UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, ~~D. C.~~D.C. 20549

~~FORM~~Form 10-Q

ý ~~QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF~~

~~THE SECURITIES EXCHANGE ACT OF 1934~~

~~For the quarterly period ended September 30, 2003~~

o ~~TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF~~

~~THE SECURITIES EXCHANGE ACT OF 1934~~

~~For the transition period from to~~
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2006
or
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file ~~number~~number: 1-8038

KEY ENERGY SERVICES, INC.

(Exact ~~name~~Name of ~~registrant~~Registrant as ~~specified~~Specified in ~~its charter)~~

Its Charter)

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.)

1301 McKinney Street, Suite 1800, Houston, Texas 77010

(Address of Principal Executive Offices) (Zip Code)

713/651-4300

(Registrant’s Telephone Number, Including Area Code)

None

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

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

Yes ý No oNox

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

Large Accelerated Filer x

Accelerated Filer o

Non-accelerated filer o

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

Yes ý NooNox

~~Common Shares~~As of June 30, 2007, the number of outstanding ~~at November 13, 2003~~ ~~130,555,141~~shares of common stock of the Registrant was 131,593,695.

KEY ENERGY SERVICES, INC.

~~Key Energy Services, Inc.~~INDEX TO FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2006

~~INDEX~~

*~~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~~June 30, 2006 and ~~Nine Months Ended September 30, 2003 and 2002~~December 31, 2005

		~~Unaudited~~Condensed Consolidated Statements of ~~Comprehensive Income (Loss)~~Operations for the Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2003~~2006 and ~~2002~~2005

		~~Unaudited~~Condensed Consolidated Statements of ~~Cash Flows~~Comprehensive Income for the ~~Nine~~Three and Six Months Ended ~~September~~June 30, ~~2003~~2006 and ~~2002~~2005
		Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2006 and 2005
		Notes to Condensed Consolidated Unaudited Financial Statements

Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 3.		Quantitative and Qualitative Disclosures ~~about~~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~~And Use ofOf Proceeds

Item 3.		Defaults Upon Senior Securities

Item 4.		Submission ofOf Matters ~~to a~~To A Vote ofOf 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 each of 2005 and the remaining two quarters for 2006. The 2005 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 the Quarterly Report, certain information presented in this report relates to significant events that have occurred subsequent to June 30, 2006.

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)

	June 30,			December 31,
	2006			2005
*ASSETS*
Current assets:
Cash and cash equivalents	$	113,769		$	94,170
Accounts receivable, net of allowance for doubtful accounts of $11,660 and $10,843 at June 30, 2006 and December 31, 2005, respectively	240,958			211,680
Inventories	17,581			17,254
Prepaid expenses	3,350			3,292
Deferred tax assets	33,034			23,912
Other current assets	3,800			6,854
Current assets of discontinued operations	621			658

Total current assets	413,113			357,820

Property and equipment:
Well servicing equipment	944,744			856,455
Contract drilling equipment	16,818			25,583
Motor vehicles	101,825			91,910
Furniture and equipment	71,528			70,485
Buildings and land	49,738			45,393

Total property and equipment	1,184,653			1,089,826
Accumulated depreciation	(526,102		)	(479,485		)

Net property and equipment	658,551			610,341

Goodwill	320,905			320,922
Deferred costs, net	10,291			11,093
Notes and accounts receivable - related parties	307			151
Other assets	29,949			28,917

TOTAL ASSETS	$	1,433,116		$	1,329,244

*LIABILITIES AND STOCKHOLDERS’ EQUITY*
Current liabilities:
Accounts payable	$	17,727		$	14,633
Accrued payroll, taxes and employee benefits	53,336			43,691
Accrued operating expenditures	33,444			39,964
Unsettled legal claims	27,113			11,249
Income, sales, use and other taxes	38,873			31,331
Workers’ compensation claims accrual	16,005			19,852
Vehicular insurance	1,744			2,632
Other accrued liabilities	12,626			6,116
Accrued interest	7,511			6,399
Current portion of capital lease obligations	9,616			8,639
Current portion of long-term debt	4,000			4,000
Current liabilities of discontinued operations	180			292

Total current liabilities	222,175			188,798

Capital lease obligations, less current portion	17,598			14,781
Long-term debt, less current portion	394,000			396,000
Workers’ compensation, vehicular, health and other insurance claims	44,611			38,311
Deferred tax liability	109,582			96,572
Other non-current accrued expenses	18,214			40,725
Commitments and contingencies	—			—

Stockholders’ equity:
Common stock, $0.10 par value; 200,000,000 shares authorized, 131,259,243 and 131,334,196 shares issued and outstanding at June 30, 2006 and December 31, 2005, respectively	13,176			13,175
Additional paid-in capital	719,812			716,389
Treasury stock, at cost; 497,501 and 416,666 shares at June 30, 2006 and December 31, 2005, respectively	(10,862		)	(9,682		)
Accumulated other comprehensive loss	(35,636		)	(36,627		)
Retained deficit	(59,554		)	(129,198		)

Total stockholders’ equity	626,936			554,057
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,433,116		$	1,329,244

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)

(Unaudited)

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 June 30,						Six Months Ended June 30,
	2006			2005			2006			2005

*REVENUES:*
Well servicing	$	288,392		$	238,696		$	561,307		$	459,029
Pressure pumping	60,199			36,246			111,997			66,750
Fishing and rental services	23,445			19,959			46,689			40,326

Total revenues	372,036			294,901			719,993			566,105

*COSTS AND EXPENSES:*
Well servicing	177,172			161,653			357,928			311,275
Pressure pumping	34,020			25,367			62,589			42,597
Fishing and rental services	14,415			13,775			29,502			27,380
Depreciation and amortization	28,924			28,212			55,738			55,986
General and administrative	43,739			34,137			87,080			69,076
Interest expense	10,030			16,326			18,608			29,678
Loss (gain) on early extinguishment of debt	—			5,481			—			5,881
Loss (gain) on sale of assets	(309		)	(755		)	(2,244		)	(30		)
Interest income	(828		)	(736		)	(2,028		)	(1,160		)
Other, net	953			(5,018		)	472			(4,970		)

Total costs and expenses, net	308,116			278,442			607,645			535,713

Income from continuing operations before income taxes	63,920			16,459			112,348			30,392
Income tax (expense) benefit	(24,338		)	(7,086		)	(42,704		)	(12,654		)

*INCOME FROM CONTINUING OPERATIONS*	39,582			9,373			69,644			17,738

Discontinued operations, net of tax expense of $4,590 for the six months ended June 30, 2005	—			—			—			(3,361		)

*NET INCOME*	$	39,582		$	9,373		$	69,644		$	14,377

*EARNINGS (LOSS) PER SHARE:*
Net income from Continuing Operations
Basic	$	0.30		$	0.07		$	0.53		$	0.14
Diluted	$	0.29		$	0.07		$	0.52		$	0.13

Discontinued Operations
Basic	$	—		$	—		$	—		$	(0.03	)
Diluted	$	—		$	—		$	—		$	(0.03	)

Net Income
Basic	$	0.30		$	0.07		$	0.53		$	0.11
Diluted	$	0.29		$	0.07		$	0.52		$	0.10

*WEIGHED AVERAGE SHARES OUTSTANDING:*
Basic	131,335			130,828			131,337			130,810
Diluted	134,979			132,879			134,752			133,085

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

Key Energy Services, Inc.

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

(In thousands)

(Unaudited)

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
)

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006			2005

*NET INCOME*	$	39,582	$	9,373	$	69,644		$	14,377
*OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:*
Foreign currency translation gain (loss)	176		53		(102		)	129
Deferred gain from cash flow hedges	1,171		—		1,094			—
*COMPREHENSIVE INCOME, NET OF TAX*	$	40,929	$	9,426	$	70,636		$	14,506

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 Cash Flows

(in thousands)

(unaudited)

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

	Six Months Ended June 30,
	2006			2005

*CASH FLOWS FROM OPERATING ACTIVITIES:*

Net income	$	69,644		$	14,377

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

Depreciation and amortization	55,738			55,986
Accretion expense	252			264
Income from equity investment	161			(27		)
Amortization of deferred issuance costs, discount and premium	803			888
Deferred income tax expense	3,888			13,661
Capitalized interest	(1,615		)	(324		)
Gain on sale of assets	(2,244		)	(30		)
Loss on early extinguishment of debt	—			5,881
Stock-based compensation	3,424			976
Amortization of deferred gain on sale-leaseback transactions	(80		)	—

Changes in working capital:

Accounts receivable, net	(29,543		)	(9,943		)
Other current assets	2,247			(1,273		)
Accounts payable, accrued interest and accrued expenses	33,033			15,256

Other assets and liabilities	(17,629		)	(5,392		)

Operating cash flows (used by) provided by discontinued operations	(75		)	13,169

Net cash provided by operating activities	118,004			103,469

*CASH FLOWS FROM INVESTING ACTIVITIES:*

Capital expenditures - Well Servicing	(74,385		)	(36,450		)
Capital expenditures - Pressure Pumping	(18,530		)	(6,216		)
Capital expenditures - Fishing and Rental	(4,755		)	(1,338		)
Capital expenditures - Other	(521		)	(4,227		)
Proceeds from sale of fixed assets	9,651			8,138

Investing cash flows provided by discontinued operations	—			60,477

Net cash (used in) provided by investing activities	(88,540		)	20,384

*CASH FLOWS FROM FINANCING ACTIVITIES:*

Repayments of long-term debt	(2,000		)	—
Repayments on revolving credit facility	—			(48,000		)
Repayments of capital lease obligations	(6,286		)	(5,557		)
Purchase of treasury stock	(1,180		)	—

Net cash used in financing activities	(9,466		)	(53,557		)

Effects of exchange rates on cash	(399		)	669

Net increase in cash and cash equivalents	19,599			70,965
Cash and cash equivalents, beginning of period	94,170			20,425
Cash and cash equivalents, end of period	$	113,769		$	91,390

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

Key Energy Services, Inc.

~~Notes to Consolidated Financial Statements~~NOTES TO CONDENSED CONSOLIDATED UNAUDITED FINANCIAL STATEMENTS

~~(Unaudited)~~

1. ORGANIZATION AND SUMMARY OF ~~SIGNFICANT~~SIGNIFICANT ACCOUNTING POLICIES

The Company

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

Basis of Presentation

The ~~consolidated financial statements~~filing of Key Energy Services, Inc. (the “Company”, or “Key”) and its wholly-owned subsidiaries as of September 30, 2003 and for the three and nine month periods ended September 30, 2003 and 2002 are unaudited. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted in this Quarterly Report on Form 10-Q ~~pursuant~~was delayed due to ~~the rules~~our restatement and ~~regulations of~~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 ~~(the “SEC”~~(“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”). ~~However,~~We did not present our other consolidated financial statements in accordance with GAAP as we were unable to determine with sufficient certainty the appropriate period(s) in 2003 or before in which to record certain write offs and write downs that were identified in our restatement process. Our former registered public accounting firm expressed an unqualified opinion that the 2003 balance sheet fairly presented our financial condition on December 31, 2003 in accordance with GAAP. The firm also audited the other financial statements presented in the 2003 Financial and Informational Report. It opined that the financial statements other than the 2003 balance sheet did not fairly present our financial condition or results of operations or cash flows for the periods covered in accordance with GAAP. Investors should refer to the 2003 Financial and Informational Report for a full description of the restatement and financial reporting process for periods prior to 2004.

The accompanying unaudited condensed consolidated financial statements in this report have been prepared in accordance with the instructions for interim financial reporting prescribed by the SEC. The December 31, 2005 year-end condensed consolidated balance sheet data was derived from audited financial statements but does not include all the disclosures required by GAAP. These interim financial statements should be read together with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2006.

The unaudited condensed consolidated financial statements contained in this report include all material adjustments that, in the opinion of management, ~~these interim financial statements include all the~~are necessary ~~adjustments to fairly present~~for a fair statement of the results of operations for the interim periods ~~presented. These unaudited~~presented herein. The results of operations for the interim periods presented in this report are not

necessarily indicative of the results to be expected for the full year or any other interim period due to fluctuations in demand for our services, timing of maintenance and other expenditures, and other factors.

