Edgar Filing: KEY ENERGY SERVICES INC

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

		For the Quarterly Period Ended September 30, 2005

or

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

Commission file number: 1-8038

KEY ENERGY SERVICES, INC.

(Exact Name of Registrant as Specified in Its Charter)

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

1301 McKinney Street, Suite 1800, Houston, Texas 77010

(Address of Principal Executive Offices) (Zip Code)

713/651-4300

(Registrant’s Telephone Number, Including Area Code)

None

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

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

Yes o 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 o No x

As of June 30, 2007, the number of outstanding shares of common stock of the Registrant was 131,593,695.

KEY ENERGY SERVICES, INC.

INDEX TO FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2005

Part I — Financial Information
Note Regarding Our Financial Reporting Process
Item 1.		Unaudited Consolidated Financial Statements
		Condensed Consolidated Balance Sheets as of September 30, 2005 and December 31, 2004
		Condensed Consolidated Statements of Operations for the Three Months Ended September 30, 2005 and 2004 and Nine Months Ended September 30, 2005 and 2004
		Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended September 30, 2005 and 2004 and Nine Months Ended September 30, 2005 and 2004
		Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2005 and 2004
		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. 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 2006 and the remaining two quarters of 2005. 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 September 30, 2005.

Item 1. CONSOLIDATED FINANCIAL STATEMENTS

Key Energy Services, Inc.

Condensed Consolidated Balance Sheets

(In thousands)

(Unaudited)

	September 30, 2005			December 31, 2004
*ASSETS*
Current assets:
Cash and cash equivalents	$	104,297		$	20,425
Accounts receivable, net of allowance for doubtful accounts of $10,190 and $8,990 at September 30, 2005 and December 31, 2004, respectively	211,787			190,518
Inventories	18,340			19,069
Prepaid expenses	6,939			7,472
Deferred tax asset	29,129			48,823
Other current assets	7,275			5,758
Current assets of discontinued operations	469			18,958

Total current assets	378,236			311,023

Property and equipment:
Well servicing equipment	813,113			770,001
Contract drilling equipment	26,021			21,916
Motor vehicles	87,973			87,189
Furniture and equipment	69,142			72,040
Buildings and land	44,481			48,268

Total property and equipment	1,040,730			999,414
Accumulated depreciation	(454,512		)	(401,636		)

Net property and equipment	586,218			597,778

Goodwill	320,963			320,942
Deferred costs, net	5,376			9,068
Notes and accounts receivable - related parties	97			101
Investment in IROC Systems Corp	10,772			3,786
Other assets	12,215			13,344

Non-current assets of discontinued operations	—			60,580

TOTAL ASSETS	$	1,313,877		$	1,316,622

*LIABILITIES AND STOCKHOLDERS’ EQUITY*

Current liabilities:
Accounts payable	$	13,536		$	14,465
Accrued payroll, taxes and employee benefits	37,316			36,218
Accrued operating expenditures	24,935			24,385
Unsettled legal claims	8,899			5,823
Income, sales, use and other taxes	15,279			21,881
Workers’ compensation claims accrual	17,697			14,684
Accrued rent	2,092			88
Accrued severance	701			326
Deferred gain on sale-leaseback transactions	159			—
Vehicular insurance	2,171			3,732
Other accrued liabilities	7,403			2,229
Accrued interest	7,282			9,980
Current portion of capital lease obligations	7,521			6,354
Current portion of long-term debt	4,000			—
Current liabilities of discontinued operations	188			4,938

Total current liabilities	149,179			145,103

Capital lease obligations, less current portion	12,662			7,177
Long-term debt, less current portion	421,680			473,870
Workers’ compensation, vehicular, health and other insurance claims	34,663			35,829
Deferred tax liability	113,385			107,760
Non-current accrued expenses	40,952			41,217
Commitments and contingencies	—			—

Stockholders’ equity:
Common stock, $0.10 par value; 200,000,000 shares authorized, 131,334,196 and 130,791,338 shares issued and outstanding at September 30, 2005 and December 31, 2004, respectively	13,175			13,121
Additional paid-in capital	715,391			713,563
Treasury stock, at cost; 416,666 and 416,666 shares at September 30, 2005 and December 31, 2004, respectively	(9,682		)	(9,682		)
Accumulated other comprehensive loss	(36,304		)	(36,421		)
Retained deficit	(141,224		)	(174,915		)

Total stockholders’ equity	541,356			505,666
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,313,877		$	1,316,622

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 September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004

*REVENUES:*
Well servicing	$	247,059		$	213,615		$	706,088		$	610,832
Pressure pumping	41,881			24,525			108,631			65,263
Fishing and rental	20,215			20,345			60,541			57,902

Total revenues	309,155			258,485			875,260			733,997

*COSTS AND EXPENSES:*
Well servicing	155,357			143,506			466,632			420,969
Pressure pumping	23,170			18,023			65,768			47,700
Fishing and rental	13,755			11,398			41,135			36,775
Depreciation and amortization	28,631			31,680			84,618			76,963
General and administrative	38,727			33,113			107,803			121,000
Interest expense	11,304			13,104			40,982			32,665
Loss on early extinguishment of debt	4,177			—			10,059			12,025
Loss on sale of assets	1,880			386			1,850			5,314
Interest income	(703		)	(277		)	(1,863		)	(531		)
Other, net	(23		)	(339		)	(4,992		)	(386		)

Total costs and expenses, net	276,275			250,594			811,992			752,494

Income (loss) from continuing operations before income taxes	32,880			7,891			63,268			(18,497		)
Income tax expense	(13,562		)	(4,543		)	(26,216		)	(957		)

*INCOME (LOSS) FROM CONTINUING OPERATIONS*	19,318			3,348			37,052			(19,454		)

Discontinued operations, net of tax benefit (expense) of $3,828, $(4,590), and $3,425 for the three months ended September 30, 2004 and nine months ended September 30, 2005 and 2004, respectively	—			(8,224		)	(3,361		)	(7,595		)

*NET INCOME (LOSS)*	$	19,318		$	(4,876	)	$	33,691		$	(27,049	)

*EARNINGS (LOSS) PER SHARE:*
Net income (loss) from Continuing Operations
Basic	$	0.15		$	0.03		$	0.28		$	(0.15	)
Diluted	$	0.14		$	0.03		$	0.28		$	(0.15	)

Discontinued operations
Basic	$	—		$	(0.06	)	$	(0.03	)	$	(0.06	)
Diluted	$	—		$	(0.06	)	$	(0.03	)	$	(0.06	)

Net income (loss)
Basic	$	0.15		$	(0.03	)	$	0.25		$	(0.21	)
Diluted	$	0.14		$	(0.03	)	$	0.25		$	(0.21	)

*WEIGHED AVERAGE SHARES OUTSTANDING:*
Basic	131,338			130,791			130,988			130,745
Diluted	134,072			130,791			133,416			130,745

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

Key Energy Services, Inc.

Consolidated Statements of Comprehensive Income

(In thousands)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005		2004

*NET INCOME (LOSS)*	$	19,318		$	(4,876	)	$	33,691	$	(27,049	)
*OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:*
Foreign currency translation (loss) gain	(12		)	17			117		139
*COMPREHENSIVE INCOME (LOSS), NET OF TAX*	$	19,306		$	(4,859	)	$	33,808	$	(26,910	)

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

Key Energy Services, Inc.

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

	Nine Months Ended September 30,
	2005			2004

*CASH FLOWS FROM OPERATING ACTIVITIES:*

Net income (loss)	$	33,691		$	(27,049	)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation and amortization	84,618			76,963
Accretion expense	386			393
Income from equity investment	(262		)	(13		)
Amortization of deferred debt issuance costs, discount and premium	1,280			1,586
Deferred income tax expense (benefit)	25,319			(18,142		)
Capitalized interest	(702		)	(1,913		)
(Gain) loss on sale of assets	1,850			5,314
Loss on early extinguishment of debt	10,059			12,025
Stock-based compensation	1,882			643
Accrual for former officer’s severance	—			30,232
Amortization of deferred gain on sale-leaseback transactions	(13		)	—

Changes in working capital:

Accounts receivable, net	(21,023		)	(46,884		)
Other current assets	568			(1,504		)
Accounts payable, accrued interest and accrued expenses	3,441			(8,630		)

Other assets and liabilities	(9,806		)	32,135

Operating cash flows provided by discontinued operations	13,842			7,916

Net cash provided by operating activities	145,130			63,072


*CASH FLOWS FROM INVESTING ACTIVITIES:*

Capital expenditures - Well Servicing	(55,141		)	(30,021		)
Capital expenditures - Pressure Pumping	(10,930		)	(4,143		)
Capital expenditures - Fishing and Rental	(2,935		)	(1,807		)
Capital expenditures - Other	(6,014		)	(8,821		)
Proceeds from sale of fixed assets	12,650			1,408
Proceeds from sale-leaseback transactions	5,757			—
Acquisitions, net of cash acquired	—			(22,153		)

