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 ~~March 31, 2006~~September 30, 2007


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)		~~(I.R.S. Employer~~ 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 xNoo No 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 oNox

As of ~~June 30,~~October 31, 2007, the number of outstanding shares of common stock of the Registrant was ~~131,593,695.~~132,670,100.

KEY ENERGY SERVICES, INC.

INDEX TO FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED ~~MARCH 31, 2006~~SEPTEMBER 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 ~~March 31, 2006~~September 30, 2007 and December 31, ~~2005~~2006
		Unaudited Condensed Consolidated Statements of Operations for the Three and Nine Months Ended ~~March 31,~~September 30, 2007 and 2006 ~~and 2005~~
		Unaudited Condensed Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended ~~March 31,~~September 30, 2007 and 2006 ~~and 2005~~
		Unaudited Condensed Consolidated Statements of Cash Flows for the ~~Three~~Nine Months Ended ~~March 31,~~September 30, 2007 and 2006 ~~and 2005~~

	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~~ 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.

~~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, and on August 13, 2007, we filed our Annual Report on Form 10-K for the year ended December 31, 2006. Concurrently with the filing of this report, we are filing our Quarterly Reports on Form 10-Q for the first three quarters of 2005 and the remaining two quarters of 2006. The 2005 Quarterly Reports on Form 10-Q also include 2004 quarterly information. In light of our inability to provide financial statements in accordance with GAAP for periods prior to 2004, we will not be filing any other earlier reports, including annual reports for 2004 and 2005, or quarterly reports for the first three quarters of 2004. Due to the delay in the filing of this Quarterly Report, certain information presented in this report relates to significant events that have occurred subsequent to March 31, 2006.

Item 1.CONDENSED CONSOLIDATED UNAUDITED FINANCIAL STATEMENTS

Key Energy Services, Inc.

Condensed Consolidated Balance Sheets

(In ~~thousands)~~thousands, except share data)

~~(Unaudited)~~

		March 31,			December 31,			September 30, 2007			December 31, 2006
		2006			2005
*ASSETS*									(Unaudited)
Current assets:
Cash and cash equivalents		$	109,529		$	94,170		$	45,736		$	88,375
Accounts receivable, net of allowance for doubtful accounts of $11,298 and $10,843 at March 31, 2006 and December 31, 2005, respectively		231,342			211,680
Marketable securities								110,156			61,767
Accounts receivable, net of allowance for doubtful accounts of $14,518 and $12,998 at September 30, 2007 and December 31, 2006, respectively								296,803			272,382
Inventories		17,853			17,254			21,334			19,505
Prepaid expenses		2,913			3,292			8,988			4,810
Deferred tax assets		24,647			23,912			30,408			35,968
Other current assets		4,373			6,854			14,881			5,799
Current assets of discontinued operations		658			658

Total current assets		391,315			357,820			528,306			488,606

Property and equipment:
Well servicing equipment		895,263			856,455
Contract drilling equipment		16,652			25,583
Motor vehicles		94,722			91,910
Furniture and equipment		71,049			70,485
Buildings and land		47,717			45,393

Total property and equipment		1,125,403			1,089,826
Property, plant and equipment								1,438,058			1,279,980
Accumulated depreciation		(502,908		)	(479,485		)	(657,980		)	(585,689		)

Net property and equipment		622,495			610,341
Net property, plant and equipment								780,078			694,291

Goodwill		320,892			320,922			324,611			320,912
Deferred costs, net		10,693			11,093			9,761			9,952
Notes and accounts receivable - related parties		307			151			177			287
Other assets		28,677			28,917			35,105			27,350

TOTAL ASSETS		$	1,374,379		$	1,329,244		$	1,678,038		$	1,541,398

*LIABILITIES AND STOCKHOLDERS’ EQUITY*
Current liabilities:
Accounts payable		$	15,921		$	14,633		$	16,147		$	15,294
Accrued operating expenditures		28,491			39,964
Accrued payroll, taxes and employee benefits		45,709			43,691
Derivative liabilities		169			—
Income, sales, use and other taxes		44,223			31,331
Unsettled Legal Claims		7,384			11,249
Vehicular Insurance		3,620			2,632
Workers’ compensation accrual		16,243			19,852
Other accrued liabilities		13,175			6,116
Accrued liabilities								174,601			189,570
Accrued interest		6,339			6,399			5,386			2,530
Current portion of capital lease obligations		8,710			8,639			10,942			11,714
Current portion of long-term debt		4,000			4,000			5,000			4,000
Current liabilities of discontinued operations		282			292

Total current liabilities		194,266			188,798			212,076			223,108

Capital lease obligations, less current portion		14,887			14,781			16,798			14,080
Long-term debt, less current portion		395,000			396,000			389,191			392,000
Workers’ compensation, vehicular, health and other insurance claims		45,958			38,311			45,309			44,617
Deferred tax liability		98,607			96,572			123,672			115,826
Other non-current accrued expenses		40,366			40,725			22,188			21,256

Commitments and contingencies		—			—

Stockholders’ equity:	��
Common stock, $0.10 par value; 200,000,000 shares authorized, 131,340,078 and 131,334,196 shares issued and outstanding at March 31, 2006 and December 31, 2005, respectively		13,176			13,175
Common stock, $0.10 par value; 200,000,000 shares authorized, 131,890,674 and 131,624,038 shares issued and outstanding at September 30, 2007 and December 31, 2006, respectively								13,242			13,212
Additional paid-in capital		717,919			716,389			728,805			722,610
Treasury stock, at cost; 416,666 and 416,666 shares at March 31, 2006 and December 31, 2005, respectively		(9,682		)	(9,682		)
Treasury stock, at cost; 533,466 and 497,501 shares at September 30, 2007 and December 31, 2006, respectively								(11,564		)	(10,862		)
Accumulated other comprehensive loss		(36,983		)	(36,627		)	(37,828		)	(36,284		)
Retained deficit		(99,135		)	(129,198		)
Retained earnings								176,149			41,835

Total stockholders’ equity		585,295			554,057			868,804			730,511
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	1,374,379		$	1,329,244		$	1,678,038		$	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 March 31,

2006

2005

REVENUES:

Well servicing

$
272,916

$
220,333

Pressure pumping

51,798

30,504

Fishing and rental services

23,244

20,367

Total revenues

347,958

271,204

COSTS AND EXPENSES:

Well servicing

180,756

149,622

Pressure pumping

28,570

17,230

Fishing and rental services

15,088

13,606

Depreciation and amortization

26,814

27,774

General and administrative

43,341

34,938

Interest expense

8,578

13,352

Loss on early extinguishment of debt

—

400

(Gain) loss on sale of assets

(1,936
)
725

Interest income

(1,200
)
(424
)
Other, net

(483
)
48

Total costs and expenses, net

299,528

257,271

Income from continuing operations before income taxes

48,430

13,933

Income tax expense

(18,367
)
(5,568
)

INCOME FROM CONTINUING OPERATIONS

30,063

8,365

Discontinued operations, net of income tax (expense) of $4,590 for the three months ended March 31, 2005

—

(3,361
)

NET INCOME

$
30,063

$
5,004

EARNINGS (LOSS) PER SHARE:

Net income from Continuing Operations

Basic

$
0.23

$
0.06

Diluted

$
0.22

$
0.06

Discontinued Operations

Basic

$
—

$
(0.03
)
Diluted

$
—

$
(0.03
)

Net Income

Basic

$
0.23

$
0.03

Diluted

$
0.22

$
0.03

WEIGHED AVERAGE SHARES OUTSTANDING:

Basic

131,339

130,791

Diluted

134,525

133,291

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006

*REVENUES:*
Well servicing	$	311,304		$	323,655		$	931,289		$	884,962
Pressure pumping	77,112			69,038			228,478			181,035
Fishing and rental services	25,551			24,907			73,629			71,596

Total revenues	413,967			417,600			1,233,396			1,137,593

*COSTS AND EXPENSES:*
Well servicing	193,151			185,486			545,983			536,000
Pressure pumping	49,357			37,305			143,299			97,764
Fishing and rental services	14,974			14,610			41,934			42,318
Depreciation and amortization	31,185			30,192			91,483			85,930
General and administrative	56,569			43,624			164,787			142,042
Interest expense	7,914			10,410			26,231			29,017
Loss (gain) on sale of assets, net	2,398			(817		)	1,945			(3,062		)
Interest income	(1,851		)	(1,841		)	(5,589		)	(3,868		)
Other, net	438			(191		)	326			280

Total costs and expenses, net	354,135			318,778			1,010,399			926,421

Income before income taxes	59,832			98,822			222,997			211,172
Income tax expense	(23,936		)	(37,937		)	(86,775		)	(80,641		)

*NET INCOME*	$	35,896		$	60,885		$	136,222		$	130,531

*EARNINGS PER SHARE:*
Basic	$	0.27		$	0.46		$	1.03		$	0.99
Diluted	$	0.27		$	0.45		$	1.02		$	0.97

*WEIGHTED AVERAGE SHARES OUTSTANDING:*
Basic	131,738			131,291			131,665			131,322
Diluted	133,808			134,187			133,955			134,564

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

Key Energy Services, Inc.

Condensed Consolidated Statements of Comprehensive Income

(In thousands)

(Unaudited)

Three Months Ended March 31,

2006

2005

NET INCOME

$
30,063

$
5,004

OTHER COMPREHENSIVE INCOME, NET OF TAX:

Foreign currency translation gain

(279
)
76

Deferred gain from cash flow hedges

(77
)
—

COMPREHENSIVE INCOME, NET OF TAX

$
29,707

$
5,080

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006

*NET INCOME*	$	35,896		$	60,885		$	136,222		$	130,531
*OTHER COMPREHENSIVE INCOME (LOSS), NET*
*OF TAX:*
Foreign currency translation loss	(921		)	(66		)	(920		)	(168		)
Net deferred (loss) gain from cash flow hedges	(510		)	(838		)	(435		)	256
Deferred gain (loss) from available for sale investments	16			54			(189		)	54
*COMPREHENSIVE INCOME, NET OF TAX*	$	34,481		$	60,035		$	134,678		$	130,673

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

(inIn thousands)

~~(unaudited)~~(Unaudited)

Three Months Ended March 31,

2006

2005

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income

$
30,063

$
5,004

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization

26,814

27,774

Accretion expense

125

135

Income from equity investment

(406
)
(119
)
Amortization of deferred issuance costs, discount and premium

400

513

Deferred income tax expense

1,300

8,238

Capitalized interest

(737
)
(115
)
(Gain) loss on sale of assets

(1,936
)
725

Loss on early extinguishment of debt

—

400

Stock-based compensation

1,531

322

Amortization of deferred gain on sale-leaseback transactions

(40
)
—

Changes in working capital:

Accounts receivable, net

(20,153
)
(6,236
)
Other current assets

2,641

208

Accounts payable, accrued interest and accrued expenses

6,150

(3,772
)

Other assets and liabilities

6,855

(4,922
)

Operating cash flows (used by) provided by discontinued operations

(10
)
12,547

Net cash provided by operating activities

52,597

40,702

CASH FLOWS FROM INVESTING ACTIVITIES:

Capital expenditures - Well Servicing

(30,684
)
(12,358
)
Capital expenditures - Pressure Pumping

(6,402
)
(1,127
)
Capital expenditures - Fishing and Rental

(1,355
)
(469
)
Capital expenditures - Other

(1,140
)
(967
)
Proceeds from sale of fixed assets

7,315

1,976

Investment in available for sale securities

—

(13,500
)
Proceeds from the sale of available of sale securities

—

650

Investing cash flows provided by discontinued operations

—

60,477

Net cash (used in) provided by investing activities

(32,266
)
34,682

CASH FLOWS FROM FINANCING ACTIVITIES:

Repayments of long-term debt

(1,000
)
—

Repayments of capital lease obligations

(3,054
)
(2,920
)

Net cash used in financing activities

(4,054
)
(2,920
)

Effects of exchange rates on cash

(918
)
192

Net increase (decrease) in cash and cash equivalents

15,359

72,656

Cash and cash equivalents, beginning of period

94,170

20,425

Cash and cash equivalents, end of period

$
109,529

$
93,081

	Nine Months Ended September 30,
	2007			2006

*CASH FLOWS FROM OPERATING ACTIVITIES:*

Net income	$	136,222		$	130,531

Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	91,483			85,930
Accretion expense	389			369
(Income) loss from equity investment	(270		)	193
Amortization of deferred debt issuance costs	1,329			1,207
Deferred income tax expense	10,041			7,026
Capitalized interest	(3,543		)	(2,570		)
Loss (gain) on sale of assets	1,945			(3,062		)
Stock-based compensation	9,076			5,014

Changes in working capital:
Accounts receivable	(23,611		)	(58,331		)
Other current assets	(17,780		)	635
Accounts payable, accrued interest and accrued expenses	(14,507		)	45,815

Other assets and liabilities	(551		)	(18,701		)

Net cash provided by operating activities	190,223			194,056

*CASH FLOWS FROM INVESTING ACTIVITIES:*

Capital expenditures - Well Servicing	(100,904		)	(107,517		)
Capital expenditures - Pressure Pumping	(44,969		)	(25,856		)
Capital expenditures - Fishing and Rental	(16,364		)	(11,053		)
Capital expenditures - Other	(5,586		)	(2,579		)
Proceeds from sale of fixed assets	3,284			10,122
Acquisitions, net of cash acquired of $628	(5,982		)	—
Investment in available for sale securities	(98,446		)	(61,883		)
Proceeds from the sale of available for sale securities	50,035			31,163

Net cash used in investing activities	(218,932		)	(167,603		)

*CASH FLOWS FROM FINANCING ACTIVITIES:*

Repayment of long-term debt	(4,463		)	(3,000		)
Repayments under capital lease obligations	(8,335		)	(9,670		)
Repayments on line of credit facility	(447		)	—
Purchase of treasury stock	(702		)	(1,180		)

Net cash used in financing activities	(13,947		)	(13,850		)

Effect of exchange rates on cash	17			(633		)

Net (decrease) increase in cash and cash equivalents	(42,639		)	11,970
Cash and cash equivalents, beginning of period	88,375			94,170
Cash and cash equivalents, end of period	$	45,736		$	106,140

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 third 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.~~Argentina and Mexico. 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. In September 2007, we acquired Advanced Measurements, Inc. (“AMI”), a privately-held Canadian technology company. We also provide limited onshore drilling services in the Rocky Mountains, the Appalachian Basin and in Argentina. ~~During 2006, we conducted~~We conduct 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.

~~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, ~~2005~~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 7) 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 ~~classifications.~~presentation. These reclassifications primarily relate to the ~~change in our reportable segments. Prior~~recasting of prior periods to ~~2004, our Pressure Pumping and Fishing and Rental segments~~conform to a realignment of certain positions that were previously reported as ~~part~~a component of our Well Servicing segment; Pressure Pumping and Fishing and Rental are now presented as independent reportable segments. Additionally, as further discussed in Note 2—“Discontinued Operations,” we sold the majority of our contract drilling assets to Patterson-UTI Energy on January 15, 2005. These assets had previously been reported as part of our Contract Drilling reportable segment. The assets, cash flows, and results of operations of these activities are presented as discontinued operations in our condensed consolidated unaudited financial statements for all periods presented in this Report.

~~Our remaining contract drilling operations~~direct expenses that are now reported as ~~part~~general and administrative. These reclassifications had no effect on previously reported net income. The following tables summarize the effects of ~~our Well Servicing segment.~~ these reclassifications on previously reported amounts (in thousands):

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

Well servicing costs	$	189,078	$	(3,592	)	$	185,486
Pressure pumping costs	38,541		(1,236		)	37,305
Fishing and rental costs	15,672		(1,062		)	14,610
General and administrative	37,734		5,890			43,624
Total	$	281,025	$	—		$	281,025

	Nine Months Ended September 30, 2006
	Amounts as Previously Reported		Effect of Reclassifications			Amounts as Currently Reported

Well servicing costs	$	547,006	$	(11,006	)	$	536,000
Pressure pumping costs	101,130		(3,366		)	97,764
Fishing and rental costs	45,174		(2,856		)	42,318
General and administrative	124,814		17,228			142,042
Total	$	818,124	$	—		$	818,124

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 9—10—“Segment Information.” Our ~~remaining~~ 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 ~~4-10,~~04-10, since the operating segments meet the aggregation criteria, we ~~are permitted to combine~~have combined information about this segment with other similar segments that individually do not meet the quantitative thresholds ~~to produce a~~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 5—6—“Investment in IROC ~~Systems~~Energy Services Corp.”