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

Due to the delay in the filing of this report as discussed above, additional information regarding certain liabilities and uncertainties that existed as of the date of this report has become available, either through additional facts about, or the ultimate settlement or resolution of, the liability or uncertainty. We have taken any additional information that has come to light into account in our estimates and disclosure of any potential liabilities or other contingencies as of the date of this report, in accordance with FASB Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies” (“SFAS 5”). The discussion of our commitments and contingencies (see Note 7) should be read in conjunction with the ~~audited financial statements included~~corresponding disclosures made in ~~the Company’s Transition~~our Annual Report on Form 10-K for the ~~six months~~year ended December 31, 2002. The results of operations for the three and nine month periods ended September 30, 2003 are not necessarily indicative of the results of operations for the full fiscal year ending December 31, 2003.

~~Stock Based Compensation~~

The Company accounts for stock option grants to employees using the recognition and measurement principles of APB Opinion No. 25 (“APB 25”), “Accounting for Stock Issued to Employees” and related interpretations. Under the Company’s stock incentive plan, the price of the stock on the grant date is the same as the amount an employee must pay to exercise the option to acquire the stock. Accordingly, the options have no intrinsic value at grant date, and in accordance with the provisions of APB 25, no compensation cost is recognized in the consolidated statement of operations.

Statement of Financial Accounting Standards No. 123 (“SFAS 123”), “Accounting for Stock-Based Compensation,” sets forth alternative accounting and disclosure requirements for stock-based compensation arrangements. Companies may continue to follow the provisions of APB 25 to measure and recognize employee stock-based compensation; however, SFAS 123 requires disclosure of pro forma net income and earnings per share that would have been reported under the fair value based recognition provisions of SFAS 123. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation:

Three Months Ended
September 30,

Nine Months Ended
September 30,

2003

2002

2003

2002

(thousands, except per share data)

Net income (loss):

As reported

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

$
(15,999
)
Deduct: Total stock-based employee compenstation expense determined under fair value based method for all awards, net of tax

(971
)
(2,497
)
(5,475
)
(8,510
)
Pro forma

$
(2,028
)
$
(8,007
)
$
(2,153
)
$
(24,509
)

Basic earnings per share:

As reported

$
(0.01
)
$
(0.04
)
$
0.03

$
(0.15
)
Pro forma

$
(0.02
)
$
(0.07
)
$
(0.02
)
$
(0.22
)

Diluted earnings per share:

As reported

$
(0.01
)
$
(0.04
)
$
0.03

$
(0.15
)
Pro forma

$
(0.02
)
$
(0.07
)
$
(0.02
)
$
(0.22
)

~~Reclassifications~~

2006.

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

Our remaining contract drilling operations are now reported as part of our Well Servicing segment. We apply the provisions of EITF Issue 04-10, “Determining Whether to Aggregate Operating Segments That Do Not Meet Quantitative Thresholds” (“EITF 04-10”) in our segment reporting in Note 9—“Segment Information.” Our remaining contract drilling operations do not meet the quantitative thresholds as described in Statement of Financial Accounting Standards No. 131, “Disclosures About Segments of an Enterprise and Related Information” (“SFAS 131”), and, under the provisions of EITF 4-10, since the operating segments meet the aggregation criteria we are permitted to combine information about this segment with other similar segments that individually do not meet the quantitative thresholds to produce a reportable segment.

Principles of Consolidation

Within our consolidated financial statements, we include our accounts and the accounts of our majority-owned or controlled subsidiaries. We eliminate intercompany accounts and transactions. We account for our interest in entities for which we do not have significant control or influence under the ~~three~~cost method. When we have an interest in an entity and ~~nine months ended September 30, 2002 to conform to~~can exert significant influence but not control, we account for that interest using the ~~presentation for~~equity method. See Note 5—“Investment in IROC Systems Corp.”

In January 2003, the ~~three~~Financial Accounting Standards Board (“FASB”) issued Interpretation No. 46, “Consolidation of Variable Interest Entities—an Interpretation of ARB No. 51” (“FIN 46”). In December 2003 the FASB issued the updated and ~~nine months ended September 30, 2003. Certain property~~final interpretation of ARB 51 (“FIN 46R”). FIN 46R requires that an equity investor in a variable interest entity have significant equity at risk (generally a minimum of 10%, which is an increase from the 3% required under previous guidance) and equipment of the Company, which may be used in either well servicing or drilling that had been previously classified as drilling has now been reclassified as well servicing along with related operating results. The reclassification was made because thehold 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 entities created or obtained after March 15, 2004. The adoption of FIN 46R did not materially impact our consolidated financial statements.

Revenue Recognition

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

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

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

Ancillary Oilfield Services.

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

2.~~ASSET RETIREMENT OBLIGATIONS – SFAS 143~~Cash and Cash Equivalents

We consider short-term investments with an original maturity of less than three months to be cash equivalents. None of our cash is restricted and we have not entered into any compensating balance arrangements. However, at June 30, 2006, all of our obligations under the Senior Secured Credit Facility (hereinafter defined) were secured by most of our assets, including assets held by our subsidiaries, which includes our cash and cash equivalents. We restrict investment of cash to financial institutions with high credit standing and limit the amount of credit exposure to any one financial institution.

~~On July 1, 2002,~~Property and Equipment

Asset Retirement Obligations. In connection with our well servicing activities, we operate a number of Salt Water Disposal (“SWD”) facilities. Our operations involve the ~~Company adopted~~transportation, handling and disposal of fluids in our SWD facilities that have been determined to be harmful to the environment. SWD facilities used in connection with our fluid hauling operations are subject to future costs associated with the abandonment of these properties. As a result, we have incurred costs associated with the proper storage and disposal of these materials. In accordance with Statement of Financial Accounting Standards No. 143, ~~Accounting~~“Accounting for Asset Retirement ~~Obligations~~Obligations” (“SFAS 143”)~~. The new standard requires the Company to~~, we recognize a liability for the ~~present~~fair value of all legal obligations associated with the retirement of tangible long-lived assets and capitalize anand equal amount as a cost of the ~~asset depreciating~~asset. We depreciate the additional cost over the estimated useful life of the ~~asset. At September 30, 2003 and December 31, 2002,~~assets. Significant judgment is involved in estimating future cash flows associated with such obligations, as well as the ultimate timing of those cash flows. If our estimates of the amount or timing of the cash flows change, such changes may have a material impact on our results of operations.

Adoption of SFAS 143 was required for all companies with fiscal years beginning after June 15, 2002. Amortization of the assets associated with the asset retirement ~~obligation~~obligations was ~~approximately $3,570,000~~$0.1 million and ~~$9,231,000, respectively, related~~$0.1 million for the quarters ended June 30, 2006, and 2005, respectively. Amortization of the assets associated with the asset retirement obligations was $0.2 million and $0.2 million for the six months ended June 30, 2006, and 2005, respectively.

Asset and Investment Impairments. We apply Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”) in reviewing our long-lived assets and investments for possible impairment. This statement requires that long-lived assets held and used by us, including certain identifiable intangibles, be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. For purposes of applying this statement, we group our long-lived assets on a division-by-division basis and compare the estimated future cash flows of each division to ~~expected abandonment costs~~the division’s net carrying value. The division level represents the lowest level for which identifiable cash flows are available. We would record an impairment charge, reducing the division’s net carrying value to an estimated fair value, if its estimated future cash flows were less than the division’s net carrying value. “Trigger events,” as defined in SFAS 144, that cause us to evaluate our fixed assets for recoverability and possible impairment may include market conditions, such as adverse changes in the prices of ~~its~~ oil and natural gas, ~~producing properties~~which could reduce the fair value of certain of our property and ~~salt water disposal wells.~~equipment. The ~~decrease in~~development of future cash flows and the ~~balance from~~determination of fair value for a division involves significant judgment and estimates. As of June 30, 2006 and December 31, ~~2002~~2005, no trigger events had been identified by management.

Goodwill and Other Intangible Assets

Goodwill results from business acquisitions and represents the excess of ~~approximately $5,661,000 is primarily due to~~acquisition costs over the ~~sale~~fair value of the ~~Company’s oil~~net assets acquired. We account for goodwill and natural gas properties (see Note 12) and, to a lesser extent, the plugging and abandonment of saltwater disposal wells, partially offset by the acquisition of saltwater disposals wells and the accretion of the discounted liability.

3.~~GOODWILL AND OTHER INTANGIBLE ASSETS – SFAS 142~~

~~The Company follows~~other intangible assets under the provisions of Statement of Financial Accounting Standards No. 142, ~~Goodwill~~“Goodwill and Other Intangible ~~Assets~~Assets” (“SFAS 142”). SFAS 142 eliminates ~~the~~ amortization for goodwill and other intangible assets with indefinite lives. Intangible assets with lives restricted by contractual, legal, or other means will continue to be amortized over their expected useful lives. Goodwill and other intangible assets ~~no longer~~not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be ~~impaired~~impaired. SFAS 142 requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. If impairment is indicated, then the fair value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities (including any unrecognized intangible assets) as ~~set forth~~if the reporting unit had been acquired in ~~SFAS 142.~~a business combination. The ~~Company completed~~amount of impairment for goodwill is measured as the excess of its carrying value over its fair value. We conduct annual impairment assessments, the most recent ~~assessment of goodwill impairment for each of its reporting units~~affecting this report as of ~~June 30, 2003.~~December 31, 2005. The ~~assessment~~assessments did not result in an indication of goodwill ~~impairment and as of September 30, 2003 management believes no additional assessment is necessary.~~

impairment.

Intangible assets subject to amortization under SFAS 142 consist of noncompete agreements and ~~patents.~~patents and trademarks. Amortization expense for ~~the~~ noncompete agreements is calculated using the straight-line method over the period of the agreement, ranging from three to seven years. The cost and accumulated amortization are retired when the noncompete agreement is fully amortized and no longer enforceable. Amortization expense for patents and trademarks is calculated using the straight-line method over the useful life of the patent or trademark, ranging from five to seven years.

~~The gross carrying amount~~ Amortization of noncompete agreements ~~subject to amortization totaled approximately $14,332,000~~for the quarters ended June 30, 2006 and ~~$18,669,000 at September 30, 2003~~2005 was $0.6 million and ~~December 31, 2002, respectively. Accumulated amortization related to these intangible assets totaled approximately $5,068,000 and $7,511,000 at September 30, 2003 and December 31, 2002,~~$0.7 million, respectively. Amortization ~~expense~~of patents and trademarks for the ~~three~~quarters ended June 30, 2006 and 2005 was $0.1 million and $0.1 million, respectively. Amortization of noncompete agreements for the six months ended ~~September~~June 30, ~~2003~~2006 and ~~2002~~2005 was ~~approximately $982,000~~$1.2 million and ~~$1,260,000,~~$1.5 million, respectively. Amortization ~~expense~~of patents and trademarks for the ~~nine~~six months ended ~~September~~June 30, ~~2003~~2006 and ~~2002~~2005 was ~~approximately $3,114,000~~$0.3 million and ~~$2,404,000,~~$0.2 million, respectively. ~~Amortization expense for~~During the ~~next five succeeding years is estimated to be approximately $3,329,000, $2,613,000, $2,026,000, $1,180,000 and $104,000.~~

The gross carrying amount of patents subject to amortization totaled approximately $2,469,000 and $2,380,000 at September 30, 2003 and December 31, 2002, respectively. Accumulated amortization related to these intangible assets totaled approximately $423,000 and $160,000 as of September 30, 2003 and December 31, 2002, respectively. The Company began acquiring patents on July 16, 2002. Amortization expense for the threesix months ended ~~September~~June 30, ~~2003~~2006, the Company capitalized approximately $0.2 million of costs associated with patents and ~~2002 was approximately $88,000 and $72,000, respectively. Amortization expense for~~trademarks. No costs associated with noncompete agreements were capitalized during the ~~nine~~six months ended ~~September~~June 30, ~~2003~~2006.