Investing cash flows provided by discontinued operations	60,477			1,752

Net cash provided by (used in) investing activities	3,864			(63,785		)


*CASH FLOWS FROM FINANCING ACTIVITIES:*

Repayment of long-term debt	—			(126,095		)
Borrowings on revolving credit facility	—			65,000
Repayments of revolving credit facility	(48,000		)	(22,000		)
Repayment of capital lease obligations	(10,433		)	(11,340		)
Proceeds paid for debt issuance costs	(7,165		)	—
Proceeds from exercise of stock options and warrants	—			1,586

Net cash used in financing activities	(65,598		)	(92,849		)

Effect of exchange rates on cash	476			(263		)

Net increase (decrease) in cash and cash equivalents	83,872			(93,825		)
Cash and cash equivalents, beginning of period	20,425			103,215
Cash and cash equivalents, end of period	$	104,297		$	9,390

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 2005, Key conducted well servicing operations onshore in the continental United States in the following regions: Gulf Coast (including South Texas, Central Gulf Coast of Texas and South Louisiana), Permian Basin of West Texas and Eastern New Mexico, Mid-Continent (including the Anadarko, Hugoton and Arkoma Basins and the ArkLaTex and North Texas regions), Four Corners (including the San Juan, Piceance, Uinta, and Paradox Basins), the Appalachian Basin, Rocky Mountains (including the Denver-Julesberg, Powder River, Wind River, Green River and Williston Basins), and California (the San Joaquin Basin), and internationally in Argentina. During 2005, we conducted pressure pumping and cementing operations in a number of major domestic producing basins including California, the Permian Basin, the San Juan Basin, the Mid-Continent region, and in the Barnett Shale of North Texas. Our fishing and rental services are located primarily in the Gulf Coast and Permian Basin regions of Texas, as well as in California and the Mid-Continent region. During 2004, we also conducted land drilling operations in a number of major domestic producing basins including the Permian Basin, the San Juan Basin, the Powder River Basin, and the Appalachian Basin, as well as internationally in Argentina; however, we sold all of our Permian Basin and San Juan Basin contract drilling assets as well as certain drilling assets located in the Rocky Mountain and Four Corners regions to Patterson-UTI Energy, Inc. on January 15, 2005. As of September 30, 2005, we continue to conduct limited land drilling operations domestically in the Appalachian Basin of West Virginia and the Powder River Basin of Wyoming, as well as internationally in Argentina.

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 Informational Report on Form 8-K/A, filed with the Securities and Exchange Commission (“SEC”) on October 25, 2005, 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 2w003 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 Information 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 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, 2004 year-end condensed consolidated balance sheet data was derived from audited financial statements but does not include all of 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 estimate and disclosure of any potential liabilities or other contingencies as of the dates 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 disclosure 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 reclassifications. These reclassifications primarily relate to the change in our reportable segments. Prior to 2004, our Pressure Pumping and Fishing and Rental segments were reported as part of our Well Servicing segment; Pressure Pumping and Fishing and Rental are now presented as independent reportable segments. Additionally, as further discussed in Note 3–“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 are now reported as part of our Well Servicing segment. 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–“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, since the operating segments meet the aggregation criteria we are permitted to combine information about this segment with other similar segments that individually do not meet the quantitative thresholds to produce a reportable segment.

Restatement for Error

In connection with the preparation of these financial statements, we identified an error in our balance sheet as of December 31, 2003. This error affected both our retained earnings and deferred tax liabilities accounts, and arose as a result of our lack of roll-forwards and other appropriate reconciliations of the differences between the book and tax bases of our fixed assets. The error had been carried forward into our consolidated balance sheets as of December 31, 2003 from differences that initially arose in our 1999 fiscal year, and resulted in an overstatement of our retained deficit as of December 31, 2003 by approximately $10 million and an overstatement of our deferred tax liability as of the same date by the same amount. Our retained earnings and deferred tax liabilities were adjusted as of December 31, 2003 to correct this error and the adjustment is reflected in these consolidated financial statements. Total liabilities and stockholders’ equity at December 31, 2003 was not impacted by this error.

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—“Investment in IROC Systems Corp.”

In January 2003, the Financial Accounting Standards Board (“FASB”) issued 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 of ARB No. 51 (“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 either 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 entities created or obtained after March 15, 2004. The adoption of FIN 46R did not materially impact our consolidated financial statements.

Revenue Recognition

Well Servicing. 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 transportation services by the hour or by the quantities hauled.

Pressure Pumping and Fishing and Rental Services. Pressure pumping and fishing rental services include well stimulation and cementing services, and recovering lost or stuck equipment from 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 the 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 September 30, 2005, 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 cash, among other assets. We restrict investment of cash to financial institutions with high credit standing and limit the amount of credit exposure to any one financial institution.

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 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 for the quarters ended September 30, 2005 and 2004. Amortization of the assets associated with the asset retirement obligations was $0.4 million for the nine months ended September 30, 2005 and 2004.

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”). 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 fixed assets. The development of future cash flows and the determination of fair value for a division involves significant judgment and estimates. As of September 30, 2005 and December 31, 2004, no trigger events had been identified by management. However, in the third quarter of 2004, in connection with the sale of the majority of our contract drilling assets to Patterson-UTI on January 15, 2005, we reduced the carrying value of our held for sale assets to their fair values. This reduction resulted in a charge of approximately $8.9 million. See Note 3– “Discontinued Operations.”

Gains and Losses on Extinguishment of Debt

We record gains and losses from the extinguishment of debt as a part of continuing operations. During 2005 and 2004, we conducted a number of refinancings of our debt. In association with these refinancings, we extinguished several of our debt instruments. We recorded $4.2 million and zero of losses associated with the extinguishment of debt for the quarters ended September 30, 2005 and 2004, respectively. We recorded $10.1 million and $12.0 million, respectively, of losses related to early extinguishment of debt during the nine months ended September 30, 2005 and 2004.

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, 2004. This assessment did not result in an indication of goodwill impairment. However, in the third quarter of 2004, in connection with the sale of the majority of our contract drilling assets to Patterson-UTI Energy, Inc., we reduced the carrying value of our drilling segment’s goodwill to its fair value. This reduction resulted in a charge of approximately $1.4 million. See Note 3– “Discontinued Operations.”

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 September 30, 2005 and 2004 was $0.6 million and $0.7 million, respectively. Amortization of noncompete agreements for the nine months ended September 30, 2005 and 2004 was $2.1 million and $2.5 million, respectively. Amortization of patents and trademarks for the quarters ended September 30, 2005 and 2004 was $0.1 million and $0.1 million, respectively. Amortization of patents and trademarks for the nine months ended September 30, 2005 and 2004 was $0.4 million and $0.3 million, respectively. During the nine months ended September 30, 2005, the Company capitalized approximately $0.2 million of costs associated with patents and trademarks. No costs associated with noncompete agreements were capitalized by the Company during the nine months ended September 30, 2005.

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. 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 September 30, 2005		Three Months Ended September 31, 2004			Nine Months Ended September 30, 2005			Nine months Ended September 31, 2004
	(in thousands, except per share data)

Basic EPS Computation:
Numerator
Income from continuing operations	$	19,318	$	3,348		$	37,052		$	(19,454	)
Discontinued operations, net of tax	—		(8,224		)	(3,361		)	(7,595		)
Net income (loss)	$	19,318	$	(4,876	)	$	33,691		$	(27,049	)

Denominator
Weighted average common shares outstanding	131,338		130,791			130,988			130,745

Basic EPS:
Income from continuing operations	$	0.15	$	0.03		$	0.28		$	(0.15	)
Discontinued operations, net of tax	—		(0.06		)	(0.03		)	(0.06		)
Net income (loss)	$	0.15	$	(0.03	)	$	0.25		$	(0.21	)

Diluted EPS Computation:
Numerator
Income from continuing operations	$	19,318	$	3,348		$	37,052		$	(19,454	)
Discontinued operations, net of tax	—		(8,224		)	(3,361		)	(7,595		)
Net income (loss)	$	19,318	$	(4,876	)	$	33,691		$	(27,049	)

Denominator
Weighted average common shares outstanding	131,338		130,791			130,988			130,745
Stock options	2,211		—			1,934			—
Warrants	523		—			494			—
	134,072		130,791			133,416			130,745

Diluted EPS:
Income from continuing operations	$	0.14	$	0.03		$	0.28		$	(0.15	)
Discontinued operations, net of tax	—		(0.06		)	(0.03		)	(0.06		)
Net income (loss)	$	0.14	$	(0.03	)	$	0.25		$	(0.21	)

The diluted earnings per share calculation for the three and nine months ended September 30, 2005 excludes the potential exercise of 25,000 and 342,500 stock options, respectively, because the effects of such exercises on earnings per share in those periods would be anti-dilutive. The diluted earnings per share calculations for the three and nine months ended September 30, 2004 excludes the potential exercise of all then-outstanding options because the effects of such exercises on earnings per share in those periods would be anti-dilutive. The diluted earnings per share calculation for the three and nine months ended September 30, 2004 excludes the potential conversion of our 5% Convertible Subordinated Notes (hereinafter defined), because the effects of the potential conversion on earnings per share would be anti-dilutive.