In ~~January 2003,~~determining whether we should consolidate an entity within our financial statements, we apply the ~~Financial Accounting Standards Board (“FASB”) issued~~provisions of FASB Interpretation No. 46 (as amended), “Consolidation of Variable Interest ~~Entities—an Interpretation of ARB No. 51” (“FIN 46”). In December 2003 the FASB issued the updated and final interpretation of ARB No. 51~~Entities” (“FIN 46R”). FIN 46R requires that an equity investor in a variable interest entity have significant equity at risk ~~(generally a minimum of 10%, which is an increase from the 3% required under previous guidance)~~ 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

~~will be~~ is required to consolidate the variable interest entities created or obtained after March 15, 2004. ~~The adoption~~

As further discussed in Note 2 — “Acquisitions,” on September 5, 2007, we acquired all the outstanding shares of ~~FIN 46R did not materially impact~~AMI, a privately-held Canadian company. On the date of acquisition, AMI owned a 48% interest in another privately-held Canadian company, Advanced Flow Technologies, Inc. (“AFTI”). In connection with the acquisition, we were required to exercise an option that increased AMI’s ownership of AFTI to 51.46%. As a result, we now consolidate AFTI into our ~~consolidated~~ financial ~~statements.~~statements, with the remaining 48.54% representing a minority interest.

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 ~~March 31, 2006,~~September 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 September 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 at par 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 marketable securities 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 September 30, 2007 was approximately $110.2 million.

Accounts Receivable

In August and September of 2007, our Argentina subsidiary factored certain of its accounts receivable in order to improve that subsidiary’s working capital position. Five invoices with a total aggregate amount of $3.1 million were factored with recourse to us. Fees of less than $0.1 million were paid on the factored receivables on net 30 days terms. The invoices were factored in order to cover a short-term working capital shortage resulting from retroactive salary increases paid to union employees in Argentina. We do not anticipate factoring additional receivables in the future.

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 ~~and~~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.

~~Adoption of SFAS 143 was required for all companies with fiscal years beginning after June 15, 2002.~~ Amortization of the assets associated with the asset retirement obligations was $0.1 million and $0.1 million for the quarters ended ~~March 31,~~September 30, 2007, and 2006, respectively. Amortization of the assets associated with the asset retirement obligations was $0.4 million and ~~2005,~~$0.4 million for the nine months ended September 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 ~~March 31, 2006~~September 30, 2007 and December 31, ~~2005,~~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 newly constructed 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 nine months ended September 30, 2007 (in thousands):

	Three Months Ended September 30, 2007			Nine Months Ended September 30, 2007
Depreciation and amortization expense using prior lives	$	29,819		$	86,005
Impact of change	1,366			5,478
Depreciation and amortization expense, as reported	$	31,185		$	91,483

Diluted earnings per share using prior lives	$	0.28		$	1.06
Impact of change on diluted earnings per share	(0.01		)	(0.04		)
Diluted earnings per share, as reported	$	0.27		$	1.02

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, ~~2005.~~2006. The assessments did not result in an indication of goodwill impairment.

~~Intangible~~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 ~~March 31,~~September 30, 2007 and 2006 ~~and 2005~~ was ~~$0.6~~$0.5 million and ~~$0.7~~$0.5 million, respectively. Amortization of patents and trademarks for the quarters ended ~~March 31,~~September 30, 2007 and 2006 ~~and 2005~~ was ~~$0.1~~$0.2 million and $0.1 million, respectively. Amortization of noncompete agreements for the nine months ended September 30, 2007 and 2006 was $1.3 million and $1.7 million, respectively. Amortization of patents and trademarks for the nine months ended September 30, 2007 and 2006 was $0.6 million and $0.4 million, respectively. During the ~~three~~nine months ended ~~March 31, 2006,~~September 30, 2007, the Company capitalized approximately ~~$0.1~~$0.5 million of costs associated with patents and trademarks. ~~No costs associated~~ During the nine months ended September 30, 2007, the Company capitalized approximately $1.8 million related to a two-year noncompete agreement

with our former Chief Executive Officer. Through September 30, 2007, amortization of this noncompete ~~agreements were capitalized during~~agreement was approximately $0.2 million.

As further discussed in Note 2 — “Acquisitions,” in connection with our acquisition of AMI in September 2007, we recorded approximately $3.5 million of goodwill and $7.2 million of specifically identifiable intangibles subject to amortization under SFAS 142. Amortization of these assets for the ~~first quarter of 2006.~~three and nine months ended September 30, 2007 was less than $0.1 million.

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)~~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 derivative 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 ~~such that~~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 interest-rate~~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 4—“Derivative Financial Instruments” for further discussion.

~~Guarantees~~

In ~~November 2002, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements~~connection with our acquisition of AMI in September 2007 (see Note 2 — “Acquisitions”), we became party to four swap arrangements that exchanged Singaporean Dollars (“SGD”) for ~~Guarantees, Including Indirect Guarantees of Indebtedness of Others”~~Canadian Dollars (“~~FIN 45”~~CDN”). ~~As required by FIN 45, we adopted~~These agreements meet the disclosure requirements on December 31, 2002. On January 1, 2003, we adopted the initial recognition and measurement provisions for guarantees issued or modified after December 31, 2002. In November 2005, the FASB issued FASB Staff Position No. 45-3, “Application of FASB Interpretation No. 45 to Minimum Revenue Guarantees Granted to Business or Its Owners” (“FSP FIN No. 45-3”). It 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 No. 45-3, a guarantor is required to recognize, at the inceptiondefinition of a ~~guarantee,~~derivative under SFAS 133 and as such will be recorded at fair value on our consolidated balance sheet. We have not elected to treat these derivatives as cash flow hedges, and as a ~~liability for~~result, any gains or losses arising out of changes in the fair value of ~~the obligation undertaken~~these contracts will be recorded as unrealized gains or losses in ~~issuing the guarantee. FSP FIN No. 45-3 is effective~~our statements of operations as a part of other income and expense. See Note 4—“Derivative Financial Instruments” for ~~new minimum revenue guarantees issued or modified on or after January 1, 2006. The adoption of FIN 45 and FSP FIN No. 45-3 did not have a material impact on our consolidated financial statements.~~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 ~~year.~~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 March 31,
2006

Three Months
Ended March 31,
2005

(in thousands, except per share data)

Basic EPS Computation:

Numerator

Income from continuing operations

$
30,063

$
8,365

Discontinued operations, net of tax

—

(3,361
)
Net income

$
30,063

$
5,004

Denominator

Weighted average shares outstanding

131,339

130,791

Basic EPS:

Income from continuing operations

$
0.23

$
0.06

Discontinued operations, net of tax

—

(0.03
)
Net income (loss)

$
0.23

$
0.03

Diluted EPS Computation:

Numerator

Income from continuing operations

$
30,063

$
8,365

Discontinued operations, net of tax

—

(3,361
)
Net income

$
30,063

$
5,004

Denominator

Weighted average shares outstanding

131,339

130,791

Stock options

2,635

2,011

Warrants

551

489

134,525

133,291

Diluted EPS:

Income from continuing operations

$
0.22

$
0.06

Discontinued operations, net of tax

—

(0.03
)
Net income

$
0.22

$
0.03

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007			2006
	(in thousands, except per share data)

Basic EPS Computation:
Numerator
Net income	$	35,896	$	60,885	$	136,222	$		130,531

Denominator
Weighted average shares outstanding	131,738		131,291		131,665		131,322

Basic earnings per share	$	0.27	$	0.46	$	1.03	$		0.99

Diluted EPS Computation:
Numerator
Net income	$	35,896	$	60,885	$	136,222	$		130,531

Denominator
Weighted average shares outstanding	131,738		131,291		131,665		131,322
Stock options	1,436		2,356		1,689		2,688
Warrants	562		540		577		554
Stock appreciation rights	72		—		24		—
	133,808		134,187		133,955		134,564

Diluted earnings per share	$	0.27	$	0.45	$	1.02	$		0.97

The diluted earnings per share calculation for the quarters ended ~~March 31,~~September 30, 2007 and 2006 ~~and 2005~~ excludes the potential exercise of ~~zero~~44,500 and ~~330,000~~776,000 stock options, respectively, because the effects of such exercises on earnings per share in those ~~years~~periods would be anti-dilutive. The diluted earnings per share calculation for the nine months ended September 30, 2007 and 2006 excludes the potential exercise of 27,500 and 258,667 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.

SFAS 123 sets forth alternative accounting and disclosure requirements for stock-based compensation arrangements. Companies were permitted to continue following the provisions of APB 25 to measure and recognize employee stock-based compensation prior to January 1, 2006; however, SFAS 123 requires disclosure of pro forma net income and earnings per share that would have been reported under the fair value recognition provisions of SFAS 123. The following table illustrates the effect on net income and earnings per share if we had applied the fair value recognition principles of SFAS 123 to stock-based employee compensation in 2005. As noted above, while we followed APB 25 to account for stock-based compensation during 2005, the stock-based compensation expense included in net income or loss in the following table represents the compensation expense for the 875,180 options, net of forfeitures, that were granted at strike prices ranging from $0.10 to $2.53 below the market price of our common stock on the date of grant. During the years in which we applied APB 25, we elected to amortize any compensation cost on a straight-line basis over the vesting period of the award, in accordance with FASB Interpretation No. 28, “Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans, an Interpretation of APB Opinions No. 15 and 25” (“FIN 28”). After the adoption of SFAS 123(R), we elected to amortize compensation cost associated with the fair value of equity-based awards ratably over the vesting period of the award.

Three Months
Ended March 31,
2005

(in thousands,
except per share
amounts)

Net income

As reported

$
5,004

Add: stock-based employee compensation expense included in reported net income, net of related tax effects

24

Deduct: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects

(296
)

Pro forma

$
4,732

Basic earnings per share:

As reported

$
0.03

Pro forma

$
0.03

Diluted earnings per share:

As reported

$
0.03

Pro forma

$
0.03

~~For additional information regarding the computations presented above, see Note 8—“Stockholders’ Equity.”~~

~~In addition to the stock option grants discussed above, beginning~~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. In 2005, for shares with immediate vesting, the Company recognized expense equal to the intrinsic value of the shares on the date of grant immediately in earnings. For restricted shares that did not immediately vest, compensation cost equal to the intrinsic value of the grant, net of actual and estimated forfeitures,

~~was recognized in earnings ratably over the vesting period of the grant. In 2006, subject~~Subject to the provisions of SFAS 123(R), the Company ~~recognized~~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.

In August 2007, the Company issued stock appreciation rights (“SARs”) to all of its executive officers. Each SAR award has a ten-year term from the date of grant and vests in equal annual installments on the first, second and third anniversaries of the date of grant. Upon the exercise of an SAR, the recipient will receive an amount equal to the difference between the exercise price and the fair market value of a share of the Company’s common stock on the date of exercise multiplied by the number of shares of common stock for which the SAR was exercised. All payments will be made in shares of the Company’s common stock. Prior to exercise, the SAR does not entitle the recipient to receive any shares of the Company’s common stock and does not provide the recipient with any voting or other stockholder rights. The Company accounts for the SARs as equity awards under SFAS 123(R) and recognizes compensation expense ratably over the vesting period of the SAR based on its fair value on the date of issuance, net of estimated and actual forfeitures.

Foreign Currency Gains and Losses

The local currency is the functional currency for our foreign operations in Argentina, Canada and ~~our former Canadian operations. The U.S. dollar is the functional currency for our former operations in Egypt.~~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.

2.~~DISCONTINUED OPERATIONS~~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 ~~15, 2005, we sold~~1, 2007 and recorded a $1.3 million decrease to the ~~majority~~balance of our ~~contract drilling operations~~retained earnings as of January 1, 2007 to ~~Patterson-UTI Energy, Inc.~~reflect the cumulative effect of adopting these standards. See Note 3—“Income Taxes” for ~~$62.0~~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 ~~in cash. We received net proceeds~~of 14% Senior Subordinated Notes due January 25, 2009 (the “14% Senior Subordinated Notes”) and 150,000 warrants to purchase an aggregate of approximately ~~$60.5~~2.2 million shares of the Company’s common stock at an exercise price of $4.88125 per share (the “Warrants”). As of September 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 past failure to file our SEC reports in a timely manner, we do not have an effective registration statement covering the Warrants, and have been required to make liquidated damages payments, and will continue to be required to make those payments until such time as we have an effective registration statement on file for exercise of the Warrants or the warrant

shares issuable thereunder are eligible for resale without registration pursuant to SEC Rule 144 or otherwise. The requirement to make liquidated damages payments constitutes an 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.

2. ACQUISITIONS

Acquisition of Advanced Measurements, Inc.

On September 5, 2007, the Company, through its wholly-owned Canadian subsidiaries, purchased all of the outstanding shares of AMI, a privately-held Canadian technology company focused on oilfield service equipment controls, data acquisition, and digital information work flow. We made this acquisition in order to improve our access to oilfield services technology.

The purchase price was approximately $6.6 million in cash ~~after paying all costs~~and approximately $3.1 million of assumed debt, which was repaid in September and November 2007. The purchase agreement also provided for deferred cash payments of up to $1.78 million related to ~~closing~~ the ~~sale.~~retention of key AMI employees. These deferred payments will be expensed as incurred.

On the date of acquisition, AMI owned a 48% interest in AFTI, a privately-held Canadian technology company focused on low cost wireless gas well production monitoring. This 48% interest was transferred to us as part of the purchase. In addition, as part of the purchase of AMI we were required to exercise an option to increase AMI’s interest in AFTI to 51.46%. The cost to exercise this option was approximately $0.5 million. As a result, AMI now owns a 51.46% interest in AFTI, and as such we consolidate AFTI into our financial statements, with the remaining 48.54% representing a minority interest.

The following table summarizes the preliminary estimated fair values of the ~~sale,~~assets acquired and the liabilities assumed at the date of acquisition (in thousands of USD):

Cash.	$	628
Other current assets	2,881
Property and equipment	555
Goodwill	3,522
Intangible assets	7,241
Other assets	1,013
Total assets acquired	15,840

Current liabilities	1,559
Long-term debt and capital leases	3,118
Deferred tax liability	4,219
Minority interest	334
Total liabilities assumed	9,230
Net assets acquired	$	6,610

The allocation of purchase price to specific assets and liabilities is based, in part, upon outside appraisals using customary valuation procedures and techniques. The allocation is still preliminary at this ~~operation, which~~time, and may potentially change by a material amount as our purchase accounting is finalized. We anticipate finalizing our allocation of purchase price in the fourth quarter of 2007, once the final tax basis of the assets and liabilities acquired has been determined and our valuation of AMI’s intangible assets is completed.

Goodwill was ~~previously reported~~recognized as part of ~~our contract drilling segment,~~the acquisition of AMI as the purchase price exceeded the fair value of the acquired assets and liabilities. We believe that the goodwill associated with the AMI acquisition is related to the acquired workforce and was therefore not allocated to the assets and liabilities acquired.

All of the $7.2 million of acquired intangible assets is subject to amortization under SFAS 142 and has a weighted-average remaining useful life of approximately 8.7 years. These intangible assets relate primarily to developed technology and customer backlog. The $3.5 million of goodwill associated with the purchase of AMI has been ~~presented as~~allocated to our Well Servicing segment; of that amount, none is expected to be deductible for income tax purposes.

In connection with our acquisition of AMI, we became party to a ~~discontinued operation for all periods. We recorded an after-tax loss from discontinued operations~~revolving credit agreement with a maximum outstanding amount of ~~$3.4~~$0.9 million. As of September 30, 2007, AMI had drawn approximately $0.2 million ~~or $0.03 per diluted share, for the three months ended March 31, 2005~~.