Derivative Instruments and 2002 was approximately $263,000 and $72,000, respectively. Amortization expense for the next five succeeding years is estimated to be approximately $401,000, $401,000, $401,000, $373,000 and $290,000.

Hedging Activities

The Company ~~has identified its~~applies Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”) as amended by Statement of Financial Accounting Standards No. 137, No. 138 and No. 149 (“SFAS 137,” “SFAS 138,” and “SFAS 149,” respectively) in accounting for derivative instruments. SFAS 133 establishes accounting and reporting ~~units~~standards for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. It requires the recognition of all derivative instruments as assets and liabilities on the balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge, and if so, the type of hedge. For derivatives designated as cash flow

hedges, the effective portion of the change in the fair value of the hedging instrument is recognized in other comprehensive income until the hedged item is recognized in earnings. Any ineffective portion of changes in the fair value of the hedging instrument is recognized currently in earnings.

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

In March 2006, under the terms of our Senior Secured Credit Facility, the Company was required to mitigate the risk of changes in future cash flows posed by changes in interest rates associated with the variable interest-rate term loan portion of our Senior Secured Credit Facility. We entered into two interest rate swap arrangements in order to offset this risk. The swaps are classified as derivative instruments and were designated at inception as cash flow hedges. Management believes that these instruments were highly effective at inception to offset changes in the future cash flows of the underlying liabilities and will continue to be highly effective throughout the life of the hedge. See Note 4—“Derivative Financial Instruments” for further discussion.

Guarantees

In November 2002, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Include Indirect Guarantees of Indebtedness of Others” (“FIN 45”). As required by FIN 45, we adopted the disclosure requirements on December 31, 2002. On January 1, 2003, we adopted the initial recognition and measurement provisions for guarantees issued or modified after December 31, 2002. In November 2005, the FASB issued FASB Staff Position No. 45-3, “Application of FASB Interpretation No. 45 to Minimum Revenue Guarantees Granted to Business or Its Owners” (“FSP FIN No. 45-3”). It served as an amendment to FIN 45 by adding minimum revenue guarantees to the list of examples of contracts to which FIN 45 applies. Under FSP FIN No. 45-3, a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. FSP FIN No. 45-3 is effective for new minimum revenue guarantees issued or modified on or after January 1, 2006. The adoption of FIN 45 and FSP FIN No. 45-3 did not have a material impact on our consolidated financial statements.

Earnings Per Share

We present earnings per share information in accordance with SFAS 142 to be well servicing and contract drilling. Net goodwill allocated to such reporting units at September 30, 2003 was approximately $332,026,000 and $14,309,000, respectively, and at December 31, 2002 was approximately $307,987,000 and $14,283,000, respectively. The change in carrying amountthe provisions of goodwill for the three and nine months ended September 30, 2003 was approximately $1,671,000 and $24,065,000, respectively, and relates principally to the allocation of goodwill from the acquisition of Q Services, Inc. (See Note 5) and the preliminary allocation of goodwill from other small acquisitions, and foreign currency translation adjustments for the Company’s Argentina operations.

4.~~EARNINGS PER SHARE~~

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002			Three Months Ended June 30, 2006		Three Months Ended June 30, 2005		Six Months Ended June 30, 2006		Six Months Ended June 30, 2005
	(thousands, except per share data)												(in 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													$	39,582	$	9,373	69,644		$	17,738
Discontinued operations, net of tax	(7,396		)	(310		)	(7,866		)	(650		)	—		—		—		(3,361		)
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	)
Net income													$	39,582	$	9,373	$	69,644	$	14,377

Denominator
Weighted average common shares outstanding	129,744			122,475			129,095			113,668
Weighted average shares outstanding													131,335		130,828		131,337		130,810

*Basic EPS:*
Income (loss) before discontinued operations	$	0.05		$	(0.02	)	$	0.09		$	(0.11	)
Income from continuing operations													$	0.30	$	0.07	$	0.53	$	0.14
Discontinued operations, net of tax	(0.06		)	—			(0.06		)	(0.01		)	—		—		—		(0.03		)
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	)
Net income													$	0.30	$	0.07	$	0.53	$	0.11

*Diluted EPS Computation:*
Numerator
Income (loss) before discontinued operations	$	6,339		$	(2,327	)	$	11,188		$	(12,476	)
Income from continuing operations													$	39,582	$	9,373	$	69,644	$	17,738
Discontinued operations, net of tax	(7,396		)	(310		)	(7,866		)	(650		)	—		—		—		(3,361		)
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	)
Net income													$	39,582	$	9,373	$	69,644	$	14,377

Denominator
Weighted average common shares outstanding	129,744			122,475			129,095			113,668
Weighted average shares outstanding													131,335		130,828		131,337		130,810
Stock options													3,072		1,581		2,853		1,796
Warrants	427			—			438			—			572		470		562		479
Stock options	1,262			—			1,454			—
	131,433			122,475			130,987			113,668			134,979		132,879		134,752		133,085

*Diluted EPS:*
Income (loss) before discontinued operations	$	0.05		$	(0.02	)	$	0.09		$	(0.11	)
Income from continuing operations													$	0.29	$	0.07	$	0.52	$	0.13
Discontinued operations, net of tax	(0.06		)	—			(0.06		)	(0.01		)	—		—		—		(0.03		)
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	)
Net income													$	0.29	$	0.07	$	0.52	$	0.10

The diluted earnings per share calculation for the ~~three~~quarters ended June 30, 2006 and ~~nine month periods ended September 30, 2003~~2005 excludes ~~the effect of~~ the potential exercise of ~~1,878,000 of the Company’s~~zero and 672,500 stock options, ~~and the potential exercise of the Company’s convertible debt~~respectively, because the effects of such ~~instruments~~exercises on earnings per share in those years would be anti-dilutive. The diluted earnings per share calculation for the ~~three~~six months ended June 30, 2006 and ~~nine month periods ended September 30, 2002~~2005 excludes ~~the effect of~~ the potential exercise of ~~the Company’s convertible debt, outstanding warrants~~zero and 501,250 stock options, respectively, because the effects of such ~~instruments~~exercises on earnings per share in those years would be anti-dilutive.

5.~~Q SERVICES ACQUISITION~~Stock-Based Compensation

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

~~On July 19, 2002,~~SFAS 123 sets forth alternative accounting and disclosure requirements for stock-based compensation arrangements. Companies were permitted to continue following the ~~Company acquired Q Services, Inc. (“QSI”) pursuant~~provisions of APB 25 to ~~an Agreement~~measure and ~~Plan~~recognize employee stock-based compensation prior to January 1, 2006; however, SFAS 123 requires disclosure of ~~Merger dated May 13, 2002, as amended, by~~pro forma net income and ~~among~~earnings per share that would have been reported under the ~~Company, Key Merger Sub, Inc.~~fair value recognition provisions of SFAS 123. The following table illustrates the effect on net income and ~~QSI.~~earnings per share if we had applied the fair value recognition principles of SFAS 123 to stock-based employee compensation in 2005. As ~~consideration~~noted above, while we followed APB 25 to account for stock-based compensation during 2005, the stock-based compensation expense

included in net income or loss in the following table represents the compensation expense for the ~~acquisition,~~875,180 options, net of forfeitures, that were granted at strike prices ranging from $0.10 to $2.53 below the ~~Company issued approximately 17.1 million~~market price of our common stock on the date of grant. During the years in which we applied APB 25, we elected to amortize any compensation cost on a straight-line basis over the vesting period of the award, in accordance with FASB Interpretation No. 28, “Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans, an Interpretation of APB Opinions No. 15 and 25” (“FIN 28”). After the adoption of SFAS 123(R), we elected to amortize compensation cost associated with the fair value of equity-based awards ratably over the vesting period of the award.

	Three Months Ended June 30, 2005			Six Months Ended June 30, 2005
	(in thousands, except per share amounts)
Net income

As reported	$	9,373		$	14,377

Add: stock-based employee compensation expense included in reported net income (loss), net of related tax effects	434			411

Deduct: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects	(677		)	(896		)

Pro forma	$	9,130		$	13,892

Basic earnings per share:
As reported	$	0.07		$	0.11
Pro forma	$	0.07		$	0.11

Diluted earnings per share:
As reported	$	0.07		$	0.10
Pro forma	$	0.07		$	0.10

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

In addition to the stock option grants discussed above, beginning in 2005 we began making grants of shares and restricted shares of ~~its~~ common stock to ~~the QSI shareholders~~certain of our employees and ~~paid approximately $94.2 million in cash at the closing~~non-employee directors. These shares have vesting periods ranging from zero to ~~retire debt and preferred stock of QSI and to satisfy certain other obligations of QSI. In addition to assuming the positive working capital of QSI,~~three years. For shares with immediate vesting, the Company ~~incurred other direct acquisition costs and assumed certain other liabilities of QSI, resulting~~recognized currently in earnings expense an amount equal to the ~~Company recording an aggregate purchase price of approximately $251 million. The~~intrinsic value of the shares ~~issued was based~~ on the ~~closing price~~date of grant. For restricted shares that did not immediately vest, the compensation cost equal to the intrinsic value of the ~~Company’s common stock on~~grant, net of actual and estimated forfeitures, was recognized in earnings ratably over the ~~closing date~~vesting period of ~~$8.75 per share. The results of QSI’s operations have been included in~~ the ~~consolidated financial statements since the closing date. Prior~~grant. In 2006, subject to the ~~acquisition, QSI was a privately held corporation conducting field production, pressure pumping, and other service operations in Louisiana, New Mexico, Oklahoma, Texas, and the Gulf~~provisions of ~~Mexico. The Company and QSI operated in adjacent and or overlapping locations and~~SFAS 123(R), the Company ~~expects~~recognized expense in earnings equal to ~~realize future cost savings and synergies in connection with the merger.~~

~~The following table summarizes~~ the fair value of the ~~assets acquired~~shares vesting during the period, net of actual and ~~liabilities assumed at the date of acquisition:~~estimated forfeitures.

Foreign Currency Gains and Losses

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

The ~~$3,242,000~~local currency is the functional currency for our foreign operations in Argentina and our former Canadian operations. The U.S. dollar is the functional currency for our former operations in Egypt. The cumulative translation gains and losses, resulting from translating each foreign subsidiary’s financial statements from the functional currency to U.S. dollars, are included as a separate component of ~~intangible~~stockholders’ equity in other comprehensive income until a partial or complete sale or liquidation of our net investment in the foreign entity.

Accounting Principles Not Yet Adopted in This Report

SFAS 157. In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 establishes a framework for measuring fair value and requires expanded disclosure about the information used to measure fair value. The statement applies whenever other statements require or permit assets consists of noncompete agreements which have a weighted-average useful life of approximately two years. The $136,640,000 of goodwill was allocated to the well servicing reporting segment. Of that amount, $11,645,000 is expectedor liabilities to be ~~deductible~~measured at fair value. SFAS 157 does not expand the use of fair value accounting in any new circumstances and is effective for ~~income taxes.~~

~~During the three months ended March 31, 2003,~~ the Company ~~recorded~~ for the year ended December 31, 2008 and for interim periods included in that year, with early adoption encouraged. The Company is evaluating the effect of adoption of SFAS 157 on its financial position, results of operations and cash flows.

