KEY ENERGY SERVICES, INC.

~~Key Energy Services, Inc.~~INDEX TO FORM 10-Q

~~INDEX~~FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2005

*~~PART I.~~Part I — Financial Information*

~~Item 1.~~Note Regarding Our Financial Reporting Process			~~Financial Statements~~
Item 1.		Unaudited Consolidated ~~Balance Sheets as of September 30, 2003 (unaudited) and December 31, 2002~~Financial Statements

		~~Unaudited~~Condensed Consolidated ~~Statements~~Balance Sheets as of ~~Operations for the Three and Nine Months Ended~~ September 30, ~~2003~~2005 and ~~2002~~December 31, 2004

		~~Unaudited~~Condensed Consolidated Statements of ~~Comprehensive Income (Loss)~~Operations for the Three Months Ended September 30, 2005 and 2004 and Nine Months Ended September 30, ~~2003~~2005 and ~~2002~~2004

		~~Unaudited~~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, ~~2003~~2005 and ~~2002~~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~~About Market ~~Risk~~Risks

Item 4.		~~Disclosure~~ Controls and Procedures

*~~PART II.~~Part II — Other Information*

Item 1.		Legal Proceedings
Item 1A.		Risk Factors
Item 2.		~~Changes in~~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 and Reports on Form 8-K~~
Exhibits
~~Signatures~~

2FORWARD-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)

September 30,
2003

December 31,
2002

(Unaudited)

(thousands, except share data)

ASSETS

Current assets:

Cash and cash equivalents

$
89,427

$
9,044

Accounts receivable, net of allowance for doubtful accounts of $5,813 and $4,439, at September 30, 2003 and December 31, 2002, respectively

162,819

141,958

Inventories

14,022

10,243

Prepaid expenses and other current assets

12,446

14,329

Total current assets

278,714

175,574

Property and equipment:

Well servicing equipment

967,013

935,911

Contract drilling equipment

132,556

128,199

Motor vehicles

81,554

79,110

Oil and natural gas properties and other related equipment, successful efforts method

—

48,362

Furniture and equipment

61,937

51,349

Buildings and land

50,003

48,922

Total property and equipment

1,293,063

1,291,853

Accumulated depreciation and depletion

(389,329
)
(335,348
)
Net property and equipment

903,734

956,505

Goodwill, net

346,335

322,270

Deferred costs, net

14,182

13,503

Notes and accounts receivable - related parties

190

251

Other assets

24,446

33,899

Total assets

$
1,567,601

$
1,502,002

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:

Accounts payable

$
20,885

$
28,818

Other accrued liabilities

70,504

57,823

Accrued interest

8,841

15,226

Current portion of long-term debt and capital lease obligations

24,616

7,008

Total current liabilities

124,846

108,875

Long-term debt, less current portion

520,837

472,336

Capital lease obligations, less current portion

11,722

14,221

Deferred revenue

726

8,460

Non-current accrued expenses

36,919

40,477

Deferred tax liability

154,182

161,265

Commitments and contingencies

—

—

Stockholders’ equity:

Common stock, $0.10 par value; 200,000,000 shares authorized, 130,337,664 and 128,757,693 shares issued at September 30, 2003 and December 31, 2002, respectively

13,034

12,876

Additional paid-in capital

687,421

673,249

Treasury stock, at cost; 416,666 shares at September 30, 2003 and December 31, 2002

(9,682
)
(9,682
)
Accumulated other comprehensive loss

(41,082
)
(45,431
)
Retained earnings

68,678

65,356

Total stockholders’ equity

718,369

696,368

Total liabilities and stockholders’ equity

$
1,567,601

$
1,502,002

(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.

~~Unaudited~~Condensed Consolidated Statements of Operations

(In thousands, except per share data)

Three Months Ended
September 30,

Nine Months Ended
September 30,

2003

2002

2003

2002

(thousands, except per share data)

REVENUES:

Well servicing

$
224,251

$
185,967

$
643,379

$
494,452

Contract drilling

18,819

14,399

51,925

41,491

Other

312

50

(174
)
1,093

Total revenues

243,382

200,416

695,130

537,036

COSTS AND EXPENSES:

Well servicing

154,565

131,630

455,645

365,953

Contract drilling

13,676

10,517

38,013

31,970

Depreciation, depletion and amortization

25,898

24,962

75,960

64,143

General and administrative.

24,974

25,808

70,248

56,103

Interest

12,726

11,262

35,940

31,548

Foreign currency transaction gain, Argentina

—

—

—

(401
)
(Gain) loss on retirement of debt

—

(10
)
(16
)
8,447

Total costs and expenses

231,839

204,169

675,790

557,763

Income (loss) from continuing operations before income taxes

11,543

(3,753
)
19,340

(20,727
)
Income tax benefit (expense)

(5,204
)
1,426

(8,152
)
8,251

INCOME (LOSS) FROM CONTINUING OPERATIONS

6,339

(2,327
)
11,188

(12,476
)
Discontinued operations including loss on sale of $7,804, net of tax

(7,396
)
(310
)
(7,866
)
(650
)
Cumulative effect on prior years of a change in accounting principle, net of tax

—

(2,873
)
—

(2,873
)
NET INCOME (LOSS)

$
(1,057
)
$
(5,510
)
$
3,322

$
(15,999
)

EARNINGS (LOSS) PER SHARE:

Net income (loss) before discontinued operations and cumulative effect of a change in accounting principle, net of tax:

Basic

$
0.05

$
(0.02
)
$
0.09

$
(0.11
)
Diluted

$
0.05

$
(0.02
)
$
0.09

$
(0.11
)

Discontinued operations

Basic

$
(0.06
)
$
—

$
(0.06
)
$
(0.01
)
Diluted

$
(0.06
)
$
—

$
(0.06
)
$
(0.01
)

Cumulative effect

Basic

$
—

$
(0.02
)
$
—

$
(0.03
)
Diluted

$
—

$
(0.02
)
$
—

$
(0.03
)

Net income (loss)

Basic

$
(0.01
)
$
(0.04
)
$
0.03

$
(0.15
)
Diluted

$
(0.01
)
$
(0.04
)
$
0.03

$
(0.15
)

WEIGHTED AVERAGE SHARES OUTSTANDING:

Basic

129,744

122,475

129,095

113,668

Diluted

131,433

122,475

130,987

113,668

(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.

~~Unaudited~~ Consolidated Statements of Comprehensive Income ~~(Loss)~~

(In thousands)

Three Months Ended
September 30,

Nine Months Ended
September 30,

2003

2002

2003

2002

(thousands)

(thousands)

NET INCOME (LOSS)

$
(1,057
)
$
(5,510
)
$
3,322

$
(15,999
)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:

Oil and natural gas derivatives adjustment, net of tax

72

(344
)
33

(980
)
Amortization of oil and natural gas derivatives, net of tax

—

210

695

31

Foreign currency translation gain (loss), net of tax

(2,044
)
1,945

3,620

(22,213
)
COMPREHENSIVE INCOME (LOSS), NET OF TAX

$
(3,029
)
$
(3,699
)
$
7,670

$
(39,161
)

(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

Long-Term Debt Principal Repayment and Interest Expense

Presented below is a schedule of the repayment requirements of long-term debt ~~retirement.~~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 ~~Company. Management does~~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 ~~to the~~on our consolidated financial position, results of operations or cash ~~flows~~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. ~~SUPPLEMENTARY INFORMATION TO THE CONSOLIDATED STATEMENT OF CASH FLOWS~~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.

~~Cash Payments.~~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 ~~Company paid interest~~1997 Incentive Plan is an amendment and restatement of ~~approximately $39,824,000~~the plans formerly known as the Key Energy Group, Inc. 1995 Stock Option Plan and ~~$38,422,000 for~~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, ~~2003~~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 ~~2002, respectively, net~~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 ~~capitalized interest of approximately $2,154,000 and $1,465,000 for~~all common stock awards granted during the nine months ended September 30, ~~2003~~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 ~~2002, respectively. The Company made income tax payments of approximately $992,000 and $246,000 for~~employees during the nine months ended September 30, ~~2003~~2005 at a weighted-average issuance price of $11.90 per share. Of these, 50,000 were issued to our outside directors and ~~2002, respectively.~~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.

~~Non-Cash Investing and Financing Activities.~~ ~~The~~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 ~~issued in purchase transactions, other than for~~grants that do not immediately vest, we recognize compensation cost ratably over the ~~acquisition~~vesting period of ~~QSI, was approximately $11,404,000~~the grant, net of actual and ~~$23,238,000 for~~estimated forfeitures. For the three and nine months ended September 30, ~~2003~~2005, we recognized $1.5 million of expense related to common stock awards, net of estimated and 2002, respectively. The Company incurred a non-compete payment obligation in a purchase transaction of approximately $200,000 for the nine months ended September 30, 2003. The Company incurred capital lease obligations of approximately $3,597,000 and $5,230,000 for the nine months ended September 30, 2003 and 2002, respectively.

actual forfeitures.

9. ~~BUSINESS~~ SEGMENT INFORMATION

~~The Company’s~~For 2005, our reportable business segments are well servicing, pressure pumping and ~~contract drilling.~~

fishing and rental.

Well ~~Servicing~~Servicing.~~: The Company’s~~ These operations provide a full range of well ~~servicing (ongoing maintenance of existing~~services, including rig-based services, oilfield transportation services and other ancillary oilfield services necessary to complete, maintain and workover oil and natural gas ~~wells), workover (major repairs or modifications necessary~~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 ~~optimize~~enhance the ~~level~~production of ~~production from existing~~ oil and natural gas ~~wells)~~wells from formations which exhibit a restricted flow of oil and ~~production~~/ or natural gas. Cementing services ~~(fluid hauling~~include pumping cement into a well between the casing and ~~fluid storage tank rental, fishing~~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 ~~tool~~equipment designed for use both on land an offshore for drilling and workover services and ~~pressure pumping services).~~includes an inventory consisting of tubulars, handling tools, pressure-control equipment and power swivels.

~~Contract Drilling~~~~: The Company provides contract drilling services for major and independent oil companies onshore the continental United States, Argentina and Ontario, Canada.~~

~~The Company’s management evaluates~~We evaluate the performance of ~~its~~our operating segments based on ~~net income~~revenue and ~~operating profits (revenues less direct operating expenses).~~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.

Well
Servicing

Contract
Drilling

Corporate
/ Other

Total

Three Months Ended September 30, 2003

Operating revenues

$
224,251

$
18,819

$
312

$
243,382

Operating profit

69,686

5,143

312

75,141

Depreciation, depletion and amortization

21,473

2,642

1,783

25,898

Interest expense

137

—

12,589

12,726

Net income (loss) from continuing operations*

13,049

319

(7,029
)
6,339

Identifiable assets

815,190

88,531

317,545

1,221,266

Capital expenditures (excluding acquisitions)

15,883

1,060

4,891

21,834

Three Months Ended September 30, 2002

Operating revenues

$
185,967

$
14,399

$
50

$
200,416

Operating profit

54,337

3,882

50

58,269

Depreciation, depletion and amortization

21,876

2,392

694

24,962

Interest expense

276

—

10,986

11,262

Net income (loss) from continuing operations*

4,988

(227
)
(7,088
)
(2,327
)
Identifiable assets

828,845

88,742

253,053

1,170,640

Capital expenditures (excluding acquisitions)

12,115

191

4,286

16,592

* Net income (loss)The following table sets forth our segment information as of and for the ~~contract drilling segment includes a portion of well servicing general~~periods ended September 30, 2005 and ~~administrative expenses allocated on a percentage of revenue basis.~~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 ~~the Company’s~~our foreign operations ~~(which consists of Argentina, Canada~~were $15.4 million and ~~Egypt)~~$15.4 million for the three months ended September 30, ~~2003~~2005 and ~~2002~~2004, respectively. Operating revenues for our foreign operations were ~~approximately $12.7~~$50.6 million and ~~$6.1~~$42.9 million ~~respectively. Operating profits~~ for the ~~Company’s~~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, ~~2003~~2005 and ~~2002~~2004, respectively. Gross margins for our foreign operations were ~~approximately $5.4~~$13.4 million and ~~$1.4~~$14.5 million respectively. The Company had approximately $55.4 million and $41.1 million of identifiable assets as of September 30, 2003 and 2002, respectively, related to foreign operations. Capital expenditures for the Company’s foreign operations for the three months ended September 30, 2003 and 2002 were approximately $0.8 million and $1.7 million, respectively.