~~Results for activities reported as discontinued operations were as follows:~~

Three Months Ended March 31,

2006

2005

(in thousands)

Revenues

$
—

$
3,361

Costs and expenses

—

2,132

Income before income taxes

—

1,229

Income tax expense

—

(4,590
)
Loss from discontinued operations

$
—

$
(3,361
)

~~Balance sheet data for discontinued operations was as follows:~~

March 31, 2006

December 31, 2005

(in thousands)

Current assets

$
658

658

Current liabilities

(282
)
(292
)
Net assets of discontinued operations

$
376

$
366

on this line of credit. In November 2007, we transferred $0.9 million to AMI in order to pay off amounts outstanding under this facility and terminate it, and to provide additional working capital.

3.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 daylight rigs for well servicing and workovers and twenty-four hour rigs for shallow drilling, sidetracking and deep workovers. In addition, the Moncla companies operate 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.

Under the stock purchase agreement, the purchase price for Moncla was, subject to certain adjustments, $145.0 million, of which $112.5 million would be paid at closing, with the balance consisting of two unsecured notes totaling $22.5 million and the assumption of approximately $10.0 million in long-term debt. The notes payable to the sellers consist of one note in the amount of $12.5 million that would be due and payable in a lump-sum, together with accrued interest, on the second anniversary of the closing. The second note would be payable in annual installments of $2.0 million, plus accrued interest, on each of the first through fifth anniversaries of the closing. Each of the notes would bear interest at the Federal Funds rate adjusted annually on the anniversary date of the closing date. Long-term debt assumed in the acquisition was paid off at closing. In addition, the purchase agreement provides for an earnout of up to $25.0 million over the next five years. The Moncla acquisition closed on October 25, 2007. See Note 11—“Subsequent Events.”

3. INCOME TAXES

~~Income~~The Company’s effective tax ~~expense differs from amounts computed by applying~~rate for the nine months ended September 30, 2007 and 2006 was 38.9% and 38.2%, respectively. The primary difference between the statutory ~~federal~~ rate ~~as follows:~~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.

Three Months Ended March 31,

2006

2005

Income tax computed at statutory rate

35.0
%
35.0
%
State taxes

1.4
%
2.5
%
Meals and entertainment

0.8
%
2.1
%
Executive and share-based compensation

1.2
%
0.6
%
Foreign rate differential

—
%
(0.6
)%
Change in valuation allowance

—
%
—
%
Other

(0.5
)%
0.4
%
Effective income tax rate

37.9
%
40.0
%

FIN No. 48 and FSP FIN 48-1.On July 12, 2006, the FASB issued 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 FSP FIN 48-1. FSP FIN 48-1 provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. In determining whether a tax position has been effectively settled, entities must evaluate (i) whether taxing authorities have completed their examination procedures; (ii) whether the entity intends to appeal or litigate any aspect of a tax position included in a completed evaluation; and (iii) whether it is remote that a taxing authority would examine or re-examine any aspect of a taxing position. FSP FIN 48-1 is to be applied upon the initial adoption of FIN 48.

We adopted the provisions of FIN 48 and FSP FIN 48-1 on January 1, 2007 and recorded a $1.3 million decrease to the balance of our retained earnings as of January 1, 2007 to reflect the cumulative effect of adopting these standards. As of January 1, 2007 and September 30, 2007, we had approximately $3.9 million and $4.1 million, respectively, 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 and foreign jurisdictions. We have substantially concluded all U.S. federal and state 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 $1.5 million and $1.0 million for the payment of interest and penalties as of September 30,

2007 and January 1, 2007, respectively. We do not expect any substantial changes within the next 12 months related to uncertain tax positions.

4.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 ~~March 31, 2006,~~September 30, 2007, our ~~variable rate~~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~~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 ~~March 31, 2006,~~September 30, 2007, we recorded ~~$1.1~~less than $0.1 million in current assets, less than $0.1 million in current liabilities and ~~$0.4~~$0.3 million in long-term liabilities in our Consolidated Balance Sheets, based on the fair value of our derivative instruments on that date. During the ~~three~~nine months ended ~~March 31, 2006,~~September 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 nine months ended ~~March 31, 2006,~~September 30, 2007, no amounts were reclassified to earnings in connection with forecasted transactions whose occurrence was no longer considered probable. ~~During~~

Foreign Currency Instruments

In connection with our acquisition of AMI in September 2007 (see Note 2 — “Acquisitions”), we became party to four swap arrangements that exchanged Singaporean Dollars (“SGD”) for Canadian Dollars (“CDN”). These agreements meet the ~~next twelve months,~~definition of a derivative under SFAS 133 and as such are recorded at fair value on our Consolidated Balance Sheets. We have not elected to treat these derivatives as cash flow hedges, and as a result, and gains or losses arising out of changes in the ~~Company anticipates that~~fair value of these contracts are recorded as unrealized gains or losses in our Consolidated Statements of Operations as a part of other income and expense.

As of September 30, 2007, the aggregate notional amount of ~~Accumulated Other Comprehensive Loss that will be reclassified to earnings upon settlement~~these contracts was approximately $0.9 million USD and the aggregate fair value of ~~hedge transactions will be less than $1 million.~~ these contracts was not material. The last of these contracts settle in January 2008. For the three and nine months ended September 30, 2007, the unrealized holding loss associated with these instruments was immaterial.

5. OTHER CURRENT AND NON-CURRENT ACCRUED LIABILITIES:

As of September 30, 2007 and December 31, 2006, the Company’s current accrued liabilities consisted of the following:

	September 30, 2007		December 31, 2006
	(in thousands)
Accrued payroll, taxes and employee benefits	$	58,383	$	64,876
Accrued operating expenditures	56,060		40,150
Income, sales, use and other taxes	29,649		30,282
Workers’ compensation accrual	14,633		17,325
Unsettled Legal Claims	7,201		28,754
Vehicular Insurance	3,874		3,298
Equity-based compensation	1,417		—
Accrued rent	421		834
Accrued severance	280		631
Deferred gain on sale-leaseback transactions	159		159
Other	2,524		3,261
Total	$	174,601	$	189,570

As of September 30, 2007 and December 31, 2006, the Company’s other non-current accrued liabilities consisted of the following:

	September 30, 2007		December 31, 2006
	(in thousands)
Asset retirement obligations	$	9,113	$	9,622
Evironmental liabilities	2,983		4,683
Accrued rent	2,939		3,241
Accrued income taxes	4,140		2,507
Equity-based compensation	1,477		—
Deferred gain on sale-leaseback transactions	603		722
Severance accruals	73		234
Other	860		247
Total	$	22,188	$	21,256

6. INVESTMENT IN IROC ~~SYSTEMS~~ENERGY SERVICES CORP.

~~On July 22, 2004,~~As of September 30, 2007 and December 31, 2006, we ~~entered into an agreement with~~owned 8,734,469 shares of IROC Energy Services Corp., formerly known as IROC Systems Corp. (“IROC”), an Alberta-based oilfield services ~~company, to sell IROC ten remanufactured Skytop well service rigs, along with supporting equipment~~company. This represented approximately 19.7% and inventory. We began delivering these rigs in the fall of 2004, and completed delivery in the second quarter of 2005. The purchase price for the rigs was $7.0 million USD, which was paid by way of the issuance of approximately 8.2 million shares of IROC’s common stock. During 2004, we recognized a loss of $0.1 million, which represents the difference between the fair market value of the IROC shares we received on the delivery dates and the carrying values of the rigs that were delivered. We delivered four additional rigs during 2005, and we recognized a gain of $1.9 million upon delivery, which represents the carrying value of the delivered rigs and the fair market value of the IROC shares we received on the delivery dates.

In July 2005, we sold additional well service rig support equipment to IROC for $0.9 million USD, and received another 547,411 shares of IROC common stock as consideration. We recognized a gain of $0.7 million on this transaction, which represents the difference between the fair market value of the IROC shares we received on the delivery dates and the carrying value of the equipment transferred.

~~As of March 31, 2006, we own 8,734,469 shares of IROC common stock, which represents approximately 23.1%~~23.0% of IROC’s outstanding common stock on ~~that date.~~September 30, 2007 and December 31, 2006, respectively. IROC shares trade on the Toronto Venture Stock Exchange and had a closing price of ~~$3.70~~$1.48 CDN and $2.10 CDN per share on ~~March~~September 30, 2007 and December 31, ~~2006. Pursuant to the terms of the agreement with IROC,~~2006, respectively. Mr. William Austin, our Chief Financial Officer, and Mr. Newton W. Wilson III, our General Counsel, ~~were appointed to~~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. ~~The value~~Our ownership interest percentage in IROC declined as a result of ~~our~~IROC issuing additional common stock during the nine months ended September 30, 2007. Our investment in IROC totaled $10.9 million and $10.7 million as of September 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 ~~$0.5~~$0.3 million of income and ~~$0.1~~$0.2 million ~~respectively,~~ of ~~equity income~~loss, respectively, related to our investment in IROC for the ~~quarters~~nine months ended ~~March 31, 2006~~September 30, 2007 and ~~2005.~~2006. During those time periods, no earnings were distributed back to us by IROC in the form of dividends. ~~The value of our investment in IROC totaled $10.7 million and $10.3 million as of March 31, 2006 and December 31, 2005, respectively.~~

6.7. LONG-TERM DEBT

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

	September 30,			December 31,
	2007			2006
	(in thousands)

Senior Credit Facility term loans	$	394,000		$	396,000
Capital lease obligations	27,740			25,794
AMI Credit Facility	191			—
	421,931			421,794
Less: current portion	(15,942		)	(15,714		)
Total long-term debt	$	405,989		$	406,080

March 31, 2006

December 31, 2005

(in thousands)

Senior Secured Credit Facility Term Loans

$
399,000

$
400,000

Capital Leases

23,597

23,420

422,597

423,420

Less current portion

12,710

12,639

Total long-term debt

$
409,887

$
410,781

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 ~~existing~~then-existing 8.375% Senior Notes due 2013 and our ~~existing~~then-existing 6.375% Senior ~~Notes.~~Notes due 2008. 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,~~June 30, 2006 by 0.50% because the Company did not meet certain filing targets for our ~~2003~~ Annual Report on Form ~~10-K.~~10-K for the year ended December 31, 2003. 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. No fees were paid in association with the First Amendment.

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 Annual Report on Form 10-K for the year ended December 31, 2006, 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.

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 were required to file our quarterly reports for the periods ending March 31 and June 30, 2007. All of these filings occurred prior to the due dates specified in the Third Amendment. We paid fees associated with the Third Amendment of approximately $1.2 million.

As of ~~March 31, 2006,~~September 30, 2007, the Company is in compliance with the debt covenants and had no borrowings under the revolving credit facility of the Senior Secured Credit Facility and had ~~$399.0~~$394.0 million borrowed at three-month Eurodollar rates, plus a margin of ~~3.75%~~2.50%. The weighted average interest rate on our outstanding debt, excluding our capital lease obligations, was approximately 5.39% as of September 30, 2007. As described above, the Company has interest rate swaps that hedge a portion of the interest rate expense on the term loan.

In connection with the consummation of the Moncla acquisition, one of our wholly-owned subsidiaries granted two unsecured promissory notes to the seller. Additionally, in November 2007, we commenced a private placement offering of up to $400 million of senior notes due 2017, entered into a commitment letter for a new senior secured credit facility, and entered into negotiations to amend our existing Senior Secured Credit Facility. See Note 11 — “Subsequent Events.”

~~Prior Senior~~AMI Credit Facility

As discussed in Note 2 — “Acquisitions,” upon our acquisition of AMI, we became party to a $0.9 million line of credit facility that AMI used to fund its working capital requirements prior to the acquisition. As of September 30, 2007, AMI had drawn approximately $0.2 million on this line of credit. On November ~~10, 2003,~~1, 2007, we entered into a Fourth Amended and Restated Credit Agreement (the “Prior Senior Credit Facility”). The Prior Senior Credit Facility consisted of a $175.0 million revolving loan facility with the entire facility available for letters of credit. We previously had the right, subject to certain conditions, to increase the total commitment under the Prior Senior Credit Facility from $175.0transferred $0.9 million to upAMI

in order to ~~$225.0 million if we were able~~pay off amounts outstanding under this line of credit facility and to ~~obtain additional lending commitments.~~fund future working capital requirements. The ~~revolving loan commitments were scheduled~~Company intends to terminate on November 10, 2007, and all revolving loans would have been required to be paid on or before that date. The revolving loans bore interest based upon, at our option, the agent’s base rate for loans or the agent’s reserve-adjusted LIBOR rate for loans, plus, in either case, a margin which would fluctuate based upon our consolidated total leverage ratio and, in either case, according to the pricing grid set forththis facility in the ~~Prior Senior Credit Facility.~~

The Prior Senior Credit Facility contained various financial covenants applicable to specific periods, including: (i) a maximum consolidated total leverage ratio, (ii) a minimum consolidated interest coverage ratio, and (iii) a minimum net worth. The Prior Senior Credit Facility subjected us to other restrictions, including restrictions upon our ability to incur additional debt, liens and guarantee obligations, to merge or consolidate with other persons, to make acquisitions, to sell assets, to pay dividends, repurchase our stock or subordinated debt, to make investments, loans and advances or to make changes to debt instruments and organizational documents. All obligations under the Prior Senior Credit Facility were guaranteed by most of our subsidiaries and were secured by most of our assets, including our accounts receivable, inventory and most equipment.

Our failure to file our 2003 Annual Report on Form 10-K on a timely basis violated covenants under the Prior Credit Facility. Between March 31, 2004 and July 29, 2005, we amended the terms of the Prior Senior Credit Facility six times to waive the covenants and extend the due date for the 2003 report and other filings. We paid a total of $1.1 million and $1.3 million in fees during the years ended December 31, 2005 and 2004, respectively, related to the various amendments to the Prior Senior Credit Facility. The final due date under the Prior Senior Credit Facility for the filing of our Annual Report on Form 10-K for 2004 and the Quarterly Reports on Form 10-Q for the first three quarters of 2004 was October 31, 2005. The last amendment also extended the date by which the Quarterly Reports on Form 10-Q for the first quarter and secondfourth quarter of ~~2005 had to be filed to December 31, 2005. On July 29, 2005, we entered into the Senior Secured Credit Facility, which replaced the Prior Senior Credit Facility.~~2007.

~~6.375% Senior Notes~~

On May 14, 2003, we completed a public offering of $150.0 million of 6.375% Senior Notes due May 1, 2013 (the “6.375% Senior Notes”). The proceeds from the public offering, net of fees and expenses, were used to repay the balance of the revolving loan facility then outstanding under our then-existing credit facility, with the remainder being used for general corporate purposes. The 6.375% Senior Notes were senior unsecured obligations and were fully and unconditionally guaranteed by substantially all of our subsidiaries. The 6.375% Senior Notes were effectively subordinated to Key’s secured indebtedness, which included borrowings under our Prior Senior Credit Facility.

~~The 6.375% Senior Notes were repaid on October 5, 2005. Proceeds from the Senior Secured Credit Facility and cash on hand were used to repay the 6.375% Notes.~~

~~8.375% Senior Notes~~

On March 6, 2001, we completed a private placement of $175.0 million of 8.375% Senior Notes due March 1, 2008 (the “8.375% Senior Notes,” together with the 6.375% Senior Notes, the “Senior Notes”). The net cash proceeds from the private placement were used to repay all of the remaining balance of prior term loans and a portion of the revolving loans then outstanding under our then-existing credit facility. On March 1, 2002, we completed a public offering of an additional $100.0 million of 8.375% Senior Notes. The net cash proceeds from the public offering were used to repay the then-outstanding balance of the revolving loan facility under our credit facility. The 8.375% Senior Notes were senior unsecured obligations. The 8.375% Senior Notes were effectively subordinated to Key’s secured indebtedness which included borrowings under our Prior Senior Credit Facility.

We redeemed all $275.0 million outstanding principal amount of the 8.375% Notes on November 8, 2005. Proceeds from the Senior Secured Credit Facility and cash on hand were used to repay the 8.375% Notes.

