 30, 2007 compared to $350.5 million for the six months ended June 30, 2006. The increase in direct costs is primarily attributable to increased salaries, wages and related payroll taxes (approximately $15.9 million), increased repairs and maintenance expense ($4.5 million), increased freight costs ($1.2 million) and increased chemical costs ($1.2 million), largely offset by decreased workers’ compensation costs ($19.1 million). Workers’ compensation costs experienced a significant decrease during the six months ended June 30, 2007 due to a reduction in incurred claims history, which resulted from fewer reportable incidents occurring during 2007 than in prior periods. Direct costs as a percent of total well service segment revenue improved to 56.9% for the six months ended June 30, 2007 compared to 62.4% for the six months ended June 30, 2006.

Pressure Pumping: PPS direct costs increased 55.4% to $93.9 million for the six months ended June 30, 2007 compared to $60.5 million for the six months ended June 30, 2006. The increase in direct costs is largely attributable to increased sand and chemical purchases as well as higher trucking and freight costs, higher labor costs, higher fuel expense and higher repair and maintenance expense. The increase in direct costs is primarily the result of increased demand for the Company’s services and the expansion of our pressure pumping operations. Direct costs as a percent of total PPS segment revenue were 62.1% for the six months ended June 30, 2007 compared to 54.0% for the six months ended June 30, 2006.

Fishing and Rental Services: FRS direct costs decreased 2.7% to $27.0 million for the six months ended June 30, 2007 compared to $27.7 million for the six months ended June 30, 2006. Decreased repairs and maintenance expenses were largely offset by increased insurance costs. Direct costs as a percent of total FRS segment revenue improved to 56.1% for the six months ended June 30, 2007 compared to 59.3% for the six months ended June 30, 2006.

General and Administrative Expense

General and administrative expense increased $9.8 million, or 10.0%, to $108.2 million for the six months ended June 30, 2007 compared to $98.4 million for the six months ended June 30, 2006. The increase in G&A expenses is primarily attributable to higher professional fees ($6.7 million) associated with the Company’s accounting and internal controls processes. G&A expense as a percent of revenue for the six months ended June 30, 2007 totaled 13.2% compared to 13.7% for the six months ended June 30, 2006.

Interest Expense

Interest expense decreased 1.6% $18.3 million for the six months ended June 30, 2007 compared to $18.6 million for the six months ended June 30, 2006. Interest expense as a percent of revenue for the six months ended June 30, 2007 totaled 2.2% compared to 2.6% for the six months ended June 30, 2006.

Depreciation Expense

Depreciation expense increased 8.2% to $60.3 million for the six months ended June 30, 2007 compared to $55.7 million for the six months ended June 30, 2006. During the first quarter of 2007, management revised its estimate of the useful lives of certain well servicing assets, which resulted in an additional $4.1 million of depreciation expense for the six months ended June 30, 2007. For the six months ended June 30, 2007, the Company spent approximately $118.7 million on capital expenditures as compared to $98.2 million for the six months ended June 30, 2006. Depreciation expense as a percent of revenue for the six months ended June 30, 2007 totaled 7.4% compared to 7.7% for the six months ended June 30, 2006.

Income Taxes

Our income tax expense was $62.8 million and $42.7 million for the six months ended June 30, 2007 and 2006, respectively. Our effective tax rate for those same periods was 38.5% and 38.0%, respectively. The differences between the rates between periods relate largely to nondeductible expense for executive compensation and other nondeductible items. Differences between the statutory rate and the effective rate are due primarily to state and foreign income taxes and nondeductible expenditures.

Liquidity and Capital Resources

We have historically funded our operations, including capital expenditures, from cash flow from operations and have funded growth opportunities, including acquisitions, through bank borrowings and the issuance of equity and long-term debt. In recent years, we have pursued a strategy of repaying indebtedness and have accomplished this objective by using cash generated by operations and cash proceeds from asset sales.

We believe that our current reserves of cash and cash equivalents and short investments, availability under our revolving credit facility, and internally generated cash flow from operations are sufficient to finance the cash requirements of our current and future operations, including our capital expenditure budget. As of June 30, 2007, we had $175.1 million in cash, cash equivalents and short term investments and $65.0 million of availability under our revolving credit facility.