Well
Servicing

Contract
Drilling

Corporate
/ Other

Total

Nine Months Ended September 30, 2003

Operating revenues

$
643,379

$
51,925

$
(174
)
$
695,130

Operating profit

187,734

13,912

(174
)
201,472

Depreciation, depletion and amortization

63,769

7,854

4,337

75,960

Interest expense

476

—

35,464

35,940

Net income (loss) from continuing operations*

33,832

471

(23,115
)
11,188

Identifiable assets

815,190

88,531

317,545

1,221,266

Capital expenditures (excluding acquisitions)

46,962

5,063

12,663

64,688

Nine Months Ended September 30, 2002

Operating revenues

$
494,452

$
41,491

$
1,093

$
537,036

Operating profit

128,499

9,521

1,093

139,113

Depreciation, depletion and amortization

54,517

7,000

2,626

64,143

Interest expense

771

—

30,777

31,548

Net income (loss) from continuing operations*

8,501

(1,464
)
(19,513
)
(12,476
)
Identifiable assets

828,845

88,742

253,053

1,170,640

Capital expenditures (excluding acquisitions)

41,571

8,975

14,081

64,627

* Net income (loss) for the contract drilling segment includes a portion of well servicing general and administrative expenses allocated on a percentage of revenue basis.

~~Operating revenues for the Company’s foreign operations~~ for the nine months ended September 30, ~~2003~~2005 and ~~2002 were approximately $34.1~~2004, respectively.

We have $53.8 million and ~~$15.3~~$54.4 million ~~respectively. Operating profits for the Company’s~~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, ~~2003~~2005 and ~~2002 were approximately $14.2 million and $3.1 million,~~2004, respectively. The Company had approximately $55.4 million and $41.1 million of identifiable assets as of September 30, 2003 and 2002, respectively, related to foreign operations. Capital expenditures for the Company’s foreign operations for the nine months ended September 30, 2003 and 2002 were approximately $2.6 million and $6.1 million, respectively.

10. CONDENSED CONSOLIDATING FINANCIAL ~~INFORMATION~~STATEMENTS

~~The Company’s senior notes~~Our Senior Notes are guaranteed by substantially all of ~~the Company’s~~our domestic subsidiaries, all of which are wholly-owned. The guarantees are joint and several, full, complete and unconditional. There are ~~currently~~ no restrictions on the ability of ~~the~~ 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 ~~accounting principles generally accepted in the United States of America.~~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	)

~~The 6~~³/CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS8~~% Senior Notes are guaranteed by the Guarantor A group of subsidiaries, which consists of substantially all of the Company’s subsidiaries. The 8~~³/8~~% Senior Notes and the 14%~~

	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

Senior Subordinated Notes are guaranteed by the Guarantor A group of subsidiaries and Guarantor B, which is Odessa Exploration Incorporated (“OEI”). Substantially all of the assets of OEI were oil and gas properties, which were sold by the Company in August 2003 (see Note 12).

CONDENSED CONSOLIDATING BALANCE SHEET

September 30, 2003

Parent
Company

Guarantor A
Subsidiaries

Guarantor B
Subsidiary

Non-
Guarantor
Subsidiaries

Eliminations

Consolidated

(thousands)

Assets:

Current assets

$
96,566

$
167,403

$
77

$
14,668

$
—

$
278,714

Net property and equipment

51,156

829,531

13

23,034

—

903,734

Goodwill, net

3,431

342,177

—

727

—

346,335

Deferred costs, net

14,182

—

—

—

—

14,182

Inter-company receivables

697,601

—

—

—

(697,601
)
—

Other assets

12,805

11,373

458

—

—

24,636

Total assets

$
875,741

$
1,350,484

$
548

$
38,429

$
(697,601
)
$
1,567,601

Liabilities and equity:

Current liabilities

$
50,275

$
68,757

$
342

$
5,472

$
—

$
124,846

Long-term debt

520,837

—

—

—

—

520,837

Capital lease obligations

1,403

10,319

—

—

—

11,722

Inter-company payables

—

674,899

3,753

18,949

(697,601
)
—

Deferred tax liability

154,182

—

—

—

—

154,182

Other long-term liabilities

33,346

4,299

—

—

—

37,645

Stockholders’ equity

115,698

592,210

(3,547
)
14,008

—

718,369

Total liabilities and stockholders’ equity

$
875,741

$
1,350,484

$
548

$
38,429

$
(697,601
)
$
1,567,601

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2002

Parent
Company

Guarantor A
Subsidiaries

Guarantor B
Subsidiary

Non-
Guarantor
Subsidiaries

Eliminations

Consolidated

(thousands)

Assets:

Current assets

$
17,716

$
142,587

$
992

$
14,279

$
—

$
175,574

Net property and equipment

43,134

861,043

32,732

19,596

—

956,505

Goodwill, net

3,431

318,208

—

631

—

322,270

Deferred costs, net

13,503

—

—

—

—

13,503

Inter-company receivables

760,990

—

—

—

(760,990
)
—

Other assets

19,687

13,882

581

—

—

34,150

Total assets

$
858,461

$
1,335,720

$
34,305

$
34,506

$
(760,990
)
$
1,502,002

Liabilities and equity:

Current liabilities

$
43,701

$
59,410

$
2,061

$
3,703

$
—

$
108,875

Long-term debt

472,336

—

—

—

—

472,336

Capital lease obligations

1,648

12,573

—

—

—

14,221

Inter-company payables

—

724,341

15,501

21,148

(760,990
)
—

Deferred tax liability

161,265

—

—

—

—

161,265

Other long-term liabilities

31,222

4,735

12,887

93

—

48,937

Stockholders’ equity

148,289

534,661

3,856

9,562

—

696,368

Total liabilities and stockholders’ equity

$
858,461

$
1,335,720

$
34,305

$
34,506

$
(760,990
)
$
1,502,002

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

Three Months Ended September 30, 2003

Parent
Company

Guarantor A
Subsidiaries

Guarantor B
Subsidiary

Non-
Guarantor
Subsidiaries

Eliminations

Consolidated

(thousands)

Revenues

$
149

$
235,631

$
—

$
7,602

$
—

$
243,382

Costs and expenses:

Direct expenses

—

162,413

—

5,828

—

168,241

Depreciation, depletion and amortization expense

1,783

23,544

—

571

—

25,898

General and administrative expense

12,240

12,195

—

539

—

24,974

Interest

12,589

104

—

33

—

12,726

Gain on retirement of debt

—

—

—

—

—

—

Total costs and expenses

26,612

198,256

—

6,971

—

231,839

Income (loss) from continuing operations before income taxes

(26,463
)
37,375

—

631

—

11,543

Income tax (expense) benefit

13,063

(17,954
)
—

(313
)
—

(5,204
)
Income (loss) from continuing operations

(13,400
)
19,421

—

318

—

6,339

Discontinued operations

—

—

(7,396
)
—

—

(7,396
)
Net income (loss)

$
(13,400
)
$
19,421

$
(7,396
)
$
318

$
—

$
(1,057
)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

Three Months Ended September 30, 2002

Parent
Company

Guarantor A
Subsidiaries

Guarantor B
Subsidiary

Non-
Guarantor
Subsidiaries

Eliminations

Consolidated

(thousands)

Revenues

$
46

$
194,469

$
—

$
5,901

$
—

$
200,416

Costs and expenses:

Direct expenses

—

138,184

—

3,963

—

142,147

Depreciation, depletion and amortization expense

793

23,782

—

387

—

24,962

General and administrative expense

11,104

14,436

—

268

—

25,808

Interest

10,986

256

—

20

—

11,262

Foreign currency transaction (gain), Argentina

—

—

—

—

—

—

Gain on retirement of debt

(10
)
—

—

—

—

(10
)
Total costs and expenses

22,873

176,658

—

4,638

—

204,169

Income (loss) from continuing operations before income taxes

(22,827
)
17,811

—

1,263

—

(3,753
)
Income tax (expense) benefit

8,920

(6,993
)
—

(501
)
—

1,426

Income (loss) from continuing operations

(13,907
)
10,818

—

762

—

(2,327
)
Discontinued operations

—

—

(310
)
—

—

(310
)
Cumulative effect

—

(658
)
(2,215
)
—

—

(2,873
)
Net income (loss)

$
(13,907
)
$
10,160

$
(2,525
)
$
762

$
—

$
(5,510
)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

Nine Months Ended September 30, 2003

Parent
Company

Guarantor A
Subsidiaries

Guarantor B
Subsidiary

Non-
Guarantor
Subsidiaries

Eliminations

Consolidated

(thousands)

Revenues

$
256

$
674,184

$
—

$
20,690

$
—

$
695,130

Costs and expenses:

Direct expenses

—

477,880

—

15,778

—

493,658

Depreciation, depletion and amortization expense

3,799

70,472

—

1,689

—

75,960

General and administrative expense

31,446

37,380

—

1,422

—

70,248

Interest

35,463

385

—

92

—

35,940

Gain on retirement of debt

(16
)
—

—

—

—

(16
)
Total costs and expenses

70,692

586,117

—

18,981

—

675,790

Income (loss) from continuing operations before income taxes

(70,436
)
88,067

—

1,709

—

19,340

Income tax (expense) benefit

29,689

(37,121
)
—

(720
)
—

(8,152
)
Income (loss) from continuing operations

(40,747
)
50,946

—

989

—

11,188

Discontinued operations

—

—

(7,866
)
—

—

(7,866
)
Net income (loss)

$
(40,747
)
$
50,946

$
(7,866
)
$
989

$
—

$
3,322

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

Nine Months Ended September 30, 2002

Parent
Company

Guarantor A
Subsidiaries

Guarantor B
Subsidiary

Non-
Guarantor
Subsidiaries

Eliminations

Consolidated

(thousands)

Revenues

$
469

$
521,448

$
—

$
15,119

$
—

$
537,036

Costs and expenses:

Direct expenses

—

386,426

—

11,497

—

397,923

Depreciation, depletion and amortization expense

1,883

60,820

—

1,440

—

64,143

General and administrative expense

23,897

31,169

—

1,037

—

56,103

Interest

30,777

767

—

4

—

31,548

Foreign currency transaction (gain), Argentina

—

—

—

(401
)
—

(401
)
Gain on retirement of debt

8,447

—

—

—

—

8,447

Total costs and expenses

65,004

479,182

—

13,577

—

557,763

Income (loss) from continuing operations before income taxes

(64,535
)
42,266

—

1,542

—

(20,727
)
Income tax (expense) benefit

25,690

(16,825
)
—

(614
)
—

8,251

Income (loss) from
continuing operations

(38,845
)
25,441

—

928

—

(12,476
)
Discontinued operations

—

—

(650
)
—

—

(650
)
Cumulative effect

—

(658
)
(2,215
)
—

—

(2,873
)
Net income (loss)

$
(38,845
)
$
24,783

$
(2,865
)
$
928

$
—

$
(15,999
)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

Nine Months Ended September 30, 2003

Parent
Company

Guarantor A
Subsidiaries

Guarantor B
Subsidiary

Non-
Guarantor
Subsidiaries

Eliminations

Consolidated

(thousands)

Net cash provided (used) by operating activities

$
35,927

$
51,996

$
(15,512
)
$
496

$
—

$
72,907

Net cash provided (used) in investing activities

(15,992
)
(49,460
)
19,698

(2,087
)
—

(47,841
)
Net cash provided (used) in financing activities

62,019

(2,250
)
(4,227
)
—

—

55,542

Effect of exchange rate changes on cash

—

—

—

(225
)
—

(225
)
Net increase (decrease) in cash

81,954

286

(41
)
(1,816
)
—

80,383

Cash at beginning of period

5,183

1,220

(258
)
2,899

—

9,044

Cash at end of period

$
87,137

$
1,506

$
(299
)
$
1,083

$
—

$
89,427

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

Nine Months Ended September 30, 2002

Parent
Company

Guarantor A
Subsidiaries

Guarantor B
Subsidiary

Non-
Guarantor
Subsidiaries

Eliminations

Consolidated

(thousands)

Net cash provided (used) by operating activities

$
29,327

$
48,746

$
(747
)
$
5,716

$
—

$
83,042

Net cash provided (used) in investing activities

(126,288
)
(42,859
)
23

(3,546
)
—

(172,670
)
Net cash provided (used) in financing activities

93,926

(6,976
)
—

—

—

86,950

Effect of exchange rate changes on cash

—

—

—

(1,460
)
—

(1,460
)
Net increase (decrease) in cash

(3,035
)
(1,089
)
(724
)
710

—

(4,138
)
Cash at beginning of period

2,507

2,983

793

1,683

—

7,966

Cash at end of period

$
(528
)
$
1,894

$
69

$
2,393

$
—

$
3,828

	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

~~11.~~Item 2. ~~INCOME TAXES~~

The Company’s effective tax rate for the three months ended September 30, 2003 was 45% compared to (38%) for the three months ended September 30, 2002. The Company’s effective tax rate for the nine months ended September 30, 2003 was 42% compared to (40%) for the nine months ended September 30, 2002. The effective tax rates are different from the statutory rate of 35% because of non-deductible expenses and the effects of state, local and foreign taxes.

~~12.~~~~DISCONTINUED OPERATIONS – SALE OF OIL AND GAS PROPERTIES~~

On August 28, 2003, the Company sold its oil and natural gas properties for approximately $19.7 million in cash. The Company received net cash proceeds of approximately $7.2 million after repaying the Company’s volumetric production payment, unwinding related hedge arrangements and other related costs. As a result of the sale, the Company will treat its oil and natural gas production business as a discontinued operation for all periods and has recorded an after-tax

~~charge to discontinued operations of approximately $7.4 million, or $0.06 per diluted share, during the three months ended September 30, 2003.~~

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

Three Months Ended
September 30,

Nine Months Ended
September 30,

2003

2002

2003

2002

(thousands)

Revenues

$
1,250

$
1,651

$
4,221

$
5,021

Costs and expenses

(613
)
(2,151
)
(4,318
)
(6,156
)

Income (loss) before income taxes

637

(500
)
(97
)
(1,135
)
Income tax benefit (expense)

(229
)
190

35

485

Income (loss) before loss on disposal

408

(310
)
(62
)
(650
)
Loss on disposal, net of tax

(7,804
)
—

(7,804
)
—

Income (loss) from discontinued operations

$
(7,396
)
$
(310
)
$
(7,866
)
$
(650
)

~~Balance Sheet Data:~~

September 30,
2003

December 31,
2002

(thousands)

Current assets

$
77

$
992

Property and equipment, net

13

32,732

Other assets

458

581

Total assets.

$
548

$
34,305

Current liabilities.

342

2,061

Non-current liabilities

3,753

28,388

Stockholders equity

(3,547
)
3,856

Total liabilities and stockholders’ equity.

$
548

$
34,305

~~13.~~~~SUBSEQUENT EVENT – NEW SENIOR CREDIT FACILITY~~

On November 10, 2003, the Company entered into a Fourth Amended and Restated Credit Agreement (the “New Senior Credit Facility”). The New Senior Credit Facility consists of a $175 million revolving loan facility with the entire revolving credit facility available for letters of credit. The Company has the right, subject to certain conditions, to increase the total commitment under the New Senior Credit Facility from $175 million to up to $225 million if it is able to obtain additional lending commitments. The revolving loan commitments will terminate on November 10, 2007 and all revolving loans must be paid on or before that date. The revolving loans bear interest based upon, at the Company’s 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 will fluctuate based upon the Company’s consolidated total leverage ratio and in either case, according to the pricing grid set forth in the New Senior Credit Facility.

The New Senior Credit Facility contains various financial covenants based on applicable periods, including: (i) a maximum consolidated total leverage ratio, (ii) a minimum consolidated interest coverage ratio, and (iii) a minimum net worth. The New Senior Credit Facility subjects the Company to other restrictions, including restrictions upon the Company’s ability to incur additional debt, liens and guarantee obligations, to merge or consolidate with other persons, to make acquisitions, to sell assets, to make dividends, purchases of the Company’s stock or subordinated debt, or to make investments, loans and advances or changes to debt instruments and organizational documents. All obligations under the New Senior Credit Facility are guaranteed by most of the Company’s subsidiaries and are secured by most of the Company’s assets, including the Company’s accounts receivable, inventory and most equipment.

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

~~NOTE REGARDING FORWARD – LOOKING STATEMENTS~~

The statements in this document that relate to matters that are not historical facts are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended. When used in this document and the documents incorporated by reference, words such as “anticipate,” “believe,” “expect,” “plan,” “intend,” “estimate,” “project,” “will,” “could,” “may,” “predict” and similar expressions are intended to identify forward-looking statements. Further events and actual results may differ materially from the results set forth in or implied in the forward-looking statements. Factors that might cause such a difference include:

• ~~fluctuations in world-wide prices and demand for oil and natural gas;~~

• ~~fluctuations in level of oil and natural gas exploration and development activities;~~

• ~~fluctuations in the demand for well servicing, contract drilling and ancillary oilfield services;~~

• ~~the existence of competitors, technological changes and developments in the industry;~~

• ~~the existence of operating risks inherent in the well servicing, contract drilling and ancillary oilfield services; and~~

• general economic conditions, the existence of regulatory uncertainties, and the possibility of political instability in any of the countries in which Key does business, in addition to other matters discussed herein.

~~These forward looking-statements speak only as of the date of this report and Key disclaims any duty or obligation to update the forward looking statement in this report.~~

The following discussion ~~provides information to assist in the understanding of the Company’s financial condition~~ and ~~results of operations. It~~analysis should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes appearing elsewhere in this report. As used in this Item 2, references to composite well servicing rig rates means, for a given period, the total well servicing revenues for that period divided by the total well servicing rig hours for that period. As used in this Item 2, references to composite contract drilling rig rates means, for a given period, the total contract drilling revenues for that period divided by the total contract drilling rig hours for that period. As used in this Item 2, references to composite truck rates means, for a given period, the total trucking revenues for that period divided by the total trucking hours for that period.

~~RESULTS OF OPERATIONS~~

~~The Company’s results~~as of ~~operations~~September 30, 2005 and for the three and nine months ended September 30, ~~2003 reflect~~2005 and 2004, included elsewhere herein.

Overview

We believe that we are the ~~impact~~leading onshore, rig-based well servicing contractor in the United States. Since 1994, we have grown rapidly through a series of ~~continued modest improvement in industry conditions resulting from continued strength in~~over 100 acquisitions, and today we provide a complete range of well services to major oil companies and independent oil and natural gas ~~prices.~~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~~Three Months Ended September 30, ~~2003 VERSUS THREE MONTHS ENDED SEPTEMBER~~2005 Compared to Three Months Ended September 30, ~~2002~~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, ~~2003~~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 ~~$42,966,000, or 21%,~~15.6% to ~~$243,382,000 from $200,416,000~~$706.1 million for the ~~three~~nine months ended September 30, ~~2002. For~~2005 compared to revenue of $610.8 million for the ~~three~~nine months ended September 30, ~~2003, the Company had net income from continuing operations of $6,339,000, an improvement of $8,666,000, from a net loss from continuing operations of $2,327,000~~2004. The increase in revenue is largely attributable to higher pricing for the ~~three~~Company’s services and higher rig hours, offset somewhat by lower trucking hours. For the nine months ended September 30, ~~2002. The increase in revenues and net income from continuing operations is principally due~~2005, the Company’s composite segment revenue to ~~increasing levels of activity. Total~~total hours (as defined as rig hours plus trucking hours) was approximately $184 per hour compared to approximately $154 per hour for the ~~three~~nine months ended September 30, ~~2003 increased approximately 12% compared to total rig~~2004. Rig hours for the ~~three~~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, ~~2002. Total trucking hours~~2005 compared to revenue of $65.3 million for the ~~three~~nine months ended September 30, ~~2003 increased approximately 18% compared~~2004. The increase in revenue is attributable to ~~total trucking hours~~incremental pressure pumping equipment, higher activity levels and higher pricing for the ~~three~~Company’s services. The Company exited the nine months ended September 30, ~~2002 principally due~~2005 with approximately 113,000 horsepower of pumping equipment as compared to ~~improved activity levels.~~

~~Operating Revenues~~

~~Well Servicing.~~ ~~Well servicing revenues~~approximately 97,000 horsepower for the ~~three~~nine months ended September 30, ~~2003 increased $38,284,000, or 21%,~~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 ~~$224,251,000 from $185,967,000~~964 for the ~~three~~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, ~~2002. The increase in revenues was primarily due~~2005 increased 4.6% to an increase in activity resulting in an increase in total well servicing rig hours and total trucking hours and a slight increase in composite well servicing rig rates and composite truck rates. Total well servicing rig hours$60.5 million compared to revenue of $57.9 million for the ~~three~~nine months ended September 30, ~~2003~~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 ~~approximately 11% compared~~10.8% to ~~total well servicing rig hours~~$466.6 million for the ~~three~~nine months ended September 30, ~~2002. Composite well servicing rig rates increased by approximately 4%~~2005 compared to $421.0 million for the ~~three~~nine months ended September 30, ~~2003 compared~~2004. The increase in direct costs is largely attributable to ~~composite~~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 ~~rig rates~~segment revenue improved to 66.1% for the ~~three~~nine months ended September 30, ~~2002. Total trucking hours~~2005 compared to 68.9% for the ~~three~~nine months ended September 30, ~~2003~~2004.