SFAS 158. In September 2006, the FASB issued Statement of Financial Accounting Standards No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans—an ~~adjustment~~amendment of ~~approximately $24.5 million to reduce~~FASB Statements No. 87, 88, 106, and 123(R)” (“SFAS 158”). SFAS 158 requires an entity that is the ~~cost allocated to certain equipment in~~sponsor of a plan within the ~~preliminary fair value allocation. The adjustment was based on an independent third party appraisal~~scope of the ~~estimated fair value of the equipment~~statement to (a) recognize on its balance sheet as an asset a plan’s over-funded status or as a liability such plan’s under-funded status; (b) measure a plan’s assets and obligations as of the ~~July 2002 acquisition date.~~

~~The following unaudited pro forma results of operations have been prepared as though QSI had been acquired on January 1, 2002. Pro forma amounts are not necessarily indicative~~end of the ~~results that may be reported~~entity’s fiscal year; and (c) recognize changes in the ~~future.~~

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
)

6.~~SENIOR NOTES OFFERING~~

~~On May 14, 2003,~~funded status of its plans in the year in which changes occur through adjustments to other comprehensive income. Adoption of the provisions of SFAS 158 is required for public companies for the first fiscal year ending after December 15, 2006. Because the Company ~~completed~~is not a ~~public offering~~sponsor of ~~$150,000,000~~a defined postretirement benefit plan as defined by SFAS 158, the adoption of 6³/8% Senior Notes due 2013. The cash proceeds from the debt offering, net of fees and expenses, were used to repay the balance of the revolving loan facility then outstanding under the Company’s senior credit facility, with the remainder to be used for general corporate purposes, including further debt retirement.

7.~~COMMITMENTS AND CONTINGENCIES~~

~~Various suits and claims arising in the ordinary course of business are pending against the Company. Management does~~this standard will not ~~believe that the disposition of any of these items will result in~~have a material ~~adverse~~ impact toon the ~~consolidated~~Company’s financial position, results of operations, or cash ~~flows of the Company.~~

flows.

8.2. ~~SUPPLEMENTARY INFORMATION TO THE CONSOLIDATED STATEMENT OF CASH FLOWS~~DISCONTINUED OPERATIONS

~~Cash Payments.~~ ~~The Company paid interest~~On January 15, 2005, we sold the majority of approximately $39,824,000 and $38,422,000 for the nine months ended September 30, 2003 and 2002, respectively, net of capitalized interest of approximately $2,154,000 and $1,465,000 for the nine months ended September 30, 2003 and 2002, respectively. The Company made income tax payments of approximately $992,000 and $246,000 for the nine months ended September 30, 2003 and 2002, respectively.

~~Non-Cash Investing and Financing Activities.~~ The fair value of common stock issued in purchase transactions, other than for the acquisition of QSI, was approximately $11,404,000 and $23,238,000 for the nine months ended September 30, 2003 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.

9.~~BUSINESS SEGMENT INFORMATION~~

~~The Company’s reportable business segments are well servicing and contract drilling.~~

~~Well Servicing~~: The Company’s operations provide well servicing (ongoing maintenance of existing oil and natural gas wells), workover (major repairs or modifications necessary to optimize the level of production from existing oil and natural gas wells) and production services (fluid hauling and fluid storage tank rental, fishing and rental tool services and pressure pumping services).

~~Contract Drilling~~~~: The Company provides~~our contract drilling ~~services~~operations to Patterson-UTI Energy, Inc. for ~~major and independent oil companies onshore the continental United States, Argentina and Ontario, Canada.~~

The Company’s management evaluates the performance of its operating segments based on net income and operating profits (revenues less direct operating expenses). 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) 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 (which consists of Argentina, Canada and Egypt) for the three months ended September 30, 2003 and 2002 were approximately $12.7 million and $6.1 million, respectively. Operating profits for the Company’s foreign operations for the three months ended September 30, 2003 and 2002 were approximately $5.4 million and $1.4 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 and 2002 were approximately $34.1 million and $15.3 million, respectively. Operating profits for the Company’s foreign operations for the nine months ended September 30, 2003 and 2002 were approximately $14.2 million and $3.1 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 nine months ended September 30, 2003 and 2002 were approximately $2.6 million and $6.1 million, respectively.

~~10.~~~~CONDENSED CONSOLIDATING FINANCIAL INFORMATION~~

The Company’s senior notes are guaranteed by substantially all of the Company’s 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.

~~The 6~~³/8~~% 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%~~

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

~~11.~~~~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~~$62.0 million in cash. ~~The Company~~We received net ~~cash~~ proceeds of approximately ~~$7.2~~$60.5 million in cash after ~~repaying~~paying all costs related to closing the ~~Company’s volumetric production payment, unwinding related hedge arrangements and other related costs.~~sale. As a result of the sale, ~~the Company will treat its oil and natural gas production business~~this operation, which was previously reported as part of our contract drilling segment, has been presented as a discontinued operation for all ~~periods and has~~periods. We recorded an after-tax

~~charge to~~ loss from discontinued operations of ~~approximately $7.4~~$3.4 million, or ~~$0.06~~$0.03 per diluted share, ~~during~~for the ~~three~~six months ended ~~September~~June 30, ~~2003.~~

2005.

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
)

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
	(in thousands)				(in thousands)

Revenues	$	—	$	—	$	—	$	3,361
Costs and expenses	—		—		—		2,132
Income before income taxes	—		—		—		1,229
Income tax expense	—		—		—		(4,590		)
Loss from discontinued operations	$	—	$	—	$	—	$	(3,361	)

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

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

	June 30, 2006			December 31, 2005
	(in thousands)

Current assets	621			658
Current liabilities	(180		)	(292		)
Net assets of discontinued operations	$	441		$	366

~~13.~~3. ~~SUBSEQUENT EVENT – NEW SENIOR CREDIT FACILITY~~INCOME TAXES

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

	Six Months Ended June 30,
	2006		2005

Income tax computed at statutory rate	35.0	%	35.0	%
State taxes	1.3	%	2.4	%
Meals and entertainment	0.8	%	2.1	%
Executive and share-based compensation	1.2	%	0.6	%
Foreign rate differential	—	%	1.1	%
Change in valuation allowance	—	%	—	%
Other	(0.4	)%	0.4	%
Effective income tax rate	37.9	%	41.6	%

4.DERIVATIVE FINANCIAL INSTRUMENTS

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

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

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

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

As of June 30, 2006, we recorded $0.6 million in current assets and $1.9 million in long-term assets in our Consolidated Balance Sheets, based on the fair value of our derivative instruments on that date. During the six months ended June 30, 2006, amounts recorded related to the ineffective portion of our cash flow hedges were less than $0.1 million. No amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows in any of the periods. During the six months ended June 30, 2006, no amounts were reclassified to earnings in connection with forecasted transactions whose occurrence was no longer considered probable. During the next twelve months, the Company anticipates that the amount of Accumulated Other Comprehensive Loss that will be reclassified to earnings upon settlement of hedge transactions will be less than $1 million.

5.INVESTMENT IN IROC SYSTEMS CORP.

On July 22, 2004, we entered into an agreement with IROC Systems Corp. (“IROC”), an Alberta-based oilfield services company, to sell IROC ten remanufactured Skytop well service rigs, along with supporting equipment and inventory. We began delivering these rigs in the fall of 2004, and completed delivery in the second quarter of 2005. The purchase price for the rigs was US $7.0 million, which was paid by way of the issuance of approximately 8.2 million shares of IROC’s common stock. During 2004 and 2005, we recognized a loss of $0.1 million, which represents the difference between the fair market value of the IROC shares we received on the delivery dates and the carrying values of the rigs that were delivered. In 2005, we delivered an additional four rigs, and we recognized a gain of $1.9 million upon delivery, which represents the difference between the value of the IROC shares we received on the delivery dates and the carrying value of the rigs that we delivered.

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

As of June 30, 2006, we own 8,734,469 shares of IROC common stock, which represents approximately 23.1% of IROC’s outstanding common stock on that date. IROC shares trade on the Toronto Venture Stock Exchange and had a closing price of $2.85 CDN per share on June 30, 2006. Pursuant to the terms of the agreement with IROC, Mr. William Austin, our Chief Financial Officer, and Mr. Newton W. Wilson III, our General Counsel, were appointed to the board of directors of IROC.

We have significant influence over the operations of IROC, but do not control it. We account for our investment in IROC using the equity method. The value of our investment is recorded in our Consolidated Balance Sheets as a component of other non-current assets. The pro-rata share of IROC’s earnings and losses to which we

are entitled are recorded in our Consolidated Statements of Operations as a component of other income and expense, with an offsetting increase or decrease to the value of our investment, as appropriate. Any earnings distributed back to us from IROC in the form of dividends would result in a decrease in the value of our equity investment.

Our pro-rata share of the losses of IROC for the quarters ended June 30, 2006 and 2005 was $0.7 million and $0.3 million, respectively. We recorded $1.1 million and $0.1 million, respectively, of equity income related to our investment in IROC for the six months ended June 30, 2006 and 2005. During those time periods, no earnings were distributed back to us by IROC in the form of dividends. The value of our investment in IROC totaled $10.5 million and $10.3 million as of June 30, 2006 and December 31, 2005, respectively.

6.LONG-TERM DEBT

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

	June 30, 2006		December 31, 2005
	(in thousands)

Senior Secured Credit Facility Term Loans	$	398,000	$	400,000
Capital Leases	27,214		23,420
	425,214		423,420
Less current portion	13,616		12,639
Total long-term debt	$	411,598	$	410,781

Senior Secured Credit Facility

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

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

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

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

The Senior Secured Credit Facility also requires that we maintain a consolidated interest coverage ratio (defined generally as the ratio of consolidated EBITDA to consolidated interest expense) as of the last day of any fiscal quarter, beginning with the fourth fiscal quarter of 2005, of not less than 3.0 to 1.0. Upon the occurrence of

certain events of default, such as payment default, our obligations under the Senior Secured Credit Facility may be accelerated.

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

First Amendment to Senior Secured Credit Facility

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

As of June 30, 2006, the Company had no borrowings under the revolving credit facility of the Senior Secured Credit Facility and had $398.0 million borrowed at three-month Eurodollar rates, plus a margin of 3.75%. As described above, the Company has interest rate swaps that hedge a portion of the interest rate expense on the term loan.

Prior Senior Credit Facility

On November 10, 2003, ~~the Company~~we entered into a Fourth Amended and Restated Credit Agreement (the ~~“New~~“Prior Senior Credit Facility”). The ~~New~~Prior Senior Credit Facility ~~consists~~consisted of a ~~$175~~$175.0 million revolving loan facility with the entire ~~revolving credit~~ facility available for letters of credit. ~~The Company has~~We previously had the right, subject to certain conditions, to increase the total commitment under the ~~New~~Prior Senior Credit Facility from ~~$175~~$175.0 million to up to ~~$225~~$225.0 million if ~~it is~~we were able to obtain additional lending commitments. The revolving loan commitments ~~will~~were scheduled to terminate on November 10, 2007, and all revolving loans ~~must~~would have been required to be paid on or before that date. The revolving loans ~~bear~~bore interest based upon, at ~~the Company’s~~our option, the agent’s base rate for loans or the agent’s ~~reserve adjusted~~reserve-adjusted LIBOR rate for loans, plus, in either case, a margin which ~~will~~would fluctuate based upon ~~the Company’s~~our consolidated total leverage ratio and, in either case, according to the pricing grid set forth in the ~~New~~Prior Senior Credit Facility.

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

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

~~NOTE REGARDING FORWARD – LOOKING STATEMENTS~~

~~The statements in this document that relate~~Our failure to ~~matters that are not historical facts are “forward-looking statements” within~~file our 2003 Annual Report on Form 10-K on a timely basis violated covenants under the ~~meaning of Section 27A~~Prior Senior Credit Facility. Between March 31, 2004 and July 29, 2005, we amended the terms 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 should be read in conjunction with the 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 of operations for the three and nine months ended September 30, 2003 reflect the impact of continued modest improvement in industry conditions resulting from continued strength in oil and natural gas prices.

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

The Company’s revenue for the three months ended September 30, 2003 increased $42,966,000, or 21%, to $243,382,000 from $200,416,000 for the three months ended September 30, 2002. For the three 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 for the three months ended September 30, 2002. The increase in revenues and net income from continuing operations is principally due to increasing levels of activity. Total rig hours for the three months ended September 30, 2003 increased approximately 12% compared to total rig hours for the three months ended September 30, 2002. Total trucking hours for the three months ended September 30, 2003 increased approximately 18% compared to total trucking hours for the three months ended September 30, 2002 principally due to improved activity levels.