Cash Flow

Our net cash provided by operating activities for the six months ended June 30, 2007, totaled $148.6 million compared to $118.0 million for the six months ended June 30, 2006. The increase in cash flow from operating activities is due primarily to higher net income. Our net cash used in investing activities for the six months ended June 30, 2007 totaled $169.3 million compared to cash used in investing activities of $88.5 million for the six months ended June 30, 2006. Our net cash used in financing activities for the six months ended June 30, 2007 totaled $7.4 million compared to $9.5 million for the six months ended June 30, 2006.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Critical Accounting Policies

Our Accounting Department is responsible for the development and application of our accounting policies and internal control procedures. It reports to the Chief Financial Officer.

The process and preparation of our financial statements in conformity with GAAP requires our management to make certain estimates, judgments and assumptions, which may affect reported amounts of our assets and liabilities, disclosures of contingencies at the balance sheet date, the amounts of revenues and expenses recognized during the reporting period and the presentation of our statement of cash flows for the period ended. We may record materially different amounts if these estimates, judgments and assumptions change or if actual results differ. However, we analyze our estimates, assumptions and judgments based on our historical experience and various other factors that we believe to be reasonable under the circumstances.

As such, we have identified the following critical accounting policies that require a significant amount of estimation and judgment to accurately present our financial position, results of operations and statement of cash flows:

· Estimate of reserves for workers’ compensation, vehicular liability and other self-insured retentions;

· Accounting for contingencies;

· Accounting for income taxes;

· Estimate of fixed asset depreciable lives; and

· Valuation of tangible and intangible assets.

Workers’ Compensation, Vehicular Liability and Other Insurance Reserves

Well servicing and workover operations expose our employees to hazards generally associated with the oilfield. Heavy lifting, moving equipment and slippery surfaces can cause or contribute to accidents involving our employees and third parties who may be present at a site. Environmental conditions in remote domestic oil and gas basins range from extreme cold to extreme heat, from heavy rain to blowing dust. Those conditions can also lead to or contribute to accidents. Our business activities incorporate significant numbers of fluid transport trucks, other oilfield vehicles and supporting rolling stock that move on public and private roads. Vehicle accidents are a significant risk for us. We also conduct contract drilling operations, which present additional hazards inherent in the drilling of wells such as blowouts, explosions and fires, which could result in loss of hole, damaged equipment and personal injury.

As a contractor, we also enter into master service agreements with our customers. These agreements subject us to potential contractual liabilities common in the oilfield.

All of these hazards and accidents could result in damage to our property or a third party’s property and injury or death to our employees or third parties. Although we purchase insurance to protect against large losses, much risk is retained in the form of large deductibles or self-insured retentions.

The occurrence of an event not fully insured or indemnified against, or the failure of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, there can be no assurance that insurance will be available to cover any or all of these risks, or that, if available, it could be obtained without a substantial increase in premiums. It is possible that, in addition to higher premiums, future insurance coverage may be subject to higher deductibles and coverage restrictions.

Based on the risks discussed above, we estimate our liability arising out of potentially insured events, including workers’ compensation, employer’s liability, vehicular liability, and general liability, and record accruals in our consolidated financial statements. Reserves related to insurance are based on the specific facts and circumstances of the insured event and our past experience with similar claims. Loss estimates for individual claims are adjusted based upon actual claim judgments, settlements and reported claims. The actual outcome of these claims could differ significantly from estimated amounts.

We are largely self-insured for physical damage to our equipment, automobiles, and rigs. Our accruals that we maintain on our consolidated balance sheet relate to these deductibles and self-insured retentions, which we estimate through the use of historical claims data and trend analysis. The actual outcome of any claim could differ significantly from estimated amounts. We adjust loss estimates in the calculation of these accruals, based upon actual claim settlements and reported claims.

Accounting for Contingencies

In addition to our workers’ compensation, vehicular liability and other self-insurance reserves, we record other loss contingencies, which relate to numerous lawsuits, claims, proceedings and tax-related audits in the normal course of our operations on our consolidated balance sheet. In accordance with Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies” (“SFAS 5”), we record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We review our loss contingencies routinely to ensure that we have appropriate reserves recorded on the balance sheet. We adjust these reserves based on estimates and judgments made by management with respect to the likely outcome of these matters, including the effect of any applicable insurance coverage for litigation matters. Our estimates and judgment could change based on new information, changes in laws or regulations, changes in management’s plans or intentions, the outcome of legal proceedings, settlements or other factors. If different estimates and judgments were applied with respect to these matters, it is likely that reserves would be recorded for different amounts. Actual results could vary materially from these reserves.