Pressure Pumping Services: PPS direct costs increased ~~approximately 18% compared~~37.9% to ~~total trucking hours~~$65.8 million for the ~~three~~nine months ended September 30, ~~2002 and composite truck rates~~2005 compared to $47.7 million for the ~~three~~nine months ended September 30, ~~2003~~2004. The increase in direct costs is largely attributable to increased ~~by approximately 4% compared to composite truck rates~~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 ~~three~~Company’s services. Direct costs as a percent of total PPS segment revenue improved to 60.5% for the nine months ended September 30, ~~2002.~~

~~Contract Drilling.~~ ~~Contract drilling revenues~~2005 compared to 73.1% for the ~~three~~nine months ended September 30, ~~2003~~2004.

Fishing and Rental Services: FRS direct costs increased ~~$4,420,000, or 31%,~~11.9% to ~~$18,819,000 from $14,399,000~~$41.1 million for the ~~three~~nine months ended September 30, ~~2002. The increase in revenues was primarily due~~2005 compared to ~~an increase in activity resulting in an increase in total contract drilling hours and a slight improvement in composite contract drilling rig rates. Total contract drilling rig hours~~$36.8 million for the ~~three~~nine months ended September 30, ~~2003~~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 ~~by approximately 24% compared to total contract drilling rig hours~~demand for the ~~three~~Company’s services. Direct costs as a percent of total FRS segment revenue deteriorated to 67.9% for the nine months ended September 30, ~~2002, while composite contract drilling rig rates~~2005 compared to 63.5% for the ~~three~~

nine months ended September 30, ~~2003 increased by approximately 5% compared~~2004.

General and Administrative Expense

General and administrative expenses decreased 10.9% to ~~composite contract drilling rig rates~~$107.8 million for the ~~three~~nine months ended September 30, ~~2002.~~

~~Operating Expenses~~

~~Well Servicing.~~ ~~Well servicing expenses~~2005 compared to $121.0 million for the ~~three~~nine months ended September 30, ~~2003~~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 ~~$22,935,000, or 17%, to $154,565,000 from $131,630,000 for~~during the ~~three~~nine months ended September 30, ~~2002.~~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 ~~was primarily due to increased levels of activity and related repair and maintenance costs. Well servicing expenses as a percentage of well servicing revenue decreased from 71% for~~is offset somewhat by lower bad debt expense. During the ~~three~~nine months ended September 30, ~~2002~~2004, the Company had $3.9 million of bad debt expense compared to ~~69%~~bad debt expense of $9.2 million for the ~~three~~nine months ended September 30, ~~2003.~~

~~Contract Drilling.~~ ~~Contract drilling expenses for~~2005. The bad debt expense during the ~~three~~nine months ended September 30, ~~2003 increased $3,159,000, or 30%, to $13,676,000 from $10,517,000 for~~2004 includes the ~~three months ended September 30, 2002. The increase was primarily due to increased levels~~write-off of ~~activity and related repair and maintenance costs. Contract drilling expenses as a percentage of contract drilling revenues was 73% for~~ the ~~three months ended September 30, 2003 and for the three months ended September 30, 2002.~~

~~Depreciation, Depletion and Amortization Expense~~

The Company’s depreciation, depletion and amortization expense for the three months ended September 30, 2003 increased $936,000, or 4%, to $25,898,000 from $24,962,000 for the three months ended September 30, 2002. The increase is primarily due$9.0 million retention bonus to the Company’s ~~ongoing capital expenditure program, which includes remanufacturing of well servicing and contract drilling equipment and the Company’s technology initiatives.~~

~~General and Administrative Expenses~~

The Company’s general and administrative expenses for the three months ended September 30, 2003 decreased $834,000, or 3%, to $24,974,000 from $25,808,000 for the three months ended September 30, 2002. The decrease for the three months ended September 30, 2003 compared to the three months ended September 30, 2002 was primarily due to the integration costs associated with the acquisition of QSI and higher general liability costs that were incurred during the three months ended September 30, 2002 offset by higher costs associated with increased activity levels for the three months ended September 30, 2003. Incremental costs include expenses related to additional personnel supporting the implementation of information technology initiatives and corporate infrastructure. General and administrative expensesformer chief executive officer. G&A expense as a ~~percentage~~percent of ~~revenues decreased from 13% for the three months ended September 30, 2002 to 10% for the three months ended September 30, 2003.~~

~~Interest Expense~~

The Company’s interest expense for the three months ended September 30, 2003 increased $1,464,000, or 13%, to $12,726,000 from $11,262,000 for the three months ended September 30, 2002. The increase was primarily due to higher average long term debt in the quarter ended September 30, 2003 as compared to September 30, 2002 resulting from the issuance of the 6³/8% Senior Notes, a portion of the proceeds of which was used to repay the outstanding indebtedness on the Company’s revolver with the balance being held for future debt repayment. Included in interest expense was the amortization of deferred debt issuance costs, discount and premium of approximately $892,000 for the three months ended September 30, 2003 compared to $967,000 for the three months ended September 30, 2002.

~~Gain (Loss) on Retirement of Debt~~

During the three months ended September 30, 2002, the Company repurchased approximately $204,000 of its long-term debt at a discount which resulted in a gain of $10,000. On July 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 145, Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections (“SFAS 145”). The new standard rescinds FASB Statement No. 4, which required all gains and losses from extinguishment of debt to be recorded as extraordinary items.

~~Income Taxes~~

The Company’s income tax expense for the three months ended September 30, 2003 increased $6,630,000 to an expense of $5,204,000 from a benefit of $1,426,000 for the three months ended September 30, 2002. The Company’s effective tax rate for the three months ended September 30, 2003 was 45% compared to (38%) for the three months ended September 30, 2002. The effective tax rates are different from the statutory rate of 35% because of non-deductible expenses and the effects of state, local and foreign taxes.

~~Discontinued Operations – Sale of Oil and Natural Gas Properties~~

On August 28, 2003, the Company sold its oil and natural gas properties. The Company received net cash proceeds of approximately $7.2 million after repaying the Company’s volumetric production payment, unwinding related hedge arrangements and other related costs. As a result of the sale, the Company will treat its oil and natural gas production business as a discontinued operation for all periods and has recorded an after-tax charge to discontinued operations of approximately $7.4 million, or $0.06 per diluted share, during the three months ended September 30, 2003.

~~Cumulative Effect on Prior Years of a Change in Accounting Principle~~

Company to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and capitalize an equal amount as a cost of the asset depreciating the additional cost over the estimated useful life of the asset. The Company recorded an after-tax charge of approximately $2,873,000 during the three months ended September 30, 2002 for the cumulative effect on prior years for depreciation of the additional costs and accretion expense on the liability related to expected abandonment costs related to its oil and natural gas producing properties and salt water disposal wells.

~~NINE MONTHS ENDED SEPTEMBER 30, 2003 VERSUS NINE MONTHS ENDED SEPTEMBER 30, 2002~~

~~The Company’s~~ revenue for the nine months ended September 30, ~~2003 increased $158,094,000, or 29%,~~2005 totaled 12.3% compared to ~~$695,130,000 from $537,036,000~~16.5% for the nine months ended September 30, 2002. For the nine months ended September 30, 2003, the Company had net income from continuing operations of $11,188,000, an improvement of $23,664,000, from a net loss from continuing operations of $12,476,0002004.

Interest Expense

Interest expense increased 25.5% to $41.0 million for the nine months ended September 30, ~~2002. The increase in revenues and increase in net income from continuing operations is principally due~~2005 compared to ~~increasing levels of activity and the acquisition of QSI. Total rig hours~~$32.7 million for the nine months ended September 30, ~~2003 increased approximately 10% compared~~2004. The increase relates to ~~total rig hours~~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, ~~2002. Total trucking hours~~2005 totaled 4.7% compared to 4.5% for the nine months ended September 30, ~~2003~~2004.

Depreciation Expense

Depreciation expense increased ~~approximately 38% compared~~9.9% to ~~total trucking hours~~$84.6 million for the nine months ended September 30, ~~2002, principally due~~2005 compared to ~~the acquisition of QSI and improved activity levels.~~

~~Operating Revenues~~

~~Well Servicing.~~ ~~Well servicing revenues~~$77.0 million for the nine months ended September 30, ~~2003 increased $148,927,000, or 30%,~~2004. During the nine months ended September 30, 2005, the Company spent approximately $75.0 million on capital expenditures as compared to ~~$643,379,000 from $494,452,000~~$44.8 million for the nine months ended September 30, ~~2002. The increase in revenues was primarily due to an increase in activity and the acquisition~~2004. Depreciation expense as a percent of QSI resulting in an increase in well servicing rig hours and total trucking hours partially offset by a decrease in composite well servicing rig and composite truck rates. Total well servicing rig hoursrevenue for the nine months ended September 30, ~~2003 increased approximately 9%~~2005 totaled 9.7% compared to ~~total well servicing rig hours~~10.5% for the nine months ended September 30, ~~2002. Composite well servicing rig rates decreased by approximately 2%~~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, 2003 compared to composite well servicing rig rates for the nine months ended September 30, 2002. Total trucking hours for the nine months ended September 30, 2003 increased by approximately 38% compared to total trucking hours for the nine months ended September 30, 2002,2005 and ~~composite truck rates for the nine months ended September 30, 2003 decreased by approximately 2% compared to composite truck rates for the nine months ended September 30, 2002.~~

~~Contract Drilling.~~ Contract drilling revenues for the nine months ended September 30, 2003 increased $10,434,000, or 25%, to $51,925,000 from $41,491,000 for the nine months ended September 30, 2002. The increase in revenues was primarily due to an increase in activity resulting in an increase in contract drilling rig hours and a slight improvement in composite

contract drilling rig rates. Total contract drilling hours for the nine months ended September 30, 2003 increased approximately 21% compared to total contract drilling rig hours for the nine months ended September 30, 2002 and composite contract drilling rig rates for the nine months ended September 30, 2003 increased by approximately 3% compared to composite contract drilling rig rates for the nine months ended September 30, 2002.

~~Operating Expenses~~

~~Well Servicing.~~ Well servicing expenses for the nine months ended September 30, 2003 increased $89,692,000, or 25%, to $455,645,000 from $365,953,000 for the nine months ended September 30, 2002. The increase was primarily due to increased levels of activity and related repair and maintenance costs and the acquisition of QSI. Well servicing expenses as a percentage of well servicing revenue decreased from 74% for the nine months ended September 30, 2002 to 71% for the nine months ended September 30, 2003.

~~Contract Drilling.~~ Contract drilling expenses for the nine months ended September 30, 2003 increased $6,043,000, or 19%, to $38,013,000 from $31,970,000 for the nine months ended September 30, 2002. The increase was primarily due to increased levels of activity and related repair and maintenance costs. Contract drilling expenses as a percentage of contract drilling revenues decreased from 77% for the nine months ended September 30, 2002 to 73% for the nine months ended September 30, 2003.

~~Depreciation, Depletion and Amortization Expense~~

The Company’s depreciation, depletion and amortization expense for the nine months ended September 30, 2003 increased $11,817,000, or 18%, to $75,960,000 from $64,143,000 for the nine months ended September 30, 2002. The increase is primarily due to the acquisition of QSI, which added approximately $114,519,000 in property and equipment and, to a lesser extent, by the Company’s ongoing capital expenditure program, which includes remanufacturing of well servicing and contract drilling equipment and the Company’s technology initiatives.