~~Operating Revenues~~

~~Well Servicing.~~ Well servicing revenues for the three months ended September 30, 2003 increased $38,284,000, or 21%, to $224,251,000 from $185,967,000 for the three months ended September 30, 2002. The increase in revenues was primarily due 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 for the three months ended September 30, 2003 increased approximately 11% compared to total well servicing rig hours for the three months ended September 30, 2002. Composite well servicing rig rates increased by approximately 4% for the three months ended September 30, 2003 compared to composite well servicing rig rates for the three months ended September 30, 2002. Total trucking hours for the three months ended September 30, 2003 increased approximately 18% compared to total trucking hours for the three months ended September 30, 2002 and composite truck rates for the three months ended September 30, 2003 increased by approximately 4% compared to composite truck rates for the three months ended September 30, 2002.

~~Contract Drilling.~~ Contract drilling revenues for the three months ended September 30, 2003 increased $4,420,000, or 31%, to $18,819,000 from $14,399,000 for the three months ended September 30, 2002. The increase in revenues was primarily due 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 for the three months ended September 30, 2003 increased by approximately 24% compared to total contract drilling rig hours for the three months ended September 30, 2002, while composite contract drilling rig rates for the three

~~months ended September 30, 2003 increased by approximately 5% compared to composite contract drilling rig rates for the three months ended September 30, 2002.~~

~~Operating Expenses~~

~~Well Servicing.~~ Well servicing expenses for the three months ended September 30, 2003 increased $22,935,000, or 17%, to $154,565,000 from $131,630,000 for the three months ended September 30, 2002. 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 the three months ended September 30, 2002 to 69% for the three months ended September 30, 2003.

~~Contract Drilling.~~ Contract drilling expenses for the three months ended September 30, 2003 increased $3,159,000, or 30%, to $13,676,000 from $10,517,000 for the three 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 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 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 expenses as a percentage 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%, to $695,130,000 from $537,036,000 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 $12,476,000 for the nine months ended September 30, 2002. The increase in revenues and increase in net income from continuing operations is principally due to increasing levels of activity and the acquisition of QSI. Total rig hours for the nine months ended September 30, 2003 increased approximately 10% compared to total rig hours for the nine months ended September 30, 2002. Total trucking hours for the nine months ended September 30, 2003 increased approximately 38% compared to total trucking hours for the nine months ended September 30, 2002, principally due to the acquisition of QSI and improved activity levels.

~~Operating Revenues~~

~~Well Servicing.~~ Well servicing revenues for the nine months ended September 30, 2003 increased $148,927,000, or 30%, to $643,379,000 from $494,452,000 for the nine months ended September 30, 2002. The increase in revenues was primarily due to an increase in activity and the acquisition 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 hours for the nine months ended September 30, 2003 increased approximately 9% compared to total well servicing rig hours for the nine months ended September 30, 2002. Composite well servicing rig rates decreased by approximately 2% 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, 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’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.

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

~~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 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.

~~Cash Flows~~

The Company’s net cash provided by operating activities for the nine months ended September 30, 2003 decreased $10,135,000 to $72,907,000 from $83,042,000 for the nine months ended September 30, 2002. The decrease in 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 to $47,841,000 from $172,670,000 for the nine months ended September 30, 2002. The decrease in 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 to $55,542,000 from $86,950,000 for the nine months ended September 30, 2002. The decrease was a result of the Company using a portion of the proceeds of the 6³/8~~% Senior Notes offering to repay its indebtedness under the~~ Senior Credit Facility six times to waive the covenants and ~~to repurchase approximately $30,800,000~~extend the due date for the 2003 report and other filings. We paid a total of ~~its outstanding 5% Convertible Subordinated Notes~~$1.1 million and $1.3 million in fees during the ~~nine months~~years ended ~~September 30, 2003 as compared~~December 31, 2005 and 2004, respectively, related to ~~a net increase of borrowings~~the various amendments to the Prior Senior Credit Facility. The final due date under the ~~revolver and an issuance of $100,000,000 of its 8~~³/8~~% 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~~

~~On November 10, 2003, the Company entered into a Fourth Amended and Restated Credit Agreement (the “New Senior Credit Facility”). The New~~Prior Senior Credit Facility ~~consists~~for the filing of ~~a $175 million revolving loan facility with~~our Annual Report on Form 10-K for 2004 and the ~~entire revolving credit facility available~~Quarterly Reports on Form 10-Q for ~~letters~~the first three quarters of ~~credit.~~2004 was October 31, 2005. The ~~Company has~~last amendment also extended the ~~right, subject~~date by which the Quarterly Reports on Form 10-Q for the first quarter and second quarter of 2005 had to ~~certain conditions,~~be filed to ~~increase~~December 31, 2005. On July 29, 2005, we entered into the ~~total commitment under the New~~ Senior Secured 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, atwhich replaced 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 NewPrior 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.

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%6.375% Senior Notes

On May 14, 2003, ~~the Company~~we completed a public offering of ~~$150,000,000~~$150.0 million of 6³/8%6.375% Senior Notes due May 1, 2013 (the “6³/8%“6.375% 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,~~our then-existing credit facility, with the remainder ~~to be~~being used for general corporate ~~purposes, including further debt retirement.~~purposes. The 6³/8%6.375% Senior Notes ~~are~~were senior unsecured obligations and ~~are~~were fully and unconditionally guaranteed by substantially all of ~~the Company’s~~our subsidiaries. The 6³/8%6.375% Senior Notes ~~are~~were effectively subordinated to Key’s secured indebtedness, which ~~includes~~included borrowings under ~~the~~our Prior 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%The 6.375% Senior Notes ~~upon not less than 30~~were repaid on October 5, 2005. Proceeds from the Senior Secured Credit Facility and ~~not more than 60 days prior notice, at~~cash on hand were used to repay 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.~~

6.375% Notes.

8³/8%8.375% Senior Notes

On March 6, 2001, ~~the Company~~we completed a private placement of ~~$175,000,000~~$175.0 million of 8³/8%8.375% Senior Notes due March 1, 2008 (the “8³/8%“8.375% Senior Notes,” together with the 6.375% Senior Notes, the “Senior Notes”). The net cash proceeds from the private placement were used to repay all of the remaining balance of ~~the original~~prior term loans ~~under the Company’s then outstanding senior credit facility (the “Prior Senior Credit Facility”)~~ and a portion of the revolving ~~loan facility~~loans then outstanding under ~~the Prior Senior Credit Facility then outstanding.~~our then-existing credit facility. On March 1, 2002, ~~the Company~~we completed a public offering of an additional ~~$100,000,000~~$100.0 million of 8³/8%8.375% Senior ~~Notes due 2008.~~Notes. The net cash proceeds from the public offering were used to repay ~~all of~~ the ~~remaining~~then-outstanding balance of the revolving loan facility under ~~the Prior Senior Credit Facility.~~our credit facility. The 8³/8%8.375% Senior Notes ~~are~~were senior unsecured ~~obligations and are fully and unconditionally guaranteed by substantially all of the Company’s subsidiaries.~~obligations. The 8³/8%8.375% Senior Notes ~~are~~were effectively subordinated to Key’s secured indebtedness which ~~includes~~included borrowings under ~~the~~our Prior Senior Credit Facility.

~~On and after March 1, 2005, the Company may redeem some or~~We redeemed 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~~$275.0 million outstanding principal amount of the 8.375% Notes on November 8,³/ 2005. Proceeds from the Senior Secured Credit Facility and cash on hand were used to repay the 8.375% Notes.

Consents to Amend to Extend the Reporting Requirements Under the Senior Note Indentures8%

Our failure to file our 2003 Annual Report on Form 10-K with the SEC and deliver it to the trustee under the Senior Note indentures on or before March 30, 2004 was a default under each of the indentures for the Senior Notes. During 2004 and 2005, we amended the terms of each of the Senior Note indentures three times to waive the covenant non-compliance and extend the due date for our 2003 Annual Report on Form 10-K and other filings. In order to obtain these amendments and consents, we incurred $9.0 million and $5.1 million of expenses in 2005 and 2004, respectively. We were required under the last consent by the holders of each series of Senior Notes ~~with~~to file our 2003 Annual Report on form 10-K on or before May 31, 2005 and our 2004 quarterly reports on Form 10-Q and our Annual Report on Form 10-K for 2004 on or before July 31, 2005. The consent also provided that the ~~proceeds~~Quarterly Reports on Form 10-Q for the first quarter and second quarter of ~~certain sales of equity at 108.375% of par plus accrued interest.~~

~~At September 30, 2003, $275,000,000 principal amount~~2005 had to be filed no later than October 31, 2005. We failed to meet those deadlines, and as a result, on June 6, 2005, the trustee for the Senior Notes sent us notice of the 8³/8%financial reporting violation, which then triggered a 60-day cure period. Due to our failure to cure this default, on September 28, 2005, we received a valid acceleration notice from the trustee for the 6.375% Senior Notes. As a result, the 6.375% Senior Notes ~~remained outstanding. The 8~~³/8%were repaid on October 5, 2005. We also redeemed all of the 8.375% 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 theNovember 8,³/8% 2005. The Senior Notes ~~indenture.~~were repaid with funds from our Senior Secured Credit Facility and cash on hand.

14% Senior Subordinated Notes

On January 22, 1999, ~~the Company~~we completed the private placement of 150,000 units (the “Units”) consisting of ~~$150,000,000~~$150.0 million of 14% Senior Subordinated Notes due January 15, 2009 (the “14% Senior Subordinated Notes”) and 150,000 warrants to purchase 2,173,433 shares of the Company’s common stock at an exercise price of $4.88125 per share (the ~~“Unit Warrants”~~“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~~were issued 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~~discount, which 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~~During the years prior to 2004, we redeemed approximately $52.5 million of principal amount of our 14% Senior Subordinated Notes ~~mature~~at varying times and redemption prices, plus accrued interest. We repaid 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 8~~³/8~~% 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~~remaining $97.5 million outstanding 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.~~ 2004.

As of ~~September~~June 30, ~~2003,~~2006, 63,500 ~~Unit~~ Warrants had been exercised, ~~producing approximately $4,173,000~~providing $4.2 million of proceeds to ~~the Company~~us and leaving 86,500 ~~Unit~~ Warrants outstanding. On the date of issuance, the value of the Warrants was estimated at $7.4 million and was classified as equity. Under the terms of the Warrants, we are required to maintain an effective registration statement covering the shares of common stock issuable upon exercise. If we are unable to maintain an effective registration statement, we are required to pay liquidated damages for periods in which an effective registration statement is not maintained. We have been unable to maintain an effective registration statement due to our failure to timely file our SEC reports. As a result, we paid liquidated damages starting at $0.05 per Warrant per week and escalating to $0.20 per Warrant per week. The total amounts paid to the holders of ~~September~~the Warrants were $0.5 million and $0.1 million during the six months ended June 30, ~~2003,~~2006 and 2005, respectively. We made no liquidated damages payments during the ~~Company was in compliance with all covenants contained in~~quarters ended June 30, 2006 and 2005.

Interest Expense

Interest expense for the ~~14% Senior Subordinated Notes indenture.~~three and six months ended June 30, 2006 and 2005 consisted of the following:

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
	(in thousands)
Cash payments	$	7,801		$	5,362		$	16,065		$	17,731
Commitment and agency fees paid	1,532			7,021			2,243			10,840
Amortization of discount and premium	—			(63		)	—			(125		)
Amortization of debt issuance costs	402			438			803			1,013
Net change in accrued interest	1,172			3,777			1,112			544
Capitalized interest	(877		)	(209		)	(1,615		)	(325		)
Total interest expense	$	10,030		$	16,326		$	18,608		$	29,678

~~5% Convertible Subordinated Notes~~7. COMMITMENTS AND CONTINGENCIES

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

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

Government Investigations. On March 29, 2004, we were notified by the Fort Worth office of the SEC that it had commenced an inquiry regarding the Company. The SEC issued a formal order of investigation on July 15, 2004. On May 30, 2007, we were informed by the staff of the Enforcement Division of the SEC that it had completed its investigation as to Key and that it did not intend to recommend enforcement action. In addition, on January 5, 2005, we were served with a subpoena issued by a grand jury in Midland, Texas, that asked for the

production of documents in connection with an investigation being conducted by the U.S. Attorney’s Office for the Western District of Texas. In October 2006, we were notified by the U.S. Attorney’s Office that it would not pursue any criminal charges against the Company.