We record liabilities when environmental assessment indicates that site remediation efforts are probable and the costs can be reasonably estimated. We measure liabilities based, in part, on relevant past experience, currently enacted laws and regulations, existing technology, site-specific costs and cost-sharing arrangements. Recognition of any joint and several liability is based upon our best estimate of our final pro-rata share of such liability. These assumptions involve the judgments and estimates of management and any changes in assumptions could lead to increases or decreases in our ultimate liability, with any such changes recognized immediately in earnings.

Under the provisions of Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations,” we record legal obligations to retire tangible, long-lived assets on our balance sheet as liabilities, which are recorded at a discount when we incur the liability. Significant judgment is involved in estimating our future cash flows associated with such obligations, as well as the ultimate timing of the cash flows. If our estimates on the amount or timing of the cash flows change, the change may have a material impact on our results of operations.

Accounting for Income Taxes

We follow Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes,” which requires that we account for deferred income taxes using the asset and liability method and provide income taxes for all significant temporary differences. Management determines our current tax liability as well as taxes incurred as a result of current operations, yet deferred until future periods. Current taxes payable represent our liability related to our income tax return for the current year, while net deferred tax expense or benefit represents the change in the balance of deferred tax assets and liabilities reported on our consolidated balance sheets. Management estimates the changes in both deferred tax assets and liabilities using the basis of assets and liabilities for financial reporting purposes and for enacted rates that management estimates will be in effect when the differences reverse. Further, management makes certain assumptions about the timing of temporary tax differences for the differing treatment of certain items for tax and accounting purposes or whether such differences are permanent.

We establish valuation allowances to reduce deferred tax assets if we determine that it is more likely than not (e.g., a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized in future periods. To

assess the likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which this taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted results, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. As a result, we can give no assurance that loss carryforwards will be realized or available in the future. Additionally, we record reserves for uncertain tax positions that are subject to management judgment related to the resolution of the tax positions and completion of audits by tax authorities in the domestic and international tax jurisdictions in which we operate.

Estimate of Depreciable Lives

We use the estimated depreciable lives of our long-lived assets, such as rigs, heavy duty trucks, trailers, etc., to compute depreciation expense, to estimate future asset retirement obligations and to conduct impairment tests. We base the estimate of our depreciable lives on a number of factors, such as the environment in which the assets operate, industry factors including forecasted prices and competition, and the assumption that we provide the appropriate amount of capital expenditures while the asset is in operation to maintain economical operation of the asset and prevent untimely demise to scrap.

We depreciate our operational assets over their depreciable lives to their salvage value, which is generally 10% of the acquisition cost. We recognize a gain or loss upon ultimate disposal of the asset.

We periodically analyze our estimates of the depreciable lives of our fixed assets to determine if the depreciable periods and salvage value continue to be appropriate. We also analyze useful lives and salvage value when events or conditions occur that could shorten the remaining depreciable life of the asset. We review the depreciable periods and salvage values for reasonableness, given current conditions. As a result, our depreciation expense is based upon estimates of depreciable lives of the fixed assets, the salvage value and economic factors, all of which require management to make significant judgments and estimates. If we determine that the depreciable lives should be shorter than originally estimated, depreciation expense may increase and impairments in the carrying values of our fixed assets may result.

In the first quarter of 2007, management reassessed the useful lives assigned to all of its equipment due to the higher activity and utilization levels experienced with recent and current market conditions. As a result, the maximum useful lives of certain assets were adjusted to reflect this 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.

Valuation of Tangible and Intangible Assets

On at least an annual basis as required by Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” and as required by Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we review long-lived assets, such as well-service rigs, drilling rigs, pressure pumping equipment, heavy duty trucks, investments, goodwill and noncompete agreements to evaluate whether our long-lived assets or goodwill may have been impaired.

Impairment tests may be required annually, as with goodwill, or as management identifies certain trigger events such as negative industry or economic trends, changes in our business strategy, and underperformance relative to historical or projected operating results. To perform an impairment test, we make judgments, estimates and assumptions regarding long-term forecasts of revenues and expenses relating to assets subject to review or, in the case of goodwill, to our reporting units. Market conditions, energy prices, estimated depreciable lives of the assets, discount rate assumptions and legal factors impact our operations and have a significant effect on the estimates of management. Using different judgments, these estimates could differ significantly and actual financial results could differ materially from these estimates. These long-term forecasts are used in the impairment tests to determine if an asset’s carrying value is recoverable or if a write-down to fair value is required.