~~General and Administrative Expenses~~

The Company’s general and administrative expenses for the nine months ended September 30, 2003 increased $14,145,000, or 25%, to $70,248,000, from $56,103,000 for the nine months ended September 30, 2002. The increase was primarily due to the acquisition of QSI and higher costs associated with increased activity levels. Incremental costs include expenses related to additional personnel supporting the implementation of information technology initiatives and corporate infrastructure. General and administrative expenses as a percentage of revenues was 10% for the nine months ended September 30, 2003 and for the nine months ended September 30, 2002.

~~Interest Expense~~

The Company’s interest expense for the nine months ended September 30, 2003 increased $4,392,000, or 14%, to $35,940,000 from $31,548,000 for the nine months ended September 30, 2002. The increase was primarily due to higher average long term debt in the nine months ended September 30, 2003 as compared to September 30, 2002 resulting from the issuance of the 6³/8% Senior Notes, a portion of the proceeds of which was used to repay the outstanding indebtedness on the Company’s revolver and to retire a portion of the 5% Convertible Subordinated Notes with the balance being held for future debt repayment. Included in interest expense was the amortization of deferred debt issuance costs, discount and premium of approximately $2,501,000 for the nine months ended September 30, 2003 compared to $2,249,000 for the nine months ended September 30, 2002.

~~Gain (Loss) on Retirement of Debt~~

During the nine months ended September 30, 2003, the Company repurchased approximately $30,855,000 of its long-term debt at a discount and expensed related debt issuance costs which resulted in a gain of $16,000. During the nine months ended September 30, 2002, the Company repurchased approximately $36,254,000 of its long-term debt at a various discounts and premiums and expensed related debt issuance costs, which resulted in a loss of $8,447,000. On July 1, 2002, the Company adopted SFAS 145. SFAS 145 rescinds FASB Statement No. 4, which required all gains and losses from extinguishment of debt to be recorded as extraordinary items.

~~Income Taxes~~

The Company’s income tax expense for the nine months ended September 30, 2003 increased $16,403,000 to an expense of $8,152,000 from a benefit of $8,251,000 for the nine months ended September 30, 2002. The Company’s2004, respectively. Our effective tax rate for those same periods was 41.4% and (5.2%), respectively. The differences between the ~~nine months ended September 30, 2003 was 42% compared~~rates between periods relate largely to ~~(40%)~~nondeductible expense for ~~the nine months ended September 30, 2002. The effective tax rates are different from~~executive compensation and other nondeductible items. Differences between the statutory rate ~~of 35% because of non-deductible expenses~~ and the ~~effects of~~effective rate are due primarily to state ~~local~~ and foreign ~~taxes.~~

income taxes and nondeductible expenditures.

~~Discontinued Operations – Sale of Oil~~Liquidity and ~~Natural Gas Properties~~Capital Resources

~~On August 28, 2003,~~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 ~~Company sold its oil~~issuance of equity and ~~natural gas properties. The Company received net~~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 ~~approximately $7.2 million after repaying~~cash and cash equivalents, availability under our revolving credit facility, and internally generated cash flow from operations are sufficient to finance the ~~Company’s volumetric production payment, unwinding related hedge arrangements~~cash requirements of our current and ~~other related costs.~~future operations, including our capital expenditure budget. As ~~a result~~ of the sale, the Company will treat its oil and natural gas production business as a discontinued operation for all periods and has recorded an after-tax charge to discontinued operations of approximately $7.4 million, or $0.06 per diluted share, during the September 2003 quarter.

~~Cumulative Effect on Prior Years of a Change in Accounting Principle~~

On July 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”). Adoption of SFAS 143 is required for all companies with fiscal years beginning after June 15, 2002. It requires the Company to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and capitalize an equal amount as a cost of the asset depreciating the additional cost over the estimated useful life of the asset. The Company recorded an after-tax charge of approximately $2,873,000 during the three months ended September 30, ~~2002 for the cumulative effect on prior years for depreciation~~2005, we had $104.3 million in cash and $65.0 million of ~~the additional costs and accretion expense on the liability related to expected abandonment costs related to its oil and natural gas producing properties and salt water disposal wells.~~availability under our revolving credit facility.

Cash ~~Flows~~Flow

~~The Company’s~~Our net cash provided by operating activities for the nine months ended September 30, ~~2003 decreased $10,135,000~~2005, totaled $145.1 million compared to ~~$72,907,000 from $83,042,000~~$63.1 million for the nine months ended September 30, ~~2002.~~2004. The ~~decrease~~increase in cash flow from operating activities is due primarily to higher net income. Our net cash provided by ~~operating activities was due to an increase in working capital, partially offset by an increase in income from higher activity levels.~~

~~The Company’s net cash used in~~ investing activities for the nine months ended September 30, ~~2003 decreased $124,829,000~~2005 totaled $3.9 million compared to ~~$47,841,000 from $172,670,000~~cash used of $63.8 million for the nine months ended September 30, ~~2002.~~2004. The ~~decrease~~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 ~~investing activities was primarily due to the acquisition of QSI in July 2002 partially offset by proceeds from the sale of the Company’s oil and gas properties in August 2003.~~

~~The Company’s net cash provided by~~ financing activities for the nine months ended September 30, ~~2003 decreased $31,408,000~~2005 totaled $65.6 million compared to ~~$55,542,000 from $86,950,000~~$92.8 million for the nine months ended September 30, ~~2002. The decrease was a result of the Company using a portion of the proceeds of the 6~~³/8% Senior Notes offering to repay its indebtedness under the Senior Credit Facility and to repurchase approximately $30,800,000 of its outstanding 5% Convertible Subordinated Notes during the nine months ended September 30, 2003 as compared to a net increase of borrowings under the revolver and an issuance of $100,000,000 of its 8³/8~~% Senior Notes, partially offset by a repurchase of a portion of the Company's 14% Senior Subordinated Notes during the nine months ended September 30, 2002.~~

The effect of exchange rates on cash for the nine months ended September 30, 2003 and 2002 was a use of $225,000 and $1,460,000, respectively. This was principally the result of the change in exchange rates of the Argentine peso for the corresponding periods.

~~LIQUIDITY AND CAPITAL RESOURCES~~

The Company has historically funded its operations, acquisitions, capital expenditures and working capital requirements from cash flow from operations, bank borrowings and the issuance of equity and long-term debt. The Company believes that its current reserves of cash and cash equivalents, availability of its existing credit lines, access to capital markets and

~~internally generated cash flows from operations are sufficient to finance the cash requirements of its current cash and future operations, acquisitions and capital expenditures.~~

~~LONG-TERM DEBT~~

~~Other than capital lease obligations and miscellaneous notes payable, as of September 30, 2003, the Company’s long-term debt was comprised of (i) a senior credit facility, (ii) a series of 6~~³/8~~% Senior Notes Due 2013, (iii) a series of 8~~³/8~~% Senior Notes Due 2008, (iv) a series of 14% Senior Subordinated Notes Due 2009, and (v) a series of 5% Convertible Subordinated Notes Due~~ 2004.

~~Senior Credit Facility~~

and advances or changes to debt instruments and organizational documents. All obligations under the New Senior Credit Facility are guaranteed by most of the Company’s subsidiaries and are secured by most of the Company’s assets, including the Company’s accounts receivable, inventory and most equipment.

The New Senior Credit Facility amended and restated the Company’s Third Amended and Restated Credit Agreement (the “Senior Credit Facility”) dated July 15, 2002, which provided for a $150,000,000 revolving loan facility with a $75,000,000 sublimit for letters of credit. The loans were secured by most of the tangible and intangible assets of the Company. The Senior Credit Facility had customary affirmative and negative covenants including a maximum leverage ratio, a minimum fixed charge coverage ratio and a minimum net worth, as well as limitations on liens and indebtedness and restrictions on dividends, acquisitions and dispositions. As of September 30, 2003, the Company was in compliance with all covenants contained in the Senior Credit Facility.

As of September 30, 2003, no revolving loans were outstanding under the revolving loan facility and approximately $53,290,000 of letters of credit related to workers’ compensation insurance was outstanding. A portion of the net cash proceeds from the debt offering of the 6³/8~~% Senior Notes completed in May 2003 were used to repay the balance of the revolving loan facility then outstanding under the Senior Credit Facility.~~

6³/8~~% Senior Notes~~

~~On May 14, 2003, the Company completed a public offering of $150,000,000 of 6~~³/8~~% Senior Notes due 2013 (the “6~~³/8% Senior Notes”). The net cash proceeds from the public offering, net of fees and expenses, were used to repay the balance of the revolving loan facility then outstanding under the Senior Credit Facility, with the remainder to be used for general corporate purposes, including further debt retirement. The 6³/8~~% Senior Notes are senior unsecured obligations and are fully and unconditionally guaranteed by substantially all of the Company’s subsidiaries. The 6~~³/8~~% Senior Notes are effectively subordinated to Key’s secured indebtedness, which includes borrowings under the Senior Credit Facility.~~

~~At any time and from time to time, the Company may, at its option, redeem all or a portion of the 6~~³/8% Senior Notes, upon not less than 30 and not more than 60 days prior notice, at the make-whole-price, plus accrued and unpaid interest to the redemption date. The make-whole-price is the sum of the outstanding principal amount of the notes to be redeemed plus an amount equal to the excess, if any, of (i) the present value of the remaining interest (excluding payments of interest accrued as of the redemption date), premium and principal payments due on the notes to be redeemed, computed at a discount rate equal to the treasury rate plus 50 basis points, over (ii) the outstanding principal amount of such notes.

~~At September 30, 2003, $150,000,000 principal amount of the 6~~³/8~~% Senior Notes remained outstanding. The 6~~³/8~~% Senior Notes require semi-annual interest payments on May 1 and November 1 of each year. As of September 30, 2003, the Company was in compliance with all covenants contained in the 6~~³/8~~% Senior Notes indenture.~~

8³/8~~% Senior Notes~~

~~On March 6, 2001, the Company completed a private placement of $175,000,000 of 8~~³/8~~% Senior Notes due 2008 (the “8~~³/8% Senior Notes”). The net cash proceeds from the private placement were used to repay all of the remaining balance of the original term loans under the Company’s then outstanding senior credit facility (the “Prior Senior Credit Facility”) and a portion of the revolving loan facility under the Prior Senior Credit Facility then outstanding. On March 1, 2002, the Company completed a public offering of an additional $100,000,000 of 8³/8~~% Senior Notes due 2008. The net cash proceeds from the public offering were used to repay all of the remaining balance of the revolving loan facility under the Prior Senior Credit Facility. The 8~~³/8~~% Senior Notes are senior unsecured obligations and are fully and unconditionally guaranteed by substantially all of the Company’s subsidiaries. The 8~~³/8~~% Senior Notes are effectively subordinated to Key’s secured indebtedness, which includes borrowings under the Senior Credit Facility.~~

~~On and after March 1, 2005, the Company may redeem some or all of the 8~~³/8% Senior Notes at any time at varying redemption prices in excess of par, plus accrued interest. In addition, before March 1, 2004, the Company may redeem up to 35% of the aggregate principal amount of the 8³/8~~% Senior Notes with the proceeds of certain sales of equity at 108.375% of par plus accrued interest.~~

~~At September 30, 2003, $275,000,000 principal amount of the 8~~³/8~~% Senior Notes remained outstanding. The 8~~³/8% Senior Notes require semi-annual interest payments on March 1 and September 1 of each year. Interest of approximately $11,516,000 was paid on September 1, 2003. As of September 30, 2003, the Company was in compliance with all covenants contained in the 8³/8~~% Senior Notes indenture.~~

~~14% Senior Subordinated Notes~~

On January 22, 1999, the Company completed the private placement of 150,000 units (the “Units”) consisting of $150,000,000 of 14% Senior Subordinated Notes due 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 “Unit Warrants”). The net cash proceeds from the private placement were used to repay substantially all of the remaining $148,600,000 principal amount (plus accrued interest) owed under the Company’s bridge loan facility arranged in connection with the acquisition of Dawson Production Services, Inc. (“Dawson”).