Stock-Based Compensation

We account for stock option grants to employees using the intrinsic value method of accounting prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”). Our stock incentive plan, which is described more fully in Note 8 – “Stockholders’ Equity,” provides that the amount an employee must pay to exercise an option to acquire a share of the Company’s stock should be at or above the closing market price on the trading day prior to the date of grant. In that event, the options have no intrinsic value at grant date, and in accordance with the provisions of APB 25, no compensation cost is recorded.

Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”), sets forth alternative accounting and disclosure requirements for stock-based compensation arrangements. Under SFAS 123, companies are permitted to continue following the provisions of APB 25 to measure and recognize employee stock-based compensation, but are required to disclose 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 2004 and 2005. As noted above, we followed APB 25 to account for stock-based compensation during those years; the stock-based compensation expense included in net income (loss) in the

following table represents the compensation expense for the 996,352 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.

	Three Months Ended September 30, 2005			Three Months Ended September 30, 2004			Nine Months Ended September 30, 2005			Nine Months Ended September 30, 2004
	(in thousands, except per share amounts)
Net income (loss):

As reported	$	19,318		$	(4,876	)	$	33,691		$	(27,049	)

Add: stock-based employee compensation expense included in reported net income (loss), net of related tax effects	579			305			929			1,060

Deduct: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects	(751		)	(1,058		)	(1,561		)	(5,412		)

Pro forma	$	19,146		$	(5,629	)	$	33,059		$	(31,401	)


Basic earnings per share:
As reported	$	0.15		$	(0.03	)	$	0.25		$	(0.21	)
Pro forma	$	0.15		$	(0.04	)	$	0.25		$	(0.24	)

Diluted earnings per share:
As reported	$	0.14		$	(0.03	)	$	0.25		$	(0.21	)
Pro forma	$	0.14		$	(0.04	)	$	0.25		$	(0.24	)

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

In addition to the stock option grants discussed above, 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.

Foreign Currency Gains and Losses

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

Accounting Principles Not Yet Adopted in This Report

SFAS 123(R). In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment,” which revises SFAS 123, (“SFAS 123(R)”). 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 will be recognized ratably over the remaining vesting period. The compensation cost for the unvested portion of awards will be based on the fair value at date of grant as calculated for our pro forma disclosure under SFAS 123. However, we will continue to account for any portion of awards outstanding on January 1, 2006 that were initially measured using intrinsic value method in accordance with APB 25. We will recognize compensation expense under SFAS 123(R) for new awards granted after January 1, 2006. We will use the

Black-Scholes option pricing model to calculate fair value of awards granted after January 1, 2006, and we will estimate forfeitures and volatility for the calculation of compensation expense and grant date fair value. The adoption of this standard will not materially impact our financial statements.

SFAS 148. In December 2002, the FASB issued SFAS 148, which was an amendment to SFAS 123 and provided transitional guidance for a voluntary change to the fair value based method of accounting for employee stock-based compensation expense. As noted above, we continue to follow APB 25 to account for stock-based compensation and will adopt SFAS 123(R) on January 1, 2006.

FIN 47. In March 2005 the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), which becomes effective for all for fiscal years ending after December 15, 2005, with early adoption encouraged. This interpretation clarifies the term of conditional asset retirement obligation used in SFAS 143 and refers to a legal obligation to perform an asset retirement 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 standard will not materially impact our consolidated 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 changes the requirements for the accounting for and reporting of a change in accounting principle and applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. SFAS 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. The provisions of SFAS 154 are effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The adoption of this standard will not have a material impact on our consolidated financial statements.

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

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

2. SALE-LEASEBACK TRANSACTIONS

We lease certain equipment such as tractors, trailers, frac tanks and forklifts from financial institutions under master lease agreements. Under our former master lease agreements, we were required to provide current annual and quarterly financial reports to the lessor. Due to our inability to provide audited financial statements for the year ended December 31, 2003 and subsequent periods, we were required to seek waivers and amendments from our equipment lessors or pay off the outstanding leases. Some lessors refused to grant these waivers and demanded settlement of the obligation and our purchase of the equipment.

We entered into two new master lease agreements on August 31, 2005 and October 14, 2005 with a new lessor. Some of the equipment, which was being leased from lessors that demanded settlement, was sold to this new lessor and subsequently leased back from that lessor, which we account for as capital leases. We received an aggregate amount of $5.8 million in proceeds from the sale-leaseback transactions. We realized a gain of $1.1 million on one of the sale-leaseback transactions, which is being amortized to interest expense over the term of the new lease. On the other sale-leaseback transaction, we realized loss of approximately $0.3 million, which was immediately recognized in earnings.

3. DISCONTINUED OPERATIONS

On January 15, 2005, we sold the majority of our contract drilling operations to Patterson-UTI Energy for $62.0 million in cash. We received net cash proceeds of $60.5 million, net of liabilities assumed by the buyer and after paying all costs related to closing the sale. As a result of the sale, the results for these operations, which was previously reported as part of our contract drilling segment, have been presented as discontinued operations for all periods, and we recorded an after-tax charge to discontinued operations of $ 8.2 million, or $0.06 per diluted share, during the three months ended September 30, 2004; $3.4 million, or $0.03 per diluted share, during the nine months ended September 30, 2005; and $7.6 million, or $0.06 per diluted share, for the nine months ended September 30, 2004.

The assets sold to Patterson-UTI were classified as held for sale beginning in the third quarter of 2004. When we classified these assets as held for sale, we adjusted the carrying values of these assets to their fair value. These adjustments resulted in reductions in the carrying value of our goodwill by approximately $1.4 million and the varying value of our property, plant and equipment by approximately $8.9 million.

Results for activities reported as discontinued operations were as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2005		2004			2005			2004
	(in thousands)

Revenues	$	—	$	19,159		$	3,361		$	52,976
Costs and expenses	—		31,211			2,132			63,996
Income (loss) before income taxes	—		(12,052		)	1,229			(11,020		)
Income tax benefit (expense)	—		3,828			(4,590		)	3,425
Loss from discontinued operations	$	—	$	(8,224	)	$	(3,361	)	$	(7,595	)

Balance sheet data attributable to discontinued operations were as follows:

	September 30, 2005			December 31, 2004
	(in thousands)

Current assets	$	469		$	18,958
Current liabilities	(188		)	(4,938		)
Property, plant and equipment, net	—			49,295
Other assets	—			11,285
Total assets	$	281		$	74,600

4. INCOME TAXES

Income tax expense differs from amounts computed by applying the statutory federal rate as follows:

	Nine Months Ended September 30,
	2005		2004

Income tax computed at statutory rate	35.0	%	35.0	%
State taxes	2.4	%	(1.7	)%
Meals and entertainment	2.1	%	(7.1	)%
Executive and share-based compensation	0.6	%	(18.9	)%
Foreign rate differential	0.9	%	(8.1	)%
Change in valuation allowance	—	%	—	%
Other	0.4	%	(4.4	)%
Effective income tax rate	41.4	%	(5.2	)%

5. INVESTMENT IN IROC SYSTEMS CORP.

On July 22, 2004, we entered into an agreement with IROC Systems Corp. (“IROC”), an Alberta-based oilfield services company, to sell IROC ten remanufactured Skytop well service rigs, along with supporting equipment 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. In 2005, we delivered an additional four rigs, and we recognized a gain of $1.9 million upon delivery, which represents the difference between the value of the IROC shares we received on the delivery dates and the carrying value of the rigs that we delivered.

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 related to this transaction, which represents the difference between the fair market value of the IROC shares we received and the carrying value of the transferred equipment.

As of September 30, 2005, we own 8,734,469 shares of IROC common stock, which represents approximately 27.8% of IROC’s outstanding common stock on that date. IROC shares trade on the Toronto Venture Stock Exchange and had a closing price of $3.20 CDN per share on September 30, 2005. Pursuant to the terms of the agreement with IROC, Mr. William Austin, our Chief Financial Officer, and Mr. Newton W. Wilson III, our General Counsel, were appointed to the board of directors of IROC.