~~Consents to Amend to Extend the Reporting Requirements Under the Senior Note Indentures~~

Our failure to file our 2003 Annual Report on Form 10-K with the SEC and deliver it to the trustee under the Senior Note indentures on or before March 30, 2004 was a default under each of the indentures for the Senior Notes. During 2004 and 2005, we amended the terms of each of the Senior Note indentures three times to waive the covenant non-compliance and extend the due date for our 2003 Annual Report on Form 10-K and other filings. In order to obtain these amendments and consents, we incurred $9.0 million and $5.1 million of expenses in 2005 and 2004, respectively. We were required under the last consent by the holders of each series of Senior Notes to file our 2003 Annual Report on Form 10-K on or before May 31, 2005 and our 2004 Quarterly Reports on Form 10-Q and our Annual Report on Form 10-K for 2004 on or before July 31, 2005. The consent also provided that the Quarterly Reports on Form 10-Q for the first quarter and second quarter of 2005 had to be filed no later than October 31, 2005. We failed to meet those deadlines, and as a result, on June 6, 2005, the trustee for the Senior Notes sent us notice of the financial reporting violation, which then triggered a 60-day cure period. Due to our failure to cure this default, on September 28, 2005, we received a valid acceleration notice from the trustee for the 6.375% Senior Notes. As a result, the 6.375% Senior Notes were repaid on October 5, 2005. We also redeemed all of the 8.375% Senior Notes on November 8, 2005. The Senior Notes were repaid with funds from our Senior Secured Credit Facility and cash on hand.

~~14% Senior Subordinated Notes~~

On January 22, 1999, we completed the private placement of 150,000 units (the “Units”) consisting of $150.0 million of 14% Senior Subordinated Notes due January 15, 2009 (the “14% Senior Subordinated Notes”) and 150,000 warrants to purchase 2,173,433 shares of the Company’s common stock at an exercise price of $4.88125 per share (the “Warrants”). The 14% Senior Subordinated Notes were issued at a discount, which was amortized to interest expense over the term of the 14% Senior Subordinated Notes. During the years prior to 2004, we redeemed approximately $52.5 million of principal amount of our 14% Senior Subordinated Notes at varying times and redemption prices, plus accrued interest. We repaid the remaining $97.5 million outstanding principal amount of the 14% Senior Subordinated Notes on January 15, 2004.

As of March 31, 2006, 63,500 Warrants had been exercised, providing $4.2 million of proceeds to us and leaving 86,500 Warrants outstanding. 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 covering the shares of common stock issuable upon exercise. If we are unable to maintain an effective registration statement, we are required to pay liquidated damages 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 $0.1 million during the three months ended March 31, 2006 and 2005, respectively.

Interest Expense

Interest expense for the three and nine months ended ~~March 31,~~September 30, 2007 and 2006 ~~and 2005~~ consisted of the following:

	Three Months Ended March 31,						Three Months Ended September 30,
	2006			2005			2007			2006
	(in thousands)						(in thousands)
Cash payments	$	8,264		$	12,369		$	7,919		$	9,721
Commitment and agency fees paid	711			3,819			653			1,147
Amortization of discount and premium	—			(62		)
Amortization of debt issuance costs	400			575			471			404
Net change in accrued interest	(60		)	(3,233		)	416			93
Capitalized interest	(737		)	(115		)	(1,545		)	(955		)
Total interest expense	$	8,578		$	13,353		$	7,914		$	10,410

	Nine Months Ended September 30,
	2007			2006
	(in thousands)
Cash payments	$	22,955		$	25,785
Commitment and agency fees paid	2,634			3,390
Amortization of debt issuance costs	1,329			1,207
Net change in accrued interest	2,856			1,205
Capitalized interest	(3,543		)	(2,570		)
Total interest expense	$	26,231		$	29,017

7.8. 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.

~~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.

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 ~~intend to vigorously defend against this action; however, we cannot predict the outcome of the lawsuit. 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.

~~Eustace Matter.~~ Joe Eustace was employed by Key from 1999 until 2004 as a Vice President and Regional Manager pursuant to an employment agreement. He filed suit in January 2006 alleging breach of contract, fraud and conversion seeking reinstatement of his stock options. 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.~~million, which was paid on July 5, 2007.

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 $0.8 million) 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 385^th 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. Partial summary judgment motions have been made by both parties, and we are awaiting the court’s decisions. Further, our former controller and assistant controller filed a joint complaint against the Company on September 3, 2006 in 133^rd 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 was dismissed and the parties agreed to a remand of the case back to the state court. Discovery is now ongoing.

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

Shareholder Class Action ~~Suits.~~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.

~~Shareholder Derivative Actions.~~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.

~~In each of~~On September 7, 2007, the ~~shareholder~~Company reached agreements in principle to settle all pending securities class ~~actions~~action and derivative ~~actions described above, plaintiffs are seeking an unspecified~~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 ~~monetary damages. At this time, we cannot ascertain the ultimate aggregate amount of monetary liability or financial impact of the~~documentation and court approval following notices to all potential claimants eligible for class actions and derivative lawsuits. While we have directors and officers insurance in the aggregate amount of $50.0 million, we cannot determine whether these actions will, individually or collectively, have a material adverse effect on our business, results of operations, financial condition and cash flows. We and named directors and officers intend to vigorously defend these actions. participation. A preliminary hearing, originally scheduled for October 24, 2007, has been reset for November 21, 2007. The final hearing is scheduled for 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 ~~March 31, 2006,~~September 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 ~~March 31, 2006~~September 30, 2007 and December 31, ~~2005,~~2006, we have recorded ~~$69.3~~$67.4 million and ~~$56.0~~$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 ~~March 31, 2006~~September 30, 2007 and December 31, ~~2005,~~2006, we have recorded ~~$5.2~~$3.0 million and ~~$5.3~~$4.7 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).

~~Francis D. John Employment Agreement.~~ Effective as of July 1, 2001, we entered into an amended and restated employment agreement with Francis D. John (the “2001 Employment Agreement”) pursuant to which Mr. John served as the Chairman of the Board, President and Chief Executive Officer of Key. The 2001 Employment Agreement provided for the payment of a one-time retention incentive payment of $13.1 million. The purpose of this retention incentive payment was to retire all amounts owed by Mr. John under incentive-based loans previously made to him (which, because certain performance criteria had been previously met, we were scheduled to forgive ratably over a ten-year period as long as Mr. John continued to serve Key in his capacity as Chairman of the Board, President and Chief Executive Officer) and in the process provide Mr. John with an incentive to remain with Key for the next ten years. On December 1, 2001, the incentive retention payment was paid to Mr. John and was comprised of two components: (i) $7.5 million in loan principal and interest accrued through the date of the payment and (ii) $5.6 million in a tax “gross-up” payment. The entire payment was withheld by us and used to satisfy Mr. John’s tax obligations and his obligations under the loans. Pursuant to the 2001 Employment Agreement, Mr. John would earn the incentive retention payment over a ten-year period beginning July 1, 2001, with one-tenth of the total bonus being earned on September 30 of each year, beginning on September 30, 2002. The 2001 Employment Agreement was amended and restated effective December 31, 2003 (the “2003 Employment Agreement”). Under the 2003 Employment Agreement, if Mr. John voluntarily terminated his employment with Key or if Mr. John was terminated by Key for Cause (as defined in the 2003 Employment Agreement), Mr. John would be obligated to repay the entire remaining unearned balance of the retention incentive payment immediately upon such termination. However, if Mr. John’s employment with Key was terminated (i) by Key other than for Cause, (ii) by Mr. John for Good Reason, (iii) as a result of Mr. John’s death or Disability (as defined in the 2003 Employment Agreement), or (iv) as a result of a Change in Control (as defined in the 2003 Employment Agreement), the remaining unearned balance of the retention incentive payment would be treated as earned as of the date of such event.

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 March 31, 2006 we have~~We ordered ~~five additional~~and took delivery of 25 rigs under ~~this option~~the agreement, returned 3 defective rigs for full credit and subsequently agreed with the seller to reduce the total number of rigs deliverable under the agreement to 22 rigs. Through September 30, 2007 we have received delivery of 10the 22 rigs and do not have any pending orders for additional rigs.

Expired Option Holders.On September 24, 2007, Belinda Taylor, on behalf of herself and all similarly situated residents of Texas, filed a lawsuit in the 11^th Judicial District of Harris County, Texas, alleging that the Company breached its contracts with former employees who held vested options that expired between April 28, 2004 and the date that the Company became current in its financial statements (the “Expired Option Holders”). The ~~purchase~~suit also alleges the Company breached its fiduciary duties and ~~sale agreement is cancelable at our option at any time. Should we cancel~~duties of good fair and fair dealing in the ~~agreement~~pricing of stock options it granted to those Expired Option Holders, based upon the alleged overstatement of assets prior to ~~taking delivery~~the Company’s restatement. She amended her lawsuit on September 25,2007, to include all Expired Option Holders, regardless of residence. The Company has denied the ~~30 well service rigs, we may be required to refund to~~allegations and does not believe that the ~~seller the amount~~ultimate resolution of ~~the contractual discount provided by the seller~~this matter will have a material impact on ~~the previously delivered well service rigs.~~our results of operations, cash flows or financial position.

8.9. STOCKHOLDERS’ EQUITY

Common Stock

On ~~March~~September 30, 2007, we had 200,000,000 shares of common stock authorized with a $0.10 par value, of which 131,890,674 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 ~~131,340,078 of these~~131,624,038 shares ~~of common stock~~ were issued and outstanding, net of ~~416,666 of~~497,501 shares held in treasury, and no dividends had been ~~issued.~~ declared or paid.

Common Stock Warrants

On ~~December 31, 2005,~~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 September 30, 2007, 63,500 Warrants had ~~200,000,000~~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 ~~authorized with~~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 past failure to file our SEC reports in a ~~$0.10 par~~timely manner, we do not have an effective registration statement covering the Warrants, and have been required to make liquidated damages payments, and will continue to be required to make those payments until such time as we have an effective registration statement on file for exercise of the Warrants or the warrant shares issuable thereunder are eligible for resale without registration pursuant to SEC Rule 144 or otherwise. 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 holders of the Warrants were $0.5 million and $0.4 million during the three months ended September 30, 2007 and 2006, respectively. The total amounts paid to the holders of the Warrants were $1.0 million and $0.9 million during the nine months ended September 30, 2007 and 2006, respectively.

Treasury Stock

During the nine months ended September 30, 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 ~~which 131,334,196~~the shares ~~were issued and outstanding, net~~based on the price of ~~416,666 shares held in treasury, and no dividends had been issued.~~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”~~“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 September 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 0.5 million Incentive Awards could still be issued under the 1997 Incentive Plan.

The following table summarizes the stock option activity related to the plans ~~(shares~~for the nine months ended September 30, 2007 (options in thousands):

Three Months Ended March 31, 2006

Options

Weighted
Average
Exercise Price

Weighted
Average Fair
Value

Outstanding at beginning of period

9,275

$
8.68

$
4.79

Granted

775

$
15.05

$
7.23

Exercised

—

$
—

$
—

Cancelled or expired

(44
)
$
9.78

$
4.43

Outstanding at end of period

10,006

$
9.17

$
4.98

Exercisable at end of period

8,656

$
8.49

4.75

	Options		Weighted Average Exercise Price		Weighted Average Fair Value

Outstanding at beginning of year	5,829		$	9.46	$	4.94
Granted	1,192		$	14.41	$	5.98
Exercised	—		$	—	$	—
Cancelled or expired	(813	)	$	10.26	$	5.00
Outstanding at end of period	6,208		$	10.36	$	5.13

Exercisable at end of period	4,165		$	8.34	$	4.51

The following tables summarize information about the stock options outstanding at ~~March 31, 2006 (shares~~September 30, 2007 (options in thousands):

Options Outstanding

Weighted
Average
Remaining
Contractual
Life (Years)

Number of
Options
Outstanding
March 31,
2006

Weighted
Average
Exercise Price

Weighted
Average
Fair Value

Range of Exercise Prices:

$3.00 - $8.00

4.38

2,216

$
6.54

$
3.77

$8.01 - $8.31

4.22

1,850

$
8.25

$
4.92

$8.32 - $8.75

4.47

1,738

$
8.48

$
5.35

$8.76 - $10.22

5.79

2,560

$
9.73

$
4.93

$10.23 - $15.05

7.87

1,642

$
13.62

$
6.39

10,006

$
9.17

$
4.98

Aggregate intrinsic value (in thousands)

$
8,589

Options Exercisable

Number of
Options
Exercisable
March 31,
2006

Weighted
Average
Exercise Price

Weighted
Average Fair
Value

Range of Exercise Prices:

$3.00 - $8.00

2,216

$
6.54

$
3.77

$8.01 - $8.31

1,850

$
8.25

$
4.92

$8.32 - $8.75

1,738

$
8.48

$
5.35

$8.76 - $10.22

2,394

$
9.69

$
5.00

$10.23 - $15.05

458

$
12.63

$
5.25

8,656

$
8.49

$
4.75

Aggregate intrinsic value (in thousands)

$
8,410

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

Range of Exercise Prices:
$3.00 - $7.44	1.75	944	$	4.85	$	3.44
$7.45 - $8.43	4.05	1,069	$	8.16	$	4.45
$8.44 - $11.75	4.35	1,681	$	9.36	$	4.96
$11.76 - $14.25	7.07	619	$	12.09	$	5.30
$14.26 - $18.90	9.34	1,895	$	14.66	$	6.46
		6,208	$	10.36	$	5.13

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

Range of Exercise Prices:
$3.00 - $7.44	944	$	4.85	$	3.44
$7.45 - $8.43	1,057	$	8.16	$	4.45
$8.44 - $11.75	1,676	$	9.36	$	4.93
$11.76 - $14.25	478	$	11.95	$	5.14
$14.26 - $18.90	10	$	14.51	$	7.19
	4,165	$	8.34	$	4.51

The weighted-average remaining contractual term of the outstanding exercisable options as of September 30, 2007, is approximately 4.0 years. The total fair value of stock options granted during the ~~quarter~~nine months ended ~~March 31, 2006~~September 30, 2007 was ~~$5.6~~$7.1 million. The fair value of each stock option granted during the ~~three~~nine months ended ~~March 31, 2006~~September 30, 2007 was estimated on the date of grant using the Black-Scholes option-pricing model, based on the following weighted-average assumptions:

	~~Three Months~~ ~~Ended March~~ ~~31, 2006~~

Risk-free interest rate	~~4.7~~	%4.4%
Expected life of options, years	~~6.00~~	6
Expected volatility of the Company’s stock price	~~49.0~~	%39.5%
Expected dividends	none

During the three months ended September 30, 2007 and 2006, we recognized approximately $1.0 million and $0.7 million, respectively, in compensation expense associated with options. For the nine months ended September 30, 2007 and 2006, we recognized approximately $2.2 million and $2.0 million, respectively, in compensation expense associated with options. Tax benefits of $0.2 million were recognized in association with stock options for the three and nine months ended September 30, 2007. For the options outstanding as of September 30, 2007, the Company expects that it will recognize approximately $9.1 million of expense over the next 1.5 years.

Common Stock Awards

~~Beginning in~~In June 2005, we began granting shares of common stock to our outside directors and certain employees. ~~These shares are restricted as~~Common stock awards granted to ~~exercisability and transferability, and in certain cases, have required service periods before they are vested~~our outside directors vest immediately, while those granted to our employees vest over a three-year period 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~~nine months ended ~~March 31,~~September 30, 2007 and 2006 was $4.5 million and ~~2005~~$0.7 million, respectively.

Pursuant to the agreement under which they are issued restricted stock, recipients of common share awards may have shares withheld in order to satisfy those individuals’ income tax obligations associated with the vesting of the awards granted to them. We account for these as treasury stock transactions. In connection with a vesting in June of 2006, one of the recipients 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 nine months ended September 30, 2007 and 2006 was $0.1 million and ~~$6.5~~$0.1 million, respectively. ~~No common stock awards were granted prior to June 2005.~~

~~We issued a total of 5,882 common shares to an outside director~~Compensation expense recognized for this award during the ~~three~~quarters ended September 30, 2007 and 2006 was less than $0.1 million in both periods.