On and after January 15, 2004, the Company may redeem some or all of the 14% Senior Subordinated Notes at any time at varying redemption prices in excess of par, which as of January 15, 2004 will be 107% of par, plus accrued interest. In addition, before January 15, 2002, the Company was allowed to redeem up to 35% of the aggregate principal amount of the 14% Senior Subordinated Notes at 114% of par plus accrued interest with the proceeds of certain sales of equity. During the fiscal year ended September 30, 2001, the Company exercised its

right of redemption for $10,313,000 principal amount of the 14% Senior Subordinated Notes at a price of 114% of the principal amount plus accrued interest. This transaction resulted in a loss of approximately $2,561,000. On January 14, 2002, the Company exercised its right of redemption for $35,403,000 principal amount of the 14% Senior Subordinated Notes at a price of 114% of the principal amount plus accrued interest. This transaction resulted in a loss of approximately $8,468,000. Also, during the fiscal year ended September 30, 2002, the Company purchased and canceled $6,784,000 principal amount of the 14% Senior Subordinated Notes at a price of 116% of the principal amount plus accrued interest. These transactions resulted in a loss of approximately $1,821,000.

The Unit Warrants separated from the 14% Senior Subordinated Notes and became exercisable on January 25, 2000. On the date of issuance, the value of the Unit Warrants was estimated at $7,434,000 and is classified as a discount to the 14% Senior Subordinated Notes on the Company’s consolidated balance sheet. The discount is being amortized to interest expense over the term of the 14% Senior Subordinated Notes. The 14% Senior Subordinated Notes mature and the Unit Warrants expire on January 15, 2009. The 14% Senior Subordinated Notes are subordinate to the Company’s senior indebtedness, which includes borrowings under the Senior Credit Facility, the 8³/8~~% Senior Notes and the 6~~³/8~~% Senior Notes. The 14% Senior Subordinated Notes are fully and unconditionally guaranteed by substantially all of the Company’s subsidiaries.~~

At September 30, 2003, $97,500,000 principal amount of the 14% Senior Subordinated Notes remained outstanding. The Company intends to redeem the remaining 14% Senior Subordinated Notes on or before January 15, 2004 using the Company's available cash or other borrowings, including the Company's revolver. The 14% Senior Subordinated Notes pay interest semi-annually on January 15 and July 15 of each year. Interest of approximately $6,825,000 was paid on July 15, 2003. As of September 30, 2003, 63,500 Unit Warrants had been exercised, producing approximately $4,173,000 of proceeds to the Company and leaving 86,500 Unit Warrants outstanding. As of September 30, 2003, the Company was in compliance with all covenants contained in the 14% Senior Subordinated Notes indenture.

~~5% Convertible Subordinated Notes~~

In 1997, the Company completed a private placement of $216,000,000 of 5% Convertible Subordinated Notes due 2004 (the “5% Convertible Subordinated Notes”). The 5% Convertible Subordinated Notes are subordinate to the Company’s senior indebtedness which includes borrowings under the Senior Credit Facility, the 14% Senior Subordinated Notes, the 8³/8~~% Senior Notes and the 6~~³/8% Senior Notes. The 5% Convertible Subordinated Notes are convertible, at the holder’s option, into shares of the Company’s common stock at a conversion price of $38.50 per share, subject to certain adjustments. The 5% Convertible Subordinated Notes are redeemable, at the Company’s option, on and after September 15, 2000, in whole or part, together with accrued and unpaid interest. The initial redemption price is 102.86% for the year beginning September 15, 2000 and declines ratably thereafter on an annual basis.

At September 30, 2003, $18,699,000 principal amount of the 5% Convertible Subordinated Notes remained outstanding. The 5% Convertible Subordinated Notes mature on September 15, 2004. The Company intends to use its available cash or other borrowings, including the Company’s revolver, to pay off the 5% Convertible Notes on or before maturity. Interest on the 5% Convertible Subordinated Notes is payable on March 15 and September 15 of each year. Interest of approximately $487,000 was

~~paid on September 15, 2003. As of September 30, 2003, the Company was in compliance with all covenants contained in the 5% Convertible Subordinated Notes indenture.~~

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 ~~judgment~~historical claims data and ~~estimates. A critical accounting policy is one that requires difficult, subjective or complex~~trend analysis. The actual outcome of any claim could differ significantly from estimated amounts. We adjust loss estimates and assessments and is fundamental to the reported amounts of assets and liabilities at the date of the financial statements and revenues and expenses during the periods presented. A complete summary of the Company’s critical accounting policies is included in Note 1 to the consolidated financial statements included in the ~~Company’s Transition Report on Form 10-K as~~calculation of these accruals, based upon actual claim settlements and reported claims.

Accounting for ~~the six months ended December 31, 2002. The Company’s critical accounting policies are as follows.~~Contingencies

~~Management makes estimates regarding the fair value of the Company’s reporting units in assessing potential impairment of goodwill.~~ 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 ~~Company makes estimates regarding future undiscounted cash flows from the future use~~normal course of ~~long-lived assets whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset may not be recoverable.~~

In assessing impairment of goodwill, the Company has used estimates and assumptions in estimating the fair value of its reporting units. Actual future results could be different than the estimates and assumptions used. Events or circumstances which might lead to an indication of impairment of goodwill would include, but might not be limited to, prolonged decreases in expectations of long-term well servicing and/or drilling activity or rates brought about by prolonged decreases in oil or natural gas prices, changes in government regulation of the oil and natural gas industry or other events which could affect the level of activity of exploration and production companies.

In assessing impairment of long-lived assets other than goodwill where there has been a change in circumstances indicating that the carrying amount of a long-lived asset may not be recoverable, the Company has estimated future undiscounted net cash flows from use of the asset basedour operations on actual historical results and expectations about future economic circumstances including oil and natural gas prices and operating costs. The estimate of future net cash flows from use of the asset could change if actual prices and costs differ due to industry conditions or other factors affecting the Company’s performance.

~~The Company computes income taxes in~~our consolidated balance sheet. In accordance with Statement of Financial Accounting Standards No. ~~109,~~ 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 ~~(“SFAS 109”). SFAS~~

We follow Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes,” which requires anthat we account for deferred income taxes using the asset and liability ~~approach which results~~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 ~~recognition~~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 ~~expected future~~differing treatment of certain items for tax ~~consequences of temporary~~and accounting purposes or whether such differences ~~between the carrying amounts and the~~are permanent.

We establish valuation allowances to reduce deferred tax ~~basis of those~~ assets ~~and liabilities. SFAS No. 109 also requires the recording of a valuation allowance~~ if we determine that it is more likely than not (e.g., a likelihood of more than 50%) that some portion or all of athe deferred tax ~~asset~~assets will not be ~~realized.~~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

~~RECENTLY ISSUED ACCOUNTING PRONOUCEMENTS~~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~~“Amendment of ~~Statement~~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 ~~149 amendments require that contracts with comparable characteristics be accounted for similarly,~~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 ~~characteristic~~characteristics of a ~~derivative and~~derivative; (2) clarifies when a derivative ~~requires special reporting in~~contains a financing component that should be recorded as a financing transaction on the balance sheet and the statement of cash ~~flows.~~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 ~~effective for~~applicable to all contracts entered into or modified after June 30, 2003 and to all hedging relationships designated ~~and for contracts entered into~~

~~or modified~~ after September 30, 2003, except for provisions that relate to SFAS 133 Statement Implementation Issues that have been effective for fiscal quarters prior to September 15, 2003, which should be applied in accordance with their respective effective dates, and certain provisions relating to forward purchases or sales of when-issued securities or other securities that do not exist, which should be applied to existing contracts as well as new contracts entered into after SeptemberJune 30, 2003. The ~~application~~adoption of ~~SFAS 149 is~~this standard did not ~~expected to have a material effect on the Company’s consolidated~~materially impact our financial statements.

SFAS 150.In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150, ~~Accounting~~“Accounting for Certain Financial Instruments with Characteristics of ~~both~~Both Liabilities and Equity,” (“SFAS 150”)~~. SFAS 150~~ which establishes ~~standards for~~ how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. ~~It requires~~Instruments that have an unconditional obligation requiring the issuer ~~classify~~to redeem the instrument by transferring an asset at a ~~financial instrument~~specified date are required to be classified as liabilities on the balance sheet. Instruments that ~~is within~~require the ~~scope~~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 as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. The application of SFAS 150 is not expected to have a material effect on the Company’s consolidated financial statements. This Statement iswas effective for ~~financial instruments entered into~~contracts in existence or created or modified ~~after May 31, 2003, and otherwise is effective at the beginning of~~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, ~~2003.~~2005. The adoption of this standard did not materially impact our financial statements.

~~ITEM 3~~.Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET ~~RISK~~RISKS

Special Note: Certain statements set forth below under this caption constitute “forward-looking statements”. See “Special Note Regarding Forward-Looking Statements” for additional factors relating to such statements.

~~The primary objective of the following information is to provide forward-looking~~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 ~~Key’s potential exposure~~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 ~~market risk. The term “market risk” refers~~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 ~~risk of loss arising from adverse changes in foreign currency exchange, interest rates~~Company’s management, including the Company’s Chairman and ~~oil~~Chief Executive Officer and ~~natural gas prices. The disclosures are not meant~~Chief Financial Officer, as appropriate to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how the Company views and manages its ongoing market risk exposures.

~~INTEREST RATE RISK~~

At September 30, 2003, the Company had long-term debt and capital lease obligations outstanding of approximately $557,170,000. Of this amount, approximately $539,587,000, or 97%, bears interest at fixed rates as follows:

As of
September 30, 2003

(thousands)

6³/8% Senior Notes Due 2013

$
150,000

8³/8% Senior Notes Due 2008

276,169

14% Senior Subordinated Notes Due 2009

94,668

5% Convertible Subordinated Notes Due 2004

18,699

Other at 8.0%

51

$
539,587

The remaining $17,583,000 of long-term debt and capital lease obligations outstanding as of September 30, 2003 bears interest at floating rates, which averaged approximately 2.8% at September 30, 2003. A 10% increase in short-term interest rates on the floating-rate debt outstanding at September 30, 2003 would equal approximately 27 basis points. Such an increase in interest rates would increase Key’s 2003 annual interest expense by approximately $50,000 assuming borrowed amounts remain outstanding.

~~The above sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments.~~

~~FOREIGN CURRENCY RISK~~

During the year ended September 30, 2002, the Argentine government suspended the law tying the Argentine peso to the U.S. dollar at the conversion ratio of 1:1 and created a dual currency system in Argentina. Key’s net assets of its Argentina subsidiaries are based on the U.S. dollar equivalent of such amounts measured in Argentine pesos as of September 30, 2003 and December 31, 2002. Assets and liabilities of the Argentine operations were translated to U.S. dollars at September 30, 2003 and December 31, 2002 using the applicable free market conversion ratio of 2.9:1 and 3.4:1, respectively, and will be translated at future dates using the applicable free market conversion ratio on such dates. Key’s net earnings and cash flows from its Argentina subsidiaries are based on the U.S. dollar equivalent of such amounts measured in Argentine pesos. Revenues, expenses and cash flows will be translated using the average exchange rates.