We have significant influence over the operations of IROC, but do not control it. We account for our investment in IROC using the equity method. The value of our investment is recorded in our 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 Consolidated Statements of Operations as a component of other income and expense, with an offsetting increase or decrease to the value of our investment, as appropriate. Any earnings distributed back to us from IROC in the form of dividends would result in a decrease in the value of our equity investment.

We recorded $0.2 million of equity income related to our investment in IROC for the quarter ended September 30, 2005. During the three and nine months ended September 30, 2004, our pro-rata share of IROC’s losses was less than $0.1 million. We recorded $0.3 million of equity income related to our investment in IROC for the nine months ended September 30, 2005. 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 $10.8 million and $3.8 million at September 30, 2005 and December 31, 2004, respectively.

6. LONG-TERM DEBT

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

	September 30, 2005		December 31, 2004
	(in thousands)

Senior Credit Facility revolving loans	$	—	$	48,000
6.375% Senior Notes Due 2013	150,000		150,000
8.375% Senior Notes Due 2008	275,680		275,870
Capital lease obligations	20,183		13,531
	445,863		487,401
Less: current portion	11,521		6,354
Total long-term debt	$	434,342	$	481,047

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 up to an aggregate principal amount of $65.0 million, which matures on July 29, 2010, (ii) a senior term loan facility in the original aggregate amount of $400.0 million, which matures on June 30, 2012, and (iii) a prefunded letter of credit facility in the aggregate amount of $82.3 million, which matures on July 29, 2010. The proceeds from the Senior Secured Credit Facility were used to refinance our existing 8.375% Senior Notes, our existing 6.375% Senior Notes, and for general corporate purposes.

Borrowings under the Senior Secured Credit Facility bear 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%. We are 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.

Prior Senior Credit Facility

On November 10, 2003, 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 revolving credit 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 $175.0 million to up to $225.0 million if we were able to obtain additional lending commitments. The revolving loan commitments were scheduled 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 forth 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, to 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 covenant for non-compliance and extend the due date for this and other filings. We paid a total of $1.1 million and $1.3 million in fees during the nine months ended September 30, 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 second 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.

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 are senior unsecured obligations and are fully and unconditionally guaranteed by substantially all of our subsidiaries. The 6.375% Senior Notes are effectively subordinated to Key’s secured indebtedness, which includes borrowings under our Prior Senior Credit Facility. The 6.375% Senior Notes require semi-annual interest payments on May 1 and November 1 of each year. Interest of $9.6 million and $8.9 million was paid on the 6.375% Senior Notes during 2004 and 2005, respectively.

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 the remaining balance of the original 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 outstanding balance of a revolving loan facility under our then-existing credit facility. The 8.375% Senior Notes are senior unsecured obligations. The 8.375% Senior Notes are effectively subordinated to Key’s secured indebtedness which includes borrowings under our Prior Senior Credit Facility. The 8.375% Senior Notes require semi-annual interest payments on March 1 and September 1 of each year. Interest of $23.0 million and $27.3 million was paid on the 8.375% Senior Notes in 2004 and 2005, respectively.

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 for the nine months ended September 30, 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 and $5.1 million of expenses in 2005 and for the nine months ended September 30, 2004, respectively. We were required under the last consent by the holder 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.

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 net cash proceeds from the private placement were used to repay substantially all of the remaining $148.6 million principal amount (plus accrued interest) owed under our bridge loan facility arranged in connection with the acquisition of Dawson Production Services, Inc. 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.

The 14% Senior Subordinated Notes required semi-annual interest payments on January 15 and July 15 of each year. The 14% Senior Subordinated Notes were subordinated to our other senior indebtedness, which included borrowings under the Prior Senior Credit Facility, the 8.375% Senior Notes and the 6.375% Senior 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 all the $97.5 million outstanding principal amount of the 14% Senior Subordinated Notes on January 15, 2004. The notes were redeemed at a redemption price of 107% of the principal amount outstanding plus accrued and unpaid interest to the redemption date, for a total cash outlay of $111.2 million. This transaction resulted in a loss of $12.0 million.

As of September 30, 2005, 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 our 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 amount paid to the holders of the Warrants during the nine months ended September 30, 2005 was $0.7 million.

5% Convertible Subordinated Notes

In 1997, we completed a private placement of $216.0 million of 5% Convertible Subordinated Notes due September 15, 2004 (the “5% Convertible Notes”). The 5% Convertible Notes were subordinated to our senior indebtedness. The 5% Convertible Notes were convertible, at the holder’s option, into shares of Key’s common stock at a conversion price of $38.50 per share, subject to certain adjustments. The 5% Convertible Notes were redeemable, at our option, on and after September 15, 2000, in whole or part, together with accrued and unpaid interest. The initial redemption price was 102.86% for the year beginning September 15, 2000 and declined ratably thereafter on an annual basis. During the years prior to 2004, we repurchased and canceled through open market transactions approximately $187.2 million principal amount of the 5% Convertible Notes at various times and prices. The remaining $18.7 million outstanding principal amount of the 5% Convertible Notes matured and were repaid on September 15, 2004, plus accrued interest and fees, for a total cash outlay of $19.2 million.

Interest on the 5% Convertible Notes was payable on March 15 and September 15 of each year. Interest of approximately $0.5 million was paid on March 15, 2004.

Long-Term Debt Principal Repayment and Interest Expense

Presented below is a schedule of the repayment requirements of long-term debt for each of the next five years and thereafter as of December 31, 2006:

As of September 30, 2005:	Principal Amount of Long-term Debt

2007	$	—
2008	275,680
2009	—
2010	—
2011	—
Thereafter	150,000
	$	425,680

Interest expense for the three and nine months ended September 30, 2005 and 2004 consisted of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(in thousands)
Cash payments	$	11,841		$	12,478		$	29,572		$	36,778
Commitment and agency fees paid	2,883			4,330			13,723			5,935
Amortization of discount and premium	(65		)	(60		)	(190		)	(175		)
Amortization of debt issuance costs	264			577			1,277			1,761
Net change in accrued interest	(3,242		)	(3,547		)	(2,698		)	(9,721		)
Capitalized interest	(377		)	(674		)	(702		)	(1,913		)
Total interest expense	$	11,304		$	13,104		$	40,982		$	32,665

7. 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. Discovery in the case is underway, but a class has not been certified. We intend to vigorously defend against this action; however, we cannot predict the outcome of the lawsuit.

Shareholder Class Action Suits. 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. The complaints generally allege 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 the shareholder class actions and derivative actions described above, plaintiffs are seeking an unspecified amount of monetary damages. At this time, we cannot ascertain the ultimate aggregate amount of monetary liability or financial impact of the 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.

Tax Audits. We are routinely the subject of audits by tax authorities and have received some material assessments from tax auditors. As of September 30, 2005, 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 $0.9 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 September 30, 2005 and December 31, 2004, we have recorded $58.8 million and $55.3 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. At September 30, 2005 and December 31, 2004, respectively, we have recorded $5.4 million and $5.5 million for our environmental remediation liabilities.

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.

8. STOCKHOLDERS’ EQUITY

Common Stock

On September 30, 2005, we had 200,000,000 shares of common stock authorized with a $0.10 par value of which 131,334,196 shares of common stock were issued and outstanding, net of 416,666 of shares held in treasury, and no dividends had been issued. On December 31, 2004, we had 200,000,000 shares of common stock authorized with a $0.10 par value of which 130,791,338 shares were issued and outstanding, net of 416,666 shares held in treasury and no dividends had been issued.

Stock Incentive Plans

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

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

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

(vii) supplemental tax bonuses (collectively, “Incentive Awards”). ISOs and NSOs are sometimes referred to collectively herein as “Options.”