Financial Accounting Standards Affecting This Report

FIN 47. FASB Financial Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”) became effective for all for fiscal years ending after December 15, 2005. This interpretation clarifies the term of conditional asset retirement obligation as used in SFAS 143 and refers to a legal obligation to perform an asset retirement activity in which the timing and method of settlement are conditional on a future event that may or may not be within our control. However, our obligation to perform the asset retirement activity is unconditional, despite the uncertainties that exist. Accordingly, we are required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value can be reasonably estimated. The adoption of this interpretation did not materially impact our financial statements.

SFAS 154. In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections—A Replacement of APB Opinion No. 20 and SFAS No. 3,” (“SFAS 154”). SFAS 154 changed the requirements for the accounting for and reporting of a change in accounting principle and applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. SFAS 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. The provisions of SFAS 154 are effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The adoption of this standard did not materially affect our financial statements.

FSP FIN No. 45-3. In November 2005, the FASB issued FASB Staff Position No. 45-3, “Application of FASB Interpretation No. 45 to Minimum Revenue Guarantees Granted to a Business or Its Owners” (“FSP FIN 45-3”). FSP Fin 45-3 served as an amendment to FIN 45 by adding minimum revenue guarantees to the list of examples of contracts to which FIN 45 applies. Under FSP FIN 45-3, a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. FSP FIN 45-3 is effective for new minimum revenue guarantees issued or modified on or after January 1, 2006. The adoption of this interpretation did not materially impact our financial statements.

EITF 04-10. In June 2005, the FASB issued EITF Issue 04-10, “Determining Whether to Aggregate Operating Segments That Do Not Meet the Quantitative Thresholds.” This standard considers how a company should evaluate the aggregation criteria in FAS 131 to operating segments that do not meet the quantitative thresholds. Several of our operating segments do not meet the quantitative thresholds as described in SFAS 131. Under this standard, we are permitted to combine information about certain operating segments with other similar segments that individually do not meet the quantitative thresholds to produce a reportable segment. It was effective for fiscal years ending after September 15, 2005.

FIN 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.

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.

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. We adopted this standard on January 1, 2007 and recorded a $1.0 million decrease to the balance of our retained earnings as of January 1, 2007 to reflect the cumulative effect of adopting FSP EITF 00-19-2.

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 January 1, 2007. 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.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

There have been no material changes in our quantitative and qualitative disclosures about market risks from those disclosed in our 2006 Annual Report on Form 10-K. More detailed information concerning market risk can be found in Item 7A. “Quantitative and Qualitative Disclosures about Market Risks” in our 2006 Annual Report on Form 10-K dated as of, and filed with the SEC on, August 13, 2007.

Item 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As of the end of the period covered by this Quarterly Report, management performed, with the participation of our Chief Executive Officer and our Chief Financial Officer, an evaluation of the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Our disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosures. Based on the evaluation and the identification of the material weaknesses in internal control over financial reporting as disclosed in our Annual Report on Form 10-K for the

year ended December 31, 2006, management concluded that, as of June 30, 2007, the Company’s disclosure controls and procedures were not effective.

Because of the material weaknesses identified in our evaluation of internal control over financial reporting for the year ended December 31, 2006, we performed additional substantive procedures so that our condensed consolidated financial statements as of and for the quarter and six months ended June 30, 2007, are presented in accordance with generally accepted accounting principles in the United States of America (“GAAP”).

We believe that because we performed the substantial additional procedures referenced above, the consolidated condensed financial statements for the periods included in this Quarterly Report are fairly presented in all material respects in accordance with GAAP.