The change in the Argentine peso to the U.S. dollar exchange rate since December 31, 2002 has increased stockholders’ equity by approximately $3,246,000, through a credit to other comprehensive loss through September 30, 2003.

Key’s net assets, net earnings and cash flows from its Canadian subsidiary are based on the U.S. dollar equivalent of such amounts measured in Canadian dollars. Assets and liabilities of the Canadian operations are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues and expenses are translated using the average exchange rate during the reporting period.

~~A 10% change in the Canadian-to-U.S. Dollar exchange rate would not be material to the net assets, net earnings or cash flows of the Company.~~

~~Key’s net assets, net earnings and cash flows from its Egyptian subsidiary are based on the U.S. dollar. Foreign currency transactions are included in determination of net income for the period.~~

~~COMMODITY PRICE RISK~~

Key sold all of its oil and natural gas properties during August 2003. As a result of the sale, the Company terminated its remaining oil option contract. Key no longer has major market risk exposure, for its oil and natural gas production operations, from pricing applicable to its oil and natural gas sales. See Note 12 to the Consolidated Financial Statements.

~~ITEM 4~~.~~DISCLOSURE CONTROLS AND PROCEDURES~~

allow timely decisions regarding required disclosure.

The Company’s ~~principal executive officer~~management, with the participation of the Company’s Chairman and ~~principal financial officer undertook an evaluation~~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 ~~the Securities Exchange Act of 1934~~ Rules 13a-15(e) and ~~15(d)-15(e))~~15d-15(e) under the Exchange Act) as of the end of the period covered by this ~~report~~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, ~~the Company’s~~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 11.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.

~~. Legal Proceedings.~~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 2~~~~. Changes in Securities and Use of Proceeds~~.

~~None.~~

Item 3.DEFAULTS UPON SENIOR SECURITIES ~~Defaults Upon Senior Securities.~~

None.

Item 44. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS~~. Submission of Matters to a Vote of Security Holders.~~

None.

Item 55.OTHER INFORMATION~~. Other Information~~

None.

Item 66.EXHIBITS~~. Exhibits and Reports on Form 8-K.~~

~~(a)Exhibits~~ 4.1~~Supplemental Indenture dated as of July 28, 2003, between the Company, the Guarantors (as defined therein) and The Bank of New York, as Trustee.~~ 4.2~~Third Supplemental Indenture dated as of July 28, 2003, among the Company, the Guarantors (as defined therein) and U.S. Bank National Association, as Trustee.~~ ~~10.1~~Fourth Amended and Restated Credit Agreement, dated as of June 7, 1997, as amended and restated through November 10, 2003, among the Company, the several Lenders from time to time parties thereto, the Guarantors, PNC Bank, National Association, as Administrative Agent, PNC Capital Markets, Inc. and Wells Fargo Bank Texas, as Co-Lead Arrangers, and Credit Lyonnais New York Branch, as Syndication Agent, Bank One N. A. and Comerica Bank, as Co-Documentation Agents (incorporated by reference to Exhibit 99.1 of the Company’s Current Report on Form 8-K dated November 13, 2003, File No. 1-8038). 10.2~~Purchase and Sale Agreement dated August 7, 2003 between Odessa Exploration Incorporated and Stallion Panhandle 2001, L.P.~~ 31.1~~Certification of CEO pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.~~ 43 31.2~~Certification of CFO pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.~~ 32~~Certification of CEO and CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.~~	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.

~~(b)~~ ~~Reports on Form 8-K~~

~~The Company filed the following report on Form 8-K during the quarter ended September 30, 2003:~~

~~(i)~~ ~~Current Report on Form 8-K dated August 19, 2003 to report the execution of an agreement to dispose of the Company’s oil and gas properties.~~

~~TheCompany furnished the following report on Form 8-K during the quarter ended September 30, 2003:~~

~~(i)~~ ~~Current Report on Form 8-K dated July 29, 2003 filed to furnish the Company’s operating results for the quarter ended June 30, 2003.~~

~~SIGN~~SIGNATURE~~ATURES~~

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)
~~Dated: November 14, 2003~~	By	~~/s/ Francis D. John~~
		/s/ Richard J. Alario	~~Francis D. John~~
	By:	Richard J. Alario
		President and Chief Executive Officer
		(Principal Executive Officer)
~~Dated: November 14, 2003~~	By	~~/s/ Royce W. Mitchell~~

~~Royce W. Mitchell~~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.)

~~Chief Financial Officer~~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.

(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

Maryland		04-2648081
(State or ~~other jurisdiction~~Other Jurisdiction of ~~incorporation or organization)~~		(I.R.S. Employer ~~Identification No.)~~
Incorporation or Organization)
~~6 Desta Drive, Midland, Texas~~		~~79705~~
~~(Address of principal executive offices)~~		~~(ZIP Code)~~

~~Registrant’s telephone number including area code:~~ ~~(432) 620-0300~~Identification No.)

	Nine Months Ended September 30,
	2003			2002
	(thousands)
*CASH FLOWS FROM OPERATING ACTIVITIES:*
Net income (loss)	$	3,322		$	(15,999	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	75,960			64,143
Amortization of deferred debt issuance costs, discount and premium	2,501			2,249
Deferred income tax expense (benefit)	7,180			(3,451		)
Loss on sale of assets	41			307
Foreign currency transaction gain, Argentina	—			(401		)
(Gain) loss on retirement of debt	(16		)	8,447
Discontinued operations, net of tax	1,168			1,846
Cumulative effect of a change in accounting principle, net of tax	—			2,873
Change in assets and liabilities, net of effects from acquisitions:
(Increase) decrease in accounts receivable	(23,206		)	24,406
(Increase) decrease in other current assets	(851		)	3,122
Decrease in accounts payable, accrued interest and accrued expenses	(708		)	(13,960		)
Other assets and liabilities	7,516			9,460
Net cash provided by operating activities	72,907			83,042

*CASH FLOWS FROM INVESTING ACTIVITIES:*
Capital expenditures – well servicing	(46,962		)	(41,571		)
Capital expenditures - contract drilling	(5,063		)	(8,975		)
Capital expenditures – other	(12,663		)	(14,081		)
Proceeds from sale of fixed assets	2,334			685
Proceeds from sale of oil and natural gas properties	19,700			—
Acquisitions – well servicing, net of cash acquired	(5,187		)	(106,691		)
Acquisitions – contract drilling, net of cash acquired	—			(2,037		)
Net cash used in investing activities	(47,841		)	(172,670		)

*CASH FLOWS FROM FINANCING ACTIVITIES:*
Repayment of long-term debt	(107,716		)	(125,839		)
Repayment of capital lease obligations	(7,173		)	(7,570		)
Repurchase of volumetric production payment	(4,227		)	—
Proceeds from long-term debt	175,000			222,500
Proceeds paid for debt issuance costs	(2,963		)	(3,940		)
Proceeds from exercise of stock options	2,920			2,046
Other	(299		)	(247		)
Net cash provided by financing activities	55,542			86,950
Effect of exchange rates on cash	(225		)	(1,460		)

Net increase (decrease) in cash and cash equivalents	80,383			(4,138		)
Cash and cash equivalents at beginning of period	9,044			7,966
Cash and cash equivalents at end of period	$	89,427		$	3,828

	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

	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	)%

	September 30, 2003			December 31, 2002
	(Unaudited)
	(thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	89,427		$	9,044
Accounts receivable, net of allowance for doubtful accounts of $5,813 and $4,439, at September 30, 2003 and December 31, 2002, respectively	162,819			141,958
Inventories	14,022			10,243
Prepaid expenses and other current assets	12,446			14,329
Total current assets	278,714			175,574

Property and equipment:
Well servicing equipment	967,013			935,911
Contract drilling equipment	132,556			128,199
Motor vehicles	81,554			79,110
Oil and natural gas properties and other related equipment, successful efforts method	—			48,362
Furniture and equipment	61,937			51,349
Buildings and land	50,003			48,922
Total property and equipment	1,293,063			1,291,853
Accumulated depreciation and depletion	(389,329		)	(335,348		)
Net property and equipment	903,734			956,505
Goodwill, net	346,335			322,270
Deferred costs, net	14,182			13,503
Notes and accounts receivable - related parties	190			251
Other assets	24,446			33,899
Total assets	$	1,567,601		$	1,502,002

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	20,885		$	28,818
Other accrued liabilities	70,504			57,823
Accrued interest	8,841			15,226
Current portion of long-term debt and capital lease obligations	24,616			7,008
Total current liabilities	124,846			108,875
Long-term debt, less current portion	520,837			472,336
Capital lease obligations, less current portion	11,722			14,221
Deferred revenue	726			8,460
Non-current accrued expenses	36,919			40,477
Deferred tax liability	154,182			161,265
Commitments and contingencies	—			—
Stockholders’ equity:
Common stock, $0.10 par value; 200,000,000 shares authorized, 130,337,664 and 128,757,693 shares issued at September 30, 2003 and December 31, 2002, respectively	13,034			12,876
Additional paid-in capital	687,421			673,249
Treasury stock, at cost; 416,666 shares at September 30, 2003 and December 31, 2002	(9,682		)	(9,682		)
Accumulated other comprehensive loss	(41,082		)	(45,431		)
Retained earnings	68,678			65,356
Total stockholders’ equity	718,369			696,368
Total liabilities and stockholders’ equity	$	1,567,601		$	1,502,002

	Three Months Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
	(thousands, except per share data)
*REVENUES:*
Well servicing	$	224,251		$	185,967		$	643,379		$	494,452
Contract drilling	18,819			14,399			51,925			41,491
Other	312			50			(174		)	1,093
Total revenues	243,382			200,416			695,130			537,036

*COSTS AND EXPENSES:*
Well servicing	154,565			131,630			455,645			365,953
Contract drilling	13,676			10,517			38,013			31,970
Depreciation, depletion and amortization	25,898			24,962			75,960			64,143
General and administrative.	24,974			25,808			70,248			56,103
Interest	12,726			11,262			35,940			31,548
Foreign currency transaction gain, Argentina	—			—			—			(401		)
(Gain) loss on retirement of debt	—			(10		)	(16		)	8,447
Total costs and expenses	231,839			204,169			675,790			557,763
Income (loss) from continuing operations before income taxes	11,543			(3,753		)	19,340			(20,727		)
Income tax benefit (expense)	(5,204		)	1,426			(8,152		)	8,251
INCOME (LOSS) FROM CONTINUING OPERATIONS	6,339			(2,327		)	11,188			(12,476		)
Discontinued operations including loss on sale of $7,804, net of tax	(7,396		)	(310		)	(7,866		)	(650		)
Cumulative effect on prior years of a change in accounting principle, net of tax	—			(2,873		)	—			(2,873		)
*NET INCOME (LOSS)*	$	(1,057	)	$	(5,510	)	$	3,322		$	(15,999	)

EARNINGS (LOSS) PER SHARE:
Net income (loss) before discontinued operations and cumulative effect of a change in accounting principle, net of tax:
Basic	$	0.05		$	(0.02	)	$	0.09		$	(0.11	)
Diluted	$	0.05		$	(0.02	)	$	0.09		$	(0.11	)