The following table summarizes the stock option activity related to the plans (shares in thousands):

	Nine Months Ended September 30, 2005
	Options		Weighted Average Exercise Price		Weighted Average Fair Value

Outstanding at beginning of period	10,408		$	8.47	$	4.77
Granted	370		$	12.12	$	6.05
Exercised	—		$	—	$	—
Cancelled or expired	(1,496	)	$	8.14	$	4.96
Outstanding at end of period	9,282		$	8.67	$	4.79

Exercisable at end of period	8,665		$	8.49	4.75

The following tables summarize information about the stock options outstanding at September 30, 2005:

	Options Outstanding
	Weighted Average Remaining Contractual Life	Number of Options Outstanding September 30, 2005		Weighted Average Exercise Price		Weighted Average Fair Value
	(Years)
Range of Exercise Prices:
$3.00 - $8.00	4.88	2,227		$	6.54	$	3.77
$8.01 - $8.25	5.01	1,725		$	8.25	$	5.05
$8.26 - $8.50	4.63	1,813		$	8.46	$	5.22
$8.51 - $9.75	5.00	1,381		$	9.25	$	5.80
$9.76 - $14.51	7.23	2,136		$	11.05	$	4.63
		9,282		$	8.67	$	4.79

Aggregate intrinsic value (in thousands)		$	8,676

	Options Exercisable
	Number of Options Exercisable September 30, 2005		Weighted Average Exercise Price		Weighted Average Fair Value
Range of Exercise Prices:
$3.00 - $8.00	2,227		$	6.54	$	3.77
$8.01 - $8.25	1,725		$	8.25	$	5.05
$8.26 - $8.50	1,800		$	8.46	$	5.22
$8.51 - $9.75	1,373		$	9.25	$	5.81
$9.76 - $14.51	1,540		$	10.93	$	4.34
	8,665		$	8.49	$	4.75

Aggregate intrinsic value (in thousands)	$	8,446

The total fair value of stock options granted during the nine months ended September 30, 2005 was $2.2 million. The fair value of each stock option grant was estimated on the date of grant using the Black-Scholes option-pricing model, based on the following weighted-average assumptions:

	Nine Months Ended September 30, 2005

Risk-free rate	3.8	%
Expected life of options, years	6.00
Expected volatility	53.9	%
Expected dividends	none

Common Stock Awards

Beginning in June 2005, we began granting shares of common stock to our outside directors and certain employees. These shares are restricted as to exercisability and transferability, and in certain cases, have required service periods before they are vested and are subject to forfeiture. The vesting periods on these grants range from zero (immediately vested) to three years. The total fair market value of all common stock awards granted during the nine months ended September 30, 2005 was $6.5 million. No common stock awards were granted prior to June 2005.

We issued a total of 550,000 common shares to our outside directors and employees during the nine months ended September 30, 2005 at a weighted-average issuance price of $11.90 per share. Of these, 50,000 were issued to our outside directors and vested immediately, while the remaining 500,000 vest ratably over a three year period. During the third quarter of 2005, one of our outside directors refused his common stock award of 7,143 shares.

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 and nine months ended September 30, 2005, we recognized $1.5 million of expense related to common stock awards, net of estimated and actual forfeitures.

9. SEGMENT INFORMATION

For 2005, 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 an 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, deferred debt financing costs and deferred income tax assets.

The following table sets forth our segment information as of and for the periods ended September 30, 2005 and 2004, respectively:

	Well Servicing			Pressure Pumping			Fishing and Rental			Corporate / Other			Discontinued Operations		Eliminations			Total
	(in thousands)
As of and for the three months ended September 30, 2005:
Operating revenues	$	247,059		$	41,881		$	20,215		$	—		$	—	$	—		$	309,155
Gross margin	91,704			18,710			6,459			—			—		—			116,873
Depreciation and amortization	22,308			1,993			1,529			2,801			—		—			28,631
Interest expense	(51		)	(78		)	18			11,415			—		—			11,304
Net income (loss) from continuing operations	51,427			15,962			3,631			(51,702		)	—		—			19,318
Propery, plant and equipment, net	466,625			57,050			27,278			35,265			—		—			586,218
Total assets	910,170			135,273			68,898			525,526			469		(326,459		)	1,313,877
Capital expenditures, excluding acquisitions	(18,690		)	(4,714		)	(1,597		)	(1,787		)	—		—			(26,788		)

	Well Servicing			Pressure Pumping			Fishing and Rental			Corporate / Other			Discontinued Operations		Eliminations			Total
	(in thousands)
As of and for the three months ended September 30, 2004:
Operating revenues	$	213,615		$	24,525		$	20,345		$	—		$	—	$	—		$	258,485
Gross margin	70,110			6,501			8,947			—			—		—			85,558
Depreciation and amortization	26,990			1,656			1,397			1,637			—		—			31,680
Interest expense	23			(14		)	4			13,091			—		—			13,104
Net income (loss) from continuing operations	27,617			4,007			6,071			(34,347		)	—		—			3,348
Propery, plant and equipment, net	537,914			46,142			27,928			49,551			—		—			661,535
Total assets	923,516			111,928			67,258			725,747			77,053		(599,334		)	1,306,168
Capital expenditures, excluding acquisitions	(6,347		)	(2,506		)	(1,380		)	(649		)	—		—			(10,882		)

	Well Servicing			Pressure Pumping			Fishing and Rental			Corporate / Other			Discontinued Operations		Eliminations			Total
	(in thousands)
As of and for the nine months ended September 30, 2005:
Operating revenues	$	706,088		$	108,631		$	60,541		$	—		$	—	$	—		$	875,260
Gross margin	239,457			42,863			19,405			—			—		—			301,725
Depreciation and amortization	65,147			6,452			4,483			8,536			—		—			84,618
Interest expense	(29		)	(162		)	30			41,143			—		—			40,982
Net income (loss) from continuing operations	126,363			37,645			10,216			(137,172		)	—		—			37,052
Propery, plant and equipment, net	466,625			57,050			27,278			35,265			—		—			586,218
Total assets	910,170			135,273			68,898			525,526			469		(326,459		)	1,313,877
Capital expenditures, excluding acquisitions	(55,141		)	(10,930		)	(2,935		)	(6,014		)	—		—			(75,020		)

	Well Servicing			Pressure Pumping			Fishing and Rental			Corporate / Other			Discontinued Operations		Eliminations			Total
	(in thousands)
As of and for the nine months ended September 30, 2004:
Operating revenues	$	610,832		$	65,263		$	57,902		$	—		$	—	$	—		$	733,997
Gross margin	189,863			17,563			21,127			—			—		—			228,553
Depreciation and amortization	64,045			4,512			4,117			4,289			—		—			76,963
Interest expense	94			(32		)	6			32,597			—		—			32,665
Net income (loss) from continuing operations	81,252			10,877			13,950			(125,533		)	—		—			(19,454		)
Propery, plant and equipment, net	537,914			46,142			27,928			49,551			—		—			661,535
Total assets	923,516			111,928			67,258			725,747			77,053		(599,334		)	1,306,168
Capital expenditures, excluding acquisitions	(27,202		)	(4,143		)	(1,807		)	(1,605		)	—		—			(34,757		)

Operating revenues for our foreign operations were $15.4 million and $15.4 million for the three months ended September 30, 2005 and 2004, respectively. Operating revenues for our foreign operations were $50.6 million and $42.9 million for the nine months ended September 30, 2005 and 2004, respectively. Gross margins for our foreign operations were $3.6 million and $5.2 million for the three months ended September 30, 2005 and 2004, respectively. Gross margins for our foreign operations were $13.4 million and $14.5 million for the nine months ended September 30, 2005 and 2004, respectively.

We have $53.8 million and $54.4 million of identifiable assets related to our foreign operations as of September 30, 2005 and December 31, 2004, respectively. Capital expenditures for our foreign operations were $5.8 million and $5.0 million for the nine months ended September 30, 2005 and 2004, respectively.

10. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

Our Senior Notes are guaranteed by substantially all of our domestic subsidiaries, all of which are wholly-owned. The guarantees are joint and several, full, complete and unconditional. There are no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company.

The accompanying condensed consolidating financial information has been prepared and presented pursuant to SEC Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered.” The information is not intended to present the financial position, results of operations and cash flows of the individual companies or groups of companies in accordance with GAAP.

CONDENSED CONSOLIDATING BALANCE SHEETS

	September 30, 2005
	Parent Company			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)

Assets:
Current assets	$	137,801		$	210,102	$	29,864		$	—		$	377,767
Current assets of discontinued operations	—			469		—			—			469
Net property and equipment	35,265			527,609		23,344			—			586,218
Goodwill	3,459			316,528		976			—			320,963
Deferred costs, net	5,376			—		—			—			5,376
Inter-company receivables	326,459			—		—			(326,459		)	—
Other assets	17,166			5,918		—			—			23,084

TOTAL ASSETS	$	525,526		$	1,060,626	$	54,184		$	(326,459	)	$	1,313,877

Liabilities and equity:
Current liabilities	$	62,669		$	70,835	$	15,487		$	—		$	148,991
Current liabilities of discontinued operations	—			188		—			—			188
Long-term debt	421,680			—		—			—			421,680
Capital lease obligations	220			12,442		—			—			12,662
Inter-company payables	—			270,101		56,358			(326,459		)	—
Deferred tax liability	112,745			89		551			—			113,385
Other long-term liabilities	63,889			10,636		1,090			—			75,615
Stockholders’ equity	(135,677		)	696,335		(19,302		)	—			541,356

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	525,526		$	1,060,626	$	54,184		$	(326,459	)	$	1,313,877