The following table summarizes information for the nine months ended ~~March 31, 2006 at a weighted-average issuance price of $14.45 per share. All of these awards vested immediately. At March 31, 2006, 48,740~~September 30, 2007 about the common share awards ~~were vested, at a weighted average issuance price~~that have been issued by the Company (shares in thousands):

	Outstanding		Weighted-Average Issuance Price		Vested		Weighted-Average Issuance Price
Shares at beginning of period (1)	833		$	13.69	258		$	12.43
Shares issued during period (2)	302		$	14.79	38		$	17.92
Previously issued shares vesting during period	—		$	—	131		$	12.03
Shares repurchased during period	(36	)	$	11.90	(36	)	$	11.90
Shares at end of period	1,099		$	14.05	391		$	12.88

(1) Net of ~~$10.46 per share. At December 31, 2005, 42,858 common share awards were vested, at a weighted-average issuance price of $11.90 per share. During 2005, one of our~~80,835 shares repurchased in June 2006.

(2) Shares issued to outside directors ~~refused his common stock award of 7,143 shares. That director was not issued a common stock award in 2006.~~are immediately vested.

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 ~~March 31,~~September 30, 2007 and 2006, ~~and 2005,~~ we recognized ~~$1.1~~$1.7 million and ~~zero,~~$0.9 million, respectively, of pre-tax expense related to common stock awards, net of estimated and actual forfeitures. For the nine months ended September 30, 2007 and 2006, we recognized $3.9 million and $3.2 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 nine months ended September 30, 2007, we recognized tax benefits of zero and $0.8 million, respectively. For the unvested common stock awards outstanding as of September 30, 2007, the Company anticipates that it will recognize approximately $6.6 million of expense over the next 0.8 years.

9.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 nine months ended September 30, 2007, we recognized approximately $0.8 million and $2.9 million of pre-tax compensation expense, respectively, associated with the Phantom Shares, and have recorded a current liability of approximately $1.4 million and a long-term liability of approximately $1.5 million as of September 30, 2007. Associated with the Phantom Shares, we recognized $0.3 million and $1.1 million, respectively, of tax benefits for the three and nine months ended September 30, 2007. For the unvested Phantom Share awards outstanding as of September 30, 2007, the Company estimates that it will recognize an additional $5.4 million of compensation expense over the next 1.8 years.

Stock Appreciation Rights

In August 2007, under the 1997 Incentive Plan, the Company issued approximately 590,000 stock appreciation rights (“SARs”) to certain executive officers. Each SAR award has a ten-year term from the date of grant and vests in equal annual installments on the first, second and third anniversaries of the date of grant. The per share exercise price of each SAR is $14.32, which was determined to be the fair market value of a share of the Company’s common stock on the date of the grant. Upon the exercise of an SAR, the recipient will receive an amount equal to the difference between the exercise price and the fair market value of a share of the Company’s common stock on the date of exercise multiplied by the number of shares of common stock for which the SAR was exercised. All payments will be made in shares of the Company’s common stock. Prior to exercise, the SAR does not entitle the recipient to receive any shares of the Company’s common stock and does not provide the recipient with any voting or other stockholder rights.

During the three and nine months ended September 30, 2007, the Company recognized approximately $0.2 million in compensation expense associated with the SARs. Tax benefits recognized in connection with the SARs for the three months ended September 30, 2007 were less than $0.1 million. For the unvested SARs outstanding as of September 30, 2007, the Company expects that it will recognize approximately $3.3 million of expense over the next 1.9 years.

10. SEGMENT INFORMATION

For ~~2006,~~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 ~~March 31,~~September 30, 2007 and September 30, 2006, ~~and March 31, 2005,~~ respectively:

Well
Servicing

Pressure
Pumping

Fishing
and Rental

Corporate /
Other

Discontinued
Operations

Eliminations

Total

(in thousands)

As of and for the three months ended March 31, 2006:

Operating revenues

$
272,916

$
51,798

$
23,244

$
—

$
—

$
—

$
347,958

Gross margin

92,160

23,228

8,156

—

—

—

123,544

Depreciation and amortization

20,075

2,362

1,590

2,787

—

—

26,814

Interest expense

(139
)
(210
)
3

8,924

—

—

8,578

Net income (loss) from continuing operations

59,111

19,934

4,834

(53,816
)
—

—

30,063

Propery, plant and equipment, net

484,323

76,557

27,352

34,263

—

—

622,495

Total assets

948,511

156,402

70,356

405,630

658

(207,178
)
1,374,379

Capital expenditures, excluding acquisitions

(30,684
)
(6,402
)
(1,355
)
(1,140
)

(39,581
)

	Well Servicing			Pressure Pumping			Fishing and Rental			Corporate / Other			Total
	(in thousands)
As of and for the three months ended September 30, 2007:
Operating revenues	$	311,304		$	77,112		$	25,551		$	—		$	413,967
Gross margin	118,153			27,755			10,577			—			156,485
Depreciation and amortization	20,100			4,362			2,126			4,597			31,185
Interest expense	(261		)	(307		)	(148		)	8,630			7,914
Net income (loss)	78,372			21,400			5,786			(69,662		)	35,896
Propery, plant and equipment, net	562,833			131,620			46,950			38,675			780,078
Total assets	1,079,728			240,503			89,930			267,877			1,678,038
Capital expenditures, excluding acquisitions	(33,230		)	(9,175		)	(5,445		)	(1,128		)	(48,978		)

Well
Servicing

Pressure
Pumping

Fishing
and Rental

Corporate /
Other

Discontinued
Operations

Eliminations

Total

(in thousands)

As of and for the three months ended March 31, 2005:

Operating revenues

$
220,333

$
30,504

$
20,367

$
—

$
—

$
—

$
271,204

Gross margin

70,711

13,274

6,761

—

—

—

90,746

Depreciation and amortization

21,294

2,164

1,449

2,867

—

—

27,774

Interest expense

5

(14
)
6

13,355

—

—

13,352

Net income (loss) from continuing operations

32,200

10,317

3,292

(37,444
)
—

—

8,365

Propery, plant and equipment, net

472,525

50,427

26,561

35,572

—

—

585,085

Total assets

913,340

119,418

69,386

665,813

2,125

(454,868
)
1,315,214

Capital expenditures, excluding acquisitions

(12,358
)
(1,127
)
(469
)
(967
)
—

—

(14,921
)

	Well Servicing			Pressure Pumping			Fishing and Rental			Corporate / Other			Total
	(in thousands)
As of and for the three months ended September 30, 2006:
Operating revenues	$	323,655		$	69,038		$	24,907		$	—		$	417,600
Gross margin	138,169			31,733			10,297			—			180,199
Depreciation and amortization	22,513			3,209			1,730			2,740			30,192
Interest expense	(218		)	(117		)	(36		)	10,781			10,410
Net income (loss)	102,439			26,150			5,918			(73,622		)	60,885
Propery, plant and equipment, net	522,962			91,122			34,963			32,762			681,809
Total assets	1,013,218			181,326			77,606			236,063			1,508,213
Capital expenditures, excluding acquisitions	(33,132		)	(7,326		)	(6,298		)	(2,058		)	(48,814		)

	Well Servicing			Pressure Pumping			Fishing and Rental			Corporate / Other			Total
	(in thousands)
As of and for the nine months ended September 30, 2007:
Operating revenues	$	931,289		$	228,478		$	73,629		$	—		$	1,233,396
Gross margin	385,306			85,178			31,696			—			502,180
Depreciation and amortization	63,372			12,354			6,520			9,237			91,483
Interest expense	(696		)	(676		)	(327		)	27,930			26,231
Net income (loss)	268,848			65,921			18,117			(216,664		)	136,222
Propery, plant and equipment, net	562,833			131,620			46,950			38,675			780,078
Total assets	1,079,728			240,503			89,930			267,877			1,678,038
Capital expenditures, excluding acquisitions	(100,904		)	(44,969		)	(16,364		)	(5,586		)	(167,823		)

	Well Servicing			Pressure Pumping			Fishing and Rental			Corporate / Other			Total
	(in thousands)
As of and for the nine months ended September 30, 2006:
Operating revenues	$	884,962		$	181,035		$	71,596		$	—		$	1,137,593
Gross margin	348,962			83,271			29,278			—			461,511
Depreciation and amortization	64,276			8,381			5,025			8,248			85,930
Interest expense	(508		)	(500		)	(43		)	30,068			29,017
Net income (loss)	233,776			68,440			15,925			(187,610		)	130,531
Propery, plant and equipment, net	522,962			91,122			34,963			32,762			681,809
Total assets	1,013,218			181,326			77,606			236,063			1,508,213
Capital expenditures, excluding acquisitions	(107,517		)	(25,856		)	(11,053		)	(2,579		)	(147,005		)

Operating revenues for our foreign operations were ~~$17.2~~$27.9 million and ~~$17.4~~$22.2 million for the three months ended ~~March 31,~~September 30, 2007 and 2006, respectively. Operating revenues for our foreign operations were $67.9 million and ~~2005,~~$57.4 million for the nine months ended September 30, 2007 and 2006, respectively. Gross margins for our foreign operations were ~~$4.8~~$6.1 million and ~~$5.4~~$6.5 million for the quarters ended ~~March 31,~~September 30, 2007 and 2006, ~~and 2005,~~ respectively. ~~We had $24.6~~Gross margins for our foreign operations were $11.7 million and ~~$25.2~~$14.7 million for the nine months ended September 30, 2007 and 2006, respectively.

We have $114.2 million and $77.9 million of identifiable assets related to our foreign operations as of ~~March 31, 2006~~September 30, 2007 and December 31, ~~2005,~~2006, respectively. Capital expenditures for our foreign operations were ~~$1.2~~$4.9 million and ~~$2.2~~$8.0 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2007 and 2006, respectively.

11.SUBSEQUENT EVENTS

Closing of Moncla Purchase

The Company closed the acquisition of Moncla on October 25, 2007. The Company paid $145.8 million for Moncla, of which $123.3 million was paid in cash at closing. Cash paid at closing included the repayment of approximately $14.7 million of Moncla indebtedness. In addition, the purchase price includes $22.5 million of notes payable to the sellers, and ~~2005, respectively.~~ the purchase agreement provides for an earnout of up to $25.0 million over the next five years. The notes payable to the sellers consist of two notes. The first is an unsecured note in the amount of $12.5 million, which is due and payable in a lump-sum, together with accrued interest, on October 25, 2009. The second unsecured note in the amount of $10.0 million is payable in annual installments of $2.0 million, plus accrued interest, beginning October 25, 2008 through 2012. Each of the notes bear interest at the Federal Funds rate adjusted annually on the anniversary date of the closing date.

Moncla is headquartered in Lafayette, Louisiana, and has offices in Sour Lake, Texas and Sandersville, Mississippi. Moncla’s fleet includes daylight rigs for well servicing and workovers and twenty-four hour rigs for shallow drilling, sidetracking and deep workovers. Moncla also has a fleet of workover barges. In addition to rigs, Moncla owns rig-up, swab, hot oil and anchor trucks, tubing testing units and rental equipment. Moncla currently operates in Texas, Louisiana, Mississippi, Alabama and Florida.

New Credit Facility

The Company also received a commitment from two lenders to provide, subject to customary conditions, $150 million of a new $400 million senior secured credit revolving credit facility and to use their best efforts to syndicate the remaining $250 million of the revolving credit facility. Three additional lenders have committed to provide an additional $150 million of the revolving credit facility. The commitment letter also provides for a $350 million term loan facility that the Company will terminate upon the successful completion of the offering of the senior notes. The Company expects to enter into the new senior secured revolving credit facility concurrently with the closing of the senior notes offering.

Senior Notes Offering

On November 5, 2007, the Company commenced an offering of up to $400 million of senior notes due 2017 through a private placement. Under the proposed terms of the offering certain of the Company’s domestic subsidiaries will fully and unconditionally guarantee the notes. The Company intends to use the net proceeds of the proposed offering to retire its outstanding $393 million of term loans under our existing Senior Secured Credit Facility.

Amendment to Existing Senior Secured Credit Facility

The Company is currently in discussions with its lenders under the revolving credit facility of its Senior Secured Credit Facility to amend the facility if the Company completes the offering of the senior notes. The amendment would permit the issuance of the notes, terminate the prefunded letter of credit facility and permit the Company to use the entire $65 million revolving credit portion of the Senior Secured Credit Facility for letters of credit.

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 ~~March 31, 2006~~September 30, 2007 and for the three and nine months ended ~~March 31,~~September 30, 2007 and 2006, ~~and 2005,~~ 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.~~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.~~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 ~~our California operation.~~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

2005:

First Quarter

$
49.73

$
6.50

1,182

Second Quarter

$
53.05

$
6.95

1,246

Third Quarter

$
63.19

$
9.73

1,334

Fourth Quarter

$
60.00

$
12.88

1,396

2006:

First Quarter

$
63.27

$
7.84

1,440

	WTI Cushing Crude Oil (1)		NYMEX Henry Hub Natural Gas (1)		Average Baker Hughes Land Drilling Rigs (2)

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
Third Quarter	$	75.46	$	6.24	1,717

(1) Represents average crude oil or natural gas price, respectively, for each of the periods presented.

(2) Source: www.bakerhughes.com.

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~~well servicing activities also rises, resulting in increased rig and trucking services and more hours worked. ~~Conversely, when~~While overall demand for the services we provide has increased during 2007, our activity levels have declined since 2006 due to increased capacity entering the marketplace. In addition, if activity levels were to decline due to lower spending by oil and natural gas producers, we would provide ~~few~~fewer rig and trucking services, which ~~results~~would result in lower hours worked. We publicly release our monthly rig and trucking hours. The following table presents our quarterly rig and trucking hours from ~~2005~~2006 through the ~~first~~third quarter of ~~2006.~~2007.

	Rig Hours	Trucking Hours	Rig Hours	Trucking Hours
2005:
2006:
First Quarter	621,228	641,841	663,819	609,317
Second Quarter	661,928	635,448	679,545	602,118
Third Quarter	668,741	607,500	677,271	587,129
Fourth Quarter	646,810	594,762	637,994	578,471
Total 2005:	2,598,707	2,479,551
Total 2006:			2,658,629	2,377,035

2006:
2007:
First Quarter	663,819	609,317	625,748	571,777
Second Quarter			611,890	583,074
Third Quarter			597,617	570,356

Market Conditions

Industry fundamentals in the U.S. marketplace remain strong as crude oil prices averaged $75.46 per barrel during the September 2007 quarter and averaged approximately $85.66 per barrel during the month of October. While natural gas prices averaged $6.24 per MMbtu during the September 2007 quarter, natural gas prices increased to an average approximately $7.22 per MMbtu during the month of October. We believe the increase in natural gas prices is seasonally related as natural gas prices tend to increase in the winter months. Industry activity levels, as measured by the Baker Hughes land drilling rig count, improved slightly during the September 2007 quarter as the rig count averaged 1,717 rigs compared to 1,680 rigs in the June 2007 quarter. The drilling rig count totaled 1,738 on November 2, 2007.