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

Eustace Matter. Joe Eustace was employed by Key from 1999 until 2004 as a Vice President and Regional Manager pursuant to an employment agreement. He filed suit in January 2006 alleging breach of contract, fraud and conversion seeking reinstatement of his stock options. We have recorded a liability for this matter and do not expect that the conclusion of this matter will have a material impact on our results of operations, cash flows or financial position.

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

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

~~In 1997,~~Additionally, on August 21, 2006, our former chief financial officer, Royce W. Mitchell, filed a suit against the Company ~~completed~~in 385th District Court, Midland County, Texas alleging breach of contract with regard to alleged bonuses, benefits and expense reimbursements, conditional stock grants and stock options, to which he believes himself entitled; as well as relief under theories of quantum meruit, promissory estoppel, and specific performance. Although there is no scheduling order in the case, discovery is underway. Further, our former controller and assistant controller filed a ~~private placement~~joint complaint against the Company on September 3, 2006 in 133rd District Court, Harris County, Texas alleging constructive termination and breach of ~~$216,000,000~~contract. Following Key’s removal of ~~5% Convertible Subordinated Notes due 2004 (the “5% Convertible Subordinated Notes”). The 5% Convertible Subordinated Notes are subordinate~~the case to the ~~Company’s senior indebtedness which includes borrowings under the Senior Credit Facility, the 14% Senior Subordinated Notes, the 8~~³/8~~% Senior Notes~~federal court, Plaintiff dismissed his constructive termination allegation and the 6³/parties agreed to a remand of the case back to the state court. Discovery is now ongoing.

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

Shareholder Class Action Suits.8~~% Senior Notes.~~ Since June 2004, we have been named as a defendant in six class action complaints for alleged violations of federal securities laws, which have been filed in federal district court in Texas. These six actions have been consolidated into one action. On November 1, 2005, the plaintiffs filed a consolidated amended class action complaint. The ~~5% Convertible Subordinated Notes are convertible, at~~complaint generally alleges that we made false and misleading statements and omitted material information from our public statements and SEC reports during the ~~holder’s option, into shares~~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 ~~common stock~~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 ~~conversion price~~material adverse effect on our business, results of ~~$38.50~~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 June 30, 2006, we have recorded reserves for future potential liabilities as a result of these audits that management feels are appropriate. While we have fully reserved for these assessments, the ultimate amount of settlement can vary from this estimate. In connection with our Egyptian operations, we are undergoing income tax audits for all periods in which we had operations. Based on information as of the period covered by this report, we have determined that additional income taxes will be owed and have recorded a liability of approximately $1.1 million.

Self-Insurance Reserves. We maintain insurance policies for workers’ compensation, vehicle liability and general liability claims. These insurance policies carry self-insured retention limits or deductibles on a per ~~share, subject~~occurrence basis. The retention limits or deductibles are accounted for in our accrual process for all workers’ compensation, vehicular liability and general liability claims. We maintain reserves for workers’ compensation and vehicle liability on our balance sheet based on our judgment and estimates using an actuarial method based on claims incurred. We estimate general liability claims on a case-by-case basis. As of June 30, 2006 and December 31, 2005, we have recorded $65.8 million and $56.0 million, respectively, of self-insurance reserves related to ~~certain adjustments. The 5% Convertible Subordinated Notes~~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 ~~redeemable,~~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 ~~Company’s option, on~~application of our insurance coverage. As of June 30, 2006 and ~~after September 15, 2000, in whole or part, together with accrued~~December 31, 2005, we have recorded $4.5 million and ~~unpaid interest. The initial redemption price is 102.86%~~$5.3 million, respectively, for our environmental remediation liabilities.

Guarantees. We provide performance bonds to provide financial surety assurances for the ~~year beginning September 15, 2000~~remediation and ~~declines ratably thereafter on~~maintenance of our SWD properties to comply with environmental protection standards. Costs for SWD properties may be mandatory (to comply with applicable laws and regulations), in the future (required to divest or cease operations), or for optimization (to improve operations, but not for safety or regulatory compliance).

Francis D. John Employment Agreement. Effective as of July 1, 2001, we entered into an ~~annual basis.~~

~~At September 30, 2003, $18,699,000 principal amount~~amended and restated employment agreement with Francis D. John (the “2001 Employment Agreement”) pursuant to which Mr. John served as the Chairman of the ~~5% Convertible Subordinated Notes remained outstanding.~~Board, President and Chief Executive Officer of Key. The ~~5% Convertible Subordinated Notes mature on September 15, 2004.~~2001 Employment Agreement provided for the payment of a one-time retention incentive payment of $13.1 million. The ~~Company intends~~purpose of this retention incentive payment was to ~~use its available cash or other borrowings, including~~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 ~~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~~Board, President 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~~Chief Executive Officer) and in the ~~5% Convertible Subordinated Notes indenture.~~

~~CRITICAL ACCOUNTING POLICIES~~

~~The preparation~~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 ~~financial statements requires the use of judgment~~two components: (i) $7.5 million in loan principal and ~~estimates. A critical accounting policy is one that requires difficult, subjective or complex estimates and assessments and is fundamental to the reported amounts of assets and liabilities at~~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~~statements. On May 31, 2007 we paid AFIP $3.5 million, representing the cumulative amount of underpayment and ~~revenues~~interest. As a result of our underpayment, AFIP has imposed fines and ~~expenses during~~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 ~~periods presented. A complete summary~~ultimate resolution of this matter to have a material impact to our results of operations, cash flows or financial position.

Well Service Rig Purchase Contract. In October 2005, we entered into a purchase and sale agreement to acquire 30 well service rigs, with the option to acquire more under the terms of the agreement. Through June 30, 2006 we have ordered five additional rigs under this option and have received delivery of 12 rigs. The purchase and sale agreement is cancelable at our option at any time. Should we cancel the agreement prior to taking delivery of the 30 well service rigs, we may be required to refund to the seller the amount of the contractual discount provided by the seller on the previously delivered well service rigs.

8. STOCKHOLDERS’ EQUITY

Common Stock

On June 30, 2006, we had 200,000,000 shares of common stock authorized with a $0.10 par value of which 131,259,243 of these shares of common stock were issued and outstanding, net of 497,501 shares held in treasury, and no dividends were issued. On December 31, 2005, we had 200,000,000 shares of common stock authorized with a $0.10 par value of which 131,334,196 of these shares were issued and outstanding, net of 416,666 shares held in treasury, and no dividends had been issued.

Treasury Stock

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

Stock Incentive Plans

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

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

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

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

	Six Months Ended June 30, 2006
	Options		Weighted Average Exercise Price		Weighted Average Fair Value

Outstanding at beginning of period	9,275		$	8.68	$	4.79
Granted	794		$	15.08	$	7.24
Exercised	—		$	—	$	—
Cancelled or expired	(144	)	$	9.68	$	4.58
Outstanding at end of period	9,925		$	9.18	$	4.99

Exercisable at end of period	8,795		$	8.55	4.76

The following tables summarize information about the stock options outstanding at June 30, 2006:

	Options Outstanding
	Weighted Average Remaining Contractual Life (Years)	Number of Options Outstanding June 30, 2006		Weighted Average Exercise Price		Weighted Average Fair Value
Range of Exercise Prices:
$3.00 - $8.00	4.12	2,173		$	6.52	$	3.76
$8.01 - $8.31	3.97	1,850		$	8.25	$	4.91
$8.32 - $8.88	4.16	1,980		$	8.53	$	5.43
$8.89 - $10.22	5.71	2,280		$	9.81	$	4.84
$10.23 - $16.25	7.62	1,642		$	13.63	$	6.39
		9,925		$	9.18	$	4.99

Aggregate intrinsic value (in thousands)		$	8,443

	Options Exercisable
	Number of Options Exercisable June 30, 2006		Weighted Average Exercise Price		Weighted Average Fair Value
Range of Exercise Prices:
$3.00 - $8.00	2,173		$	6.52	$	3.76
$8.01 - $8.31	1,850		$	8.25	$	4.92
$8.32 - $8.88	1,980		$	8.53	$	5.43
$8.89 - $10.22	2,225		$	9.80	$	4.86
$10.23 - $16.25	567		$	12.49	$	5.38
	8,795		$	8.55	$	4.76

Aggregate intrinsic value (in thousands)	$	8,443

The total fair value of stock options granted during the quarter and six months ended June 30, 2006 was $0.1 million and $5.7 million, respectively. The fair value of each stock option granted during the six months ended June 30, 2006 was estimated on the date of grant using the Black-Scholes option-pricing model, based on the following weighted-average assumptions:

	Six Months Ended June 30, 2006

Risk-free rate	4.7	%
Expected life of options, years	6.00
Expected volatility	49.0	%
Expected dividends	none

Common Stock Awards

Beginning in June 2005, we began granting shares of common stock to our outside directors and certain employees. These shares are restricted as to exercisability and transferability, and in certain cases, have required service periods before they are vested and are subject to forfeiture. The vesting periods on these grants range from zero (immediately vested) to three years. The total fair market value of all common stock awards granted during the six months ended June 30, 2006 and 2005 was $0.1 million and $6.5 million, respectively. No common stock awards were granted prior to June 2005.

In June 2006, pursuant to the agreement under which they were issued restricted stock, certain of the Company’s officers had a number of common shares withheld in order to satisfy those individuals’ income tax obligations associated with the vesting of the first tranche of shares that were conveyed to them in June 2005. In this transaction, the Company purchased 80,835 shares from the officers, which had a fair market value of approximately $1.2 million on the purchase date. We accounted for this as a treasury stock transaction. One of the officers was permitted to have an amount withheld that was in excess of the required minimum required withholding under current tax law. Under SFAS 123(R) and previously under variable plan accounting ~~policies is~~under APB 25, we are required to account for this grant as a liability award. Compensation expense for this award for the six months ended June 30, 2006 was $0.1 million. Compensation expense recognized for this award during the quarter ended June 30, 2006 was less than $0.1 million. No compensation expense was recognized on this award for the three and six months ended June 30, 2005.

We issued a total of 550,000 common shares to our outside directors and employees during the six months ended June 30, 2005 at a weighted-average issuance price of $11.90 per share. Of these, 50,000 were issued to our outside directors and vested immediately, while the remaining 500,000 vest ratably over a three year period. We issued a total of 5,882 common shares to an outside director during the six months ended June 30, 2006 at a weighted-average issuance price of $14.45 per share. All of these awards vested immediately. At June 30, 2006, 298,739 common share awards were vested, at a weighted average issuance price of $11.95 per share. At December 31, 2005, 42,858 common share awards were vested, at a weighted-average issuance price of $11.90 per share. During 2005, one of our outside directors refused his common stock award of 7,143 shares. That director was not issued a common stock award in 2006.

For common stock grants that vest immediately upon issuance, we record expense equal to the fair market value of the shares on the date of grant. For common stock grants that do not immediately vest, we recognize compensation cost ratably over the vesting period of the grant, net of actual and estimated forfeitures. For the three months ended June 30, 2006 and 2005, we recognized $0.5 million and $0.6 million, respectively, of expense related to common stock awards, net of estimated and actual forfeitures. For the six months ended June 30, 2006 and 2005, we recognized $2.3 million and $0.6 million, respectively, of expense related to common stock awards, net of estimated and actual forfeitures.

9.SEGMENT INFORMATION

For 2006, our reportable business segments are well servicing, pressure pumping and fishing and rental.

Well Servicing. These operations provide a full range of well services, including rig-based services, oilfield transportation services and other ancillary oilfield services necessary to complete, maintain and workover oil and natural gas producing wells. Our Argentina operations are included in ~~Note 1~~our well servicing segment. We aggregate our operating divisions engaged in well servicing activities into our well servicing reportable segment.