	December 31, 2004
	Parent Company			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(in thousands)

Assets:
Current assets	$	75,365		$	190,972	$	25,728		$	—		$	292,065
Current assets of discontinued operations				18,958								18,958
Net property and equipment	43,392			526,662		27,724			—			597,778
Goodwill	3,459			316,527		956			—			320,942
Deferred costs, net	9,068			—		—			—			9,068
Inter-company receivables	566,726			—		—			(566,726		)	—
Other assets	7,723			9,508		—			—			17,231
Non-current assets of discontinued operations	—			60,580		—			—			60,580

TOTAL ASSETS	$	705,733		$	1,123,207	$	54,408		$	(566,726	)	$	1,316,622

Liabilities and equity:
Current liabilities	$	59,784		$	62,683	$	17,698		$	—		$	140,165
Current liabilities of discontinued operations				4,938								4,938
Long-term debt	473,870			—		—			—			473,870
Capital lease obligations	576			6,601		—			—			7,177
Inter-company payables	—			510,430		56,296			(566,726		)	—
Deferred tax liability	107,168			88		504			—			107,760
Other long-term liabilities	65,030			10,811		1,205			—			77,046
Stockholders’ equity	(695		)	527,656		(21,295		)	—			505,666

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	705,733		$	1,123,207	$	54,408		$	(566,726	)	$	1,316,622

CONDENSED CONSOLIDATING INCOME STATEMENTS

	Three Months Ended September 30, 2005
	Parent Company			Guarantor Subsidiaries			Non-guarantor subsidiaries			Consolidated
	(in thousands)

Revenues	$	—		$	293,741		$	15,414		$	309,155
Costs and expenses:
Direct expenses	—			180,448			11,834			192,282
Depreciation and amortization	2,801			24,700			1,130			28,631
General and administrative expenses	23,343			13,680			1,704			38,727
Interest	11,415			(116		)	5			11,304
Loss on early extinguishment of debt	4,177			—			—			4,177
Other, net	(3,237		)	1,241			3,150			1,154
Total costs and expenses	38,499			219,953			17,823			276,275
Income (loss) from continuing operations before income taxes	(38,499		)	73,788			(2,409		)	32,880
Income tax expense	(13,202		)	—			(360		)	(13,562		)
Income (loss) from continuing operations	(51,701		)	73,788			(2,769		)	19,318
Discontinued operations, net of tax	—			—			—			—
NET INCOME (LOSS)	$	(51,701	)	$	73,788		$	(2,769	)	$	19,318

	Three Months Ended September 30, 2004
	Parent Company			Guarantor Subsidiaries			Non-guarantor subsidiaries			Consolidated
	(in thousands)

Revenues	$	—		$	243,092		$	15,393		$	258,485
Costs and expenses:
Direct expenses	—			162,697			10,230			172,927
Depreciation and amortization	1,637			29,072			971			31,680
General and administrative expenses	16,765			15,156			1,192			33,113
Interest	13,091			6			7			13,104
Loss on early extinguishment of debt	—			—			—			—
Other, net	(352		)	(36		)	158			(230		)
Total costs and expenses	31,141			206,895			12,558			250,594
Income (loss) from continuing operations before income taxes	(31,141		)	36,197			2,835			7,891
Income tax expense	(3,205		)	—			(1,338		)	(4,543		)
Income (loss) from continuing operations	(34,346		)	36,197			1,497			3,348
Discontinued operations, net of tax	—			(8,224		)	—			(8,224		)
NET INCOME (LOSS)	$	(34,346	)	$	27,973		$	1,497		$	(4,876	)

	Nine Months Ended September 30, 2005
	Parent Company			Guarantor Subsidiaries			Non-guarantor subsidiaries			Consolidated
	(in thousands)

Revenues	$	—		$	824,635		$	50,625		$	875,260
Costs and expenses:
Direct expenses	—			536,293			37,242			573,535
Depreciation and amortization	8,536			72,787			3,295			84,618
General and administrative expenses	61,824			44,107			1,872			107,803
Interest	41,143			(198		)	37			40,982
Loss on early extinguishment of debt	10,059			—			—			10,059
Other, net	(8,089		)	(703		)	3,787			(5,005		)
Total costs and expenses	113,473			652,286			46,233			811,992
Income (loss) from continuing operations before income taxes	(113,473		)	172,349			4,392			63,268
Income tax expense	(23,700		)	—			(2,516		)	(26,216		)
Income (loss) from continuing operations	(137,173		)	172,349			1,876			37,052
Discontinued operations, net of tax	—			(3,361		)	—			(3,361		)
NET INCOME (LOSS)	$	(137,173	)	$	168,988		$	1,876		$	33,691

	Nine Months Ended September 30, 2004
	Parent Company			Guarantor Subsidiaries			Non-guarantor subsidiaries			Consolidated
	(in thousands)

Revenues	$	—		$	691,122		$	42,875		$	733,997
Costs and expenses:
Direct expenses	—			477,031			28,413			505,444
Depreciation and amortization	4,289			69,848			2,826			76,963
General and administrative expenses	77,812			39,018			4,170			121,000
Interest	32,597			29			39			32,665
Loss on early extinguishment of debt	12,025			—			—			12,025
Other, net	510			3,584			303			4,397
Total costs and expenses	127,233			589,510			35,751			752,494
Income (loss) from continuing operations before income taxes	(127,233		)	101,612			7,124			(18,497		)
Income tax benefit (expense)	1,699			—			(2,656		)	(957		)
Income (loss) from continuing operations	(125,534		)	101,612			4,468			(19,454		)
Discontinued operations, net of tax	—			(7,595		)	—			(7,595		)
NET INCOME (LOSS)	$	(125,534	)	$	94,017		$	4,468		$	(27,049	)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	Nine Months Ended September 30, 2005
	Parent Company			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Consolidated
	(in thousands)

Net cash provided by operating activities	$	159,653		$	(20,364	)	$	5,841		$	145,130
Net cash used in investing activities	491			9,224			(5,851		)	3,864
Net cash provided by financing activities	(76,031		)	10,433			—			(65,598		)
Effect of exchange rates on cash	—			—			476			476
Net increase (decrease) in cash	84,113			(707		)	466			83,872
Cash at beginning of period	18,622			1,068			735			20,425
Cash at end of period	$	102,735		$	361		$	1,201		$	104,297

	Nine Months Ended September 30, 2004
	Parent Company			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Consolidated
	(in thousands)

Net cash provided by operating activities	$	15,303		$	43,487		$	4,282		$	63,072
Net cash used in investing activities	(1,605		)	(57,198		)	(4,982		)	(63,785		)
Net cash provided by financing activities	(104,189		)	11,340			—			(92,849		)
Effect of exchange rates on cash	—			—			(263		)	(263		)
Net increase (decrease) in cash	(90,491		)	(2,371		)	(963		)	(93,825		)
Cash at beginning of period	100,109			1,802			1,304			103,215
Cash at end of period	$	9,618		$	(569	)	$	341		$	9,390

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 September 30, 2005 and for the three and nine months ended September 30, 2005 and 2004, 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, Egypt and Canada. However, in 2004 we shut down our operation in Ontario, Canada and our contract in Egypt was completed on June 30, 2005.

We operate in three business segments:

Well Servicing Services:

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.

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.

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 has increased significantly over the past several years as commodity prices, both oil and natural gas, have increased.

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

2004:
First Quarter	$	35.24	$	5.71	1,021
Second Quarter	$	38.35	$	6.16	1,068
Third Quarter	$	43.87	$	5.58	1,134
Fourth Quarter	$	48.30	$	7.26	1,148

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

Internally, we measure activity levels primarily through our rig and trucking hours. As capital spending by oil and natural gas producers increases, demand for our services also rises, resulting in increased rig and trucking services and more hours worked. Conversely, when activity levels decline due to lower spending by oil and natural

gas producers, we provide few rig and trucking services, which results in lower hours worked. We publicly release our monthly rig and trucking hours and the following table presents our quarterly rig and trucking hours from 2004 through the third quarter of 2005.

	Rig Hours	Trucking Hours
2004:
First Quarter	584,897	729,020
Second Quarter	609,116	718,003
Third Quarter	626,556	690,542
Fourth Quarter	600,217	664,283
Total 2004:	2,420,786	2,801,848

2005:
First Quarter	621,228	641,841
Second Quarter	661,928	635,448
Third Quarter	668,741	607,500

Results of Operations

Key Energy Services, Inc.