According to the Energy Information Association, there was approximately 3.5 Tcf of natural gas in storage as of November 1, 2007. This is 8.4% higher than the five-year average and the current high levels of natural gas storage have led to concern that natural gas prices could be weak in the event that the United States has a warm winter and demand for natural gas deteriorates. As a result, natural gas prices averaged $6.24 during the September 2007 quarter, but have since improved modestly to $7.22 in the month of October 2007. Although natural gas prices have declined significantly from earlier this year, the NYMEX 12-month strip averaged over $7.50 per MMbtu as of November 1, 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 1,738 on November 2, 2007, which is near the 20-year high of 1,754. 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 long-term activity levels should remain stable despite the recent softness in natural gas prices. We remain positive about long term industry fundamentals. Our long-term 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. In the short-term, our activity levels have been negatively impacted by new capacity additions in many of our markets. This has resulted in lower equipment utilization and pricing pressure for our services. We anticipate that this additional capacity will be minimized over the next few quarters as (i) capital expenditures for new equipment are expected to decline in 2008, (ii) as service providers use new equipment to retire older equipment, and (iii) through industry consolidation. 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)~~thousands)

(Unaudited)

Three Months Ended March 31,

2006

2005

REVENUES:

Well servicing

$
272,916

$
220,333

Pressure pumping

51,798

30,504

Fishing and rental services

23,244

20,367

Total revenues

347,958

271,204

COSTS AND EXPENSES:

Well servicing

180,756

149,622

Pressure pumping

28,570

17,230

Fishing and rental services

15,088

13,606

Depreciation and amortization

26,814

27,774

General and administrative

43,341

34,938

Interest expense

8,578

13,352

Loss on early extinguishment of debt

—

400

(Gain) loss on sale of assets

(1,936
)
725

Interest income

(1,200
)
(424
)
Other, net

(483
)
48

Total costs and expenses, net

299,528

257,271

Income from continuing operations before income taxes

48,430

13,933

Income tax expense

(18,367
)
(5,568
)

INCOME FROM CONTINUING OPERATIONS

30,063

8,365

Discontinued operations, net of income tax expense of $4,590 for the three months ended March 31, 2005

—

(3,361
)

NET INCOME

$
30,063

$
5,004

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006

*REVENUES:*
Well servicing.	$	311,304		$	323,655		$	931,289		$	884,962
Pressure pumping	77,112			69,038			228,478			181,035
Fishing and rental services	25,551			24,907			73,629			71,596

Total revenues.	413,967			417,600			1,233,396			1,137,593

*COSTS AND EXPENSES:*
Well servicing	193,151			185,486			545,983			536,000
Pressure pumping	49,357			37,305			143,299			97,764
Fishing and rental services	14,974			14,610			41,934			42,318
Depreciation and amortization	31,185			30,192			91,483			85,930
General and administrative	56,569			43,624			164,787			142,042
Interest expense.	7,914			10,410			26,231			29,017
Loss (gain) on sale of assets, net	2,398			(817		)	1,945			(3,062		)
Interest income	(1,851		)	(1,841		)	(5,589		)	(3,868		)
Other, net	438			(191		)	326			280

Total costs and expenses, net	354,135			318,778			1,010,399			926,421

Income before income taxes	59,832			98,822			222,997			211,172
Income tax expense	(23,936		)	(37,937		)	(86,775		)	(80,641		)

*NET INCOME*	$	35,896		$	60,885		$	136,222		$	130,531

Three Months Ended ~~March 31, 2006~~September 30, 2007 Compared to Three Months Ended ~~March 31, 2005~~September 30, 2006

Revenue:

Well Servicing: Well servicing revenues ~~increased 23.9%~~decreased 3.8% to ~~$272.9~~$311.3 million for the quarter ended ~~March 31, 2006~~September 30, 2007 compared to revenue of ~~$220.3~~$323.7 million for the quarter ended ~~March 31, 2005.~~September 30, 2006. The decrease in revenue is largely attributable to lower rig and trucking hours, offset modestly by increased revenue from the Company’s cased-hole wireline operation and operations under the Mexico contract, which commenced in the second quarter of 2007. For the September 2007 quarter, the Company’s composite segment revenue to total hours (defined as rig hours plus trucking hours) was approximately $266 per hour compared to approximately $256 per hour for the September 2006 quarter. The improvement is largely attributable to the Mexico contract and the incremental revenue from the cased-hole electric wireline business. Rig hours for the Company decreased 11.8% to 597,617 in the September 2007 quarter from 677,271 in the September 2006 quarter while the Company’s trucking hours decreased 2.9% to 570,356 in the September 2007 quarter from 587,129 in the September 2006 quarter. The decrease in the rig and trucking hours is largely attributable to the impact of lost market share due to new capacity additions.

Pressure Pumping Services: Pressure pumping services (“PPS”) segment revenues increased 11.7% to $77.1 million for the quarter ended September 30, 2007 compared to revenue of $69.0 million for the quarter ended September 30, 2006. The increase in revenue is attributable to incremental pressure pumping equipment and higher activity levels. At September 30, 2007, the Company had approximately 203,000 horsepower of pumping equipment as compared to approximately 162,000 horsepower at September 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 535 in the September 2007 quarter compared to 405 the September 2006 quarter while cementing jobs totaled 594 in the September 2007 quarter compared to 538 the September 2006 quarter.

Fishing and Rental Services: Fishing and rental services (“FRS”) segment revenues for the quarter ended September 30, 2007 increased 2.6% to $25.6 million compared to revenue of $24.9 million for the quarter ended September 30, 2006. The increase in revenue is attributable to additional rental equipment and stable market conditions.

Direct Costs:

Well Servicing: Well servicing direct costs increased 4.1% to $193.2 million for the quarter ended September 30, 2007 compared to $185.5 million for the quarter ended September 30, 2006. Despite modestly lower rig and trucking hours, direct costs increased primarily due to higher vehicular liability reserves, workers’ compensation, health insurance expense and higher repairs and maintenance expense, offset by lower incentive compensation expense. Direct costs as a percent of well servicing segment revenue were 62.0% for the quarter ended September 30, 2007 as compared to 57.3% for the quarter ended September 30, 2006.

Pressure Pumping Services: PPS direct costs increased 32.3% to $49.4 million for the quarter ended September 30, 2007 compared to $37.3 million for the quarter ended September 30, 2006. The increase in direct costs is largely attributable to increased sand and chemical purchases as well as higher trucking and freight costs and higher repair and maintenance expense. The higher activity is a function of continued demand for pressure pumping services and incremental additions of pressure pumping equipment. Direct costs as a percent of PPS segment revenue were 64.0% for the quarter ended September 30, 2007 as compared to 54.0% for the quarter ended September 30, 2006.

Fishing and Rental Services: FRS direct costs increased by 2.5%, or $0.4 million, to $15.0 million for the quarter ended September 30, 2007 compared to $14.6 million for the quarter ended September 30, 2006. The increase in costs is due primarily to increased repair and maintenance and increased insurance premiums. Direct costs as a percent of total FRS segment revenue improved slightly to 58.6% for the quarter ended September 30, 2007 compared to 58.7% for the quarter ended September 30, 2006.

General and Administrative Expense

General and administrative (“G&A”) expenses increased 29.7%, to $56.6 million for the quarter ended September 30, 2007 compared to $43.6 million for the quarter ended September 30, 2006. G&A increased primarily due to higher professional fees ($9.1 million) and higher equity-based compensation ($1.8 million). The third quarter 2006 results also include the effects of a legal settlement, which resulted in a benefit of approximately $7.3 million during the third quarter of 2006. Absent this benefit, the increase in professional fees would be approximately $1.8 million and the overall increase in G&A would be approximately $5.7 million. The increase in professional fees was primarily attributable to the Company’s accounting and internal controls processes associated with the recently-completed three year audit. G&A expense as a percent of revenue for the quarter ended September 30, 2007 totaled 13.7% compared to 10.4% for the quarter ended September 30, 2006.

Interest Expense

Interest expense declined 24.0% to $7.9 million for the quarter ended September 30, 2007 compared to $10.4 million for the quarter ended September 30, 2006. The decline is primarily attributable to higher capitalized interest expense and lower interest rates and commitment fees on our Senior Secured Credit Facility. Interest expense as a percent of revenue for the quarter ended September 30, 2007 totaled 1.9% compared to 2.5% for the quarter ended September 30, 2006.

Depreciation Expense

Depreciation expense was essentially flat at $31.2 million for the quarter ended September 30, 2007 compared to $30.2 million for the quarter ended September 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 $1.4 million of depreciation expense for the three months ended September 30, 2007. For the quarter ended September 30, 2007, the Company spent approximately $49.0 million on capital expenditures as compared to $48.8 million for the quarter ended September 30, 2006. Depreciation

expense as a percent of revenue for the quarter ended September 30, 2007 totaled 7.5% compared to 7.2% for the quarter ended September 30, 2006.

Income Taxes

Our income tax expense was $23.9 million and $37.9 million for the three months ended September 30, 2007 and 2006, respectively. Our effective tax rate for those same periods was 40.0% and 38.4%, respectively. The differences between the rates between periods relate largely to nondeductible expense for executive compensation and other nondeductible items, as well as the Texas Margin Tax. Differences between the statutory rate and the effective rate are due primarily to state and foreign income taxes and nondeductible expenditures.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

Revenue

Well Servicing: Well servicing revenues increased 5.2% to $931.3 million for the nine months ended September 30, 2007 compared to revenue of $885.0 million for the nine months ended September 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 ~~March 2006 quarter,~~nine months ended September 30, 2007, the Company’s composite segment revenue to total hours (as defined as rig hours plus trucking hours) was approximately ~~$214~~$261 per hour compared to approximately ~~$174~~$232 per hour for the ~~March 2005 quarter.~~nine months ended September 30, 2006. Rig hours for the Company ~~increased 6.9% from 621,228~~decreased 9.2% to 1,835,254 in the ~~March 2005 quarter to 663,819~~first nine months of 2007 from 2,020,635 in the ~~March~~first nine months of 2006 ~~quarter~~ while the Company’s trucking hours decreased ~~5.1% from 641,841~~4.1% to 1,725,207 in the ~~March 2005 quarter to 609,317~~first nine months of 2007 from 1,798,564 in the ~~March 2006 quarter.~~first nine months of 2006. The ~~increase~~decrease in rig hours ~~is due to higher demand for well maintenance~~ and ~~workover services while the decline in~~ trucking hours is due primarily to lost market ~~share.~~share and to a lesser extent, inclement weather in early 2007.

Pressure Pumping Services: ~~Pressure pumping services (“PPS”)~~ PPS segment revenues increased ~~69.8%~~26.2% to ~~$51.8~~$228.5 million for the ~~quarter~~nine months ended ~~March 31, 2006~~September 30, 2007 compared to revenue of ~~$30.5~~$181.0 million for the ~~quarter~~nine months ended ~~March 31, 2005.~~September 30, 2006. The increase in revenue is attributable to incremental pressure pumping equipment and higher activity ~~levels and higher pricing for~~levels. At September 30, 2007, the ~~Company’s services. The~~ Company ~~exited the March 2006 quarter with~~had approximately ~~136,000~~203,000 horsepower of pumping equipment as compared to approximately ~~110,000~~162,000 horsepower at ~~the end of the March 2005 quarter.~~September 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~~segment’s revenue. Fracturing jobs totaled ~~365 in~~1,546 during the ~~March 2006 quarter~~first nine months of 2007 compared to ~~304 in~~1,157 the ~~March 2005 quarter~~first nine months of 2006 while cementing jobs totaled ~~473 in~~1,537 during the ~~March 2006 quarter~~first nine months of 2007 compared to ~~309 in~~1,488 the ~~March 2005 quarter.~~ first nine months of 2006.

Fishing and Rental Services: ~~Fishing and rental services (“FRS”)~~ FRS segment revenues for the ~~quarter~~nine months ended ~~March 31, 2006~~September 30, 2007 increased ~~14.1%~~2.8% to ~~$23.2~~$73.6 million compared to revenue of ~~$20.4~~$71.6 million for the ~~quarter~~nine months ended ~~March 31, 2005.~~September 30, 2006. The ~~growth~~increase in revenue ~~was largely~~is primarily attributable to ~~higher pricing~~continued stable demand for ~~the Company’s~~ services.

Direct ~~Costs:~~Costs

Well Servicing: Well servicing direct costs increased ~~20.8%~~1.9%, to ~~$180.8~~$546.0 million for the ~~quarter~~nine months ended ~~March 31, 2006~~September 30, 2007 compared to ~~$149.6~~$536.0 million for the ~~quarter~~nine months ended ~~March 31, 2005.~~September 30, 2006. The increase in direct costs is ~~largely~~primarily attributable to ~~higher labor~~increased freight, repairs and maintenance and chemical costs and insurance premiums. These increases were offset somewhat by decreased fuel and equipment costs, including higher wages, higher workers compensation expense, higher repair and maintenance expense, higher fuel expense and higher supplies expense. The increase in these costs is primarily due to higher activity levels.rental costs. Direct costs as a percent of total well ~~servicing~~service segment revenue improved to ~~66.2%~~58.6% for the ~~quarter~~nine months ended ~~March 31, 2006~~September 30, 2007 compared to ~~67.9%~~60.6% for the ~~quarter~~nine months ended ~~March 31, 2005.~~ September 30, 2006.

Pressure Pumping: PPS direct costs increased ~~65.8%~~46.6% to ~~$28.6~~$143.3 million for the ~~quarter~~nine months ended ~~March 31, 2006~~September 30, 2007 compared to ~~$17.2~~$97.8 million for the ~~quarter~~nine months ended ~~March 31, 2005.~~September 30, 2006. The increase in direct costs is largely attributable to increased sand and chemical purchases as well as higher ~~labor~~trucking and freight costs, higher fuel expense and higher ~~trucking~~repair and ~~freight~~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 ~~improved to 55.2%~~were 62.7% for the ~~quarter~~nine months ended ~~March 31, 2006~~September 30, 2007 compared to ~~56.5%~~54.0% for the ~~quarter~~nine months ended ~~March 31, 2005.~~ September 30, 2006.

Fishing and Rental Services: FRS direct costs ~~increased 10.9%~~decreased slightly by 0.9% to ~~$15.1~~$41.9 million for the ~~quarter~~nine months ended ~~March 31, 2006~~September 30, 2007 compared to ~~$13.6~~$42.3 million for the ~~quarter~~nine months ended ~~March 31, 2005. The increase~~September 30, 2006. Increases in ~~direct~~ costs ~~is largely attributable to higher labor costs which are the result of increased demand~~ for ~~the Company’s services.~~supplies and small parts were more than offset by decreased repair and maintenance expenses. Direct costs as a percent of

total FRS segment revenue improved to ~~64.9%~~57.0% for the ~~quarter~~nine months ended ~~March 31, 2006~~September 30, 2007 compared to ~~66.8%~~59.1% for the ~~quarter~~nine months ended ~~March 31, 2005.~~September 30, 2006.

General and Administrative ~~Expense:~~Expense

General and administrative ~~(“G&A”) expenses~~expense increased ~~24.1%~~16.0%, to ~~$43.3~~$164.8 million for the ~~quarter~~nine months ended

~~March 31, 2006~~ September 30, 2007 compared to ~~$34.9~~$142.0 million for the ~~quarter~~nine months ended ~~March 31, 2005.~~September 30, 2006. The increase in G&A ~~expenses~~expense is primarily attributable to higher professional fees ($15.7 million) associated with the Company’s ~~restatement process as well as~~accounting and internal controls processes in connection with the recently completed three-year audit, higher equity-based compensation ~~expense~~($3.7 million), and increased salaries associated with ~~increased personnel~~higher corporate headcount. 2006 results also include the effects of a legal settlement which resulted in a benefit of approximately $7.3 million for the nine months ended September 30, 2006. Absent this benefit, the increase in professional fees would be approximately $8.4 million and ~~increased incentive compensation.~~the overall increase in G&A would be approximately $15.5 million. These increases were offset by decreased expenses related to information technology services ($1.3 million). G&A expense as a percent of revenue for the ~~quarter~~nine months ended ~~March 31, 2006~~September 30, 2007 totaled ~~12.5%~~13.4% compared to ~~12.9%~~12.5% for the ~~quarter~~nine months ended ~~March 31, 2005.~~September 30, 2006.

Interest ~~Expense:~~Expense

Interest expense decreased ~~35.8%~~9.6% to ~~$8.6~~$26.2 million for the ~~quarter~~nine months ended ~~March 31, 2006~~September 30, 2007 compared to ~~$13.4~~$29.0 million for the ~~quarter~~nine months ended ~~March 31, 2005.~~September 30, 2006. The decrease ~~is primarily attributable~~in interest expense was caused by increased capitalized interest due to ~~the elimination of consent~~increased Work in Progress and lower commitment fees ~~paid to~~on our ~~debt holders in consideration for our inability to timely file our audited financial statements.~~Senior Secured Credit Facility. Interest expense as a percent of revenue for the ~~quarter~~nine months ended ~~March 31, 2006~~September 30, 2007 totaled ~~2.5%~~2.1% compared to ~~4.9%~~2.6% for the ~~quarter~~nine months ended ~~March 31, 2005.~~ September 30, 2006.

Depreciation ~~Expense:~~Expense

Depreciation expense ~~decreased 3.5%~~increased 6.5% to ~~$26.8~~$91.5 million for the ~~quarter~~nine months ended ~~March 31, 2006~~September 30, 2007 compared to ~~$27.8~~$85.9 million for the nine months ended September 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 $5.5 million of depreciation expense for the nine months ended ~~March 31, 2005.~~September 30, 2007. For the ~~quarter~~nine months ended ~~March 31, 2006,~~September 30, 2007, the Company spent approximately ~~$39.6~~$167.8 million on capital expenditures as compared to ~~$14.9~~$147.0 million for the ~~quarter~~nine months ended ~~March 31, 2005.~~September 30, 2006. Depreciation expense as a percent of revenue for the ~~quarter~~nine months ended ~~March 31, 2006~~September 30, 2007 totaled ~~7.7%~~7.4% compared to ~~10.2%~~7.6% for the ~~quarter~~nine months ended ~~March 31, 2005.~~ September 30, 2006.