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

Fishing and Rental. These operations provide services that include “fishing” to recover lost or stuck equipment in a wellbore through the ~~Company’s Transition Report~~use of “fishing tools.” In addition, this segment offers a full line of services and

rental equipment designed for use both on ~~Form 10-K~~land and offshore for drilling and workover services and includes an inventory consisting of tubulars, handling tools, pressure-control equipment and power swivels.

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

The following table sets forth our segment information as of and for the periods ended June 30, 2006 and June 30, 2005, respectively:

	Well Servicing			Pressure Pumping			Fishing and Rental			Corporate / Other			Discontinued Operations		Eliminations			Total
	(in thousands)
As of and for the three months ended June 30, 2006:
Operating revenues	$	288,392		$	60,199		$	23,445		$	—		$	—	$	—		$	372,036
Gross margin	111,219			26,179			9,031			—			—		—			146,429
Depreciation and amortization	21,689			2,810			1,705			2,720			—		—			28,924
Interest expense	(152		)	(173		)	(9		)	10,364			—		—			10,030
Net income (loss) from continuing operations	72,225			22,356			5,173			(60,172		)	—		—			39,582
Propery, plant and equipment, net	510,456			86,394			29,486			32,215			—		—			658,551
Total assets	975,004			172,823			72,648			352,267			621		(140,247		)	1,433,116
Capital expenditures, excluding acquisitions	(43,082		)	(12,129		)	(3,399		)	—			—		—			(58,610		)

	Well Servicing			Pressure Pumping			Fishing and Rental			Corporate / Other			Discontinued Operations		Eliminations			Total
	(in thousands)
As of and for the three months ended June 30, 2005:
Operating revenues	$	238,696		$	36,246		$	19,959		$	—		$	—	$	—		$	294,901
Gross margin	77,041			10,880			6,185			—			—		—			94,106
Depreciation and amortization	21,545			2,295			1,505			2,867			—		—			28,212
Interest expense	18			(71		)	6			16,373			—		—			16,326
Net income (loss) from continuing operations	42,738			11,367			3,293			(48,025		)	—		—			9,373
Propery, plant and equipment, net	471,679			53,948			26,565			36,110			—		—			588,302
Total assets	909,838			125,224			69,202			578,633			1,193		(386,858		)	1,297,232
Capital expenditures, excluding acquisitions	(24,092		)	(5,090		)	(869		)	(3,259		)	—		—			(33,310		)

	Well Servicing			Pressure Pumping			Fishing and Rental			Corporate / Other			Discontinued Operations		Eliminations			Total
	(in thousands)
As of and for the six months ended June 30, 2006:
Operating revenues	$	561,307		$	111,997		$	46,689		$	—		$	—	$	—		$	719,993
Gross margin	203,379			49,408			17,187			—			—		—			269,974
Depreciation and amortization	41,764			5,172			3,295			5,507			—		—			55,738
Interest expense	(292		)	(382		)	(6		)	19,288			—		—			18,608
Net income (loss) from continuing operations	131,335			42,290			10,007			(113,988		)	—		—			69,644
Propery, plant and equipment, net	510,456			86,394			29,486			32,215			—		—			658,551
Total assets	975,004			172,823			72,648			352,267			621		(140,247		)	1,433,116
Capital expenditures, excluding acquisitions	(74,385		)	(18,530		)	(4,755		)	(521		)	—		—			(98,191		)

	Well Servicing			Pressure Pumping			Fishing and Rental			Corporate / Other			Discontinued Operations		Eliminations			Total
	(in thousands)
As of and for the six months ended June 30, 2005:
Operating revenues	$	459,029		$	66,750		$	40,326		$	—		$	—	$	—		$	566,105
Gross margin	147,754			24,153			12,946			—			—		—			184,853
Depreciation and amortization	42,838			4,459			2,955			5,734			—		—			55,986
Interest expense	22			(84		)	12			29,728			—		—			29,678
Net income (loss) from continuing operations	74,939			21,684			6,585			(85,470		)	—		—			17,738
Propery, plant and equipment, net	471,679			53,948			26,565			36,110			—		—			588,302
Total assets	909,838			125,224			69,202			578,633			1,193		(386,858		)	1,297,232
Capital expenditures, excluding acquisitions	(36,450		)	(6,216		)	(1,338		)	(4,227		)	—		—			(48,231		)

Operating revenues for our foreign operations were $18.0 million and $17.8 million for the three months ended June 30, 2006 and 2005, respectively. Operating revenues for our foreign operations were $35.2 million and $35.2 million for the six months ended June 30, 2006 and 2005, respectively. Gross margins for our foreign operations were $3.5 million and $4.4 million for the quarters ended June 30, 2006 and 2005, respectively. Gross margins for our foreign operations were $8.3 million and $9.8 million for the six months ended June 30, 2006 and 2005, respectively.

We have $28.6 million and $24.0 million of identifiable assets related to our foreign operations as of June 30, 2006 and December 31, ~~2002.~~ 2005, respectively. Capital expenditures for our foreign operations were $6.3 million and $4.1 million for the six months ended June 30, 2006 and 2005, respectively.

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

The ~~Company’s critical accounting policies~~following discussion and analysis should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes as of June 30, 2006 and for the three months and six months ended June 30, 2006 and 2005, included elsewhere herein.

Overview

We believe that we are ~~as follows.~~the leading onshore, rig-based well servicing contractor in the United States. Since 1994, we have grown rapidly through a series of over 100 acquisitions, and today we provide a complete range of well services to major oil companies and independent oil and natural gas production companies; including rig-based well maintenance, workover, well completion, and recompletion services; oilfield transportation services; fishing and rental services; pressure pumping services; and ancillary oilfield services.

~~Management makes estimates regarding the fair value~~We operate in most major oil and natural gas producing regions of the ~~Company’s reporting units~~United States as well as internationally in ~~assessing potential impairment~~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:

We provide a broad range of ~~goodwill. In addition, the Company makes estimates regarding future undiscounted cash flows from the future use~~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 ~~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~~rig services for our customers: (i) maintenance, (ii) workover, (iii) completion, and ~~assumptions in estimating the fair value of its reporting units. Actual future results could be different than the estimates~~(iv) plugging 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 inabandonment 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 ~~prices, changes~~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 ~~government regulation~~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 ~~industry~~wells from formations which exhibit restricted flow of oil and natural gas. In the fracturing process, we typically pump fluid and sized sand, or ~~other events which could affect~~proppants, into a well at high pressure in order to fracture the ~~level~~formation and thereby increase the flow of ~~activity~~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 ~~exploration~~Texas, the Barnett Shale of North Texas, the Mid-Continent region of Oklahoma and ~~production companies.~~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 ~~assessing impairment~~determining the overall health of ~~long-lived assets other than goodwill where there has been a change in circumstances indicating~~the oilfield service industry, we believe that the ~~carrying amount~~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 ~~long-lived asset may not be recoverable,~~weekly basis. Historically, our activity levels have correlated well with the ~~Company has estimated future undiscounted net cash flows from use of the asset based on actual historical results and expectations about future economic circumstances including~~capital spending by oil and natural gas producers. When commodity prices are strong, capital spending tends to be high, as illustrated by the Baker Hughes land drilling rig count. As the following table indicates, the land drilling rig count increased significantly over the past several years as commodity prices, both oil and ~~operating~~natural gas, increased.

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

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

2006:
First Quarter	$	63.27	$	7.84	1,440
Second Quarter	$	70.41	$	6.65	1,539

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. The following table presents our quarterly rig and trucking hours from 2005 through the second quarter of 2006.

	Rig Hours	Trucking Hours
2005:
First Quarter	621,228	641,841
Second Quarter	661,928	635,448
Third Quarter	668,741	607,500
Fourth Quarter	646,810	594,762
Total 2005:	2,598,707	2,479,551

2006:
First Quarter	663,819	609,317
Second Quarter	679,545	602,118

Results of Operations

Key Energy Services, Inc.

Condensed Consolidated Statements of Operations

(In thousands, except per share data)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005

*REVENUES:*
Well servicing	$	288,392		$	238,696		$	561,307		$	459,029
Pressure pumping	60,199			36,246			111,997			66,750
Fishing and rental services	23,445			19,959			46,689			40,326

Total revenues	372,036			294,901			719,993			566,105

*COSTS AND EXPENSES:*
Well servicing	177,172			161,653			357,928			311,275
Pressure pumping	34,020			25,367			62,589			42,597
Fishing and rental services	14,415			13,775			29,502			27,380
Depreciation and amortization	28,924			28,212			55,738			55,986
General and administrative	43,739			34,137			87,080			69,076
Interest expense	10,030			16,326			18,608			29,678
Loss (gain) on early extinguishment of debt	—			5,481			—			5,881
Loss (gain) on sale of assets	(309		)	(755		)	(2,244		)	(30		)
Interest income	(828		)	(736		)	(2,028		)	(1,160		)
Other, net	953			(5,018		)	472			(4,970		)

Total costs and expenses, net	308,116			278,442			607,645			535,713

Income from continuing operations before income taxes	63,920			16,459			112,348			30,392
Income tax (expense) benefit	(24,338		)	(7,086		)	(42,704		)	(12,654		)

*INCOME FROM CONTINUING OPERATIONS*	39,582			9,373			69,644			17,738

Discontinued operations, net of tax expense of $4,590 for the six months ended June 30, 2005	—			—			—			(3,361		)

*NET INCOME*	$	39,582		$	9,373		$	69,644		$	14,377

Three Months Ended June 30, 2006 Compared to Three Months Ended June 30, 2005

Revenue:

Well Servicing: Well servicing revenues increased 20.8% to $288.4 million for the quarter ended June 30, 2006 compared to revenue of $238.7 million for the quarter ended June 30, 2005. 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 June 2006 quarter, the Company’s composite segment revenue to total hours (as defined as rig hours plus trucking hours) was approximately $225 per hour compared to approximately $184 per hour for the June 2005 quarter. Rig hours for the Company increased 2.7% from 661,928 in the June 2005 quarter to 679,545 in the June 2006 quarter while the Company’s trucking hours decreased 5.2% from 635,448 in the June 2005 quarter to 602,118 in the June 2006 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 66.1% to $60.2 million for the quarter ended June 30, 2006 compared to revenue of $36.2 million for the quarter ended June 30, 2005. 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 June 2006 quarter with approximately 162,000 horsepower of pumping equipment as compared to approximately 113,000 at the end of the June 2005 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 431 in the June 2006 quarter compared to 331 in the June 2005 quarter while cementing jobs totaled 521 in the June 2006 quarter compared to 352 in the June 2005 quarter.

Fishing and Rental Services: Fishing and rental services (“FRS”) segment revenues for the quarter ended June 30, 2006 increased 17.5% to $23.4 million compared to revenue of $20.0 million for the quarter ended June 30, 2005. The increase in revenue is attributable to higher pricing.

Direct Costs:

Well Servicing: Well servicing direct costs increased 9.6% to $177.2 million for the quarter ended June 30, 2006 compared to $161.7 million for the quarter ended June 30, 2005. The increase in direct costs is largely attributable to higher labor and equipment costs, including higher wages, higher repair and maintenance expense, higher fuel expense and higher supplies expense. The increase in these costs is primarily due to higher activity levels. Direct costs as a percent of total well servicing segment revenue improved to 61.4% for the quarter ended June 30, 2006 compared to 67.7% for the quarter ended June 30, 2005.

Pressure Pumping Services: PPS direct costs increased 34.1% to $34.0 million for the quarter ended June 30, 2006 compared to $25.4 million for the quarter ended June 30, 2005. 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 56.5% for the quarter ended June 30, 2006 compared to 70.0% for the quarter ended June 30, 2005.

Fishing and Rental Services: FRS direct costs increased 4.6% to $14.4 million for the quarter ended June 30, 2006 compared to $13.8 million for the quarter ended June 30, 2005. The increase in direct costs is largely attributable to higher labor costs. The ~~estimate~~increase in direct costs is primarily the result of increased demand for the Company’s services. Direct costs as a percent of total FRS segment revenue improved to 61.5% for the quarter ended June 30, 2006 compared to 69.0% for the quarter ended June 30, 2005.