Discontinued operations
Basic	$	(0.06	)	$	—		$	(0.06	)	$	(0.01	)
Diluted	$	(0.06	)	$	—		$	(0.06	)	$	(0.01	)

Cumulative effect
Basic	$	—		$	(0.02	)	$	—		$	(0.03	)
Diluted	$	—		$	(0.02	)	$	—		$	(0.03	)

Net income (loss)
Basic	$	(0.01	)	$	(0.04	)	$	0.03		$	(0.15	)
Diluted	$	(0.01	)	$	(0.04	)	$	0.03		$	(0.15	)

WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic	129,744			122,475			129,095			113,668
Diluted	131,433			122,475			130,987			113,668

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30, 2005		Three Months Ended September 31, 2004			Nine Months Ended September 30, 2005			Nine months Ended September 31, 2004
	2003			2002			2003			2002			(in thousands, except per share data)
	(thousands, except per share data)
*Basic EPS Computation:*
Numerator
Income (loss) before discontinued operations	$	6,339		$	(2,327	)	$	11,188		$	(12,476	)
Income from continuing operations													$	19,318	$	3,348		$	37,052		$	(19,454	)
Discontinued operations, net of tax	(7,396		)	(310		)	(7,866		)	(650		)	—		(8,224		)	(3,361		)	(7,595		)
Cumulative effect of a change in accounting principle, net of tax	—			(2,873		)	—			(2,873		)
Net income (loss)	$	(1,057	)	$	(5,510	)	$	3,322		$	(15,999	)	$	19,318	$	(4,876	)	$	33,691		$	(27,049	)

Denominator
Weighted average common shares outstanding	129,744			122,475			129,095			113,668			131,338		130,791			130,988			130,745

*Basic EPS:*
Income (loss) before discontinued operations	$	0.05		$	(0.02	)	$	0.09		$	(0.11	)
Income from continuing operations													$	0.15	$	0.03		$	0.28		$	(0.15	)
Discontinued operations, net of tax	(0.06		)	—			(0.06		)	(0.01		)	—		(0.06		)	(0.03		)	(0.06		)
Cumulative effect of a change in accounting principle, net of tax	—			(0.02		)	—			(0.03		)
Net income (loss)	$	(0.01	)	$	(0.04	)	$	0.03		$	(0.15	)	$	0.15	$	(0.03	)	$	0.25		$	(0.21	)

*Diluted EPS Computation:*
Numerator
Income (loss) before discontinued operations	$	6,339		$	(2,327	)	$	11,188		$	(12,476	)
Income from continuing operations													$	19,318	$	3,348		$	37,052		$	(19,454	)
Discontinued operations, net of tax	(7,396		)	(310		)	(7,866		)	(650		)	—		(8,224		)	(3,361		)	(7,595		)
Cumulative effect of a change in accounting principle, net of tax	—			(2,873		)	—			(2,873		)
Net income (loss)	$	(1,057	)	$	(5,510	)	$	3,322		$	(15,999	)	$	19,318	$	(4,876	)	$	33,691		$	(27,049	)

Denominator
Weighted average common shares outstanding	129,744			122,475			129,095			113,668			131,338		130,791			130,988			130,745
Stock options													2,211		—			1,934			—
Warrants	427			—			438			—			523		—			494			—
Stock options	1,262			—			1,454			—
	131,433			122,475			130,987			113,668			134,072		130,791			133,416			130,745

*Diluted EPS:*
Income (loss) before discontinued operations	$	0.05		$	(0.02	)	$	0.09		$	(0.11	)
Income from continuing operations													$	0.14	$	0.03		$	0.28		$	(0.15	)
Discontinued operations, net of tax	(0.06		)	—			(0.06		)	(0.01		)	—		(0.06		)	(0.03		)	(0.06		)
Cumulative effect of a change in accounting principle, net of tax	—			(0.02		)	—			(0.03		)
Net income (loss)	$	(0.01	)	$	(0.04	)	$	0.03		$	(0.15	)	$	0.14	$	(0.03	)	$	0.25		$	(0.21	)

	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	)

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

	Net Assets Acquired
	(thousands)

Current assets	$	37,734
Property and equipment	114,519
Intangible assets	3,242
Other assets	344
Goodwill	136,640
Total assets aquired	292,479
Current liabilities	18,597
Capital lease obligations	77
Non-current accrued expenses	17,908
Deferred tax liablity	5,124
Total liabilities assumed	41,706
Net assets acquired	$	250,773

	Nine Months Ended September 30, 2002
	(thousands, except per share data)

Revenues	$	622,799
Net income (loss)	(17,595		)
Basic earnings (loss) per share	$	(0.14	)

	Well Servicing		Contract Drilling			Corporate / Other			Total

Three Months Ended September 30, 2003
Operating revenues	$	224,251	$	18,819		$	312		$	243,382
Operating profit	69,686		5,143			312			75,141
Depreciation, depletion and amortization	21,473		2,642			1,783			25,898
Interest expense	137		—			12,589			12,726
Net income (loss) from continuing operations*	13,049		319			(7,029		)	6,339
Identifiable assets	815,190		88,531			317,545			1,221,266
Capital expenditures (excluding acquisitions)	15,883		1,060			4,891			21,834

Three Months Ended September 30, 2002
Operating revenues	$	185,967	$	14,399		$	50		$	200,416
Operating profit	54,337		3,882			50			58,269
Depreciation, depletion and amortization	21,876		2,392			694			24,962
Interest expense	276		—			10,986			11,262
Net income (loss) from continuing operations*	4,988		(227		)	(7,088		)	(2,327		)
Identifiable assets	828,845		88,742			253,053			1,170,640
Capital expenditures (excluding acquisitions)	12,115		191			4,286			16,592

CONDENSED CONSOLIDATING BALANCE SHEET

	September 30, 2003
	Parent Company		Guarantor A Subsidiaries		Guarantor B Subsidiary			Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(thousands)

Assets:
Current assets	$	96,566	$	167,403	$	77		$	14,668	$	—		$	278,714
Net property and equipment	51,156		829,531		13			23,034		—			903,734
Goodwill, net	3,431		342,177		—			727		—			346,335
Deferred costs, net	14,182		—		—			—		—			14,182
Inter-company receivables	697,601		—		—			—		(697,601		)	—
Other assets	12,805		11,373		458			—		—			24,636
Total assets	$	875,741	$	1,350,484	$	548		$	38,429	$	(697,601	)	$	1,567,601

Liabilities and equity:
Current liabilities	$	50,275	$	68,757	$	342		$	5,472	$	—		$	124,846
Long-term debt	520,837		—		—			—		—			520,837
Capital lease obligations	1,403		10,319		—			—		—			11,722
Inter-company payables	—		674,899		3,753			18,949		(697,601		)	—
Deferred tax liability	154,182		—		—			—		—			154,182
Other long-term liabilities	33,346		4,299		—			—		—			37,645
Stockholders’ equity	115,698		592,210		(3,547		)	14,008		—			718,369
Total liabilities and stockholders’ equity	$	875,741	$	1,350,484	$	548		$	38,429	$	(697,601	)	$	1,567,601


CONDENSED CONSOLIDATING BALANCE SHEET

	December 31, 2002
	Parent Company		Guarantor A Subsidiaries		Guarantor B Subsidiary			Non- Guarantor Subsidiaries		Eliminations			Consolidated
	(thousands)
Assets:
Current assets	$	17,716	$	142,587	$	992		$	14,279	$	—		$	175,574
Net property and equipment	43,134		861,043		32,732			19,596		—			956,505
Goodwill, net	3,431		318,208		—			631		—			322,270
Deferred costs, net	13,503		—		—			—		—			13,503
Inter-company receivables	760,990		—		—			—		(760,990		)	—
Other assets	19,687		13,882		581			—		—			34,150
Total assets	$	858,461	$	1,335,720	$	34,305		$	34,506	$	(760,990	)	$	1,502,002

Liabilities and equity:
Current liabilities	$	43,701	$	59,410	$	2,061		$	3,703	$	—		$	108,875
Long-term debt	472,336		—		—			—		—			472,336
Capital lease obligations	1,648		12,573		—			—		—			14,221
Inter-company payables	—		724,341		15,501			21,148		(760,990		)	—
Deferred tax liability	161,265		—		—			—		—			161,265
Other long-term liabilities	31,222		4,735		12,887			93		—			48,937
Stockholders’ equity	148,289		534,661		3,856			9,562		—			696,368
Total liabilities and stockholders’ equity	$	858,461	$	1,335,720	$	34,305		$	34,506	$	(760,990	)	$	1,502,002

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

	Nine Months Ended September 30, 2003
	Parent Company			Guarantor A Subsidiaries			Guarantor B Subsidiary			Non- Guarantor Subsidiaries			Eliminations		Consolidated
	(thousands)
Revenues	$	256		$	674,184		$	—		$	20,690		$	—	$	695,130
Costs and expenses:
Direct expenses	—			477,880			—			15,778			—		493,658
Depreciation, depletion and amortization expense	3,799			70,472			—			1,689			—		75,960
General and administrative expense	31,446			37,380			—			1,422			—		70,248
Interest	35,463			385			—			92			—		35,940
Gain on retirement of debt	(16		)	—			—			—			—		(16		)
Total costs and expenses	70,692			586,117			—			18,981			—		675,790
Income (loss) from continuing operations before income taxes	(70,436		)	88,067			—			1,709			—		19,340
Income tax (expense) benefit	29,689			(37,121		)	—			(720		)	—		(8,152		)
Income (loss) from continuing operations	(40,747		)	50,946			—			989			—		11,188
Discontinued operations	—			—			(7,866		)	—			—		(7,866		)
Net income (loss)	$	(40,747	)	$	50,946		$	(7,866	)	$	989		$	—	$	3,322

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

	Nine Months Ended September 30, 2002
	Parent Company			Guarantor A Subsidiaries			Guarantor B Subsidiary			Non- Guarantor Subsidiaries			Eliminations		Consolidated
	(thousands)
Revenues	$	469		$	521,448		$	—		$	15,119		$	—	$	537,036
Costs and expenses:
Direct expenses	—			386,426			—			11,497			—		397,923
Depreciation, depletion and amortization expense	1,883			60,820			—			1,440			—		64,143
General and administrative expense	23,897			31,169			—			1,037			—		56,103
Interest	30,777			767			—			4			—		31,548
Foreign currency transaction (gain), Argentina	—			—			—			(401		)	—		(401		)
Gain on retirement of debt	8,447			—			—			—			—		8,447
Total costs and expenses	65,004			479,182			—			13,577			—		557,763
Income (loss) from continuing operations before income taxes	(64,535		)	42,266			—			1,542			—		(20,727		)
Income tax (expense) benefit	25,690			(16,825		)	—			(614		)	—		8,251
Income (loss) from continuing operations	(38,845		)	25,441			—			928			—		(12,476		)
Discontinued operations	—			—			(650		)	—			—		(650		)
Cumulative effect	—			(658		)	(2,215		)	—			—		(2,873		)
Net income (loss)	$	(38,845	)	$	24,783		$	(2,865	)	$	928		$	—	$	(15,999	)

	As of September 30, 2003
	(thousands)
6³/8% Senior Notes Due 2013	$	150,000
8³/8% Senior Notes Due 2008	276,169
14% Senior Subordinated Notes Due 2009	94,668
5% Convertible Subordinated Notes Due 2004	18,699
Other at 8.0%	51
	$	539,587