Income ~~Taxes:~~Taxes

Our income tax expense ~~from continuing operations~~ was ~~$18.4~~$86.8 million and ~~$5.6~~$80.6 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2007 and 2006, ~~and 2005~~ respectively. Our effective tax rate for those same periods was ~~37.9%~~38.9% and ~~40.0%~~38.2%, respectively. The differences between the rates between periods relate largely to nondeductible expense for executive compensation and other nondeductible ~~items.~~items, including the Texas Margin Tax. 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~~anticipate that our ~~current reserves~~capital expenditures, excluding acquisitions, for 2007 will be between $200 million and $210 million, of which we have spent approximately $168 million through September 30, 2007. We are presently targeting capital expenditures of approximately $175 million in 2008. We do not budget for acquisitions; however we are continually evaluating opportunities that fit our specific acquisition profile.

As of September 30, 2007, we had $155.9 million in cash, ~~and~~ cash equivalents and short term investments and $65.0 million of availability under our revolving credit facility. On October 25, 2007, we paid approximately $123.3 million in

cash in connection with the closing of our purchase of the Moncla companies. We have utilized, and expect to utilize in the future, bank and capital lease financing in order to obtain capital resources.

On November 5, 2007, the Company announced that it plans to offer up to $400 million of senior notes due 2017 through a private placement. Under the proposed terms of the offering certain of the Company’s domestic subsidiaries would fully and unconditionally guarantee the notes. The Company intends to use the net proceeds of the proposed offering to retire its outstanding $393 million of term loans under our existing Senior Secured Credit Facility.

Contemporaneously with the closing of the offering of the senior notes, we expect to enter into a new $400 million senior secured revolving credit facility and ~~internally generated~~to terminate our existing credit facility. As of November 1, 2007, we had approximately $68 million of outstanding letters of credit under our existing Senior Secured Credit Facility. We expect to be able to use the new senior secured credit facility to replace these outstanding letters of credit. We believe that this new senior secured revolving credit facility, together with our cash ~~flow~~and cash equivalents and cash flows from operations, ~~are~~will be sufficient to finance ~~the cash requirements of~~ our current and future operations, including our capital expenditure budget. As

In the event that we are not able to close this new senior secured revolving credit facility, we are pursuing an amendment to our existing Senior Secured Credit Facility. The amendment would permit the issuance of ~~March 31, 2006, we had $109.5~~the senior notes, terminate the $82.3 million inprefunded letter of credit facility and permit us to use the entire $65 million revolving portion of our existing Senior Secured Credit Facility for letters of credit. We believe that this amended facility, together with our cash and ~~$65.0 million of availability under~~cash equivalents and cash flow from operations will be sufficient to finance our ~~revolving credit facility.~~near term operations, but we would expect to promptly pursue alternative financing arrangements to provide for greater long-term liquidity.

Cash Flow

Our net cash provided by operating activities for the ~~quarter~~nine months ended ~~March 31, 2006,~~September 30, 2007, totaled ~~$52.6~~$190.2 million compared to ~~$40.7~~$194.1 million for the ~~quarter~~nine months ended ~~March 31, 2005.~~September 30, 2006. The ~~increase~~decrease in cash flow from operating activities is due primarily to ~~higher net income.~~increased working capital. Our net cash used in investing activities for the ~~quarter~~nine months ended ~~March 31, 2006~~September 30, 2007 totaled ~~$32.3~~$218.9 million compared to ~~net~~ cash ~~provided of $34.7 million for the quarter ended March 31, 2005. The decrease in cash flow~~ used in investing activities ~~is due to~~of $167.6 million for the ~~$60.5 million~~nine months ended September 30, 2006. Cash flows used in investing activities increased as a result of increased capital expenditures, cash investments in available for sale securities, lower proceeds received from the sale of fixed assets and our ~~land drilling operations.~~acquisition of AMI. Our net cash used in financing activities for the ~~quarter~~nine months ended ~~March 31, 2006~~September 30, 2007 totaled ~~$4.1~~$14.0 million compared to ~~$2.9~~$13.9 million for the ~~quarter~~nine months ended ~~March 31, 2005.~~September 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.~~assets; and

•Stock-based compensation.

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 timing of the recognition of these losses and the associated expense is based, in part, on the timing of the events resulting in the claim and varies from period to period, in some cases materially. 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~~Consolidated Balance Sheets 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.~~Consolidated Balance Sheet. In accordance with Statement of Financial Accounting Standards No. 5, “Accounting for ~~Contingencies,”~~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~~Stock-Based Compensation

~~SFAS 132.~~~~In December 2003,~~We account for stock-based compensation under the ~~Financial Accounting Standards Board (“FASB”) released Statement~~provisions of Financial Accounting Standards No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (“SFAS 132”). The revised standard requires disclosures for pensions and other postretirement benefit plans and replaces existing pension disclosure requirements. While we adopted the new disclosure requirements as of December 31, 2003, we do not have pension or postretirement benefit plans, other than our 401(k) plan.

~~SFAS 123(R).~~~~In December 2004, the FASB issued~~ Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (‘(“SFAS 123(R)”), which ~~revises SFAS No. 123. SFAS 123(R) is effective July 1, 2005 for all calendar year-end companies and requires companies to expense the fair value of~~

employee stock options and other forms of stock-based compensation. This expense will be recognized over the period during which an employee is required to provide services in exchange for the award. Compensation cost for the unvested portion of awards that are outstanding as of January 1, 2006 is recognized ratably over the remaining vesting period. The compensation cost for the unvested portion of the awards is basedwe adopted on ~~the fair value at the date of grant as calculated for our pro forma disclosure under SFAS 123. We recognize compensation expense under SFAS 123(R) for new awards granted after~~ January 1, 2006. We ~~use~~adopted the Black-Scholes option pricing model to calculate the fair value of awards granted after January 1, 2006 and estimate forfeitures and volatility for the calculation of compensation expense and grant date fair value. We adopted SFAS 123(R) effective January 1, 2006. The adoption of this standard did not materially impact our financial statements.

~~SFAS 149.~~In April 2003, the FASB issued Statement of Financial Accounting Standards No. 149, “Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities,” (“SFAS 149”) which clarifies and amends various issues related to derivatives and financial instruments addressed in SFAS 133 and interpretations issued by the Derivatives Implementation Group. In particular, SFAS 149: (1) clarifies when a contract with an initial net investment meets the characteristics of a derivative; (2) clarifies when a derivative contains a financing component that should be recorded as a financing transaction on the balance sheet and the statement of cash flows; (3) amends the definition of an “underlying” in SFAS 133 to conform to the language used in FIN 45; and (4) clarifies other derivative concepts. SFAS 149 is applicable to all contracts entered into or modified after June 30, 2003 and to all hedging relationships designated after June 30, 2003. The adoption of this standard did not materially impact our financial statements.

~~SFAS 150.~~In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity,” (“SFAS 150”) which establishes how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. Instruments that have an unconditional obligation requiring the issuer to redeem the instrument by transferring an asset at a specified date are required to be classified as liabilities on the balance sheet. Instruments that require the issuance of a variable number of equity shares by the issuer generally do not have the risks associated with equity instruments and as such should also be classified as liabilities on the balance sheet. SFAS 150 was effective for contracts in existence or created or modified for the first interim period beginning after June 15, 2003. The adoption of this standard did not materially impact our financial statements.

~~FIN 46R.~~In January 2003, the FASB issued Financial Interpretation No. 46, “Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51” (“FIN 46”). In December 2003, the FASB issued the updated and final interpretation FIN 46 (“FIN 46R”). FIN 46R requires that an equity investor in a variable interest entity have significant equity at risk (generally a minimum of 10%, which is an increase from the 3% required under previous guidance) and hold a controlling interest, evidenced by voting rights, and absorb a majority of the entity’s expected losses, 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 will be required to consolidate the variable interest entity as the primary beneficiary. FIN 46R was applicable immediately to variable interest entities created or obtained after March 15, 2004. The adoption of this interpretation did not materially impact our financial statements.

~~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~~123(R) using the modified prospective transition method. Stock option awards granted by the Company are ~~effective for accounting changes~~fair valued using a Black-Scholes option model and ~~correction~~are amortized to compensation expense over the vesting period of ~~errors made~~the option award, net of estimated and actual forfeitures.

Beginning in ~~fiscal years beginning after December 15, 2005. The adoption~~June 2005 we began making grants of ~~this standard did not materially affect~~shares of common stock to certain of 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~~employees and non-employee directors. These shares have vesting periods ranging from zero 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~~three years. Subject to the ~~list~~provisions of ~~examples of contracts~~SFAS 123(R), the Company recognizes expense in earnings equal 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~~shares vesting during the period, net of actual and estimated forfeitures.

In August 2007, the Company began issuing stock appreciation rights (“SARs”) to its executive officers. Each SAR award has a ten-year term from the ~~guarantee.~~date of grant and vests in equal annual installments on the first, second and third anniversaries of the date of grant. Upon the exercise of an SAR, the recipient will receive the spread between the exercise price and the fair market value of a share of the Company’s common stock on the date of exercise multiplied by the number of shares of common stock for which the SAR was exercised. All payments will be made in shares of the Company’s common stock. Prior to exercise, the SAR does not entitle the recipient to receive any shares of the Company’s common stock and does not provide the recipient with any voting or other stockholder rights. The Company accounts for the SARs as equity awards under SFAS 123(R) and recognizes compensation expense ratably over the vesting period of the SAR based on its fair value on the date of issuance, net of estimated and actual forfeitures.

Financial Accounting Standards Affecting This Report

FIN No. 48 and 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.~~48-1. ~~In June 2005,~~On July 12, 2006, the FASB issued 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.

FSP EITF ~~Issue 04-10, “Determining Whether~~00-19-2. In December 2006, the FASB issued 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 ~~Aggregate Operating Segments That Do Not Meet~~file a registration statement and to have that registration statement declared effective by the ~~Quantitative Thresholds.~~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,” ~~This standard considers how~~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 September 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 past failure to file our SEC reports in a ~~company should evaluate the aggregation criteria in FAS 131 to operating segments that~~timely manner, we do not ~~meet~~have an effective registration statement covering the ~~quantitative thresholds. Several~~Warrants, and have been required to make liquidated damages payments, and will continue to be required to make those payments until such time as we have an effective registration statement on file for exercise of ~~our operating segments do not meet~~ the ~~quantitative thresholds~~Warrants or the warrant shares issuable thereunder are eligible for resale without registration pursuant to SEC Rule 144 or otherwise. The requirement to make liquidated damages payments 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 ~~described~~high as $1.4 million. Any subsequent changes in ~~SFAS 131. Under this standard, we are permitted to combine information about certain operating segments with~~the carrying value of the RPA liability will be recorded in earnings as other similar segments that individually do not meet the quantitative thresholds to produce a reportable segment since the operating segments meet the aggregation criteria. It was effective for fiscal years ending after September 15, 2005.income and expense.
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.~~10-K for the year ended December 31, 2006. 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 for the year ended December 31, 2006 dated as of, and filed with the SEC on, August 13, 2007.
Item 4.CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
~~We maintain a set~~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 ~~that~~as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Our disclosure controls and procedures are designed to ~~provide reasonable assurance~~ensure that information required to be disclosed in ~~our~~the reports ~~filed~~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 ~~that~~ we file or submit under the Exchange Act is accumulated and communicated to ~~the Company’s~~our management, including ~~the Company’s Chairman and~~our Chief Executive Officer and our Chief Financial Officer, ~~as appropriate~~ to allow timely decisions regarding required ~~disclosure.~~
The Company’s management, with the participation of the Company’s Chairman and Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report.disclosures. Based on ~~such~~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, ~~the Company’s Chairman and Chief Executive Officer and Chief Financial Officer have~~management concluded that, as of ~~December 31, 2006 and March 31, 2006, our~~September 30, 2007, the Company’s disclosure controls and procedures were not effective.
~~We believe that, based on~~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 ~~we have performed in connection with the preparation of the consolidated financial statements contained in~~so that our ~~Annual Report on Form 10-K, our~~condensed consolidated financial statements as of and for the ~~year~~quarter and nine months ended ~~December 31, 2006, including quarterly~~September 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. ~~See~~
43

Management is committed to achieving effective internal control over financial reporting. Our remediation efforts are described in Item ~~9A. “Controls and Procedures,” included~~9A in our Annual Report on Form 10-K for the year ended December 31, ~~2006 for a complete discussion of material weaknesses of internal~~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 ~~over financial reporting identified for the year ended December 31, 2006.~~environment.

Changes in Internal Control over Financial Reporting
~~We believe that there~~There have been no changes in our internal control over financial reporting during the ~~period from January 1, 2004 to December 31, 2006~~most recently completed fiscal quarter that have materially affected or are reasonably likely to materially affect, our internal control over financial reporting.   However, in light of the delayed filing of this report, it is impracticable for us to identify the changes that may have occurred within the quarter covered by this report.  Please refer to Item 9A. “Controls and Procedures” in our 2006 Annual Report on Form 10-K for a description of material weaknesses in internal control over financial reporting as of December 31, 2006.
PART II — OTHER INFORMATION
Item 1.    LEGAL PROCEEDINGS
~~Please refer~~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 ~~Item 3. “Legal Proceedings” included~~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 hearing, originally scheduled for October 24, 2007, has been set for November 21, 2007. The final hearing is scheduled for March 25, 2008.
Litigation with Former General Counsel
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, ~~Annual Report~~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 ~~Form 10-K, which section is incorporated herein by reference~~its own motion transferred the case to the U.S. District Court for the Eastern District of
44

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 ~~filed~~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 ~~Exhibit 99.1~~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 Mr. Loftis’ claims; however, we cannot predict the outcome of this ~~report.~~lawsuit.

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 for the year ended December 31, 2006 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 for the year ended December 31, 2006 dated as of, and filed with the SEC on, August 13, 2007.
Item 2.    UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
On ~~January 9, 2006,~~July 10, 2007, we awarded ~~5,882~~an aggregate amount of 37,944 shares of stock to ~~Mr. Daniel Dienstbier in connection with his appointment~~our non-employee directors for services provided to the ~~Board~~Company. On August 22, 2007, we awarded an aggregate amount of ~~Directors~~258,734 shares of ~~the Company.~~restricted stock and an aggregate amount of 587,405 stock appreciation rights to our current executive officers for retention purposes. All such shares of ~~stock and~~ restricted stock were granted under the Key Energy Group, Inc. 1997 Incentive Plan. Each of these issuances were made in reliance upon the exemption from the registration requirements of the Securities Act of 1933 provided by Section 4(2) thereof for transactions by an issuer not involving any public offering.
Item 3.    DEFAULTS UPON SENIOR SECURITIES
None.
Item 4.SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
Item 5.    OTHER INFORMATION
None.
45

Item 6.    EXHIBITS
3.1

~~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.)

3.4
Amendment to Second Amended and Restated Bylaws of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Form 8-K filed on November 2, 2007.)
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.)

~~4.3~~10.1*
~~First Supplemental Indenture~~
Employment Agreement dated ~~as of March 1, 2002 among~~August 14, 2007 between the ~~Registrant, the Guarantors (as defined therein)~~Company and ~~U.S. Bank National Association. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated March 1, 2002, File No. 1-8038.)~~J. Marshall Dodson.

~~4.4~~10.2*
~~First Supplemental Indenture to the Indenture~~
Employment Agreement dated ~~May 9, 2003, dated as of May~~August 14, ~~2003~~2007 between the Company and ~~U.S. Bank National Association, as Trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated May 14, 2003, File No. 1-8038.)~~D. Bryan Norwood.