General and Administrative Expense

General and administrative (“G&A”) expenses increased 28.1% to $43.7 million for the quarter ended June 30, 2006 compared to $34.1 million for the quarter ended June 30, 2005. The increase in G&A is primarily attributable to higher compensation expense and higher professional fees. G&A expense as a percent of revenue for the quarter ended June 30, 2006 totaled 11.8% compared to 11.6% for the quarter ended June 30, 2005.

Interest Expense

Interest expense decreased 38.6% to $10.0 million for the quarter ended June 30, 2006 compared to $16.3 million for the quarter ended June 30, 2005. The decrease is primarily attributable to the elimination of consent fees paid to our debt holders in consideration for our inability to timely file our audited financial statements. Interest expense as a percent of revenue for the quarter ended June 30, 2006 totaled 2.7% compared to 5.5% for the quarter ended June 30, 2005.

Depreciation Expense

Depreciation expense increased 2.5% to $28.9 million for the quarter ended June 30, 2006 compared to $28.2 million for the quarter ended June 30, 2005. The increase is primarily attributable to a greater fixed asset base which is due to increased capital expenditures. For the quarter ended June 30, 2006, the Company spent approximately $58.6 million on capital expenditures as compared to $33.3 million for the quarter ended June 30, 2005. Depreciation expense as a percent of revenue for the quarter ended June 30, 2006 totaled 7.8% compared to

9.6% for the quarter ended June 30, 2005.

Income Taxes

Our income tax expense from continuing operations was $24.3 million and $7.1 million for the three months ended June 30, 2006 and 2005 respectively. Our effective tax rate for those same periods was 38.1% and 43.1%, respectively. The differences between the rates between periods relate largely to nondeductible expense for executive compensation and other nondeductible items. Differences between the statutory rate and the effective rate are due primarily to state and foreign income taxes and nondeductible expenditures.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Revenue

Well Servicing: Well servicing revenues increased 22.3% to $561.3 million for the six months ended June 30, 2006 compared to revenue of $459.0 million for the six months ended June 30, 2005. The increase in revenue is largely attributable to higher pricing for the Company’s services and higher rig hours, offset somewhat by lower trucking hours. For the six months ended June 30, 2006, the Company’s composite segment revenue to total hours (as defined as rig hours plus trucking hours) was approximately $220 per hour compared to approximately $179 per hour for the six months ended June 30, 2005. Rig hours for the Company increased 4.7% from 1,283,156 in the first six months of 2005 to 1,343,364 in the first six months of 2006 while the Company’s trucking hours decreased 5.2% from 1,277,289 in the first six months of 2005 to 1,211,435 in the first six months of 2006. 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 67.8% to $112.0 million for the six months ended June 30, 2006 compared to revenue of $66.8 million for the six months ended June 30, 2005. 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 six months ended June 30, 2006 with approximately 162,000 horsepower of pumping equipment as compared to approximately 113,000 horsepower for the six months ended June 30, 2005. 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 796 during the first six months of 2006 compared to 635 for the first six months of 2005 while cementing jobs totaled 994 during the first six months of 2006 compared to 661 for the first six months of 2005.

Fishing and Rental Services: FRS segment revenues for the six months ended June 30, 2006 increased 15.8% to $46.7 million compared to revenue of $40.3 million for the six months ended June 30, 2005. The increase in revenue is primarily attributable to higher pricing.

Direct Costs

Well Servicing: Well serving direct costs increased 15.0% to $357.9 million for the six months ended June 30, 2006 compared to $311.3 million for the six months ended June 30, 2005. The increase in direct costs is largely attributable to higher labor and equipment costs, including higher wages, higher repair and maintenance expense, higher fuel expense and higher supplies expense. The increase in these costs is primarily due to higher activity levels. Direct costs as a percent of total well service segment revenue improved to 63.8% for the six months ended June 30, 2006 compared to 67.8% for the six months ended June 30, 2005.

Pressure Pumping: PPS direct costs increased 46.9% to $62.6 million for the six months ended June 30, 2006 compared to $42.6 million for the six months ended June 30, 2005. The increase in direct costs is largely

attributable to increased sand and chemical purchases as well as higher trucking and freight costs, higher labor costs, higher fuel expense and higher repair and maintenance expense. The increase in direct costs is primarily the result of increased demand for the Company’s services. Direct costs as a percent of total PPS segment revenue improved to 55.9% for the six months ended June 30, 2006 compared to 63.8% for the six months ended June 30, 2005.

Fishing and Rental Services: FRS direct costs increased 7.8% to $29.5 million for the six months ended June 30, 2006 compared to $27.4 million for the six months ended June 30, 2005. The increase in direct costs is largely attributable to higher labor costs, which is the result of increased demand for the Company’s services. Direct costs as a percent of total FRS segment revenue improved to 63.2% for the six months ended June 30, 2006 compared to 67.9% for the six months ended June 30, 2005.

General and Administrative Expense

General and administrative expense increased 26.1% to $87.1 million for the six months ended June 30, 2006 compared to $69.1 million for the six months ended June 30, 2005. The increase in G&A expenses is primarily attributable to higher compensation expense as well as higher professional fees. The increase is offset somewhat by lower bad debt expense. G&A expense as a percent of revenue for the six months ended June 30, 2006 totaled 12.1% compared to 12.2% for the six months ended June 30, 2005.

Interest Expense

Interest expense decreased 37.3% to $18.6 million for the six months ended June 30, 2006 compared to $29.7 million for the six months ended June 30, 2005. The decrease is primarily attributable to the elimination of consent fees paid to our bondholders and lower total debt. Interest expense as a percent of revenue for the six months ended June 30, 2006 totaled 2.6% compared to 5.2% for the six months ended June 30, 2005.

Depreciation Expense

Depreciation expense was flat, totaling $55.7 million for the six months ended June 30, 2006 compared to $56.0 million for the six months ended June 30, 2005. For the six months ended June 30, 2006, the Company spent approximately $98.2 million on capital expenditures as compared to $48.2 million for the six months ended June 30, 2005. Depreciation expense as a percent of revenue for the six months ended June 30, 2006 totaled 7.7% compared to 9.9% for the six months ended June 30, 2005.

Income Taxes

Our income tax expense from continuing operations was $42.7 million and $12.7 million for the six months ended June 30, 2006 and 2005 respectively. Our effective tax rate for those same periods was 38.0% and 41.6%, 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.

Liquidity and Capital Resources

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

We believe that our current reserves of cash and cash equivalents, availability under our revolving credit facility, and internally generated cash flow from operations are sufficient to finance the cash requirements of our

current and future operations, including our capital expenditure budget. As of June 30, 2006, we had $113.8 million in cash and $65.0 million of availability under our revolving credit facility.

Cash Flow

Our net cash provided by operating activities for the six months ended June 30, 2006, totaled $118.0 million compared to $103.5 million for the six months ended June 30, 2005. The increase in cash flow from operating activities is due primarily to higher net income. Our net cash used in investing activities for the six months ended June 30, 2006 totaled $88.5 million compared to cash provided by investing activities of $20.4 million for the six months ended June 30, 2005. The increase in cash flow used in investing activities is due to the cash flows associated with the sale of our land drilling operations. Our net cash used in financing activities for the six months ended June 30, 2006 totaled $9.5 million compared to $53.6 million for the six months ended June 30, 2005.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Critical Accounting Policies

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

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

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

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

· Accounting for contingencies;

· Accounting for income taxes;

· Estimate of fixed asset depreciable lives; and

· Valuation of tangible and intangible assets.

Workers’ Compensation, Vehicular Liability and Other Insurance Reserves

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

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

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

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

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

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

Accounting for Contingencies

In addition to ~~industry conditions or~~our workers’ compensation, vehicular liability and other ~~factors affecting~~self-insurance reserves, we record other loss contingencies, which relate to numerous lawsuits, claims, proceedings and tax-related audits in the ~~Company’s performance.~~

~~The Company computes income taxes in~~normal course of our operations on 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 123(R). In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (‘SFAS 123(R)”), which revises SFAS No. 123. SFAS 123(R) is effective July 1, 2005 for all calendar year-end companies and requires companies to expense the fair value of employee stock options and other forms of stock-based compensation. This expense will be recognized over the period during which an employee is required to provide services in exchange for the award. Compensation cost for the unvested portion of awards that are outstanding as of January 1, 2006 is recognized ratably over the remaining vesting period. The compensation cost for the unvested portion of the awards is based on the fair value at the date of grant as calculated for our pro forma disclosure under SFAS 123. We recognize compensation expense under SFAS 123(R) for new awards granted after January 1, 2006. We use the Black-Scholes option pricing model to calculate the fair value of awards granted after January 1, 2006 and estimate forfeitures and volatility for the calculation of compensation expense and grant date fair value. We adopted SFAS 123(R) effective January 1, 2006. The adoption of this standard did not materially impact our financial statements.

SFAS 149. In April 2003, the FASB issued Statement of Financial Accounting Standards No. 149, ~~Amendment~~“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.

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

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

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

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

EITF 04-10. In June 2005, the FASB issued EITF Issue 04-10, “Determining Whether to Aggregate Operating Segments That Do Not Meet the Quantitative Thresholds.” This standard considers how a company should evaluate the aggregation criteria in FAS 131 to operating segments that do not meet the quantitative thresholds. Several of our operating segments do not meet the quantitative thresholds as described in SFAS 131. Under this standard, we are permitted to combine information about certain operating segments with other similar segments that individually do not meet the quantitative thresholds to produce a reportable segment since the operating segments meet the aggregation criteria. It was effective for fiscal years ending after September 15, ~~2003.~~2005.

~~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:

39allow timely decisions regarding required disclosure.

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 onCompany’s management, with 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~~participation of the ~~short-term maturity of such instruments.~~

~~FOREIGN CURRENCY RISK~~

~~During~~Company’s Chairman and Chief Executive Officer and Chief Financial Officer, has evaluated 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~~

~~The Company’s principal executive officer and principal financial officer undertook an evaluation~~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 June 30, 2006, 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~~. 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.

~~None.~~

Item 21A. RISK FACTORS~~. Changes~~

There have been no material changes in ~~Securities and Use of Proceeds~~.

~~None.~~

~~Item 3.~~ ~~Defaults Upon Senior Securities.~~

~~None.~~

~~Item 4~~~~. Submission of Matters to a Vote of Security Holders.~~

~~None.~~

~~Item 5~~~~. Other Information~~

~~None.~~

~~Item 6~~~~. Exhibits and Reports~~our risk factors from those disclosed in our 2006 Annual Report on Form ~~8-K.~~

~~(a)Exhibits~~

4.1*~~Supplemental Indenture~~10-K dated as of, ~~July 28, 2003, between~~and filed with the ~~Company, the Guarantors (as defined therein) and The Bank~~SEC on, August 13, 2007. For a discussion of ~~New York, as Trustee.~~

4.2*~~Third Supplemental Indenture~~our risk factors, see Item 1A. “Risk Factors” in our 2006 Annual Report on Form 10-K dated as of, ~~July 28, 2003, among~~and filed with the ~~Company, the Guarantors (as defined therein) and U.S. Bank National Association, as Trustee.~~SEC on, August 13, 2007.

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

~~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).None.

Item 3. DEFAULTS UPON SENIOR SECURITIES

10.2*~~Purchase and Sale Agreement dated August 7, 2003 between Odessa Exploration Incorporated and Stallion Panhandle 2001, L.P.~~None.

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

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.~~None.

Item 5. OTHER INFORMATION

43None.

Item 6. EXHIBITS

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.)

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~~
			~~Francis D. John~~	/s/ Richard J. Alario
		By:		Richard J. Alario
				President and Chief Executive Officer

~~Dated: November 14, 2003~~	By	~~/s/ Royce W. Mitchell~~			(Principal Executive Officer)
			~~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.)

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 June 30, 2006

or

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

	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

	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