Management is committed to achieving effective internal control over financial reporting. Our remediation efforts are described in Item 9A in our Annual Report on Form 10-K for the year ended December 31, 2006. While these efforts continue, we will rely on additional substantive procedures and other measures as needed to assist us with meeting the objectives otherwise fulfilled by an effective control environment.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting during the most recently completed fiscal quarter that have materially affected or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

Class Action Lawsuits and Derivative Actions

Since June 2004, we have been named as a defendant in six class action complaints for alleged violations of federal securities laws, which have been filed in federal district court in Texas. These six actions have been consolidated into one action. On November 1, 2005, the plaintiffs filed a consolidated amended class action complaint. The complaint is brought on behalf of a putative class of purchasers of our securities between April 29, 2003 and June 4, 2004. The complaint names Key, Francis D. John, Royce W. Mitchell, Richard J. Alario and James J. Byerlotzer as defendants. The complaint generally alleges that we made false and misleading statements and omitted material information from our public statements and SEC reports during the class period in violation of the Securities Exchange Act of 1934, including alleged: (i) overstatement of revenues, net income, and earnings per share, (ii) failure to take write-downs of assets, consisting of primarily idle equipment, (iii) failure to amortize the Company's goodwill, (iv) failure to disclose that the Company lacked adequate internal controls and therefore was unable to ascertain the true financial condition of the Company, (v) material inflation of the Company's financial results at all relevant times, (vi) misrepresentation of the value of acquired businesses, and (vii) failure to disclose misappropriation of funds by employees.

In addition, four shareholder derivative suits have been filed by certain of our shareholders. The first derivative suit was filed on August 9, 2004 in state court in Midland, Texas. Two other derivative suits were filed in federal court in El Paso, Texas on December 10, 2004 and subsequently transferred to federal court in Midland, Texas and consolidated by agreement of the parties. Following dismissal of those two actions for failure to make a demand, a fourth derivative suit was filed in Texas state court in Harris County, Texas on May 22, 2004. Francis D. John, David J. Breazzano, Kevin P. Collins, William D. Fertig, W. Phillip Marcum, Ralph S. Michael III, J. Robinson West, James J. Byerlotzer, Royce W. Mitchell, and Richard J. Alario have been named as defendants in one or more of those actions. Those actions are filed by individual shareholders purporting to act on our behalf, asserting various claims against the named officer and director defendants. The derivative actions generally allege the same facts as those in the shareholder class action suits. Those suits also allege breach of fiduciary duty, abuse of control, waste of corporate assets, and unjust enrichment by these defendants.

On September 7, 2007, the Company reached agreements in principle to settle all pending securities class action and derivative lawsuits in consideration of payments totaling $16.6 million in exchange for full and complete releases for all defendants. The Company’s contribution to the settlement, net of payments by its insurers and contributions from other defendants, will amount to $1.0 million. The settlement is subject to completion of documentation and court approval following notices to all potential claimants eligible for class participation. A preliminary approval hearing is scheduled for October 24, 2007, with a final hearing scheduled on March 25, 2008.

Government Investigations

On March 29, 2004, we were notified by the Fort Worth office of the SEC that it had commenced an inquiry regarding the Company. The SEC issued a formal order of investigation on July 15, 2004. On May 30, 2007, we were informed by the staff of the Enforcement Division of the SEC that it had completed its investigation as to Key and that it did not intend to recommend enforcement action. In addition, on January 5, 2005, we were served with a subpoena issued by a grand jury in Midland, Texas, that asked for the production of documents in connection with an investigation being conducted by the U.S. Attorney’s Office for the Western District of Texas. In October 2006, we were notified by the U.S. Attorney’s Office that it would not pursue any criminal charges against the Company.

Litigation with Former Officers and Employees

We have been named in a lawsuit by our former general counsel, Jack D. Loftis, Jr., filed in the U.S. District Court, District of New Jersey on April 21, 2006, in which he alleges a “whistle-blower” claim under the Sarbanes-Oxley Act, breach of contract, breach of good faith and fair dealing, breach of fiduciary duty, and wrongful termination. Mr. Loftis previously filed his “whistle-blower” claim with the Department of Labor (“DOL”), which found that there was no reasonable cause to believe that we violated the Sarbanes-Oxley Act when we terminated Mr. Loftis and dismissed the complaint. On July 28, and October 2, 2006, Key moved to dismiss the lawsuit for lack of jurisdiction over Key Energy or for lack of venue. On June 28, 2007, the court denied our motions but on its own motion transferred the case to the U.S. District Court for the Eastern District of Pennsylvania. On July 6, 2007, we delivered a notice to Mr. Loftis, through his counsel, of our intention to treat his termination of employment effective July 8, 2004 as “for cause” under his employment agreement. On August 17, 2007, the Company filed counterclaims against Mr. Loftis alleging attorney malpractice, breach of contract, and breach of fiduciary duties. In its counterclaims, the Company seeks repayment of all severance paid to Mr. Loftis to date (approximately $815,000) plus benefits paid during the period July 8, 2004 to September 21, 2004, as well as damages relating to the allegations of malpractice and breach of fiduciary duties. On September 21, 2007, the Company’s Board of Directors determined that Mr. Loftis should be terminated “for cause” effective July 8, 2004, and further found that his vested and unvested stock options should be deemed expired.