~~4.5~~10.3*
~~Consent Solicitation Statement of~~
First Amendment to Stock and Membership Interest Purchase Agreement dated October 25, 2007, among Key Energy Services, LLC and the Company dated July 6, 2004, regarding the solicitation of consents from the holders of its outstanding 6.375% senior notes due 2013 and 8.375% senior notes due 2008. (Incorporated by reference to Exhibit 99.2 of the Company’s Current Report on Form 8-K dated July 7, 2004, File No. 1-8038.)Sellers (as defined therein).

~~4.6~~
Second Supplemental Indenture, dated as of July 12, 2004, between the Company and U.S. Bank National Association, as Trustee. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)
~~4.7~~
Fourth Supplemental Indenture, dated as of July 12, 2004, among the Company, the Guarantors (as defined therein) and U.S. Bank National Association, as Trustee. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)
~~4.8~~
Supplement to July 6, 2004 Consent Solicitation Statement of the Company, dated July 15, 2004 regarding the solicitation of consents from the holders of its outstanding 6.375% senior notes due 2013 and 8.375% senior notes due 2008. (Incorporated by reference to Exhibit 99.3 of the Company’s Current Report on Form 8-K dated July 16, 2004, File No. 1-8038.)
~~4.9~~
Third Supplemental Indenture, dated as of July 19, 2004, between the Company and U.S. Bank National Association, as Trustee. (Incorporated by reference to Exhibit 4.4 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)
~~4.10~~
Fifth Supplemental Indenture, dated as of July 19, 2004, among the Company, the Guarantors (as defined therein) and U.S. Bank National Association, as Trustee. (Incorporated by reference to Exhibit 4.5 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)
~~4.11~~
Consent Solicitation Statement of Key Energy Services, Inc. dated January 7, 2005, regarding the solicitation of consents from the holders of its outstanding 6.375% senior notes due 2013 and 8.375% senior notes due 2008. (Incorporated by reference to Exhibit 99.2 of the Company’s Current Report on Form 8-K dated January 7, 2005, File No. 1-8038.)

~~4.12~~
Fourth Supplemental Indenture dated as of January 19, 2005, among Key Energy Services, Inc., the guarantors party thereto and U.S. Bank National Association, as Trustee, with respect to the Company’s 6.375% senior notes due 2008. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated January 24, 2005, File No. 1-8038.)
~~4.13~~
Sixth Supplemental Indenture dated as of January 21, 2005, among Key Energy Services, Inc., the guarantors party thereto and U.S. Bank National Association, as Trustee, with respect to the Company’s 8.375% senior notes due 2008. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated January 24, 2005, File No. 1-8038.)
~~4.14~~
Fifth Supplemental Indenture dated as of April 5, 2005, among Key Energy Services, Inc., the guarantors party thereto and U.S. Bank National Association, as Trustee, with respect to the Company’s 6.375% senior notes due 2013. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K dated April 7, 2005.)
~~4.15~~
Seventh Supplemental Indenture dated as of April 5, 2005, among Key Energy Services, Inc., the guarantors party thereto and U.S. Bank National Association, as Trustee, with respect to the Company’s 8.375% senior notes due 2008. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K dated April 7, 2005, File No. 1-8038.)

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

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

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.~~

99.1*
~~“Legal Proceedings” section of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006.~~
*                    Filed ~~herewith~~herewith.
46

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)~~

(Registrant)

/s/ Richard J. Alario

By:
Richard J. Alario

President and Chief Executive Officer

(Principal Executive Officer)
Date: November 9, 2007

~~Date:  August 13, 2007~~47

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.)

3.4
Amendment to Second Amended and Restated Bylaws of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Form 8-K filed on November 2, 2007.)
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.)

~~4.3~~10.1*
~~First Supplemental Indenture~~
Employment Agreement dated ~~as of March 1, 2002 among~~August 14, 2007 between the ~~Registrant, the Guarantors (as defined therein)~~Company and ~~U.S. Bank National Association. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated March 1, 2002, File No. 1-8038.)~~J. Marshall Dodson.

~~4.4~~10.2*
~~First Supplemental Indenture to the Indenture~~
Employment Agreement dated ~~May 9, 2003, dated as of May~~August 14, ~~2003~~2007 between the Company and ~~U.S. Bank National Association, as Trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated May 14, 2003, File No. 1-8038.)~~D. Bryan Norwood.

~~4.5~~10.3*
~~Consent Solicitation Statement of~~
First Amendment to Stock and Membership Interest Purchase Agreement dated October 25, 2007, among Key Energy Services, LLC and the Company dated July 6, 2004, regarding the solicitation of consents from the holders of its outstanding 6.375% senior notes due 2013 and 8.375% senior notes due 2008. (Incorporated by reference to Exhibit 99.2 of the Company’s Current Report on Form 8-K dated July 7, 2004, File No. 1-8038.)Sellers (as defined therein).

~~4.6~~
Second Supplemental Indenture, dated as of July 12, 2004, between the Company and U.S. Bank National Association, as Trustee. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)
~~4.7~~
Fourth Supplemental Indenture, dated as of July 12, 2004, among the Company, the Guarantors (as defined therein) and U.S. Bank National Association, as Trustee. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)
~~4.8~~
Supplement to July 6, 2004 Consent Solicitation Statement of the Company, dated July 15, 2004 regarding the solicitation of consents from the holders of its outstanding 6.375% senior notes due 2013 and 8.375% senior notes due 2008. (Incorporated by reference to Exhibit 99.3 of the Company’s Current Report on Form 8-K dated July 16, 2004, File No. 1-8038.)
~~4.9~~
Third Supplemental Indenture, dated as of July 19, 2004, between the Company and U.S. Bank National Association, as Trustee. (Incorporated by reference to Exhibit 4.4 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)

~~4.10~~
Fifth Supplemental Indenture, dated as of July 19, 2004, among the Company, the Guarantors (as defined therein) and U.S. Bank National Association, as Trustee. (Incorporated by reference to Exhibit 4.5 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)
~~4.11~~
Consent Solicitation Statement of Key Energy Services, Inc. dated January 7, 2005, regarding the solicitation of consents from the holders of its outstanding 6.375% senior notes due 2013 and 8.375% senior notes due 2008. (Incorporated by reference to Exhibit 99.2 of the Company’s Current Report on Form 8-K dated January 7, 2005, File No. 1-8038.)
~~4.12~~
Fourth Supplemental Indenture dated as of January 19, 2005, among Key Energy Services, Inc., the guarantors party thereto and U.S. Bank National Association, as Trustee, with respect to the Company’s 6.375% senior notes due 2008. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated January 24, 2005, File No. 1-8038.)
~~4.13~~
Sixth Supplemental Indenture dated as of January 21, 2005, among Key Energy Services, Inc., the guarantors party thereto and U.S. Bank National Association, as Trustee, with respect to the Company’s 8.375% senior notes due 2008. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated January 24, 2005, File No. 1-8038.)
~~4.14~~
Fifth Supplemental Indenture dated as of April 5, 2005, among Key Energy Services, Inc., the guarantors party thereto and U.S. Bank National Association, as Trustee, with respect to the Company’s 6.375% senior notes due 2013. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K dated April 7, 2005.)
~~4.15~~
Seventh Supplemental Indenture dated as of April 5, 2005, among Key Energy Services, Inc., the guarantors party thereto and U.S. Bank National Association, as Trustee, with respect to the Company’s 8.375% senior notes due 2008. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K dated April 7, 2005, File No. 1-8038.)

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

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

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.~~

99.1*
~~“Legal Proceedings” section of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006.~~
*                    Filed ~~herewith~~herewith.
42
48

	Three Months Ended March 31, 2006		Three Months Ended March 31, 2005
	(in thousands, except per share data)

Basic EPS Computation:
Numerator
Income from continuing operations	$	30,063	$	8,365
Discontinued operations, net of tax	—		(3,361		)
Net income	$	30,063	$	5,004

Denominator
Weighted average shares outstanding	131,339		130,791

Basic EPS:
Income from continuing operations	$	0.23	$	0.06
Discontinued operations, net of tax	—		(0.03		)
Net income (loss)	$	0.23	$	0.03

Diluted EPS Computation:
Numerator
Income from continuing operations	$	30,063	$	8,365
Discontinued operations, net of tax	—		(3,361		)
Net income	$	30,063	$	5,004

Denominator
Weighted average shares outstanding	131,339		130,791
Stock options	2,635		2,011
Warrants	551		489
	134,525		133,291

Diluted EPS:
Income from continuing operations	$	0.22	$	0.06
Discontinued operations, net of tax	—		(0.03		)
Net income	$	0.22	$	0.03

	Three Months Ended March 31, 2005
	(in thousands, except per share amounts)
Net income

As reported	$	5,004

Add: stock-based employee compensation expense included in reported net income, net of related tax effects	24

Deduct: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects	(296		)

Pro forma	$	4,732

Basic earnings per share:
As reported	$	0.03
Pro forma	$	0.03

Diluted earnings per share:
As reported	$	0.03
Pro forma	$	0.03

	March 31, 2006			December 31, 2005
	(in thousands)

Current assets	$	658		658
Current liabilities	(282		)	(292		)
Net assets of discontinued operations	$	376		$	366

	Three Months Ended March 31, 2006
	Options		Weighted Average Exercise Price		Weighted Average Fair Value

Outstanding at beginning of period	9,275		$	8.68	$	4.79
Granted	775		$	15.05	$	7.23
Exercised	—		$	—	$	—
Cancelled or expired	(44	)	$	9.78	$	4.43
Outstanding at end of period	10,006		$	9.17	$	4.98

Exercisable at end of period	8,656		$	8.49	4.75

	Options Outstanding
	Weighted Average Remaining Contractual Life (Years)	Number of Options Outstanding March 31, 2006		Weighted Average Exercise Price		Weighted Average Fair Value
Range of Exercise Prices:
$3.00 - $8.00	4.38	2,216		$	6.54	$	3.77
$8.01 - $8.31	4.22	1,850		$	8.25	$	4.92
$8.32 - $8.75	4.47	1,738		$	8.48	$	5.35
$8.76 - $10.22	5.79	2,560		$	9.73	$	4.93
$10.23 - $15.05	7.87	1,642		$	13.62	$	6.39
		10,006		$	9.17	$	4.98

Aggregate intrinsic value (in thousands)		$	8,589

	Options Exercisable
	Number of Options Exercisable March 31, 2006		Weighted Average Exercise Price		Weighted Average Fair Value
Range of Exercise Prices:
$3.00 - $8.00	2,216		$	6.54	$	3.77
$8.01 - $8.31	1,850		$	8.25	$	4.92
$8.32 - $8.75	1,738		$	8.48	$	5.35
$8.76 - $10.22	2,394		$	9.69	$	5.00
$10.23 - $15.05	458		$	12.63	$	5.25
	8,656		$	8.49	$	4.75

Aggregate intrinsic value (in thousands)	$	8,410

	Well Servicing			Pressure Pumping			Fishing and Rental			Corporate / Other			Discontinued Operations		Eliminations			Total
	(in thousands)
As of and for the three months ended March 31, 2006:
Operating revenues	$	272,916		$	51,798		$	23,244		$	—		$	—	$	—		$	347,958
Gross margin	92,160			23,228			8,156			—			—		—			123,544
Depreciation and amortization	20,075			2,362			1,590			2,787			—		—			26,814
Interest expense	(139		)	(210		)	3			8,924			—		—			8,578
Net income (loss) from continuing operations	59,111			19,934			4,834			(53,816		)	—		—			30,063
Propery, plant and equipment, net	484,323			76,557			27,352			34,263			—		—			622,495
Total assets	948,511			156,402			70,356			405,630			658		(207,178		)	1,374,379
Capital expenditures, excluding acquisitions	(30,684		)	(6,402		)	(1,355		)	(1,140		)						(39,581		)

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

2005:
First Quarter	$	49.73	$	6.50	1,182
Second Quarter	$	53.05	$	6.95	1,246
Third Quarter	$	63.19	$	9.73	1,334
Fourth Quarter	$	60.00	$	12.88	1,396

2006:
First Quarter	$	63.27	$	7.84	1,440

3.1
~~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.)

3.4		Amendment to Second Amended and Restated Bylaws of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Form 8-K filed on November 2, 2007.)

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.)

~~4.3~~10.1*	~~First Supplemental Indenture~~	Employment Agreement dated ~~as of March 1, 2002 among~~August 14, 2007 between the ~~Registrant, the Guarantors (as defined therein)~~Company and ~~U.S. Bank National Association. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated March 1, 2002, File No. 1-8038.)~~J. Marshall Dodson.

~~4.4~~10.2*	~~First Supplemental Indenture to the Indenture~~	Employment Agreement dated ~~May 9, 2003, dated as of May~~August 14, ~~2003~~2007 between the Company and ~~U.S. Bank National Association, as Trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated May 14, 2003, File No. 1-8038.)~~D. Bryan Norwood.

~~4.5~~10.3*	~~Consent Solicitation Statement of~~	First Amendment to Stock and Membership Interest Purchase Agreement dated October 25, 2007, among Key Energy Services, LLC and the Company dated July 6, 2004, regarding the solicitation of consents from the holders of its outstanding 6.375% senior notes due 2013 and 8.375% senior notes due 2008. (Incorporated by reference to Exhibit 99.2 of the Company’s Current Report on Form 8-K dated July 7, 2004, File No. 1-8038.)Sellers (as defined therein).

~~4.6~~	Second Supplemental Indenture, dated as of July 12, 2004, between the Company and U.S. Bank National Association, as Trustee. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)

~~4.7~~	Fourth Supplemental Indenture, dated as of July 12, 2004, among the Company, the Guarantors (as defined therein) and U.S. Bank National Association, as Trustee. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)

~~4.8~~	Supplement to July 6, 2004 Consent Solicitation Statement of the Company, dated July 15, 2004 regarding the solicitation of consents from the holders of its outstanding 6.375% senior notes due 2013 and 8.375% senior notes due 2008. (Incorporated by reference to Exhibit 99.3 of the Company’s Current Report on Form 8-K dated July 16, 2004, File No. 1-8038.)

~~4.9~~	Third Supplemental Indenture, dated as of July 19, 2004, between the Company and U.S. Bank National Association, as Trustee. (Incorporated by reference to Exhibit 4.4 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)

~~4.10~~	Fifth Supplemental Indenture, dated as of July 19, 2004, among the Company, the Guarantors (as defined therein) and U.S. Bank National Association, as Trustee. (Incorporated by reference to Exhibit 4.5 of the Company’s Current Report on Form 8-K dated October 19, 2006, File No. 1-8038.)

~~4.11~~	Consent Solicitation Statement of Key Energy Services, Inc. dated January 7, 2005, regarding the solicitation of consents from the holders of its outstanding 6.375% senior notes due 2013 and 8.375% senior notes due 2008. (Incorporated by reference to Exhibit 99.2 of the Company’s Current Report on Form 8-K dated January 7, 2005, File No. 1-8038.)

~~4.12~~	Fourth Supplemental Indenture dated as of January 19, 2005, among Key Energy Services, Inc., the guarantors party thereto and U.S. Bank National Association, as Trustee, with respect to the Company’s 6.375% senior notes due 2008. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated January 24, 2005, File No. 1-8038.)

~~4.13~~	Sixth Supplemental Indenture dated as of January 21, 2005, among Key Energy Services, Inc., the guarantors party thereto and U.S. Bank National Association, as Trustee, with respect to the Company’s 8.375% senior notes due 2008. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated January 24, 2005, File No. 1-8038.)

~~4.14~~	Fifth Supplemental Indenture dated as of April 5, 2005, among Key Energy Services, Inc., the guarantors party thereto and U.S. Bank National Association, as Trustee, with respect to the Company’s 6.375% senior notes due 2013. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K dated April 7, 2005.)

~~4.15~~	Seventh Supplemental Indenture dated as of April 5, 2005, among Key Energy Services, Inc., the guarantors party thereto and U.S. Bank National Association, as Trustee, with respect to the Company’s 8.375% senior notes due 2008. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K dated April 7, 2005, File No. 1-8038.)

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

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

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.~~

99.1*	~~“Legal Proceedings” section of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006.~~

			KEY ENERGY SERVICES, INC.
	~~(Registrant)~~
			(Registrant)

			/s/ Richard J. Alario
		By:	Richard J. Alario
			President and Chief Executive Officer
			(Principal Executive Officer)
Date: November 9, 2007