Condensed Consolidated Statements of Operations

(In thousands, except per share data)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004

*REVENUES:*
Well servicing	$	247,059		$	213,615		$	706,088		$	610,832
Pressure pumping	41,881			24,525			108,631			65,263
Fishing and rental	20,215			20,345			60,541			57,902

Total revenues	309,155			258,485			875,260			733,997

*COSTS AND EXPENSES:*
Well servicing	155,357			143,506			466,632			420,969
Pressure pumping	23,170			18,023			65,768			47,700
Fishing and rental	13,755			11,398			41,135			36,775
Depreciation and amortization	28,631			31,680			84,618			76,963
General and administrative	38,727			33,113			107,803			121,000
Interest expense	11,304			13,104			40,982			32,665
Loss on early extinguishment of debt	4,177			—			10,059			12,025
Loss on sale of assets	1,880			386			1,850			5,314
Interest income	(703		)	(277		)	(1,863		)	(531		)
Other, net	(23		)	(339		)	(4,992		)	(386		)

Total costs and expenses, net	276,275			250,594			811,992			752,494

Income (loss) from continuing operations before income taxes	32,880			7,891			63,268			(18,497		)
Income tax expense	(13,562		)	(4,543		)	(26,216		)	(957		)

*INCOME (LOSS) FROM CONTINUING OPERATIONS*	19,318			3,348			37,052			(19,454		)

Discontinued operations, net of tax benefit (expense) of $3,828, $(4,590), and $3,424 for the three months ended September 30, 2004 and nine months ended September 30, 2005 and 2004, respectively	—			(8,224		)	(3,361		)	(7,595		)

*NET INCOME (LOSS)*	$	19,318		$	(4,876	)	$	33,691		$	(27,049	)

Three Months Ended September 30, 2005 Compared to Three Months Ended September 30, 2004

Revenue:

Well Servicing: Well servicing revenues increased 15.7% to $247.1 million for the quarter ended September 30, 2005 compared to revenue of $213.6 million for the quarter ended September 30, 2004. 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 September 2005 quarter, the Company’s composite segment revenue to total hours (as defined as rig hours plus trucking hours) was approximately $194 per hour compared to approximately $162 per hour for the September 2004 quarter. Rig hours for the Company increased 6.7% from 626,556 in the September 2004 quarter to 668,741 in the September 2005 quarter while the Company’s trucking hours decreased 12.0% from 690,542 in the September 2004 quarter to 607,500 in the September 2005 quarter. The increase 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.

Pressure Pumping Services: Pressure pumping services (“PPS”) segment revenues increased 70.8% to $41.9 million for the quarter ended September 30, 2005 compared to revenue of $24.5 million for the quarter ended September 30, 2004. The increase in revenue is attributable to incremental pressure pumping equipment, higher activity levels and higher pricing for the Company’s services. The Company exited the September 2005 quarter with approximately 113,000 horsepower of pumping equipment as compared to approximately 97,000 at the end of the September 2004 quarter. The Company’s pressure pumping segment performs several different services including fracturing, cementing, acidizing, nitrogen services, abandonment and other miscellaneous jobs. Generally,

the fracturing and cementing jobs represent the substantial majority of the segments revenue. Fracturing jobs totaled 347 in the September 2005 quarter compared to 324 in the September 2004 quarter while cementing jobs totaled 442 in the September 2005 quarter compared to 281 in the September 2004 quarter.

Fishing and Rental Services: Fishing and rental services (“FRS”) segment revenues for the quarter ended September 30, 2005 was flat at $20.2 million compared to revenue of $20.3 million for the quarter ended September 30, 2004. Despite strong industry conditions, the FRS segment underwent management changes during 2005 which negatively impacted operations.

Direct Costs

Well Servicing: Well serving direct costs increased 8.3% to $155.4 million for the quarter ended September 30, 2005 compared to $143.5 million for the quarter ended September 30, 2004. The increase in direct costs is largely attributable to higher labor and equipment costs, including higher wages, repair and maintenance expense, higher fuel expense and higher supplies expense. The increase in these costs is primarily due to higher activity levels. The increase in direct costs was modestly offset by the loss of the Company’s Egypt contract in July 2005. During the quarter ended September 30, 2005, the Company’s Egypt operations generated direct costs of approximately $0.3 million compared to direct costs of approximately $1.7 million in the quarter ended September 30, 2004. Direct costs as a percent of total well service segment revenue improved to 62.9% for the quarter ended September 30, 2005 compared to 67.2% for the quarter ended September 30, 2004.

Pressure Pumping Services: PPS direct costs increased 28.6% to $23.2 million for the quarter ended September 30, 2005 compared to $18.0 million for the quarter ended September 30, 2004. The increase in direct costs is largely attributable to increased sand and chemical purchases as well as higher trucking and freight costs, higher labor costs and higher repair and maintenance expense. The increase in direct costs is primarily the result of increased demand for the Company’s services. Direct costs as a percent of total PPS segment revenue improved to 55.3% for the quarter ended September 30, 2005 compared to 73.5% for the quarter ended September 30, 2004.

Fishing and Rental Services: FRS direct costs increased 20.7% to $13.8 million for the quarter ended September 30, 2005 compared to $11.4 million for the quarter ended September 30, 2004. The increase in direct costs is largely attributable to higher repairs and maintenance expense and higher labor costs, offset slightly by reduced contracted labor costs. The increase in direct costs is primarily the result of continued demand for the Company’s services. Direct costs as a percent of total FRS segment revenue deteriorated to 68.0% for the quarter ended September 30, 2005 compared to 56.0% for the quarter ended September 30, 2004. The margin contraction is due to higher costs on flat year-over-year revenue.

General and Administrative Expense

General and administrative (“G&A”) expenses increased 17.0% to $38.7 million for the quarter ended September 30, 2005 compared to $33.1 million for the quarter ended September 30, 2004. The increase in G&A expenses is primarily attributable to higher compensation costs and travel-related expense. The increase in compensation expenses is attributable to increased equity-based compensation and higher incentive compensation. G&A expense as a percent of revenue for the quarter ended September 30, 2005 totaled 12.5% compared to 12.8% for the quarter ended September 30, 2004.

Interest Expense

Interest expense decreased 13.7% to $11.3 million for the quarter ended September 30, 2005 compared to $13.1 million for the quarter ended September 30, 2004. The decrease is primarily attributable to the refinancing of the Company’s long term debt in July 2005. In conjunction with the Company’s $547.25 million Senior Secured Credit Facility, the Company was able to eliminate the consent fees which had previously been paid to the Company’s bondholders. Interest expense as a percent of revenue for the quarter ended September 30, 2005 totaled 3.7% compared to 5.1% for the quarter ended September 30, 2004.

Depreciation Expense

Depreciation expense decreased 9.6% to $28.6 million for the quarter ended September 30, 2005 compared to $31.7 million for the quarter ended September 30, 2004. The decrease is primarily attributable to a lower fixed asset base which is due to the sale of our Michigan assets in May 2005. For the quarter ended September 30, 2005, the Company spent approximately $26.8 million on capital expenditures as compared to $18.5 million for the quarter ended September 30, 2004. Depreciation expense as a percent of revenue for the quarter ended September 30, 2005 totaled 9.3% compared to 12.3% for the quarter ended September 30, 2004.

Income Taxes

Our income tax expense (benefit) from continuing operations was $13.6 million and $4.5 million for the three months ended September 30, 2005 and 2004, respectively. Our effective tax rate for those same periods was 41.2% and 57.6%, respectively. The differences between the rates between periods relate largely to nondeductible expense for executive compensation and other nondeductible items. Differences between the statutory rate and the effective rate are due primarily to state and foreign income taxes and nondeductible expenditures.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Revenue

Well Servicing: Well servicing revenues increased 15.6% to $706.1 million for the nine months ended September 30, 2005 compared to revenue of $610.8 million for the nine months ended September 30, 2004. 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 nine months ended September 30, 2005, the Company’s composite segment revenue to total hours (as defined as rig hours plus trucking hours) was approximately $184 per hour compared to approximately $154 per hour for the nine months ended September 30, 2004. Rig hours for the Company increased 7.2% from 1,820,569 in the first nine months of 2004 to 1,951,897 in the first nine months of 2005 while the Company’s trucking hours decreased 11.8% from 2,137,565 in the first nine months of 2004 to 1,884,789 in the first nine months of 2005. The increase 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.

Pressure Pumping Services: PPS segment revenues increased 66.5% to $108.6 million for the nine months ended September 30, 2005 compared to revenue of $65.3 million for the nine months ended September 30, 2004. The increase in revenue is attributable to incremental pressure pumping equipment, higher activity levels and higher pricing for the Company’s services. The Company exited the nine months ended September 30, 2005 with approximately 113,000 horsepower of pumping equipment as compared to approximately 97,000 horsepower for the nine months ended September 30, 2004. The Company’s pressure pumping segments performs several different services including fracturing, cementing, acidizing, nitrogen services, abandonment and other miscellaneous jobs. Generally, the fracturing and cementing jobs represent the substantial majority of the segments revenue. Fracturing jobs totaled 982 during the first nine months of 2005 compared to 964 for the first nine months of 2004 while cementing jobs totaled 1,103 during the first nine months of 2005 compared to 595 for the first nine months of 2004.

Fishing and Rental Services: FRS segment revenues for the nine months ended September 30, 2005 increased 4.6% to $60.5 million compared to revenue of $57.9 million for the nine months ended September 30, 2004. Despite strong industry conditions, the FRS segment underwent management changes during 2005 which negatively impacted operations.

Direct Costs

Well Servicing: Well servicing direct costs increased 10.8% to $466.6 million for the nine months ended September 30, 2005 compared to $421.0 million for the nine months ended September 30, 2004. The increase in direct costs is largely attributable to higher labor and equipment costs, including higher wages, higher repair and maintenance expense, higher fuel expense and higher insurance premiums. The increase in these costs is primarily

due to higher activity levels combined with increased hourly wages. Direct costs as a percent of total well servicing segment revenue improved to 66.1% for the nine months ended September 30, 2005 compared to 68.9% for the nine months ended September 30, 2004.

Pressure Pumping Services: PPS direct costs increased 37.9% to $65.8 million for the nine months ended September 30, 2005 compared to $47.7 million for the nine months ended September 30, 2004. The increase in direct costs is largely attributable to increased sand and chemical purchases as well as higher trucking and freight costs, higher labor costs and higher repair and maintenance expense. The increase in direct costs is primarily the result of increased demand for the Company’s services. Direct costs as a percent of total PPS segment revenue improved to 60.5% for the nine months ended September 30, 2005 compared to 73.1% for the nine months ended September 30, 2004.

Fishing and Rental Services: FRS direct costs increased 11.9% to $41.1 million for the nine months ended September 30, 2005 compared to $36.8 million for the nine months ended September 30, 2004. The increase in direct costs is largely attributable to higher repairs and maintenance expense and higher labor costs, offset slightly by reduced contracted labor costs. The increase in direct costs is primarily the result of increased demand for the Company’s services. Direct costs as a percent of total FRS segment revenue deteriorated to 67.9% for the nine months ended September 30, 2005 compared to 63.5% for the nine months ended September 30, 2004.

General and Administrative Expense

General and administrative expenses decreased 10.9% to $107.8 million for the nine months ended September 30, 2005 compared to $121.0 million for the nine months ended September 30, 2004. The decrease in G&A expenses is primarily attributable to the $21.5 million settlement expense with the Company’s former chief executive officer that was incurred in the June 2004 quarter. Excluding the settlement expense, G&A expense increased during the nine months ended September 30, 2005 due primarily to higher professional fees associated with the restatement process as well as higher compensation expense associated with increased corporate staff. The increase is offset somewhat by lower bad debt expense. During the nine months ended September 30, 2004, the Company had $3.9 million of bad debt expense compared to bad debt expense of $9.2 million for the nine months ended September 30, 2005. The bad debt expense during the nine months ended September 30, 2004 includes the write-off of the $9.0 million retention bonus to the Company’s former chief executive officer. G&A expense as a percent of revenue for the nine months ended September 30, 2005 totaled 12.3% compared to 16.5% for the nine months ended September 30, 2004.

Interest Expense

Interest expense increased 25.5% to $41.0 million for the nine months ended September 30, 2005 compared to $32.7 million for the nine months ended September 30, 2004. The increase relates to higher waiver and consent fees paid to our bondholders due to our inability to timely file our audited financial statements. Interest expense as a percent of revenue for the nine months ended September 30, 2005 totaled 4.7% compared to 4.5% for the nine months ended September 30, 2004.

Depreciation Expense

Depreciation expense increased 9.9% to $84.6 million for the nine months ended September 30, 2005 compared to $77.0 million for the nine months ended September 30, 2004. During the nine months ended September 30, 2005, the Company spent approximately $75.0 million on capital expenditures as compared to $44.8 million for the nine months ended September 30, 2004. Depreciation expense as a percent of revenue for the nine months ended September 30, 2005 totaled 9.7% compared to 10.5% for the nine months ended September 30, 2004.

Income Taxes

Our income tax expense (benefit) from continuing operations was $26.2 million and $1.0 million for the nine months ended September 30, 2005 and 2004, respectively. Our effective tax rate for those same periods was 41.4% and (5.2%), respectively. The differences between the rates between periods relate largely to nondeductible expense for executive compensation and other nondeductible items. Differences between the statutory rate and the effective rate are due primarily to state and foreign income taxes and nondeductible expenditures.

Liquidity and Capital Resources

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

We believe that our current reserves of cash and cash equivalents, availability under our revolving credit facility, and internally generated cash flow from operations are sufficient to finance the cash requirements of our current and future operations, including our capital expenditure budget. As of September 30, 2005, we had $104.3 million in cash and $65.0 million of availability under our revolving credit facility.

Cash Flow

Our net cash provided by operating activities for the nine months ended September 30, 2005, totaled $145.1 million compared to $63.1 million for the nine months ended September 30, 2004. The increase in cash flow from operating activities is due primarily to higher net income. Our net cash provided by investing activities for the nine months ended September 30, 2005 totaled $3.9 million compared to cash used of $63.8 million for the nine months ended September 30, 2004. The increase in cash flow provided by investing activities is due to cash received from the sale of our drilling assets. Our net cash used in financing activities for the nine months ended September 30, 2005 totaled $65.6 million compared to $92.8 million for the nine months ended September 30, 2004.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Critical Accounting Policies

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

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

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

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

· Accounting for contingencies;

· Accounting for income taxes;

· Estimate of fixed asset depreciable lives; and

· Valuation of tangible and intangible assets.

Workers’ Compensation, Vehicular Liability and Other Insurance Reserves

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

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

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

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

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

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

Accounting for Contingencies

In addition to our workers’ compensation, vehicular liability and other self-insurance reserves, we record other loss contingencies, which relate to numerous lawsuits, claims, proceedings and tax-related audits in the normal course of our operations on our consolidated balance sheet. In accordance with Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies,” 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 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.

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

SFAS 132. In December 2003, the Financial Accounting Standards Board (“FASB”) released Statement 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 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.

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

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.

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

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

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

Item 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We maintain a set of disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed in our reports filed 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 management, including the Company’s Chairman and Chief Executive Officer and 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. Based on such 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 concluded that, as of December 31, 2006 and September 30, 2005, our disclosure controls and procedures were not effective.

We believe that, based on the substantive procedures we have performed in connection with the preparation of the consolidated financial statements contained in our Annual Report on Form 10-K, our consolidated financial statements as of and for the year ended December 31, 2006, including quarterly periods, are fairly presented accordance with GAAP. See Item 9A. “Controls and Procedures,” included in our Annual Report on Form 10-K for the year ended December 31, 2006 for a complete discussion of material weaknesses of internal control over financial reporting identified for the year ended December 31, 2006.

Changes in Internal Control over Financial Reporting

We believe that there have been changes in our internal control over financial reporting during the period from January 1, 2004 to December 31, 2006 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 to Item 3. “Legal Proceedings” included in our 2006 Annual Report on Form 10-K, which section is incorporated herein by reference and filed as Exhibit 99.1 to this report.

Item 1A. RISK FACTORS

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

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

None.

Item 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

Item 5. OTHER INFORMATION

None.

Item 6. EXHIBITS

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

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

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

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

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

	4.3	First Supplemental Indenture dated as of March 1, 2002 among the Registrant, the Guarantors (as defined therein) 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.)

	4.4	First Supplemental Indenture to the Indenture dated May 9, 2003, dated as of May 14, 2003 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.)

	4.5	Consent Solicitation Statement of 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.)

	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.)

	10.1	Second Amendment to Office Lease dated as of July 24, 2005 between Crescent 1301 McKinney, L.P. and Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K dated June 30, 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.

SIGNATURE

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

		KEY ENERGY SERVICES, INC.
		(Registrant)

		/s/ Richard J. Alario
	By:	Richard J. Alario
		President and Chief Executive Officer
		(Principal Executive Officer)


Date: August 13, 2007

EXHIBITS INDEX

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

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

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

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

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

4.3		First Supplemental Indenture dated as of March 1, 2002 among the Registrant, the Guarantors (as defined therein) 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.)

4.4		First Supplemental Indenture to the Indenture dated May 9, 2003, dated as of May 14, 2003 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.)

4.5		Consent Solicitation Statement of 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.)

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.)

10.1		Second Amendment to Office Lease dated as of July 24, 2005 between Crescent 1301 McKinney, L.P. and Key Energy Services, Inc. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K dated June 30, 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.