We are vigorously defending against these claims; however, we cannot predict the outcome of the lawsuits.

Other Matters

A class action lawsuit, Gonzalez v. Key Energy Services, Inc., was filed in Ventura County, California, Superior Court in September 2005 alleging that Key did not pay its hourly employees for travel time between the yard and the wellhead and that certain employees were denied meal and rest periods during shifts. Discovery in the case is underway, but a class has not been certified. Key moved for a legal determination regarding its use of on-duty meal periods, and the Court issued a ruling on March 16, 2007 contrary to Key’s interpretation of the relevant law. Key has recently filed a Petition for Writ with the Court of Appeals of the State of California. We are vigorously defending against this action; however, we cannot predict the outcome of the lawsuit.

In addition, we are involved in various suits and claims that have arisen in the ordinary course of business. We do not believe that the disposition of any of these items will result in a material adverse effect on the consolidated financial position, results of operations or cash flows of Key.

Item 1A. RISK FACTORS

There have been no material changes in our risk factors from those disclosed in our 2006 Annual Report on Form 10-K dated as of, and filed with the SEC on, August 13, 2007. For a discussion of our risk factors, see Item 1A. “Risk Factors” in our 2006 Annual Report on Form 10-K dated as of, and filed with the SEC on, August 13, 2007.

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

Item 3. DEFAULTS UPON SENIOR SECURITIES

None.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

Item 5. OTHER INFORMATION

None.

Item 6. EXHIBITS

3.1		Articles of Restatement of the Company. (Incorporated by reference to Exhibit 3.1 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006, File No. 1-8038.)

3.2		Unanimous consent of the Board of Directors of the Company dated January 11, 2000, limiting the designation of the additional authorized shares to common stock. (Incorporated by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-8038.)

3.3		Second Amended and Restated By-laws of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Form 8-K filed on September 22, 2006, File No. 1-8038.)

4.1		Warrant Agreement dated as of January 22, 1999 between the Company and the Bank of New York, a New York banking corporation as warrant agent. (Incorporated by reference to Exhibit 99(b) of the Company’s Form 8-K filed on February 3, 1999, File No. 1-8038.)

4.2		Warrant Registration Rights Agreement dated January 22, 1999, by and among the Company and Lehman Brothers Inc., Bear, Stearns & Co., Inc., F.A.C. / Equities, a division of First Albany Corporation, and Dain Rauscher Wessels, a division of Dain Rauscher Incorporated. (Incorporated by reference to Exhibit 99(e) of the Company’s Form 8-K filed on February 3, 1999, File No. 1-8038.)

31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32*		Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		KEY ENERGY SERVICES, INC.
		(Registrant)

		/s/ Richard J. Alario
	By:	Richard J. Alario
		President and Chief Executive Officer
		(Principal Executive Officer)
Date: September 24, 2007

EXHIBITS INDEX

3.1		Articles of Restatement of the Company. (Incorporated by reference to Exhibit 3.1 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006, File No. 1-8038.)

3.2		Unanimous consent of the Board of Directors of the Company dated January 11, 2000, limiting the designation of the additional authorized shares to common stock. (Incorporated by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-8038.)

3.3		Second Amended and Restated By-laws of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Form 8-K filed on September 22, 2006, File No. 1-8038.)

4.1		Warrant Agreement dated as of January 22, 1999 between the Company and the Bank of New York, a New York banking corporation as warrant agent. (Incorporated by reference to Exhibit 99(b) of the Company’s Form 8-K filed on February 3, 1999, File No. 1-8038.)

4.2		Warrant Registration Rights Agreement dated January 22, 1999, by and among the Company and Lehman Brothers Inc., Bear, Stearns & Co., Inc., F.A.C. / Equities, a division of First Albany Corporation, and Dain Rauscher Wessels, a division of Dain Rauscher Incorporated. (Incorporated by reference to Exhibit 99(e) of the Company’s Form 8-K filed on February 3, 1999, File No. 1-8038.)

31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32*		Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith.