UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


þ		Quarterly Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended ~~September~~June 30, ~~2007~~2008


o		Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to

Commission File Number 1-8226

Grey Wolf, Inc.

(Exact name of registrant as specified in its charter)

Texas		74-2144774
(State or jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)
10370 Richmond Avenue, Suite 600
Houston, Texas		77042
(Address of principal executive offices)		(Zip Code)


Texas (State or jurisdiction of incorporation or organization)		74-2144774 (I.R.S. Employer Identification No.)


10370 Richmond Avenue, Suite 600
Houston, Texas		77042
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (713) 435-6100

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 þ No o

~~Yes~~ Indicate þby Nocheck omark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and ”smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

~~Indicate~~Large ~~by check mark whether the registrant is a large~~ accelerated filer, anþ ~~accelerated~~ Accelerated filer, oro ~~a non~~Non-accelerated filer. ~~See~~o ~~definition~~Smaller ofreporting ~~“accelerated~~company ~~filer~~o ~~and~~(Do ~~large~~not ~~accelerated filer”~~check inif ~~Rule 12b-2~~a ofsmaller ~~the~~reporting ~~Exchange Act. (Check one~~company):

~~Large~~ Indicate ~~accelerated~~by ~~filer~~check þmark ~~Accelerated~~whether ~~filer~~the oregistrant ~~Non~~is a shell company (as defined in Rule 12b-~~accelerated~~2 ~~filer~~of the Exchange Act). Yes o No þ

~~Indicate~~The bynumber ~~check~~of ~~mark~~shares ~~whether~~of the registrant’s iscommon astock, ~~shell~~par ~~company~~value ~~(as~~$0.10 ~~defined~~per inshare, ~~Rule~~outstanding at July ~~12b-2~~31, ~~of the~~2008, ~~Exchange~~was ~~Act)~~178,926,881.

Yes o No þ

The number of shares of the registrant’s common stock, par value $0.10 per share, outstanding at October 31, 2007, was 183,150,457.

GREY WOLF, INC. AND SUBSIDIARIES
Table of Contents

	Page			~~Page~~
Part I.	Financial Information
Part I. Financial Information
	Item 1.		Financial Statements
Item 1. Financial Statements
Consolidated Balance Sheets		3	~~Consolidated Balance Sheets~~		3
Consolidated Statements of Operations		4	~~Consolidated Statements of Operations~~		4
Consolidated Statements of Shareholders’ Equity and Comprehensive Income		5	~~Consolidated Statements of Shareholders’ Equity and Comprehensive Income~~		5
Consolidated Statements of Cash Flows		6	~~Consolidated Statements of Cash Flows~~		6
Notes to Consolidated Financial Statements		7	~~Notes to Consolidated Financial Statements~~		7
	Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
	Item 3.		Quantitative and Qualitative Disclosure about Market Risk		31
Item 3. Quantitative and Qualitative Disclosure about Market Risk		31
	Item 4.		Controls and Procedures		32
Item 4. Controls and Procedures		31
Part II.	Other Information
Part II. Other Information
	Item 1.		Legal Proceedings		33
Item 1. Legal Proceedings		32
	Item 1a.		Risk Factors		33
Item 1a. Risk Factors		32
	Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds		33
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		32
	Item 3.		Defaults Upon Senior Securities		33
Item 3. Defaults Upon Senior Securities		33
	Item 4.		Submission of Matters to a Vote of Security Holders		33
Item 4. Submission of Matters to a Vote of Security Holders		33
	Item 5.		Other Information		34
Item 5. Other Information		33
	Item 6.		Exhibits		35
Item 6. Exhibits		35
Signatures		36	~~Signatures~~		36
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)
Certification Pursuant to 18 U.S.C. Section 1350
Certification Pursuant to Section 906

-2-

GREY WOLF, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

(Amounts in thousands, except share data)

	September 30,			December 31,
	June 30,			December 31,
	2007			2006
	2008			2007
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	~~255~~313,~~149~~061		$	~~229~~247,~~773~~701
Restricted cash		~~847~~867			~~817~~847
Accounts receivable, net of allowance of $3,169		182,103			206,523
Accounts receivable, net of allowance of $2,922 at June 30, 2008 and $3,169 at December 31, 2007		159,091			176,466
Prepaids and other current assets		1512,~~324~~968			713,~~817~~337
Deferred tax assets		56,~~239~~037			65,~~916~~145
Total current assets		~~458~~492,~~662~~024			~~451~~443,~~846~~496
Property and equipment:
Land, buildings and improvements		89,~~050~~099			78,~~044~~534
Drilling equipment		1,~~303~~428,~~455~~372			1,~~107~~331,~~457~~401
Furniture and fixtures		5,~~262~~815			45,~~839~~397
Total property and equipment		1,~~316~~443,~~767~~286			1,~~119~~345,~~340~~332
Less: accumulated depreciation		(~~578~~661,~~249~~334	)		(~~511~~607,~~204~~388	)
Net property and equipment		~~738~~781,~~518~~952			~~608~~737,~~136~~944
Goodwill		10,377			10,377
Other noncurrent assets, net		1120,~~494~~598			16,~~625~~153
	$	1,~~219~~304,~~051~~951		$	1,~~086~~207,~~984~~970
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable-trade	$	6674,~~171~~595		$	8552,~~253~~557
Accrued workers’ compensation		75,~~849~~580			7,~~435~~608
Payroll and related employee costs		1116,~~400~~311			15,~~952~~439
Accrued interest payable		31,~~934~~811			2,~~536~~553
Current income taxes payable		811,~~932~~584			2014,~~641~~705
Other accrued liabilities		2412,~~197~~600			1511,~~265~~830
Total current liabilities		122,~~483~~481			~~147~~104,~~082~~692
Contingent convertible senior notes		275,000			275,000
Other long-term liabilities		1419,~~599~~605			918,~~877~~126
Deferred income taxes		~~149~~162,~~449~~349			~~121~~150,~~231~~643
Commitments and contingent liabilities		—			—
Shareholders’ equity:
Series B Junior Participating Preferred stock; $1 par value; 250,000 shares authorized; none outstanding		—			—
Common stock; $0.10 par value; shares authorized: 500,000,000 at September 30, 2007 and 300,000,000 at December 31, 2006; shares issued: 196,889,691 at September 30, 2007 and 195,228,691 at December 31, 2006; shares outstanding: 184,277,938 at September 30, 2007 and 185,936,440 at December 31, 2006		19,688			19,523
Common stock; $0.10 par value; shares authorized: 500,000,000; shares issued: 198,193,049 at June 30, 2008 and 197,045,996 at December 31, 2007; shares outstanding: 178,882,637 at June 30, 2008 and 178,345,603 at December 31, 2007		19,819			19,704
Additional paid-in capital		~~392~~399,~~001~~619			~~383~~393,~~482~~894
Treasury stock, at cost: 12,611,753 shares at September 30, 2007 and 9,292,251 shares at December 31, 2006		(87,158	)		(65,119	)
Treasury stock, at cost: 19,310,412 shares at June 30, 2008 and 18,700,393 shares at December 31, 2007		(124,550	)		(121,096	)
Retained earnings		~~332~~430,~~989~~628			~~195~~367,~~908~~007
Total shareholders’ equity		~~657~~725,~~520~~516			~~533~~659,~~794~~509
	$	1,~~219~~304,~~051~~951		$	1,~~086~~207,~~984~~970

See accompanying notes to consolidated financial statements

-3-

GREY WOLF, INC. AND SUBSIDIARIES

Consolidated Statements of Operations

(Amounts in thousands, except per share data)

(Unaudited)

	Three Months Ended						~~Nine~~Six Months Ended
	September 30,						September 30,
	June 30,						June 30,
	2007			2006			2007			2006
	2008			2007			2008			2007
Contract drilling revenue	$	~~223~~216,~~999~~707		$	~~242~~227,~~728~~520		$	~~693~~418,~~532~~229		$	~~705~~469,~~197~~533
Costs and expenses:
Drilling operations		~~136~~129,~~947~~953			~~131~~132,~~577~~307			~~390~~243,~~207~~461			~~383~~253,~~722~~260
Depreciation and amortization		2426,~~355~~994			1822,~~700~~397			6854,~~166~~753			5443,~~047~~811
General and administrative		68,~~757~~221			67,~~249~~159			2116,~~315~~833			1714,~~428~~558
Gain on sale of assets		(42	)		(839	)		(171	)		(10,376	)
(Gain) loss on sale of assets		12			(76	)		50			(129	)
Gain on insurance proceeds		—			—			—			(4,159	)
Total costs and expenses		165,180			161,787			315,097			311,500
Total costs and expenses		168,017			155,687			479,517			440,662
Operating income		51,527			65,733			103,132			158,033
Operating income		55,982			87,041			214,015			264,535
Other income (expense):
Interest income		31,~~334~~991			3,~~199~~593			104,~~086~~478			86,~~380~~752
Interest expense		(32,~~521~~709	)		(3,~~514~~438	)		(106,~~451~~046	)		(106,~~150~~930	)
Other expense, net		(187	)		(315	)		(365	)		(1,770	)
Other income (expense), net		(718	)		155			(1,568	)		(178	)
Income before income taxes		5550,~~795~~809			8665,~~726~~888			~~213~~101,~~650~~564			~~262~~157,~~765~~855
Income tax expense:
Current		1514,~~205~~001			3117,~~434~~307			5927,~~492~~129			8844,~~732~~287
Deferred		54,~~002~~510			306,873			1810,~~284~~814			613,~~607~~282
Total income tax expense		2018,~~207~~511			3124,~~464~~180			7737,~~776~~943			9557,~~339~~569
Net income	$	3532,~~588~~298		$	5541,~~262~~708		$	~~135~~63,~~874~~621		$	~~167~~100,~~426~~286
Net income per common share (Note 2):
Basic	$	0.1918		$	0.2923		$	0.7436		$	0.8755
Diluted	$	0.1715		$	0.2519		$	0.6331		$	0.7446
Weighted average common shares outstanding:
Basic		~~182~~176,~~599~~001			~~190~~183,~~391~~009			~~182~~175,~~875~~886			~~191~~183,~~795~~016
Diluted		~~226~~220,~~292~~042			~~233~~226,~~945~~734			~~226~~219,~~533~~687			~~235~~226,~~557~~655

See accompanying notes to consolidated financial statements

-4-

GREY WOLF, INC. AND SUBSIDIARIES

Consolidated Statements of Shareholders’ Equity and Comprehensive Income (Amounts in thousands)

(Amounts in thousands)


	Common Stock					Additional			Treasury Stock
	Number of			Amount,		Paid-in			Number of		Amount,			Retained
	Shares			at $0.10 par value		Capital			Shares		at cost			Earnings		Total
Balance, December 31, 2006		185,936		$	19,523	$	383,482			9,292	$	(65,119	)	$	195,908	$	533,794

Adjustment for the adoption of FASB Interpretation No. (FIN)48		—			—		—			—		—			1,207		1,207

Exercise of stock options		802			80		2,785			—		—			—		2,865

Tax effect of share-based payments		—			—		749			—		—			—		749

Issuance of restricted stock, net of forfeitures		1,016			101		(101	)		—		—			—		—

Stock-based compensation expense		—			—		6,979			—		—			—		6,979

Purchase of treasury stock		(9,408	)		—		—			9,408		(55,977	)		—		(55,977	)

Comprehensive net income		—			—		—			—		—			169,892		169,892


Balance, December 31, 2007		178,346			19,704		393,894			18,700		(121,096	)		367,007		659,509

Exercise of stock options		144			15		737			—		—			—		752

Tax effect of share-based payments		—			—		(168	)		—		—			—		(168	)

Issuance of restricted stock, net of forfeitures		1,003			100		(100	)		—		—			—		—

Stock-based compensation expense		—			—		5,256			—		—			—		5,256

Purchase of treasury stock		(610	)		—		—			610		(3,454	)		—		(3,454	)

Comprehensive net income		—			—		—			—		—			63,621		63,621


Balance, June 30, 2008 (unaudited)		178,883		$	19,819	$	399,619			19,310	$	(124,550	)	$	430,628	$	725,516

	Common Stock					Additional			Treasury Stock					Retained
	Number of			Amount,		Paid-in			Number of		Amount,			Earnings
	Shares			at $0.10 par value		Capital			Shares		at cost			(Deficit)			Total
Balance, December 31, 2005		192,626		$	19,263	$	374,012			—	$	—		$	(24,043	)	$	369,232
Exercise of stock options		905			90		3,062			—		—			—			3,152
Tax benefit of stock option exercises		—			—		1,330			—		—			—			1,330
Issuance of restricted stock, net of forfeitures		1,697			170		(170	)		—		—			—			—
Stock-based compensation expense		—			—		5,248			—		—			—			5,248
Purchase of treasury stock		(9,292	)		—		—			9,292		(65,119	)		—			(65,119	)
Comprehensive net income		—			—		—			—		—			219,951			219,951
Balance, December 31, 2006		185,936			19,523		383,482			9,292		(65,119	)		195,908			533,794
Adjustment for the adoption of FASB Interpretation No. (FIN) 48		—			—		—			—		—			1,207			1,207
Exercise of stock options		802			80		2,785			—		—			—			2,865
Tax effect of share-based payments		—			—		747			—		—			—			747
Issuance of restricted stock, net of forfeitures		859			85		(85	)		—		—			—			—
Stock-based compensation expense		—			—		5,072			—		—			—			5,072
Purchase of treasury stock		(3,319	)		—		—			3,319		(22,039	)		—			(22,039	)
Comprehensive net income		—			—		—			—		—			135,874			135,874
Balance, September 30, 2007 (Unaudited)		184,278		$	19,688	$	392,001			12,611	$	(87,158	)	$	332,989		$	657,520

See accompanying notes to consolidated financial statements

-5-

GREY WOLF, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(Amounts in thousands)

(Unaudited)

	Nine Months Ended
	Six Months Ended
	September 30,
	June 30,
	2007			2006
	2008			2007
Cash flows from operating activities:
Net income	$	~~135~~63,~~874~~621		$	~~167~~100,~~426~~286
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		6854,~~166~~753			5443,~~047~~811
Deferred income taxes		1810,~~284~~814			613,~~607~~282
Gain on sale of assets		(171	)		(10,376	)
(Gain) loss on sale of assets		50			(129	)
Gain on insurance proceeds		—			(4,159	)
Stock-based compensation expense		5,256			3,290
Stock-based compensation expense		5,072			3,499
Excess tax benefit of stock option exercises and vested restricted stock		(58	)		(696	)
Excess tax benefit of stock option exercises and vested restricted stock		(708	)		(818	)
Net effect of changes in assets and liabilities related to operating accounts		37,782			30,475
Net effect of changes in assets and liabilities related to operating accounts		9,163			16,570
Cash provided by operating activities		172,218			190,319
Cash provided by operating activities		235,680			232,796
Cash flows from investing activities:
Property and equipment additions		(~~190~~96,~~131~~077	)		(~~132~~122,~~067~~842	)
Proceeds from sale of property and equipment		3,019			19,554
Deposits for new rig purchases		(5,766	)		—
Insurance proceeds		—			11,076
Merger activity costs		(4,362	)		—
Deposits for new rig purchases		(4,726	)		(15,997	)
Proceeds from sale of property and equipment		1,991			2,493
Cash used in investing activities		(~~191~~104,~~838~~214	)		(~~117~~120,~~434~~349	)
Cash flows from financing activities:
Proceeds from exercise of stock options		~~2,865~~752			2,~~704~~794
Excess tax benefit of stock option exercises and vested restricted stock		~~708~~58			~~818~~696
Purchase of treasury stock		(223,~~039~~454	)		(4911,~~180~~504	)
Cash used in financing activities		(182,~~466~~644	)		(458,~~658~~014	)
Net increase in cash and cash equivalents		2565,~~376~~360			6961,~~704~~956
Cash and cash equivalents, beginning of period		~~229~~247,~~773~~701			~~173~~229,~~145~~773
Cash and cash equivalents, end of period	$	~~255~~313,~~149~~061		$	~~242~~291,~~849~~729
Supplemental cash flow disclosure:
Cash paid for interest	$	86,~~434~~358		$	76,~~580~~505
Cash paid for taxes	$	5531,~~601~~096		$	7943,~~477~~295

See accompanying notes to consolidated financial statements

-6-

GREY WOLF, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(Unaudited)

(1) General

Grey Wolf, Inc. (the “Company” or “Grey Wolf”), a Texas corporation formed in 1980, is a holding company with no independent assets or operations. Through its subsidiaries, Grey Wolf is engaged in the business of providing onshore contract drilling services to the oil and gas industry in the United States of America and Mexico.

The accompanying unaudited consolidated financial statements have been prepared by the Company in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and include the accounts of the Company and its subsidiaries. In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments, which are of a normal recurring nature, necessary to present fairly the Company’s financial position as of June ~~September~~ 30, ~~2007~~2008 and the results of operations and cash flows for the periods indicated. All ~~intercompany~~ intercompany transactions have been eliminated. The results of operations for the three and ~~nine~~ six months ended ~~September~~ June 30, ~~2007~~2008 are not necessarily indicative of the results for any other period or for the year as a whole. Additionally, pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual ~~financial~~ financial statements in accordance with U.S. GAAP have been omitted. Therefore, these consolidated ~~financial~~ financial statements should be read in conjunction with the Company’s audited consolidated ~~financial~~ financial statements and notes thereto included in the Company’s annual report on Form 10-K for the ~~year~~ year ended December 31, ~~2006~~2007.

(2) Significant Accounting Policies

Earnings Per Share

Basic earnings per share (“EPS”) is based on the weighted average number of shares of common stock outstanding during the applicable period and excludes shares of restricted stock that have not vested. The computation of diluted earnings per share is based on the weighted average number of shares of common ~~shares~~stock outstanding during the period plus, when their effect is dilutive, ~~incremental~~ incremental shares consisting of shares subject to stock options, restricted stock and shares issuable upon conversion of the Floating Rate Contingent Convertible Senior Notes due 2024 (the “Floating Rate Notes”) and the 3.75% Contingent Convertible Senior Notes due 2023 (the “3.75% Notes” and together with the Floating Rate Notes, referred to as the “Contingent Convertible Senior Notes”).

The Company accounts for the Contingent Convertible Senior Notes using the “if converted” method set forth in the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 128 “Earnings Per Share” for calculating diluted earnings per share. Under the “if converted” method, the after-tax effect of interest expense related to the Contingent Convertible Senior Notes is added back to net income, and the convertible debt is assumed to have been converted into common stock at the beginning of the period and is added to outstanding shares.

-7-

GREY WOLF, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

The following is a reconciliation of the components of the basic and diluted earnings per share calculations for the applicable periods:

	Three Months Ended				~~Nine~~Six Months Ended
	September 30,				September 30,
	June 30,				June 30,
	2007		2006		2007		2006
	2008		2007		2008		2007
	(In thousands, except per share amounts)
Numerator:
Net income	$	3532,~~588~~298	$	5541,~~262~~708	$	~~135~~63,~~874~~621	$	~~167~~100,~~426~~286
Add interest expense on contingent convertible senior notes, net of related tax effects		21,~~094~~558		2,~~114~~059		63,~~227~~451		64,~~051~~135
Adjusted net income–diluted	$	3733,~~682~~856	$	5743,~~376~~767	$	~~142~~67,~~101~~072	$	~~173~~104,~~477~~421
Denominator:
Weighted average common shares outstanding–basic		~~182~~176,~~599~~001		~~190~~183,~~391~~009		~~182~~175,~~875~~886		~~191~~183,~~795~~016
Effect of dilutive securities
Options–treasury stock method		~~548~~716		~~746~~740		~~660~~596		~~948~~715
Restricted stock–treasury stock method		~~688~~868		~~351~~528		~~541~~748		~~357~~467
Contingent convertible senior notes		42,457		42,457		42,457		42,457
Weighted average common shares outstanding–diluted		~~226~~220,~~292~~042		~~233~~226,~~945~~734		~~226~~219,~~533~~687		~~235~~226,~~557~~655
Earnings per common share:
Basic	$	0.1918	$	0.2923	$	0.7436	$	0.8755
Diluted	$	0.1715	$	0.2519	$	0.6331	$	0.7446

A summary of securities excluded from the computation of basic and diluted earnings per share is presented below for the applicable periods (in thousands):

	Three Months Ended				~~Nine~~Six Months Ended
	September 30,				September 30,
	June 30,				June 30,
	2007		2006		2007		2006
	2008		2007		2008		2007
Basic earnings per share:
Unvested restricted stock		2,~~358,705~~870		12,~~805,533~~166		2,~~358,705~~706		12,~~805,533~~112
Diluted earnings per share:
Anti-dilutive stock options		~~1,287,613~~918		1,~~037,409~~301		1,~~288,013~~400		~~671~~1,~~725~~288
Anti-dilutive restricted stock		~~10,000~~1		—1		~~3,553~~198		—
Total anti-dilutive shares excluded from the computation of diluted earnings per share		1,297,613		1,037,409		1,291,566		671,725
Total anti-dilutive securities excluded from the computation of diluted earnings per share		919		1,302		1,598		1,288

-8-

GREY WOLF, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

Share-Based Payment Arrangements

At ~~September~~June 30, ~~2007~~2008, the Company had stock-based compensation plans with amounts outstanding to to employees and directors, which are more fully described in Note 7. ~~Prior~~The ~~to January 1, 2006, the~~ Company ~~accounted~~records for those plans under the recognition and measurement provisions of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations, as permitted by SFAS No. 123, “Accounting for Stock-Based Compensation.” Accordingly, no stock-based compensation expense ~~was~~over ~~recognized, as all options granted under those plans had an exercise price equal to~~ the ~~market~~requisite ~~value~~service ofperiod ~~the underlying common stock on the date of grant. Effective January 1, 2006, the Company adopted the fair value provisions of SFAS No. 123(R), “Share-Based Payment,”~~ using the ~~modified~~straight-~~prospective~~line ~~transition~~ method. Under that transition method, compensation expense recognized for the three and nine months ended September 30, 2007 includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested, as ofprovided ~~January 1, 2006, based on the grant date fair value estimated~~ in ~~accordance with the original provisions of~~ SFAS No. ~~123; and (b) compensation cost for all share-based payments granted~~ ~~subsequent to January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No.~~ 123(R)., ~~The Company records compensation expense over the requisite service period using the straight~~“Share-~~line~~Based ~~method~~Payment.”

The fair value of each stock option is estimated on the date of grant using the Black-Scholes-Merton option-valuation model. During the first ~~nine~~six months of ~~2007~~2008, ~~578~~885,~~220~~590 options were granted at an average exercise price of $6.6743 per share. The key input variables used in valuing these options under the Black-Scholes-Merton model were: risk-free interest rate based on three-year Treasury strips of 42.8325%; dividend yield of zero; stock price volatility of 3634.0% based on on historical volatility of the common stock with consideration given to implied volatilities from traded options on the common stock; and expected option lives of three years based on historical stock option exercise data and future expectations. Also during the first ~~nine~~six months of ~~2007~~2008, the Company granted ~~891~~1,~~460~~093,680 shares of restricted stock at a weighted-average grant-date fair value of $6.8944 per share.

Recent Accounting Pronouncements

~~The~~In ~~Company~~May 2008, ~~adopted~~ the ~~provisions~~FASB ofissued ~~Financial~~FASB ~~Accounting~~Staff ~~Standards~~Position ~~Board~~ (“~~FASB~~FSP”) ~~Interpretation~~ ~~No.~~APB ~~(“FIN”) 48~~14-1, “Accounting for ~~Uncertainty in Income Taxes,” on January 1, 2007.~~Convertible ~~FIN~~Debt 48Instruments ~~clarifies~~That ~~the~~May ~~accounting~~Be ~~for~~Settled ~~uncertainty~~ in ~~income~~Cash ~~taxes~~upon ~~recognized~~Conversion.” inThis anFSP ~~enterprise’s financial~~requires ~~statements~~entities ~~in accordance~~ with ~~Statement of Financial Accounting Standards (“SFAS”) No.~~ ~~109,~~cash ~~“Accounting~~settled ~~for~~convertibles ~~Income~~to ~~Taxes.”~~bifurcate ~~FIN 48 prescribes a recognition threshold and measurement attribute for~~ the ~~financial~~securities ~~statement~~into ~~recognition and measurement of~~ a ~~tax~~debt ~~position~~component ~~taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest~~ and ~~penalties,~~an ~~accounting~~equity ~~in interim periods, disclosure, and transition~~component and isaccrete ~~effective for fiscal years beginning after December 15, 2006. The Company analyzed filing positions in all of~~ the ~~federal~~debt ~~and~~component ~~state jurisdictions where it is required~~ to ~~file~~par ~~income~~over ~~tax returns,~~the asexpected ~~well~~life ~~as all open tax years in these jurisdictions. As a result~~ of ~~adopting FIN 48,~~ the ~~Company~~ ~~recorded an increase to beginning retained earnings, as prescribed in this interpretation, in the amount of $1~~convertible.~~2 million.~~ This ~~increase~~FSP ~~relates~~will tobe effective ~~net tax benefits~~ for ~~positions~~fiscal ~~taken~~year ~~in the Company’s income tax returns that meet the recognition criteria in FIN 48~~2009. ~~Prior~~Early ~~to the~~ adoption ofis ~~FIN~~not 48permitted, ~~these~~and ~~benefits~~the ~~were~~FSP ~~not~~must ~~recognized~~be ~~for financial statement purposes.~~applied ~~The~~retrospectively ~~Company’s policy is~~ to ~~accrue~~all ~~interest and penalties associated with uncertain tax positions in income tax expense~~instruments. AtManagement ~~January 1,~~does ~~2007,~~not nobelieve ~~interest~~this ~~and~~pronouncement ~~penalties~~will ~~were accrued in connection with~~be ~~uncertain~~applicable ~~tax positions. At September 30, 2007, there was $426,000 of interest and penalties accrued in connection with uncertain tax positions. The tax years that remain open~~ to ~~examination by~~ the ~~major taxing jurisdictions to~~Company.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” This pronouncement requires most identifiable assets, liabilities, non-controlling interests, and goodwill acquired in a business combination to be recorded at “full fair value.” The Statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under SFAS No. 141(R), all business combinations will be accounted for by applying the acquisition method. The Statement is effective for periods beginning on or after December 15, 2008 and earlier application is prohibited. SFAS No. 141(R) will be applied to business combinations occurring after the effective date.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities–Including an Amendment of FASB Statement No. 115.” This pronouncement permits entities to use the fair value method to measure certain financial assets and liabilities by electing an irrevocable option to use the fair value method at specified election dates. After election of the option, subsequent changes in fair value would result in the recognition of unrealized gains or losses as period costs during the period the change occurred. It also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. The Company adopted this standard and it did not have a material impact on the consolidated financial statements for the six months ended June 30, 2008.

-9-

GREY WOLF, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

~~which~~ In September 2006, the ~~Company~~FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS No. 157 applies to other accounting pronouncements that require or permit fair value measurements and is ~~subject~~effective ~~range~~for ~~from~~financial ~~1996~~statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. In November 2007, the FASB deferred for one year the application of the fair value measurement requirements to ~~2006~~nonfinancial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis. The Company has ~~identified~~adopted ~~its~~the ~~major~~provisions ~~taxing~~of ~~jurisdictions~~SFAS asNo. 157 related to financial assets and liabilities. The adoption did not have a material impact on the consolidated ~~United~~financial ~~States~~statements for the six months ended June 30, ~~Texas~~2008. Beginning January 1, 2009, the Company will adopt the provisions for nonfinancial assets and ~~Louisiana~~liabilities that are not required or permitted to be measured at fair value on a recurring basis, which management does not expect to have a material impact on the consolidated financial statements.

At the date of adoption, the Company had $1.4 million of unrecognized tax benefits, all of which would have an impact on the effective tax rate, net of federal tax benefits, if recognized. As of September 30, 2007, the Company had $2.0 million of unrecognized tax benefits, all of which would have an impact on the effective tax rate, net of federal tax benefits, if recognized.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements because the FASB previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, SFAS No. 157 does not require any new fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. Management is currently evaluating the requirements of SFAS No. 157 and has not yet determined the impact on the consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115.” This pronouncement permits entities to use the fair value method to measure certain financial assets and liabilities by electing an irrevocable option to use the fair value method at specified election dates. After election of the option, subsequent changes in fair value would result in the recognition of unrealized gains or losses as period costs during the period the change occurred. It also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007. Management is currently evaluating the requirements of SFAS No. 159 and has not yet determined the impact on the consolidated financial statements.

(3) Accounting for Income Taxes

The Company records deferred taxes utilizing an asset and liability approach. This method gives consideration to the future tax consequences associated with differences between the financial accounting and tax basis of assets and liabilities. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The Company and its domestic subsidiaries file a consolidated federal income tax return and foreign subsidiaries file returns in the appropriate jurisdictions.

The Company currently believes that it is more likely than not that future earnings and reversal of deferred tax liabilities will be sufficient to permit the Company to utilize its domestic deferred tax assets recorded at ~~September~~June 30, ~~2007~~2008. The Company has $2.1 million of net operating losses (“NOL’s”) related to its Mexico operations. These NOL’s are not expected to be realized due to the level of future taxable income, and as such a valuation allowance has been applied to the full amount of NOL’s.

The Company follows the provisions of FASB Interpretation No. (“FIN”) 48, “Accounting for Uncertainty in Income Taxes.” As of June 30, 2008, there were $1.5 million of unrecognized tax benefits, all of which could have an impact on the effective tax rate, net of federal tax benefits, if recognized. The Company’s policy is to accrue interest and penalties associated with uncertain tax positions in income tax expense. At June 30, 2008, there was $402,000 of interest and penalties accrued in connection with uncertain tax positions. The tax years that remain open to examination by the major taxing jurisdictions to which the Company is subject range from 1996 to 2007. The Company’s major taxing jurisdictions have been identified as the United States, and the states of Texas, Louisiana and Colorado.

-10-

GREY WOLF, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

(4) Long-Term Debt

Long-term debt consists of the following (amounts in thousands):

	September 30,		December 31,
	June 30,		December 31,
	2007		2006
	2008		2007
3.75% Contingent Convertible Senior Notes due May 2023	$	150,000	$	150,000
Floating Rate Contingent Convertible Senior Notes due April 2024		125,000		125,000
		275,000		275,000
Less current maturities		—		—
Long-term debt	$	275,000	$	275,000

3.75% Notes

The 3.75% Notes bear interest at 3.75% per annum and mature on May 7, 2023. The 3.75% Notes are convertible into shares of common stock, upon the occurrence of certain events, at a conversion price of $6.45 per share. The Company will be required to pay contingent interest at a rate equal to 0.50% per annum commencing May 7, 2008 upon the occurrence of certain events. The 3.75% Notes are general unsecured senior obligations of the Company and are fully and unconditionally guaranteed, on a joint and several basis, by all domestic wholly-owned subsidiaries of the Company. Non-guarantor subsidiaries are not significant.

~~The~~If ~~Company~~the ~~may~~average ~~redeem~~trading inprice ~~cash some or all~~ of the 3.75% Notes atper ~~any~~$1,000 ~~time~~principal onamount orfor ~~after~~the ~~May 14,~~five ~~2008,~~trading atday ~~various~~period ~~redemption~~ending ~~prices~~on ~~depending~~the ~~upon~~third ~~the~~trading ~~date~~day ~~redeemed~~immediately ~~plus~~preceding ~~accrued~~the ~~but~~first ~~unpaid~~day of the ~~interest,~~applicable ~~including~~six-month ~~contingent~~period ~~interest.~~(as ~~Holders~~defined ~~may~~below) ~~require~~equals $1,200 or more, the Company would be required to ~~repurchase~~pay ~~all~~contingent orinterest. Contingent interest would be payable at a ~~portion~~ ofrate ~~the~~equal 3to 0.7550% ~~Notes~~per annum onduring ~~May 7,~~any ~~2013~~six-month orperiod, from May 7, ~~2018,~~7th ~~and~~to ~~upon~~November a6th ~~change~~and offrom ~~control,~~November as7th ~~defined~~to May 6th, inwith the ~~indenture~~initial ~~governing~~six-month ~~the~~period ~~3.75%~~commencing ~~Notes~~May 7, at2008. ~~100%~~For the period of ~~the~~May 7, ~~principal~~2008 ~~amount~~to November 6, of2008 the 3.75% ~~Notes, plus~~notes ~~accrued~~did ~~but~~not ~~unpaid~~trade ~~interest,~~at ~~including~~or ~~contingent~~above ~~interest~~$1,200 iffor ~~any, to~~ the ~~date~~time ofperiod ~~repurchase,~~required and ~~payable~~therefore, inno ~~cash~~contingent interest is payable.

AsThe ofCompany ~~July 1,~~may ~~2007~~redeem ~~and~~in ~~through~~cash ~~September 30,~~some ~~2007,~~or all of the 3.75% Notes ~~were~~at ~~convertible~~any ~~into shares~~time ofon ~~common~~or ~~stock~~after ~~because~~May 14, 2008, ~~one~~at ofvarious ~~the~~redemption ~~triggering~~prices ~~events~~depending ~~permitting~~upon ~~note~~the ~~holders~~date toredeemed ~~convert their~~plus ~~3.75%~~accrued ~~Notes~~but ~~occurred~~unpaid interest, ~~during~~including ~~the~~contingent ~~second~~interest. ~~quarter~~As of ~~2007.~~June 30, ~~The~~2008, ~~triggering~~the ~~event~~Company ~~was~~has ~~that~~not ~~the closing~~elected ~~price~~to ~~per~~redeem any ~~share~~ of ~~common~~the ~~stock~~3.75% ~~exceeded~~Notes. ~~110%~~Holders ofmay require the ~~conversion~~Company ~~price~~to ~~($7.10~~repurchase ~~per~~all ~~share)~~or a portion of the 3.75% Notes ~~for~~on atMay 7, ~~least~~2013 20or ~~trading~~May 7, ~~days~~2018, inand ~~the~~upon ~~period~~a change of 30control, ~~consecutive~~as ~~trading~~defined ~~days~~in ~~ended~~the onindenture ~~June 30,~~governing ~~2007~~the 3.75% ~~As of September 30~~Notes, ~~2007,~~at ~~none~~100% of the ~~note~~principal ~~holders~~amount ~~exercised~~of ~~their right to convert~~ the 3.75% Notes, ~~into~~plus ~~shares~~accrued but unpaid interest, including contingent interest, if any, to the date of ~~common~~repurchase, ~~stock~~payable in cash.

The ~~price~~3.75% Notes are convertible into shares of common stock, ~~during~~upon the ~~three~~occurrence ~~months~~of ~~ended~~certain events, ~~September~~at a conversion price of $6.45 per share. As of July 301, ~~2007~~2008, ~~did~~and ~~not~~at ~~meet~~any time during the ~~criteria~~third ~~that~~quarter ~~would~~of ~~allow~~2008, the 3.75% Notes are convertible into shares of the Company’s common stock because the closing price per share of the Company’s common stock exceeded 110% of the conversion price ($7.10 per share) of the 3.75% Notes for at least 20 trading days in the period of 30 consecutive trading days ended on June 30, 2008. Between July 7, 2008 and July 8, 2008, two note holders exercised their right to beconvert ~~converted~~$275,000 in principal amount of the notes into approximately 42,600 shares of the Company’s common stock, ~~during~~reducing the ~~fourth quarter~~aggregate principal amount of ~~2007~~the outstanding 3.75% Notes to $149.7 million. The 3.75% Notes will cease to be convertible after September 30, 2008, unless the trading price

Floating Rate Notes

The Floating Rate Notes bear interest at a per annum rate equal to 3-month LIBOR, adjusted quarterly, minus a spread of 0.05%. The per annum interest rate will never be less than zero or more than

-11-

GREY WOLF, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

~~6.00%.~~of ~~For~~ the ~~three~~Company’s ~~months~~common ~~ended~~stock ~~September 30,~~again ~~2007~~exceeds ~~and~~(as it ~~2006,~~did in the ~~interest~~second ~~rate~~quarter) on110% of the ~~Floating~~ ~~Rate~~conversion ~~Notes~~price ~~was~~of ~~5.31%~~the ~~and 5~~3.4675%, ~~respectively.~~Notes ~~The~~for ~~Floating~~at ~~Rate~~least ~~Notes~~20 trading ~~mature~~days onin ~~April 1, 2024~~the ~~and~~period ~~are~~of ~~convertible~~30 ~~into~~consecutive ~~shares~~trading ofdays ~~common~~on ~~stock,~~the ~~upon~~last ~~the~~trading ~~occurrence~~day of ~~certain~~the ~~events, at a~~third ~~conversion~~quarter ~~price~~ of $62008.51 ~~per~~In ~~share.~~that ~~The~~event, ~~Floating~~the ~~Rate~~3.75% Notes ~~are~~would ~~general~~remain ~~unsecured~~convertible ~~senior~~through the fourth ~~obligations~~quarter of ~~the~~2008. ~~Company~~The ~~and~~3.75% ~~are~~Notes ~~fully~~may ~~and~~also ~~unconditionally~~become ~~guaranteed,~~convertible on(or aremain ~~joint~~convertible) ~~and~~in ~~several~~the fourth ~~basis,~~quarter byor ~~all~~other ~~domestic~~future ~~wholly-owned~~periods ~~subsidiaries~~if any of the ~~Company.~~other ~~Non-guarantor~~events ~~subsidiaries~~that ~~are~~entitle ~~not~~holders to convert the ~~significant~~3.75% Notes occur.

Floating Rate Notes

The Floating Rate Notes bear interest at a per annum rate equal to 3-month LIBOR, adjusted quarterly, minus a spread of 0.05%. The per annum interest rate will never be less than zero or more than 6.00%. For the three months ended June 30, 2008 and 2007, the interest rate on the Floating Rate Notes was 2.65% and 5.30%, respectively. These notes mature on April 1, 2024. The Floating Rate Notes are general unsecured senior obligations of the Company and are fully and unconditionally guaranteed, on a joint and several basis, by all domestic wholly-owned subsidiaries of the Company. Non-guarantor subsidiaries are not significant.

The Company may redeem some or all of the Floating Rate Notes at any time on or after April 1, 2014, at a redemption price equal to 100% of the principal amount of the Floating Rate Notes, plus accrued but unpaid interest and liquidated damages, if any, to the date of repurchase, payable in cash. Holders may require the Company to repurchase all or a portion of the Floating Rate Notes on April 1, 2014 or April 1, 2019, and upon a change of control, as defined in the indenture governing the Floating Rate Notes, at 100% of the principal amount of the Floating Rate Notes, plus accrued but unpaid interest and liquidated damages, if any, to the date of repurchase, payable in cash.

AsThe ~~of July 1, 2007 and through September 30, 2007, the~~ Floating Rate Notes ~~were~~are convertible into shares of common stock, ~~because~~upon ~~one~~the occurrence of certain ~~the~~events, ~~triggering~~at ~~events~~a ~~permitting~~conversion ~~note~~price ~~holders~~of to$6.51 ~~convert their~~per ~~Floating~~share. ~~Rate~~As ~~Notes~~of ~~occurred~~July 1, 2008, and at any time during the ~~second~~third quarter of ~~2007.~~2008, ~~The~~the ~~triggering~~Floating ~~event~~Rate ~~was~~Notes ~~that~~are convertible into shares of the Company’s common stock because the closing price per share of the Company’s common stock exceeded 120% of the conversion price ($7.81 per share) of the Floating Rate Notes for at least 20 trading days in the period of 30 consecutive trading days ended on June 30, ~~2007~~2008. AsThe ofFloating Rate Notes will cease to be convertible after September 30, ~~2007~~2008, ~~none~~unless the trading price of the ~~note~~Company’s common ~~holders~~stock ~~exercised~~again ~~their~~exceeds (as it did in the second quarter) 120% of the conversion price of the ~~right~~Floating toRate ~~convert~~Notes for at least 20 trading days in the period of 30 consecutive trading days on the last trading day of the third quarter of 2008. In that event, the Floating Rate Notes ~~into~~would remain ~~shares~~convertible through the fourth quarter of ~~common~~2008. ~~stock~~The Floating Rate Notes may also become convertible (or remain convertible) in the fourth quarter or other future periods if any of the other events that entitle holders to convert the Floating Rate Notes occur.

The price of common stock during the three months ended September 30, 2007 did not meet the criteria that would allow the Floating Rate Notes to be converted into common stock during the fourth quarter of 2007.

CIT Facility

The Company’s subsidiary Grey Wolf Drilling Company L.P. has a $100.0 million credit facility with the CIT Group/Business Credit, Inc. (the “CIT Facility”) which expires December 31, 2008. The CIT Facility provides the Company with the ability to borrow up to the lesser of $100.0 million or 50% of the Orderly Liquidation Value (as defined in the agreement) of certain drilling rig equipment located in the 48 contiguous states of the United States of America. Periodic interest payments are due at a floating rate based upon the Company’s debt service coverage ratio within a range of either LIBOR plus 1.75% to 3.50% or prime plus 0.25% to 1.50%. The CIT Facility provides up to $50.0 million available for letters of credit. The Company is required to pay a quarterly commitment fee ofranging from 0.375% to 0.50% per ~~annum on the unused portion of the CIT Facility. Letters of~~ credit accrue a fee of 1.25% per annum. These amounts are included in interest expense for the periods presented. The CIT Facility contains affirmative and negative covenants and the Company is in compliance with these covenants. Substantially all of the Company’s assets, including its drilling equipment, are pledged as collateral under the CIT Facility which is also guaranteed by the Company and certain of the Company’s wholly-owned subsidiaries.

The CIT Facility allows the Company to repurchase shares of its common stock, pay dividends to its shareholders, and make prepayments on the Contingent Convertible Senior Notes. However, all of the following conditions must be met to enable the Company to make payments for any of the above-mentioned reasons: (i) payments may not exceed $150.0 million in the aggregate, (ii) no Default or Event of Default shall exist at the time of any such payments, (iii) at least $35.0 million of Availability (availability under the CIT Facility plus cash on hand) exists immediately after any such payments, and

-12-

GREY WOLF, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

~~(iv) the~~annum ~~Company~~on ~~must~~the ~~provide~~unused ~~CIT~~portion ~~Group/Business~~of ~~Credit,~~the ~~Inc.~~CIT ~~three~~Facility. ~~Business~~Letters ~~Days~~of ~~prior~~credit ~~written~~accrue ~~notice~~a fee of ~~any~~1.25% ~~such~~per ~~payments~~annum. ~~Capitalized~~These ~~terms~~amounts ~~used~~are included in interest expense for the ~~preceding~~periods presented. The CIT Facility contains affirmative and negative covenants and the ~~sentence~~Company ~~but~~is ~~not~~in ~~defined~~compliance ~~herein~~with these covenants. Substantially all of the Company’s assets, including its drilling equipment, are ~~defined~~pledged inas collateral under the CIT Facility which is also guaranteed by the Company and certain of the Company’s wholly-owned subsidiaries.

The CIT Facility allows the Company ~~currently~~to ~~has~~repurchase noshares ~~outstanding~~of ~~balance~~its ~~under~~common ~~the~~stock, ~~CIT~~pay ~~Facility~~dividends to its shareholders, and ~~had~~make ~~$30~~prepayments on the Contingent Convertible Senior Notes.~~9 million of~~ ~~undrawn~~However, ~~standby~~all ~~letters~~of the following conditions must be met to enable the Company to make payments for any of ~~credit~~the above-mentioned atreasons: ~~September~~(i) ~~30,~~payments ~~2007.~~may ~~These~~not ~~standby~~exceed ~~letters~~$150.0 million ofin ~~credit~~the ~~are~~aggregate, (ii) no ~~for~~Default ~~the~~or ~~benefit~~Event of ~~various~~Default ~~insurance~~shall ~~companies~~exist asat ~~collateral~~the ~~for~~time ~~premiums~~of ~~and~~any ~~losses~~such ~~which~~payments, ~~may~~(iii) at least $35.0 ~~become~~million ~~payable~~of Availability (availability under the ~~terms~~CIT ofFacility plus cash on hand) exists immediately after any such payments, and (iv) the ~~underlying~~Company ~~insurance~~must ~~contracts~~provide CIT Group/Business Credit, Inc. ~~Outstanding~~three Business ~~letters~~Days prior written notice of ~~credit reduce~~any such payments. Capitalized terms used in the ~~amount~~preceding sentence ~~available~~but ~~for~~not ~~borrowing~~defined ~~under~~herein are defined in the CIT Facility.

The Company currently has no outstanding balance under the CIT Facility and had $30.9 million of undrawn, standby letters of credit at June 30, 2008. These standby letters of credit are for the benefit of various insurance companies as collateral for premiums and losses which may become payable under the terms of the underlying insurance contracts. Outstanding letters of credit reduce the amount available for borrowing under the CIT Facility.

(5) Segment Information

~~Prior~~The toCompany ~~the~~manages ~~third~~its ~~quarter~~business ofthrough ~~2007,~~two ~~the~~reportable ~~Company~~segments. ~~managed~~The ~~its~~domestic ~~business~~and ~~as one reportable~~Mexican ~~segment.~~operations ~~Although~~are ~~the~~considered ~~Company~~separate ~~provided~~segments ~~onshore~~as ~~contract~~a ~~drilling~~result ~~services~~of differences in ~~several~~economic ~~markets~~characteristics, separate ~~these~~regulatory environments, and different types of customers being served. Domestic operations were aggregated into one reportable segment based on the similarity of economic characteristics among all markets, including the nature of the services provided and the type of customers of such services. Intersegment revenue is eliminated in consolidation.

During the third quarter of 2007, the Company began drilling operations in Mexico. The domestic and Mexican operations are considered separate segments as a result of differences in economic characteristics, separate regulatory environments, and different types of customers being served. Domestic operations were aggregated into one reportable segment based on the similarity of economic characteristics among all markets, including the nature of the services provided and the type of customers of such services. Intersegment revenue is eliminated in consolidation.

-13-

GREY WOLF, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

The following tables set forth certain financial information with respect to the Company’s reportable segments (in thousands):

	Three Months Ended					~~Nine~~Six Months Ended
	September 30,					September 30,
	June 30,					June 30,
	2007			2006		2007			2006
	2008			2007		2008			2007
Revenue
United States	$	~~220~~209,~~713~~862		$	~~242~~227,~~728~~520	$	~~690~~405,~~062~~463		$	~~705~~469,~~197~~533
Mexico		36,~~286~~845			—		312,~~470~~766			—
Total revenue	$	~~223~~216,~~999~~707		$	~~242~~227,~~728~~520	$	~~693~~418,~~532~~229		$	~~705~~469,~~197~~533
Operating Income
United States	$	5651,~~473~~017		$	8765,~~041~~733	$	~~215~~101,~~233~~036		$	~~264~~158,~~535~~033
Mexico		~~(491~~510	)		—		(12,~~218~~096	)		—
Total operating income	$	5551,~~982~~527		$	8765,~~041~~733	$	~~214~~103,~~015~~132		$	~~264~~158,~~535~~033

	As of		As of
	September 30,		December 31,
	2007		2006
Assets
United States	$	1,205,184	$	1,086,984
Mexico		13,867		—
Total assets	$	1,219,051	$	1,086,984

(6) Contingencies

The Company is involved in litigation incidental to the conduct of its business, none of which management believes is, individually or in the aggregate, material to the Company’s consolidated financial condition or results of operations.

(7) Capital Stock and Option Plans

The 2003 Incentive Plan (the “2003 Plan”) was approved by the Company’s shareholders in May 2003. The 2003 Plan authorizes the grant of the following equity-based awards:

	•		incentive stock options;

	•		non-statutory stock options;

	•		restricted shares; and

	•		other stock-based and cash awards.

The 2003 Plan replaced the Company’s 1996 Employee Stock Option Plan (the “1996 Plan”) but all outstanding awards previously granted under the 1996 Plan will continue to be exercisable subject to the terms and conditions of such grants. The 1996 Plan allowed for grants of non-statutory options to purchase shares of common stock, but no further grants of common stock will be made under the 1996 Plan. The 2003 Plan reserves a maximum of 22.0 million shares of common stock underlying all equity-based awards, which includes an additional 5.0 million shares that were approved by shareholders in 2007 and is reduced by the number of shares subject to previous grants under the 1996 Plan. At June 30, 2008, there were 5.4 million shares of common stock available for grant under the 2003 Plan until March 2013. Prior to 2003, the Company also granted options under stock option agreements with its outside directors that are outside of the 1996 Plan and the 2003 Plan. At June 30, 2008, these individuals had options outstanding to purchase an aggregate of 700,500 shares of common stock.

-14-

GREY WOLF, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

and is reduced by the number of shares subject to previous grants under the 1996 Plan. At September 30, 2007, there were 7.4 million shares of common stock available for grant under the 2003 Plan until March 2013. Prior to 2003, the Company also granted options under stock option agreements with its outside directors that are outside of the 1996 Plan and the 2003 Plan. At September 30, 2007, these individuals had options outstanding to purchase an aggregate of 700,500 shares of common stock.

The exercise price of stock options approximates the fair market value of the stock at the time the option is granted. A portion of the outstanding options became exercisable upon issuance and the remaining become exercisable in varying increments over three to five year periods. The options expire on the tenth anniversary of the date of grant.

As of ~~September~~June 30, ~~2007~~2008, the Company had 2.48 million shares of restricted stock outstanding ~~under~~ under the 2003 Plan, which vest over periods of three to five years. Each share of restricted stock entitles the holder to one vote and the shares are only restricted due to time-related vesting conditions.

As discussed in Note 2, the Company records expense for the value of stock options and restricted stock on a straight-line basis over the vesting period in accordance with SFAS No. 123(R).

(8) Treasury Stock

On May 25, 2006, the Company announced that its Board of Directors approved a plan authorizing the repurchase of up to $100.0 million in shares of common stock in open market or in privately negotiated block-trade transactions. On September 25, 2007, the Company announced that its Board of Directors authorized a $50.0 million increase in the common stock repurchase program. The number of of shares purchased and the timing of purchases is based on several factors, including the price of the common stock, general market conditions, available cash and alternate investment opportunities. The stock repurchase program is subject to termination prior to completion. As of ~~September~~June 30, ~~2007,~~ 2008, the Company has repurchased 1219.50 million shares under this program at a total price of $86122.~~4 million, inclusive~~5 ~~of commissions, under this program~~million. For the ~~nine~~six months ended ~~September~~June 30, ~~2007~~2008, the Company repurchased ~~3.2 million~~399,000 shares at a total price of $212.31 million ~~under this program~~.

The Company also ~~had~~has treasury shares that were acquired through the vesting of restricted stock. The Company’s employees ~~elected~~may elect to have shares withheld to cover required minimum payroll tax withholdings incurred when restricted stock vests. The number of shares withheld is based upon the market price of the common stock at the time of vesting. The Company then pays the taxes on ~~the~~ the employees’ behalf and ~~holds~~records the shares withheld as treasury stock. For the ~~nine~~six months ended ~~September~~June 30, ~~2007~~2008, approximately ~~108~~211,000 shares were acquired through such treasury share purchases at a cost of $1.3 million.

(9) Concentrations

~~Substantially~~The ~~all~~majority of the Company’s contract drilling activities are conducted with independent ~~and~~ and major oil and gas companies in the United States. Historically, the Company has not required collateral or other security to support the related receivables from such customers. However, the Company has required certain customers to deposit funds in escrow prior to the commencement of drilling. Actions typically taken by the Company in the event of nonpayment include filing a lien on the customer’s producing property and filing a lawsuit against the customer.

For the ~~three~~six ~~and nine~~ months ended ~~September~~June 30, ~~2007~~2008 and ~~2006~~2007, there were no customers representing greater than 10% of the Company’s revenue.

-15-

GREY WOLF, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)

(10) Subsequent ~~Insurance Recoveries~~Event

~~The~~On ~~Company~~April 21, ~~maintains~~2008, ~~insurance~~the ~~coverage~~Company toannounced ~~protect~~that ~~against~~its ~~certain~~board ~~hazards~~of ~~inherent~~directors inapproved a definitive ~~contract~~agreement ~~drilling~~with ~~operations.~~Basic ~~During~~Energy ~~the~~Services, ~~first~~Inc. ~~quarter~~(“Basic”) ofto ~~2006,~~combine the ~~Company~~two ~~experienced~~businesses in a ~~fire~~“merger ~~on one~~ of ~~its~~equals” ~~2,000~~transaction. ~~horsepower~~On ~~diesel~~July 15, 2008, ~~electric~~the ~~rigs,~~Company ~~which~~announced ~~was~~that ~~drilling~~its ~~under~~proposed amerger ~~daywork~~with ~~contract~~Basic ~~in Louisiana.~~did ~~The~~not ~~fire~~receive ~~resulted~~sufficient invotes from aits ~~total~~shareholders ~~loss~~to ofapprove the ~~rig~~transaction ~~and~~at ~~one~~its special meeting of shareholders. As a result, the ~~Company’s~~merger ~~top~~agreement ~~drives~~with ~~which~~ Basic was ~~being~~terminated ~~used~~ on ~~this~~that ~~rig~~day. The Company ~~filed~~expects ato ~~claim~~take ~~with~~a pre-tax ~~its~~charge ~~insurance~~to ~~carriers~~earnings toof ~~recoup~~approximately ~~this loss~~$17.0 million ~~The~~during ~~net~~the ~~book~~third ~~value~~quarter of ~~the~~2008 ~~rig~~related to ~~and~~transaction ~~top~~costs ~~drive~~incurred ~~was~~in ~~$6.9 million~~connection atwith the ~~time~~merger ofactivities. ~~the~~This ~~loss.~~includes ~~The~~a $5.0 ~~Company~~million ~~recorded~~termination afee ~~gain~~payable ofto Basic and approximately $4.24 million of costs recorded in other non-current assets at June 30, 2008. Should the ~~second~~Company ~~quarter~~enter into an agreement of ~~2006~~similar ~~resulting~~nature with ~~from~~another company within one year of the ~~excess~~termination date of the ~~insurance~~agreement ~~proceeds~~with ~~over~~Basic, the company ~~net~~may ~~book~~be ~~value~~required to pay Basic an additional $25.0 million fee upon consummation of the subsequent transaction.

In the third quarter of 2006, the Company encountered difficulties on a well being drilled under one of the turnkey contracts. The cost associated with the difficulties is covered by the Company’s insurance subject to a deductible of $1.4 million. The costs incurred through September 30, 2007 totaled approximately $8.7 million, of which $7.2 million is expected to be recovered through the Company’s insurance after satisfaction of the deductible. As of September 30, 2007, the Company has recorded a receivable of $2.7 million in connection with this claim.

In the second quarter of 2007, the Company encountered difficulties on a well being drilled under one of the turnkey contracts. The cost associated with the difficulties is covered by the Company’s insurance, subject to a deductible of $375,000. The costs incurred through September 30, 2007 totaled approximately $2.5 million, of which $2.1 million is expected to be recovered through the Company’s insurance after satisfaction of the deductible. As of September 30, 2007, none of the $2.1 million was collected.

The Company has a total insurance receivable of $4.8 million at September 30, 2007 for uncollected costs.

(11) Asset Sales

During the first quarter of 2006, the Company sold five of its rigs formerly held for refurbishment for $15.3 million. The sale resulted in a pre-tax gain of $9.4 million.

-16-

~~GREY WOLF, INC~~Item 2. ~~AND SUBSIDIARIES~~ Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere herein and with our audited consolidated financial statements and accompanying notes included in our annual report on Form 10-K for the year ended December 31, ~~2006~~2007.

Overview

We are a leading provider of contract oil and gas land drilling services in the United States. As of ~~October~~July 31, ~~2007~~2008, we had a fleet of ~~121~~122 rigs. Our customers include independent producers and major oil and gas companies. We conduct substantially all of our operations through our subsidiaries. inOur ~~what~~business weis ~~believe~~cyclical and our financial results depend upon several factors. These tofactors beinclude the ~~best~~overall ~~natural~~demand ~~gas~~for ~~producing~~land ~~regions~~drilling inservices, the ~~United~~dayrates ~~States~~we receive for our services, the level of demand for turnkey services, and our success drilling turnkey wells.

Our business is cyclical and our financial results depend upon several factors. These factors include the overall demand for land drilling services, the dayrates we receive for our services, the level of demand for turnkey services, our success drilling turnkey wells and the demand for deep versus shallow drilling services.

We make available free of charge through our website our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with the Securities and Exchange Commission (the “SEC”). Information on our website is not a part of this report. Our website address is www.gwdrilling.com.

~~New~~Termination ~~Rig~~of ~~Purchases~~Definitive Merger Agreement and ~~Reactivations~~Review of Strategic Alternatives

InOn ~~September~~April ~~2007~~20, we2008, ~~entered~~our ~~into~~board ~~three-year~~of ~~term~~directors ~~contracts~~approved ~~with~~a ~~two~~definitive ~~exploration~~merger ~~and production~~agreement ~~companies~~with toBasic Energy ~~deploy two new 1~~Services,~~500~~ ~~horsepower built-for-purpose rigs~~Inc. ~~With~~(“Basic”), ~~deliveries expected~~a inmajor ~~the~~well ~~second~~site ~~and~~services ~~third quarters of 2008~~provider, ~~these rigs are designed~~ to ~~drill~~combine ~~multiple wells from~~ the ~~same~~two ~~location. The expected purchase price per rig is approximately $21.0 million, and~~businesses ~~these rigs will be deployed~~ in ~~the~~a ~~Rocky~~“merger ~~Mountain~~of ~~market~~equals” transaction. InOn July ~~2007~~15, ~~we purchased two 1~~2008,~~500 horsepower~~ ~~rigs~~we ~~from~~announced athat ~~privately~~our ~~owned~~proposed ~~exploration~~merger ~~and production company. The cash purchase price~~with ~~for~~Basic ~~the~~did ~~two~~not ~~rigs,~~receive ~~which~~sufficient ~~were~~votes ~~manufactured~~from inGrey ~~2006,~~Wolf ~~was~~shareholders ~~$28.0 million,~~to orapprove ~~approximately 80% of~~ the ~~current~~ ~~cost to build comparable rigs~~transaction. ~~Concurrent~~As a ~~with the purchase~~result, weGrey ~~signed~~Wolf aand ~~term~~Basic ~~contract totaling~~terminated ~~1,095~~their ~~rig~~merger ~~days~~agreement ~~for~~on ~~each~~that ofday. ~~the~~We ~~rigs~~expect ~~purchased~~ to ~~provide~~take ~~drilling~~a pre-tax ~~services~~charge to ~~the~~earnings ~~seller. We assumed operation~~ of ~~the~~approximately ~~rigs July~~$17.0 1,million ~~2007~~during ~~and~~the ~~they~~third ~~are~~quarter ~~operating in East Texas. Both~~ of ~~the~~2008 related ~~rigs~~to ~~are~~transaction ~~1,500~~costs ~~horsepower~~incurred ~~diesel~~in ~~electric~~connection ~~SCR~~with ~~rigs~~the ~~capable~~merger ofactivities. ~~drilling~~This upincludes toa ~~18,000 feet~~$5.0 ~~Additionally,~~million wetermination ~~recently~~fee ~~constructed~~paid ato ~~1,000~~Basic ~~horsepower~~and ~~diesel~~approximately ~~electric~~$4.4 million ~~SCR rig capable~~ of ~~drilling~~ tocosts ~~15,000~~recorded ~~feet.~~in ~~The rig has been deployed under a two~~other non-~~year~~current ~~term~~assets ~~contract~~at ~~and~~June 30, ~~is currently working in the Rocky Mountain market~~2008. ~~During~~Should ~~2006,~~ we ~~entered~~enter into ~~agreements~~an toagreement ~~purchase six new 1,500 horsepower rigs for a total~~ of ~~$91.6 million~~similar ~~and~~nature aswith another ofcompany ~~October 31,~~within ~~2007,~~one ~~all~~year of ~~these~~the ~~rigs are~~termination ~~working.~~date ~~All eight~~ of ~~the~~our ~~recently~~agreement ~~purchased~~with ~~rigs~~Basic, ~~the~~we ~~rig~~may ~~recently constructed, the two~~be ~~built-for-purpose~~required ~~rigs expected~~ to bepay ~~deployed~~Basic inan ~~2008~~additional ~~and the 17 rig refurbishments completed over the last several years were supported by long-term contracts~~$25.0 million ~~The~~fee ~~Company~~upon ~~expects~~consummation ~~to recover substantially all~~ of the ~~cumulative cost of the capital expended for these rigs over the term of their~~subsequent ~~long-term contracts~~transaction.

~~Also~~In inlight ~~September 2007~~of this development, weour ~~announced~~Board ~~that~~of ~~the~~Directors ~~component~~plans ~~parts~~to ofreview ~~three~~alternatives offor enhancing shareholder value. This review will include an update to our ~~marketed~~existing ~~rigs~~strategic plan and will beencompass ~~utilized~~consideration asof ~~spare~~continued ~~equipment.~~internal ~~These~~growth ~~rigs~~by ~~are~~remaining ~~low~~independent, ~~horsepower~~acquisitions, mergers, ~~mechanical~~sale ~~rigs~~of ~~located~~the inCompany, ~~the~~strategic alliances, joint ventures and financial alternatives. The ~~Rocky~~Board ~~Mountain~~has ~~market~~engaged UBS Investment Bank as its independent financial advisor to assist us in conducting this review. ~~With~~We ~~the~~can ~~addition~~give ofno assurance that the ~~rigs~~review will result in any specific transaction and ~~the~~no ~~transfer~~timetable ofhas ~~the~~been ~~three~~set ~~rigs~~for its completion. We expect to ~~spare~~incur additional costs ~~equipment~~in connection with the strategic review, ~~our~~an ~~fleet~~amount for which is ~~expected~~not currently determinable. We do not intend to ~~total~~disclose ~~123~~developments ~~rigs~~relating byto ~~the~~this ~~end~~review unless and until our Board of ~~the~~Directors approves ~~third~~a ~~quarter~~specific ~~2008~~agreement or transaction.

New Rig Purchases

In September 2007, we entered into three-year term contracts with two exploration and production companies to deploy two new 1,500 horsepower built-for-purpose rigs. These rigs are designed to drill multiple wells from a single well site location. One of these rigs began working in July 2008 and the remaining rig is expected to be delivered and begin working in the fourth quarter of 2008. The expected purchase price per rig is approximately $22.2 million, and these rigs will be deployed in the Rocky Mountain market. The Company expects to recover the majority of the cost of the capital

-17-

expended for these rigs over their initial long-term contracts. With the addition of these rigs, our fleet is expected to total 123 rigs by the end of 2008.

Rig Activity

The ~~U.S.~~ land rig count atper ~~October 26,~~Baker ~~2007,~~Hughes ~~per~~has ~~the~~continued ~~Baker~~to ~~Hughes~~increase ~~rotary~~from ~~rig~~a ~~count,~~low ~~was~~in 2007 of 1,~~680~~610 rigs to 1,864 rigs ~~and~~on ~~has~~July 25, ~~remained~~2008. ~~relatively~~The ~~stable~~influx ~~over~~of ~~the~~newly-built ~~past~~land ~~year~~drilling atrigs ~~historically~~during ~~high~~the ~~levels.~~last ~~However,~~two ~~there~~years iscreated ~~currently~~ some excess capacity in the land drilling market. ~~with~~This ~~the~~new ~~addition~~build ofactivity ~~new rigs~~has lessened considerably during the ~~last~~first ~~year~~half of 2008. ~~Our~~The ~~average~~excess ~~rigs~~capacity ~~working~~of ~~declined~~rigs in the ~~third~~market ~~quarter~~has pressured ofthe ~~2007~~average ~~because~~number of ~~this~~ ~~excess capacity of~~ rigs inwe ~~the~~have ~~market~~working. WeOur ~~believe~~long-term ~~that~~contract weportfolio ~~are~~ has partially protected us from ~~this decline~~the bydeclines ~~our~~in ~~significant~~the ~~long-term~~land ~~contract~~drilling ~~portfolio~~market and bolstered our results. ~~For~~We have ~~the~~recently ~~week~~seen ~~ended~~an ~~October 26,~~increase ~~2007~~in our average rigs running, ~~we had~~with an average of ~~104~~112 rigs ~~working~~for the week ended July 25, 2008. The table below shows the average number of land rigs working in the United States according to the Baker Hughes rotary rig count and the average number of our ~~rigs~~ rigs working.

Domestic

~~2005~~2006

~~2006~~2007

~~2007~~2008

Land Rig

Full

7/1

~~10/1 -~~

Count

Year

Q-1

Q-2

Q-3

Q-4

Year

Q-1

Q-2

~~Q-3~~to 7/25

~~10/31~~

Baker Hughes

1,~~263~~535

1,~~417~~626

1,~~512~~653

1,~~603~~691

1,~~609~~705

1,~~535~~669

1,~~626~~690

1,~~653~~775

1,~~691~~842

~~1,685~~

Grey Wolf

~~102~~108

~~109~~110

~~108~~104

~~107~~104

~~110~~103

~~108~~105

~~110~~100

~~104~~105

~~104~~109

~~103~~

Term Contracts

We endeavor to enter into term contracts to provide drilling services on a daywork basis. Typically, the length of our term contracts ranges from six months to three years. They usually include a per rig day cancellation fee approximately equal to the dayrate under the contract less estimated contract drilling operating expenses for the unexpired term of the contract. In addition, we are able to pass ~~any~~most increases in labor costs on to our customers through our dayrates on all daywork contracts, including term contracts. We seek term contracts with our customers when we believe that those contracts may mitigate the financial impact to us of a potential decline in dayrates during the period in which the term contract is in effect. This provides greater stability to our business and allows us to plan and manage our business more efficiently. We also have used term contracts to contractually assure that we receive sufficient cash flow to recover substantially all of the costs of improvements we make to the rigs under the term contract, particularly when those improvements are requested by the customer.

WeDuring ~~signed~~2008, ~~three-year~~we have seen greater interest in term contracts ~~for~~from ~~each~~our customers, as evidenced by the recent increase in our long term contract portfolio. As of the ~~two~~date of this report, we have 14 rigs ~~acquired~~working inunder ~~July 2007~~renewed ~~from~~term acontracts since the first quarter of 2008. We also have 18 rigs ~~customer~~currently working under term contracts that were working under spot market dayrate contracts prior to the second quarter of 2008. In addition, ~~signed~~we ahave renewed two- term contracts and obtained nine new term contracts that begin later this year or early in 2009. Only six rigs have moved off of term ~~contract~~contracts ~~for~~since the ~~rig~~beginning ~~recently~~of ~~constructed~~2008. At June 30, ~~and~~2008, ~~signed~~we ~~three-year~~had approximately 29,500 rig days contracted under term contracts, ~~for~~as ~~each~~compared with 25,900 rig days under term contract at June 30, 2007. Our rig days under contract at June 30, 2008 are approximately equivalent to an average of 66 rigs working under term contracts for the remaining two ~~built-for-purpose~~quarters in 2008 and an average of 38 rigs working for 2009. These term contracts are expected to beprovide ~~deployed~~revenue of approximately $435.5 million in 2008 and $281.4 million in 2009. At July 31, 2008 we had 66 rigs working under term contracts, representing 54% of our total rig fleet.

In the first quarter of 2007, we signed three-year term contracts with a major oilfield services company for two of our rigs to go to work in Mexico. This decision was made because it enabled us to enter into additional term contracts that provided us better returns than were otherwise available in our domestic markets at the time. These two rigs began drilling operations in Mexico in the third quarter of 2007. See footnote five in the Notes to Consolidated Financial Statements for information regarding segment reporting.

At September 30, 2007, we had approximately 25,000 rig days contracted under term contracts, as compared with 31,100 rig days under term contract at September 30, 2006. Our rig days under contract at September 30, 2007 are approximately equivalent to an average of 58 rigs working under term contracts for the fourth quarter in 2007 and an average of 31 rigs working for 2008. These term contracts are expected to provide revenue of approximately $531.6 million in 2007 and $253.6 million in 2008. At October 31, 2007 we had 61 rigs working under term contracts, representing 50% of our total rig fleet.

-18-

Drilling ~~and~~ Contract Rates

As anoted ~~result of newly-built and refurbished rigs that have come to market~~above, ~~there is currently some excess capacity of land drilling rigs. Since~~ the ~~fourth~~demand ~~quarter~~for ~~of 2006, we and many of~~ our ~~competitors~~ ~~have~~services ~~experienced~~has ~~rigs~~been ~~becoming~~increasing ~~idle~~as ~~because~~shown ofin ~~this excess rig capacity. During~~ the ~~fourth~~increase ~~quarter of 2006, spot market dayrates began weakening~~ in ~~connection with~~ the ~~excess supply of~~ land ~~drilling~~rig ~~rigs with the most competitive pressure on smaller horsepower mechanical rigs~~count. ~~Additionally,~~Following ~~since~~this ~~the~~increase ~~second~~in ~~quarter of 2007~~demand, ~~market~~there ~~forces~~has ~~have~~been ~~lead~~an usupward tomovement ~~make concessions~~ in ~~contractual~~leading ~~terms~~edge relating to amounts we seek to charge customers when moving rigs to their locations. While we have a significant number of existing term contracts at fixed dayrates that have buffered our exposure to the recent erosion in spot market ~~dayrates~~daywork ~~and~~bid ~~the effects of extra capacity, we expect to experience pressure on our overall dayrates in the fourth quarter of 2007 as some of our spot and term contracts come up for renewal at lower~~ rates. Aswhich ofnow ~~October 31, 2007, our leading edge rates~~ range from $1418,000 to $2223,~~000~~500 per rig day, without fuel or top drives~~, compared~~. toThese arates ~~range~~have ofincreased from $1815,000 to $2721,000 ~~for~~per ~~the~~rig ~~same~~day ~~time a year ago. Leading edge dayrates,~~in ~~although down from a year ago, have been relatively stable over the past several months~~April 2008. A rig day is defined as a twenty-four hour period in which a rig is under contract and should be earning revenue.

In addition to our fleet of drilling rigs, we owned 2933 top drives at ~~October~~July 31, ~~2007,~~2008. ~~for~~Top drive ~~which~~utilization ~~our~~for ~~rates~~the month of July 2008 was 73%. Rates are upas tomuch as $3,~~000~~300 per rig day. ~~Rates~~These rates ~~for our top drives~~ are in addition to the above stated rates for our rigs.

Turnkey Contract Activity

Turnkey work is an important part of our business and operating strategy. Our engineering and operating expertise allow us to provide this service to our customers and has historically provided higher revenues and earnings before interest expense, income taxes, depreciation and amortization (“EBITDA”) per rig day worked than under daywork contracts (see discussion under Reconciliation of Non-GAAP Financial Measures regarding the use of EBITDA and EBITDA per rig day). However, under turnkey contracts we are typically required to bear additional operating costs (such as drill bits) and risk (such as loss of hole) that would otherwise be assumed by the customer under daywork contracts. For the quarter ended ~~September~~June 30, ~~2007~~2008, our turnkey EBITDA was $1216,~~133~~598 per rig day, compared to daywork EBITDA of $87,~~379~~840 per rig day, and our turnkey revenue per rig day was $5461,~~925~~759 compared to $2019,~~311~~819 per rig day for daywork. For the quarter ended ~~September~~June 30, ~~2007~~2008, turnkey work represented 97% of total days worked compared to 87% in the ~~second~~first quarter of ~~2007~~2008 and 98% in the ~~third~~second quarter of ~~2006~~2007. Turnkey EBITDA represented 1214% of total company EBITDA in the ~~third quarter~~second quarter of ~~2007~~2008, compared to 10% in both the ~~second~~first quarter of 2008 and the second quarter 2007. EBITDA generated on turnkey contracts can vary widely based upon a number of factors, including the location of the contracted work, the depth and ~~11%~~level inof complexity of the ~~third~~wells ~~quarter~~drilled ~~2006~~and the ultimate success of drilling the well.

~~EBITDA~~Stock ~~generated~~Repurchase ~~on turnkey contracts can vary widely based upon a number of factors,~~Program including the location of the contracted work, the depth and level of complexity of the wells drilled and the ultimate success of drilling the well. The demand for drilling services under turnkey contracts has historically been lower during periods of overall higher rig demand. Overall rig demand has been higher as evidenced by the increase in rig count; however, demand for our turnkey services has been relatively constant.

We may from time to time make purchases of common stock up to $150.0 million in open market or in privately negotiated block-trade transactions. As of July 31, 2008, we have repurchased 19.0 million shares at a total cost of $121.9 million, exclusive of other direct costs, under the program. The number of shares to be purchased and the timing of purchases will be based on a number of factors: the price of the common stock, general market conditions, available cash and alternate investment opportunities. We may terminate the stock repurchase program prior to completion.

Financial Outlook

~~Announcements of~~As ~~new~~noted, ~~rig~~we ~~orders~~are inseeing ~~the~~additional ~~U.S.~~demand ~~market~~for ~~over~~our ~~the~~services ~~past~~which ~~several~~should ~~months~~continue ~~have~~to ~~been for~~improve ~~built-for-purpose~~our ~~rigs.~~utilization Weof ~~believe~~working ~~the~~rigs ~~vast~~and ~~majority~~require ofus ~~the~~to ~~new~~return ~~rigs~~some ~~will~~stacked berigs ~~delivered~~to bywork. ~~the~~Leading edge ~~end~~daywork ofbid ~~2007.~~rates Wehave ~~also~~improved ~~believe~~due ~~that~~to ~~the~~this ~~new~~higher ~~rigs~~demand ~~that~~and ~~have~~what ~~come~~we ~~into~~believe ~~the~~to ~~market~~be ~~have~~our ~~generally~~customers’ ~~displaced~~confidence ~~low~~in commodity prices has sparked more interest in long-~~end~~term ~~equipment~~contracts and renewals. The ability to provide equipment that addresses the challenges of deep, directional or multi-well site drilling is critical to meeting our customers’ needs in the most active domestic land drilling markets. ~~Our~~Additionally, our fleet is well suited to these drilling opportunities given the recent ~~acquisition~~ acquisition of new rigs and substantial rig upgrades completed over the past three to four years.

Oil and natural gas prices remain historically strong with the twelve-month strips at $125.58 per barrel and $9.61 per mmbtu at July 31, 2008, respectively. Natural gas decline rates are steeper than ever in the United States and Canada and we believe it will take more rigs running to meet the United States’ long-term natural gas requirements.

-19-

~~Oil~~During ~~and~~the ~~natural~~third ~~gas~~quarter ~~prices~~of ~~remain~~2008, ~~strong~~we expect to average 108 to 111 rigs working, with ~~the~~seven ~~twelve-month~~to nine ~~strips~~of atthese ~~$89~~rigs performing turnkey services.09 ~~per~~In ~~barrel~~addition, ~~and~~we expect average daywork EBITDA per rig day to increase by $8400 to $600 due to the continuing improvement in our drilling markets.41 ~~per~~We also ~~mmbtu~~expect atdepreciation ~~October~~expense of approximately $27.5 31million, ~~2007,~~interest ~~respectively.~~expense ~~Natural~~of ~~gas~~approximately $2.7 million ~~decline~~and ~~rates~~an ~~are~~effective ~~steeper~~tax ~~than~~rate ~~ever in~~of ~~the~~approximately ~~United~~37% ~~States~~for ~~and~~the ~~Canada~~third ~~and~~quarter weof ~~believe~~2008. itWe ~~will~~also expect to take ~~more~~a ~~rigs~~pre-tax ~~running~~charge to ~~meet~~earnings of approximately $17.0 million (or approximately $0.05 per diluted share) during the ~~United~~third quarter as a result of the shareholder vote and related ~~States’~~termination ~~long-term~~on ~~natural~~July 15, ~~gas~~2008 ~~requirements~~of a proposed merger with Basic.

In September 2007, the Board of Directors authorized a $50.0 million increase in our common stock repurchase program, bringing the total authorization to $150.0 million. We may from time to time make purchases of common stock in open market or in privately negotiated block-trade transactions. As of October 31, 2007, we have repurchased 13.6 million shares at a total cost of $93.1 million, exclusive of commissions, under the program. The number of shares to be purchased and the timing of purchases will be based on a number of factors: the price of the common stock, general market conditions, available cash and alternate investment opportunities. The stock repurchase program is subject to termination prior to completion.

During the fourth quarter of 2007, we expect to average 97 to 100 rigs working, with 7 to 9 of these rigs performing turnkey services. In addition, we expect average daywork EBITDA per rig day to decrease by $600 to $800 in response to fewer rigs working and pricing pressure on contract renewals and mobilization recoveries. We also expect depreciation expense of approximately $26.7 million, interest expense of approximately $3.4 million and an effective tax rate of approximately 37% for the fourth quarter of 2007.

These projections are forward-looking statements and, while we believe our estimates are reasonable, we can give no assurance that such expectations or the assumptions that underlie such expectations will prove to be correct.

Critical Accounting Policies

Our consolidated financial statements and accompanying notes have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires our management to make subjective estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. However, these estimates, judgments and assumptions concern matters that are inherently uncertain. Accordingly, actual amounts and results could differ from these estimates made by management, sometimes materially. Critical accounting policies and estimates are defined as those that are both most important to the portrayal of our financial condition and operating results and require management’s most subjective judgments. The accounting policies that we believe are critical ~~are~~relate to property and equipment, impairment of long-lived assets, goodwill, revenue recognition, ~~insurance~~ insurance accruals, and income taxes.

Property and Equipment

Property and equipment, including betterments and improvements, are stated at cost with depreciation calculated using the straight-line method over the estimated useful lives of the assets. We make estimates with respect to the useful lives that we believe are reasonable. However, the cyclical nature of our business or the introduction of new technology in the industry could cause us to change our estimates, thus impacting the future calculation of depreciation. When any asset is tested for recoverability, we also review the remaining useful life of the asset. Any changes to the estimated useful life resulting from that review are made prospectively. We estimate that the useful lives of our assets are between three and 1520 years. We expense our maintenance and repair costs as incurred.

Impairment of Long-Lived Assets

We assess the impairment of our long-lived assets under the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Such indicators include changes in our business plans, a change in the physical condition of a long-lived asset or the extent or manner in which it is being used, or a severe or sustained downturn in the oil and gas industry. If we determine that a triggering event, such as those described previously, has occurred, we perform a review of our rigs and rig equipment. Our review is performed by comparing the carrying value of each rig, plus the estimated cost to refurbish or reactivate (if any), to the estimated undiscounted future net cash flows for that rig. If the carrying value plus estimated refurbishment and reactivation cost of any rig is more than the estimated undiscounted future net cash flows expected to result from the use of the rig, a write-down of the rig to estimated fair market value must be made. The estimated fair market value is the amount at which an asset could be bought or sold in a current transaction between willing parties. Quoted market prices in active markets are the best estimate of fair market value; however, quoted market prices are generally not available. As a result, fair value must be determined based upon other valuation techniques. This could include appraisals or present

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change in the physical condition of a long-lived asset or the extent or manner in which it is being used, or a severe or sustained downturn in the oil and gas industry. If we determine that a triggering event, such as those described previously, has occurred, we perform a review of our rigs and rig equipment. Our review is performed by comparing the carrying value of each rig, plus the estimated cost to refurbish or reactivate (if any), to the estimated undiscounted future net cash flows for that rig. If the carrying value plus estimated refurbishment and reactivation cost of any rig is more than the estimated undiscounted future net cash flows expected to result from the use of the rig, a write-down of the rig to estimated fair market value must be made. The estimated fair market value is the amount at which an asset could be bought or sold in a current transaction between willing parties. Quoted market prices in active markets are the best estimate of fair market value; however, quoted market prices are generally not available. As a result, fair value must be determined based upon other valuation techniques. This could include appraisals or present value calculations. The calculation of undiscounted future net cash flows and fair market value is based on our estimates and projections.

The demand for land drilling services is cyclical and has historically resulted in fluctuations in rig utilization. Weand we believe ~~the~~these ~~contract~~fluctuations ~~drilling industry~~ will continue toin ~~be cyclical~~the ~~and rig utilization will continue to fluctuate~~future. The likelihood of an asset impairment increases during extended periods of low rig utilization. ~~During the third quarter of 2007, no~~ ~~impairment of our long-lived assets was recorded as no change in circumstances indicated that the carrying value of the assets was not recoverable.~~

Each year we evaluate our rigs available for refurbishment, if any, and determine our intentions for their future use. This evaluation takes into consideration, among other things, the physical condition and marketability of the rig, and projected reactivation or refurbishment cost. To the extent that our estimates of refurbishment and reactivation cost, undiscounted future net cash flows or fair market value change or there is a deterioration in the physical condition of the rigs available for refurbishment, we could be required under SFAS No. 144 to record an impairment charge. During the first six months of 2008, no impairment of our long-lived assets was recorded as no change in circumstances indicated that the carrying value of the assets was not recoverable.

Goodwill

During ~~the second quarter of~~ 2004, we completed the acquisition of New Patriot Drilling Corp., which was accounted for as a business combination in accordance with SFAS No. 141, “Business Combinations.” In conjunction with the purchase price allocation for this acquisition, we recorded goodwill of $10.4 million.

Goodwill represents the excess of costs over the fair value of assets of businesses acquired. None of the goodwill resulting from this acquisition is deductible for tax purposes. We follow the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets.” Pursuant to SFAS No. 142, goodwill and intangible assets acquired in a purchase business combination and determined to have an indefinite useful life are not amortized, but instead are tested for impairment at least annually in accordance with the provisions of this ~~Statement~~statement. During the first ~~nine~~six months of ~~2007~~2008, no impairment of our goodwill was recorded.

Revenue Recognition

Revenues are earned under daywork and turnkey contracts. Revenue from daywork contracts is recognized when it is realized or realizable and earned. On daywork contracts, revenue is recognized based on the number of days completed at fixed rates stipulated by the contract. For certain contracts, we receive lump-sum fees for mobilization of equipment. Mobilization fees and the related costs are deferred and amortized over the contract term. Revenue from turnkey drilling contracts is recognized using the percentage-of-completion method based upon costs incurred to date compared to our estimate of the total contract costs. Under the percentage-of-completion method, we make estimates of the total contract costs to be incurred, and to the extent these estimates change, the amount of revenue recognized could be affected. The significance of the accrued turnkey revenue varies from period to period depending on the timing of our turnkey projects, the overall level of demand for our services and the portion of that demand that is for turnkey services. At ~~September~~June 30, ~~2007~~2008, there were ~~seven~~eight turnkey wells in progress versus ~~ten~~11 wells at ~~September~~June 30, ~~2006~~ 2007, with accrued revenue of $1017.6 million and $1524.36 million, respectively at such dates. Anticipated losses, if any, on uncompleted contracts are recorded at the time our estimated costs exceed the contract revenue.

Insurance Accruals

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~~Insurance~~$100.0 million. ~~Accruals~~At June 30, 2008 and December 31, 2007, we had $21.9 million and $19.9 million, respectively, accrued for losses incurred within the deductible amounts for workers’ compensation, general liability claims and for uninsured claims. These amounts are included in current accrued workers’ compensation and other long-term liabilities on the balance sheet.

We maintain insurance coverage related to workers’ compensation and general liability claims up to $1.0 million per occurrence with an aggregate of $2.0 million for general liability claims. These policies include deductibles of $500,000 per occurrence for workers’ compensation coverage and $250,000 per occurrence for general liability coverage. If losses should exceed the workers’ compensation and general liability policy amounts, we have excess liability coverage up to a maximum of $100.0 million. At September 30, 2007 and December 31, 2006, we had $18.8 million and $16.5 million, respectively, accrued for losses incurred within the deductible amounts for workers’ compensation and general liability claims and for uninsured claims. These amounts are included in current accrued workers’ compensation and other long-term liabilities on the balance sheet.

The amount accrued for the provision for losses incurred varies depending on the number and nature of the claims outstanding at the balance sheet dates. In addition, the accrual includes management’s estimate of the future cost to settle each claim such as future changes in the severity of the claim and increases in medical costs. We use third parties to assist us in developing our estimate of the ultimate costs to settle each claim, which is based upon historical experience associated with the type of each claim and specific information related to each claim. The specific circumstances of each claim may change over time prior to settlement and as a result, our estimates made on the balance sheet dates may change.

Income Taxes

We are subject to income and other similar taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of our annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; and (c) future events often impact the timing of when we recognize income tax expenses and benefits. We have deferred tax assets mostly relating to workers’ compensation liabilities and stock-based compensation awards. We routinely evaluate all deferred tax assets to determine the likelihood of their realization.

We ~~adopted~~follow the provisions of FASB Interpretation No. (“FIN”) 48, “Accounting for Uncertainty in ~~Income Taxes,” on January 1, 2007. FIN 48 clarifies the accounting for uncertainty~~ in ~~income~~ ~~taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for~~ Income Taxes.” ~~FIN~~As ~~48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement~~ of ~~a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition~~June 30, ~~classification~~2008, ~~interest~~we ~~and penalties,~~had ~~accounting in interim periods, disclosure, and transition and is effective for fiscal years beginning after December~~$1.5 ~~15,~~million ~~2006. We analyzed filing positions in all~~ of ~~the~~unrecognized ~~federal and state jurisdictions where we are required to file income~~ tax ~~returns~~benefits, ~~as well as~~ all ~~open~~of ~~tax years~~which incould ~~these~~have ~~jurisdictions. As a result of adopting FIN 48, we recorded~~ an ~~increase~~impact toon ~~beginning retained~~the ~~earnings,~~effective astax ~~prescribed in this interpretation~~rate, innet ~~the amount~~ of ~~$1.2 million.~~federal ~~This increase relates to net~~ tax benefits ~~for positions taken in our income tax returns that meet the recognition criteria in FIN 48. Prior to the adoption of FIN 48~~, ~~these~~if ~~benefits were not~~ recognized ~~for financial statement purposes~~. Our policy is to accrue interest and penalties associated with uncertain tax positions in income tax expense. At ~~January~~June ~~1, 2007, no interest and penalties were accrued in connection with uncertain tax positions. At September~~ 30, ~~2007~~2008, there was $~~426~~402,000 of interest and penalties accrued in connection with uncertain tax positions. The tax years that remain open to examination by the major taxing jurisdictions to which we are subject range from 1996 to ~~2006~~2007. We have identified our major taxing jurisdictions as the United States, and the states of Texas and Louisiana.

At the date of adoption, we had $1.4 million of unrecognized tax benefits, all of which would have an impact on the effective tax rate, net of federal tax benefits, if recognized. As of September 30, 2007, we had $2.0 million of unrecognized tax benefits, all of which would have an impact on the effective tax rate, net of federal tax benefits, if recognized.

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Financial Condition and Liquidity

The following table summarizes our financial condition as of ~~September~~June 30, ~~2007~~2008 and December 31, ~~2006~~2007.

	September 30, 2007				December 31, 2006
	June 30, 2008				December 31, 2007
	(Unaudited)
	(Dollars in thousands)
	Amount		%		Amount		%
Working capital	$	~~336~~369,~~179~~543		31	$	~~304~~338,~~764~~804		3231
Property and equipment, net		~~738~~781,~~518~~952		6766		~~608~~737,~~136~~944		6567
Goodwill		10,377		1		10,377		1
Other noncurrent assets, net		1120,~~494~~598		12		16,~~625~~153		21
Total	$	1,~~096~~182,~~568~~470		100	$	~~939~~1,~~902~~103,278		100
Long-term debt	$	275,000		2523	$	275,000		2925
Other long-term liabilities		~~164~~181,~~048~~954		15		~~131~~168,~~108~~769		1415
Shareholders’ equity		~~657~~725,~~520~~516		6062		~~533~~659,~~794~~509		5760
Total	$	1,~~096~~182,~~568~~470		100	$	~~939~~1,~~902~~103,278		100

Significant Changes in Financial Condition

The significant changes in our financial condition from December 31, ~~2006~~2007 to ~~September~~June 30, ~~2007~~ ~~are~~2008 are an increase in working capital of $3130.47 million, an increase in net property and equipment of ~~$130.4 million, a decrease in net other noncurrent assets~~ of $544.~~1 million, an increase in other~~0 ~~long-term liabilities of $32.9~~ million, and an increase in shareholders’ equity of $~~123~~66.70 million.

The increase in working capital is primarily the result of higher balances in cash and cash equivalents ~~and~~being ~~decreases~~partially offset by an increase in trade accounts payable and ~~current income taxes payable partially offset by~~ a decrease in accounts receivable. The increase in cash and cash equivalents is due primarily to net income ~~and~~ for the ~~timing~~first ofsix ~~accounts~~months ~~receivable~~of ~~collections~~2008. The ~~decrease~~increase in accounts payable is primarily due to the timing of payments made for capital expenditures and operating costs. The decrease in ~~current~~accounts ~~income taxes~~receivable ~~payable~~ is due ~~primarily~~ to the ~~adoption~~timing of ~~FIN 48 during the first quarter of 2007~~collections.

The increase in net property and equipment is primarily due to capital expenditures made during ~~2007~~2008. Capital expenditures of $~~190~~96.1 million in ~~2007~~2008 ~~include~~included costs tofor ~~purchase~~betterments ~~four~~and improvements ~~new~~to ~~1,500~~our ~~horsepower~~ rigs, ~~the~~new ~~purchase~~rig ~~of two 1~~purchases,~~500~~ ~~horsepower rigs from a customer,~~ the ~~construction~~acquisition of ~~a 1,000 horsepower rig,~~ drill pipe ~~purchases, betterments~~ and ~~improvements~~drill ~~to our rigs~~collars, ~~the purchase of~~ top ~~drives~~drive purchases, and other capital items. Net other noncurrent assets decreased due primarily to the movement of cash deposits in connection with the delivery of four new rigs to property and equipment at the time of delivery being partially offset by a deposit made on one of the new built-for-purpose rigs. The increase in other long-term liabilities is primarily the result of higher deferred tax liabilities. Deferred tax liabilities are higher due to an increase in temporary book-to-tax differences as a result of our high levels of capital expenditures since the beginning of 2005 as well as to temporary book-to-tax differences related to interest deductions. The increase in shareholders’ equity is primarily due to net income for the period ~~partially offset by repurchases of our common stock~~.

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Long-Term Debt

~~Our~~As of June 30, 2008, our $275.0 million of long-term debt consists of $150.0 million of 3.75% ~~Contingent~~ Contingent Convertible Senior Notes due 2023 (the “3.75% Notes”) and $125.0 million of Floating ~~Rate~~ Rate Contingent Convertible Senior Notes due 2024 (the “Floating Rate Notes”). Our subsidiary, Grey ~~Wolf~~ Wolf Drilling Company L.P., has a $100.0 million credit facility with the CIT Group/Business Credit, Inc. (the “CIT Facility”) which expires on December 31, 2008.

3.75% Notes

The ~~$150.0 million aggregate principal amount of the~~ 3.75% Notes bear interest at 3.75% per annum and mature on May 7, 2023. The 3.75% Notes ~~are convertible into shares of our common stock,~~ upon the occurrence of certain events, at a conversion price of $6.45 per share. We will be required to pay contingent interest at a rate equal to 0.50% per annum commencing May 7, 2008, upon the occurrence of certain events. The 3.75% Notes are general unsecured senior obligations and are fully and unconditionally guaranteed, on a joint and ~~several basis, by all of our domestic~~ ~~wholly-owned subsidiaries. Non-guarantor subsidiaries are not significant.~~

~~We may redeem in cash some or all of the 3.75% Notes at any time on or after May 14, 2008, at~~-23- various redemption prices depending upon the date redeemed plus accrued but unpaid interest, including contingent interest. Holders may require us to repurchase all or a portion of their 3.75% Notes on May 7, 2013 or May 7, 2018, and upon a change of control, as defined in the indenture governing the 3.75% Notes, at 100% of the principal amount of the 3.75% Notes, plus accrued but unpaid interest, including contingent interest, if any, to the date of repurchase, payable in cash.

AsTable of July 1, 2007 and through September 30, 2007, the 3.75% Notes were convertible into shares of common stock because one of the triggering events permitting note holders to convert their 3.75% Notes occurred during the second quarter of 2007. The triggering event was that the closing price per share of our common stock exceeded 110% of the conversion price ($7.10 per share) of the 3.75% Notes for at least 20 trading days in the period of 30 consecutive trading days ended on June 30, 2007. As of September 30, 2007, none of the note holders exercised their right to convert the 3.75% Notes into shares of common stock. Contents

~~The~~several ~~price of our common stock during the three months ended September 30~~basis, ~~2007~~by ~~did~~all ~~not~~of ~~meet the~~our ~~criteria~~domestic ~~that~~wholly-owned ~~would allow the 3~~subsidiaries.~~75%~~ ~~Notes~~Non-guarantor tosubsidiaries beare ~~converted into common stock during the fourth~~not ~~quarter of 2007~~significant.

If the average trading price of the 3.75% Notes per $1,000 principal amount for the five trading day period ending on the third trading day immediately preceding the first day of the applicable six-month period (as defined below) equals $1,200 or more, we would be required to pay contingent interest. Contingent interest would be payable at a rate equal to 0.50% per annum during any six-month period, from May 7th to November 6th and from November 7th to May 6th, with the initial six-month period commencing May 7, 2008. For the period of May 7, 2008 to November 6, 2008 the 3.75% notes did not trade at or above $1,200 for the time period required and therefore, no contingent interest is payable.

We may redeem in cash some or all of the 3.75% Notes at any time on or after May 14, 2008, at various redemption prices depending upon the date redeemed plus accrued but unpaid interest, including contingent interest. As of the date of this report, we have not elected to redeem any of the 3.75% Notes. Holders may require us to repurchase all or a portion of their 3.75% Notes on May 7, 2013 or May 7, 2018, and upon a change of control, as defined in the indenture governing the 3.75% Notes, at 100% of the principal amount of the 3.75% Notes, plus accrued but unpaid interest, including contingent interest, if any, to the date of repurchase, payable in cash.

The 3.75% Notes are convertible into shares of our common stock, upon the occurrence of certain events, at a conversion price of $6.45 per share. As of July 1, 2008, and at any time during the third quarter of 2008, the 3.75% Notes are convertible into shares of our common stock because the closing price per share of our common stock exceeded 110% of the conversion price ($7.10 per share) of the 3.75% Notes for at least 20 trading days in the period of 30 consecutive trading days ended on June 30, 2008. Between July 7, 2008 and July 8, 2008, two note holders exercised their right to convert $275,000 in principal amount of the notes into approximately 42,600 shares of our common stock, reducing the aggregate principal amount of the outstanding 3.75% Notes to $149.7 million. The 3.75% Notes will cease to be convertible after September 30, 2008, unless the trading price of our common stock again exceeds (as it did in the second quarter) 110% of the conversion price of the 3.75% Notes for at least 20 trading days in the period of 30 consecutive trading days on the last trading day of the third quarter of 2008. In that event, the 3.75% Notes would remain convertible through the fourth quarter of 2008. The 3.75% Notes may also become convertible (or remain convertible) in the fourth quarter or other future periods if any of the other events that entitle holders to convert the 3.75% Notes occur.

Floating Rate Notes

The ~~$125.0 million aggregate principal amount of the~~ Floating Rate Notes bear interest at a per annum rate equal to 3-month LIBOR, adjusted quarterly, minus a spread of 0.05% but will never be less than zero or more than 6.00%. For the three months ended ~~September~~June 30, ~~2007~~2008 and ~~2006~~2007, the interest rate on the Floating Rate Notes was 52.3165% and 5.4630%, respectively. For the ~~fourth~~third quarter of ~~2007~~2008, the interest rate has been set at 52.1874%. These notes mature on April 1, 2024. The Floating ~~Rate~~ ~~Notes are convertible into shares of our common stock, upon the occurrence of certain events, at a conversion price of $6.51 per share. The Floating~~ Rate Notes are general unsecured senior obligations and are fully and unconditionally guaranteed, on a joint and several basis, by all of our domestic wholly-owned subsidiaries. Non-guarantor subsidiaries are not significant.

We may redeem some or all of the Floating Rate Notes at any time on or after April 1, 2014, at a redemption price equal to 100% of the principal amount of the Floating Rate Notes, plus accrued but unpaid interest and liquidated damages, if any, to the date of repurchase, payable in cash. Holders may require us to repurchase all or a portion of the Floating Rate Notes on April 1, 2014 or April 1, 2019, and upon a change of control, as defined in the indenture governing the Floating Rate Notes, at 100% of the principal amount of the Floating Rate Notes, plus accrued but unpaid interest and liquidated damages, if any, to the date of repurchase, payable in cash.

The Floating Rate Notes are convertible into shares of our common stock, upon the occurrence of certain events, at a conversion price of $6.51 per share. As of July 1, 2008, and at any time during the

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~~principal~~third ~~amount~~quarter of 2008, the Floating Rate Notes, ~~plus~~are ~~accrued~~convertible ~~but~~into ~~unpaid~~shares of our common stock ~~interest~~because ~~and~~the ~~liquidated~~closing ~~damages~~price per share of our common stock exceeded 120% of the conversion price ($7.81 per share) of the Floating Rate Notes for at least 20 trading days in the period of 30 consecutive trading days ended on June 30, if2008. ~~any~~As of the date of this report, none of the note holders had exercised their right to convert the ~~date~~Floating Rate Notes into shares of ~~repurchase~~our common stock. The Floating Rate Notes will cease to be convertible after September 30, ~~payable~~2008, unless the trading price of our common stock again exceeds (as it did in ~~cash~~the second quarter) 120% of the conversion price of the Floating Rate Notes for at least 20 trading days in the period of 30 consecutive trading days on the last trading day of the third quarter of 2008. In that event, the Floating Rate Notes would remain convertible through the fourth quarter of 2008. The Floating Rate Notes may also become convertible (or remain convertible) in the fourth quarter or other future periods if any of the other events that entitle holders to convert the Floating Rate Notes occur.

As of July 1, 2007 and through September 30, 2007, the Floating Rate Notes were convertible into shares of common stock because one of the triggering events permitting note holders to convert their Floating Rate Notes occurred during the second quarter of 2007. The triggering event was that the closing price per share of our common stock exceeded 120% of the conversion price ($7.81 per share) of the Floating Rate Notes for at least 20 trading days in the period of 30 consecutive trading days ended on June 30, 2007. As of September 30, 2007, none of the note holders exercised their right to convert the Floating Rate Notes into shares of common stock.

The price of our common stock during the three months ended September 30, 2007 did not meet the criteria that would allow the Floating Rate Notes to be converted into common stock during the fourth quarter of 2007.

CIT Facility

The CIT Facility provides us with the ability to borrow up to the lesser of $100.0 million or 50% of the Orderly Liquidation Value (as defined in the agreement) of certain drilling rig equipment located in the 48 contiguous states of the United States of America. Periodic interest payments are due at a floating rate based upon our debt service coverage ratio within a range of either LIBOR plus 1.75% to 3.50% or prime plus 0.25% to 1.50%. The CIT Facility provides up to $50.0 million available for letters of credit. We are required to pay a quarterly commitment fee of ranging from 0.375% to 0.50% per annum on the unused portion of the CIT Facility. Letters of credit accrue a fee of 1.25% per annum. These amounts are included in interest expense for the periods presented. The CIT Facility contains affirmative and negative covenants and we are in compliance with these covenants. Substantially all of our assets, including our drilling equipment, are pledged as collateral under the CIT Facility which is also secured by a guarantee of Grey Wolf, Inc. and guarantees of certain of our wholly-owned subsidiaries.

The CIT Facility allows us to repurchase shares of our common stock, pay dividends to our shareholders, and make prepayments on the 3.75% Notes and the Floating Rate Notes. However, all of the following conditions must be met to enable us to make payments for any of the above-mentioned reasons: (i) payments may not exceed $150.0 million in the aggregate, (ii) no Default or Event of Default shall exist at the time of any such payments, (iii) at least $35.0 million of Availability (availability under the CIT Facility plus cash on hand) exists immediately after any such payments, and (iv) we must provide CIT Group/Business Credit, Inc. three Business Days prior written notice of any such payments. Capitalized terms used in the preceding sentence but not defined herein are defined in the CIT Facility.

As of the date of this report, we did not have an outstanding balance under the CIT Facility and had $30.9 million of undrawn standby letters of credit. These standby letters of credit are for the benefit of various insurance companies as collateral for premiums and losses which may become payable under the terms of the underlying insurance contracts. Outstanding letters of credit reduce the amount available for borrowing under the CIT Facility.

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Cash Flow

The net cash provided by or used in our operating, investing and financing activities is summarized below:

	Nine Months Ended
	Six Months Ended
	September 30,
	June 30,
	2007			2006
	2008			2007
	(In thousands)
	(Unaudited)
Net cash provided by (used in):
Operating activities	$	~~235~~172,~~680~~218		$	~~232~~190,~~796~~319
Investing activities		(~~191~~104,~~838~~214	)		(~~117~~120,~~434~~349	)
Financing activities		(182,~~466~~644	)		(458,~~658~~014	)
Net increase in cash	$	2565,~~376~~360		$	6961,~~704~~956

Our cash flows from operating activities are affected by a number of factors including the number of rigs working under contract, whether the contracts are daywork or turnkey, and the rate received for these services. Our cash flow from operating activities ~~provided~~were $~~235~~18.71 million ~~and $232.8 million~~lower ~~during~~ for the first ~~nine~~six months of ~~2007~~2008 ~~and~~compared ~~2006,~~to ~~respectively. Cash flow from operating activities for~~ the ~~nine~~same ~~months~~period ~~ended~~in ~~September 30,~~ 2007. ~~were~~This ~~comparable~~decrease tois ~~the~~due ~~nine~~primarily ~~months~~to ~~ended September 30, 2006 as the~~ lower net income inperiod ~~2007~~over ~~was offset by the 2006 gain from sale of assets, the 2006 gain from insurance proceeds and higher depreciation expense in 2007~~period.

Cash flow used in investing activities for the ~~nine~~six months ended ~~September~~June 30, ~~2007~~2008 consisted ~~primarily~~ of $~~190~~96.1 million of capital expenditures. ~~Capital~~compared ~~expenditures for 2007 include costs~~ to ~~purchase~~ four new 1,500 horsepower rigs, the purchase of two 1,500 horsepower rigs from a customer, and the construction of a 1,000 horsepower rig. Cash flow used in investing activities for the nine months ended September 30, 2006 consisted of $~~132~~122.18 million of capital expenditures ~~and $16.0 million in deposits~~ for ~~new rig purchases partially offset by $19.6 million in proceeds from~~ the ~~sale~~six ofmonths ~~property~~ended ~~and equipment~~June 30, ~~and $11~~2007.~~1 million~~ ~~in proceeds from an insurance claim on the loss of one rig and top drive.~~ Capital expenditures ~~for 2006 include costs for the reactivation of five rigs held for refurbishment. The $19.6 million~~ in ~~proceeds~~2008 ~~from~~and ~~the~~2007 ~~sale~~included ofbetterments ~~property~~ and ~~equipment~~ ~~was~~improvements ~~primarily~~to ~~the result of the sale of five of~~ our rigs, ~~previously available for refurbishment in~~ the ~~first~~purchase ~~quarter~~ of ~~2006.~~new ~~Capital expenditures in 2007 and 2006 also included betterments and improvements to our~~ rigs, the acquisition of drill pipe and collars, the purchase of top drives and other capital items.

Cash flow used in financing activities for the ~~nine~~six months ended ~~September~~June 30, ~~2007~~2008 consisted primarily of $223.05 million in treasury stock purchases compared to $4911.25 million in treasury stock purchases for the ~~nine~~six months ended ~~September~~June 30, ~~2006~~2007.

Projected Cash Sources and Uses

We expect to use cash generated from operations to ~~cover~~meet our cash requirements, including debt service on the 3.75% Notes and Floating Rate Notes, capital expenditures in ~~2007~~2008, tax payments, and common stock repurchases. We will make quarterly interest payments on the Floating Rate Notes on January 1, April 1, July 1 and October 1 of each year and semi-annual interest payments of $2.8 million on the 3.75% Notes on May 7 and November 7 of each year as long as those notes are outstanding. We believe that we will have sufficient cash from operations to meet these requirements. In future periods, we will continue to make interest payments on our Floating Rate Notes and 3.75% Notes through the maturity dates. Since 2004, we have generated sufficient earnings to cover debt related fixed charges, including interest. To the extent that we are unable to generate sufficient cash from operations, we would be required to use cash on hand or draw on our CIT Facility. In addition, under our previously announced ~~share~~stock repurchase program, we ~~may~~have ~~use~~the ability ~~cash on hand~~ to repurchase $5628.91 million in common stock as of ~~October~~July 31, ~~2007~~2008, representing the remaining amount approved under the plan.

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Capital expenditures for ~~2007~~2008 are projected to be between $~~200~~160 million and $~~210~~170 million. This includes approximately $2834.06 million, ~~for~~net ~~the purchase~~ of ~~two 1,500 horsepower rigs from a customer, approximately~~ $129.68 million ~~for the construction~~ of adeposits ~~1,000~~made ~~horsepower~~in ~~rig~~2007, ~~and~~for ~~approximately $40.5~~the ~~million to~~ purchase ~~four~~of two new ~~1,500~~built-for-purpose ~~horsepower drilling~~ rigs. We have obtained long-term contracts on each of these rigs which, in the aggregate, are expected to generate revenue of approximately $~~173~~47.4 million over the term of the contracts. WeOne ~~believe~~of ~~that~~the ~~this~~new ~~revenue~~rigs ~~will~~began ~~enable~~drilling usin ~~to substantially~~July ~~recover~~of 2008, ~~after~~while ~~operating~~the ~~expenses,~~other is expected to begin drilling in the ~~purchase~~fourth ~~prices~~quarter of ~~these rigs~~2008.

In addition, our projected capital expenditures for the remainder of ~~2007~~2008 include costs for betterments and improvements to our rigs, the acquisition of drill pipe and drill collars, the purchase of top drives, and other capital items.

Inflation and Changing Prices

Contract drilling revenues do not necessarily track the changes in general inflation as they tend to respond to the level of activity on the part of the oil and gas industry in combination with the supply of equipment and the number of competing companies. Capital and operating costs are influenced to a larger extent by specific price changes in the oil and natural gas industry, demand for drilling services and to a lesser extent by changes in general inflation. Our daywork contracts allow us to pass most wage increases, the most significant component of our operating costs, on to ~~our~~ our daywork customers in the form of higher dayrates.

Results of Operations

Our drilling contracts generally provide compensation on either a daywork or turnkey basis. Successfully completed turnkey contracts generally result in higher revenues per rig day worked than under daywork contracts. EBITDA per rig day worked on successful turnkey jobs are also generally greater than under daywork contracts, although we are typically required to bear additional operating costs (such as drill bits) and risk (such as loss of hole) that would otherwise ~~typically~~ be ~~paid~~assumed by the customer under a daywork ~~contracts~~contract. Contract drilling revenues and EBITDA on turnkey contracts are affected by a number of variables, which include location of the contracted work, the depth of the well, geological complexities and the actual ~~difficulties~~ difficulties encountered in drilling the well.

-27-

Reconciliation of Non-GAAP Financial Measures

In the following discussion of the results of our operations and elsewhere in this filing, we use EBITDA and EBITDA per rig day. EBITDA and EBITDA per rig day are non-GAAP financial measures under the rules and regulations of the SEC. We believe that our disclosure of EBITDA and EBITDA per rig day as a measure of our operating performance allows investors to make a direct comparison between us and our competitors, without regard to differences in capital structure or to differences in the cost basis of our rigs and those of our competitors. Investors should be aware, however, that there are limitations inherent in using these performance measures as a measure of overall company profitability because they exclude significant expense items such as depreciation expense and interest expense. An improving trend in EBITDA or EBITDA per rig day may not be indicative of an improvement in our overall profitability. To compensate for the limitations in utilizing EBITDA and EBITDA per rig day as operating measures, our management also uses GAAP measures of performance including operating income and net income to evaluate performance but only with respect to the company as a whole and not on a per rig basis. In accordance with SEC rules, we have included below a reconciliation of EBITDA to net income, which is the nearest comparable GAAP financial measure.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
				(Dollars in thousands)
				(Unaudited)
Earnings before interest expense, taxes, depreciation and amortization	$	83,671		$	108,940		$	292,267		$	326,962
Depreciation and amortization		(24,355	)		(18,700	)		(68,166	)		(54,047	)
Interest expense		(3,521	)		(3,514	)		(10,451	)		(10,150	)
Total income tax expense		(20,207	)		(31,464	)		(77,776	)		(95,339	)
Net income applicable to common shares	$	35,588		$	55,262		$	135,874		$	167,426

-27-


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
				(Dollars in thousands)
				(Unaudited)
Earnings before interest expense, income taxes, depreciation and amortization	$	80,512		$	91,723		$	162,363		$	208,596
Depreciation and amortization		(26,994	)		(22,397	)		(54,753	)		(43,811	)
Interest expense		(2,709	)		(3,438	)		(6,046	)		(6,930	)
Total income tax expense		(18,511	)		(24,180	)		(37,943	)		(57,569	)

Net income applicable to common shares	$	32,298		$	41,708		$	63,621		$	100,286

Comparison of the Three Months Ended June 30, 2008 and 2007

The following table highlights rig days worked, contract drilling revenues, and EBITDA for our daywork and turnkey operations for the three months ended June 30, 2008 and 2007.


	Three Months Ended									Three Months Ended
	June 30, 2008									June 30, 2007
	Daywork			Turnkey						Daywork			Turnkey
	Operations			Operations			Total			Operations			Operations			Total
	(Dollars in thousands except averages per rig day worked)
	(Unaudited)
Rig days worked		8,862			665			9,527			8,715			761			9,476

Contract drilling revenues	$	175,637		$	41,070		$	216,707		$	186,225		$	41,295		$	227,520
Drilling operations expenses		(100,280	)		(29,673	)		(129,953	)		(100,762	)		(31,545	)		(132,307	)
General and administrative expenses		(7,731	)		(490	)		(8,221	)		(6,659	)		(500	)		(7,159	)
Interest income		1,860			131			1,991			3,303			290			3,593
Gain (loss) on sale of assets		(12	)		—			(12	)		72			4			76

EBITDA	$	69,474		$	11,038		$	80,512		$	82,179		$	9,544		$	91,723


Average per rig day worked:
Contract drilling revenues	$	19,819		$	61,759		$	22,747		$	21,368		$	54,264		$	24,010
EBITDA	$	7,840		$	16,598		$	8,451		$	9,430		$	12,541		$	9,680

Our EBITDA decreased by $11.2 million, or 12%, to $80.5 million for the quarter ended June 30, 2008 compared with the same period in 2007. The decrease resulted from a $12.7 million decrease in EBITDA from daywork operations being partially offset by a $1.5 million increase in EBITDA from turnkey operations. On a per rig day basis, our EBITDA decreased by $1,229 per rig day, or 13%, to $8,451 in the second quarter of 2008 from $9,680 for the same period in 2007. This decrease included a $1,590 per rig day decrease from daywork operations offset by a $4,057 per rig day increase from turnkey operations. Total general and administrative expenses increased by $1.1 million due primarily to higher costs for stock-based compensation and higher payroll costs. Total interest income decreased by $1.6 million due to lower interest rates during the second quarter of 2008 compared with the same period in 2007.

-28-

Comparison of the Three Months Ended September 30, 2007 and 2006

The following table highlights rig days worked, contract drilling revenues, and EBITDA for our daywork and turnkey operations for the three months ended September 30, 2007 and 2006.

	Three Months Ended									Three Months Ended
	September 30, 2007									September 30, 2006
	Daywork			Turnkey						Daywork			Turnkey
	Operations			Operations			Total			Operations			Operations			Total
				(Dollars in thousands except averages per rig day worked)
							(Unaudited)
Rig days worked		8,784			830			9,614			8,933			929			9,862
Contract drilling revenues	$	178,411		$	45,588		$	223,999		$	192,445		$	50,283		$	242,728
Drilling operations expenses		(101,634	)		(35,313	)		(136,947	)		(93,924	)		(37,653	)		(131,577	)
General and administrative expenses		(6,256	)		(501	)		(6,757	)		(5,688	)		(561	)		(6,249	)
Interest income		3,043			291			3,334			2,899			300			3,199
Gain on sale of assets		37			5			42			763			76			839
EBITDA	$	73,601		$	10,070		$	83,671		$	96,495		$	12,445		$	108,940
Average per rig day worked:
Contract drilling revenues	$	20,311		$	54,925		$	23,299		$	21,543		$	54,126		$	24,612
EBITDA	$	8,379		$	12,133		$	8,703		$	10,802		$	13,396		$	11,046

Our EBITDA decreased by $25.3 million, or 23%, to $83.7 million for the quarter ended September 30, 2007 compared with the same period in 2006. The decrease resulted from a $22.9 million decrease in EBITDA from daywork operations and a $2.4 million decrease in EBITDA from turnkey operations. On a per rig day basis, our EBITDA decreased by $2,343 per rig day, or 21%, to $8,703 in the third quarter of 2007 from $11,046 for the same period in 2006. This decrease included a $2,423 per rig day decrease from daywork operations and a $1,263 per rig day decrease from turnkey operations. Total general and administrative expenses increased by $508,000 due primarily to higher costs for stock-based compensation. Total interest income increased by $135,000 due to higher cash balances during the third quarter of 2007 compared with the same period in 2006.

Daywork Operations

~~The~~Despite the slight increase in rig days worked, the decrease in daywork EBITDA discussed above was due primarily to lower dayrates, ~~decreased rig activity and higher expenses~~ in the ~~third~~second quarter of ~~2007~~2008 versus the same period in ~~2006~~2007. Contract drilling revenue per rig day decreased $1,~~232~~549, or 67% due to declining dayrates as a result of the excess capacity of land rigs in the industry that began in 2007. ~~Expenses~~Our rig days worked increased ~~overall~~147 days, ~~due~~or to2%, ~~several~~for ~~factors,~~the ~~including~~second ~~higher~~quarter ~~maintenance~~of ~~and~~2008 ~~repair~~compared ~~costs~~with ~~and~~the ~~higher~~same period in 2007 as ~~labor-related~~a ~~costs~~result of the recent increase in demand for our services.

Turnkey Operations

Turnkey EBITDA was ~~lower~~higher in the ~~third~~second quarter of ~~2007~~2008 ~~primarily~~compared ~~due~~ to athe ~~decrease~~second inquarter ~~rig~~of ~~days~~2007 ~~worked~~primarily ondue ~~turnkey~~to ~~contracts. Rig days worked decreased by 99 days, or 11% for~~ the ~~three~~success ~~months ended~~of ~~September 30, 2007 compared to~~ the ~~same~~wells drilled period inover ~~2006~~period. ~~Also,~~The ~~differences in the~~ complexity and success of the wells drilled are a contributing ~~factor~~factors to EBITDA and EBITDA per rig day fluctuations. ~~During the third quarter of 2007, we encountered difficulties on one turnkey~~ ~~contract, generating a loss, which contributed to the lower EBITDA when compared to the third quarter of 2006.~~

Other

Depreciation and amortization expense increased by $4.6 million, or 21%, to $27.0 million for the three months ended June 30, 2008, compared to the same period in 2007. The increase in depreciation and amortization expense was due to capital expenditures made during 2007 and 2008, including the cost to purchase and construct new rigs.

Interest expense decreased by $729,000, or 21%, to $2.7 million for the three months ended June 30, 2008 from $3.4 million for the same period in 2007. This decrease is due primarily to a lower average interest rate on our Floating Rate Notes during the three months ended June 30, 2008 as compared to the three months ended June 30, 2007. There has been no change in our debt balance that would have impacted interest expense for either period.

Our income tax expense decreased by $5.7 million to $18.5 million for second quarter of 2008 compared to the same period in 2007. The decrease is primarily due to the lower level of income for the second quarter of 2008.

-29-

~~Other~~Comparison of the Six Months Ended June 30, 2008 and 2007

~~Depreciation~~The ~~and~~following ~~amortization~~tables ~~expense~~highlight ~~increased~~rig bydays ~~$5.7 million~~worked, orcontract ~~30%,~~drilling torevenue ~~$24.4 million~~and EBITDA for ~~the~~ ~~three months ended September 30, 2007, compared to the same period in 2006. The increase in~~our ~~depreciation~~daywork and ~~amortization~~turnkey ~~expense~~operations ~~was~~for ~~due~~the tosix ~~capital~~months ~~expenditures~~ended ~~made during 2006 and 2007~~June 30, ~~including~~ ~~the~~2008 ~~cost to purchase~~ and ~~construct new rigs~~2007.

Our income tax expense decreased by $11.3 million to $20.2 million for the three months ended September 30, 2007 compared to the same period in 2006. The decrease is primarily due to the lower level of income for the third quarter of 2007.


	Six Months Ended									Six Months Ended
	June 30, 2008									June 30, 2007
	Daywork			Turnkey						Daywork			Turnkey
	Operations			Operations			Total			Operations			Operations			Total
	(Dollars in thousands except averages per rig day worked)
	(Unaudited)
Rig days worked		17,395			1,269			18,664			18,017			1,380			19,397

Contract drilling revenues	$	347,981		$	70,248		$	418,229		$	393,589		$	75,944		$	469,533
Drilling operations expenses		(193,180	)		(50,281	)		(243,461	)		(200,625	)		(52,635	)		(253,260	)
General and administrative expenses		(15,850	)		(983	)		(16,833	)		(13,617	)		(941	)		(14,558	)
Interest income		4,182			296			4,478			6,264			488			6,752
Gain on sale of assets		(48	)		(2	)		(50	)		110			19			129

EBITDA	$	143,085		$	19,278		$	162,363		$	185,721		$	22,875		$	208,596


Average per rig day worked:
Contract drilling revenues	$	20,005		$	55,357		$	22,408		$	21,845		$	55,032		$	24,206
EBITDA	$	8,226		$	15,191		$	8,699		$	10,308		$	16,576		$	10,754

~~Comparison~~ Our ofEBITDA ~~the~~decreased ~~Nine~~by ~~Months~~$46.2 million, ~~Ended~~or ~~September~~22%, to $162.4 million for the six months ended June 30, 2008 compared to the same period in 2007. The decrease resulted from a $42.6 million decrease in EBITDA from daywork operations and ~~2006~~a $3.6 million decrease in EBITDA from turnkey operations. On a per rig day basis, our total EBITDA decreased by $2,055 per rig day, or 19% to $8,699 for the first six months of 2008 from $10,754 for the same period in 2007. This decrease included a $2,082 per rig day decrease from daywork operations and a $1,385 per rig day decrease from turnkey operations. Total general and administrative expenses increased by $2.3 million due primarily to higher costs for stock-based compensation and higher payroll costs. Total interest income decreased by $2.3 million due to lower interest rates during the first six months of 2008 compared with the same period in 2007.

The following tables highlight rig days worked, contract drilling revenue and EBITDA for our daywork and turnkey operations for the nine months ended September 30, 2007 and 2006.

	Nine Months Ended									Nine Months Ended
	September 30, 2007									September 30, 2006
	Daywork			Turnkey						Daywork			Turnkey
	Operations			Operations			Total			Operations			Operations			Total
				(Dollars in thousands except averages per rig day worked)
							(Unaudited)
Rig days worked		26,802			2,210			29,012			26,319			3,129			29,448
Contract drilling revenues	$	572,000		$	121,532		$	693,532		$	535,065		$	170,132		$	705,197
Drilling operations expenses		(302,259	)		(87,948	)		(390,207	)		(268,340	)		(115,382	)		(383,722	)
General and administrative expenses		(19,873	)		(1,442	)		(21,315	)		(15,642	)		(1,786	)		(17,428	)
Interest income		9,307			779			10,086			7,495			885			8,380
Gain on sale of assets		147			24			171			9,250			1,126			10,376
Gain on insurance proceeds		—			—			—			3,675			484			4,159
EBITDA	$	259,322		$	32,945		$	292,267		$	271,503		$	55,459		$	326,962
Average per rig day worked:
Contract drilling revenues	$	21,342		$	54,992		$	23,905		$	20,330		$	54,373		$	23,947
EBITDA	$	9,675		$	14,907		$	10,074		$	10,316		$	17,724		$	11,103

Our EBITDA decreased by $34.7 million, or 11%, to $292.3 million for the nine months ended September 30, 2007 compared to the same period in 2006. The decrease resulted from a $22.5 million decrease in EBITDA from turnkey operations and a $12.2 million decrease in EBITDA from daywork operations. On a per rig day basis, our total EBITDA decreased by $1,029 per rig day, or 9% to $10,074 for the first nine months of 2007 from $11,103 for the same period in 2006. This decrease included a $2,817 per rig day decrease from turnkey operations and a $641 per rig day decrease from daywork operations. Total general and administrative expenses increased by $3.9 million due primarily to higher costs for stock-based compensation, higher professional fees, and higher payroll costs. Total interest income increased by $1.7 million due primarily to higher cash balances during the first nine months of 2007 compared with the same period in 2006. The gain on sale of assets of $10.4 million in 2006 relates to the sale of five rigs in January 2006. The gain on insurance proceeds of $4.2 million in 2006 relates to the proceeds received from the loss of one of our rigs and top drives.

-30-

Daywork Operations

~~Despite~~The andecrease ~~increase~~in ofdaywork ~~483~~EBITDA ~~rig~~discussed ~~days~~above ~~worked~~was ondue ~~daywork~~primarily ~~contacts~~to lower dayrates and decreased rig activity in the first ~~nine~~six months of ~~2007~~ ~~when~~2008 ~~compared~~versus ~~with~~ the same period ofin ~~2006, daywork EBITDA decreased by $12~~2007.~~2 million.~~ ~~The 2006 daywork EBITDA included a $9.3 million gain on sale of assets and a $3.7 million gain on insurance proceeds.~~ Contract drilling revenue per rig day ~~increased~~decreased $1,~~012~~840, or 58%, ~~including~~due ~~the effect~~to ofdeclining dayrates as a ~~wage~~result ~~increase~~of ~~effective~~the excess ~~May 1,~~capacity ~~2006~~of ~~which~~land ~~was~~rigs ~~passed~~in onthe toindustry ~~our~~that ~~customers~~began in ~~the~~2007. ~~form~~Our ~~of higher~~rig ~~dayrates.~~days ~~Expenses~~worked ~~increased~~declined ~~overall~~622 days, ~~and~~or on3%, afor ~~per~~the ~~rig~~first ~~day~~six ~~basis,~~months ~~due~~of to2008 ~~several~~compared ~~factors, including~~with ~~higher~~the ~~maintenance~~same ~~and~~period ~~repair~~in ~~costs~~2007 ~~and~~due ~~higher~~to ~~labor~~the excess ~~costs~~rig capacity.

Turnkey Operations

Turnkey EBITDA was lower for the ~~nine~~six months ended ~~September~~June 30, ~~2007~~2008 due to a decrease in rig ~~days~~ days worked and ~~higher~~lower ~~costs~~revenues on turnkey contracts. Rig days worked decreased by ~~919~~111 days, or 298% ~~for~~ for the ~~nine~~six months ended ~~September~~June 30, ~~2007~~2008 compared to the same period in ~~2006~~2007. Also, differences in the complexity and success of the wells drilled between the two periods contributed to the ~~decreased~~ decreased EBITDA and EBITDA per rig day. ~~During the nine months ended September 30, 2007, we~~ ~~encountered difficulties on two turnkey contracts, generating losses, which contributed to the lower EBITDA when compared to the same period in 2006.~~

-30-

Other

Depreciation and amortization expense increased by $1410.19 million, or 2625%, to $6854.28 million for the ~~nine~~six months ended ~~September~~June 30, ~~2007~~2008 compared to the same period in ~~2006~~2007. Depreciation and amortization expense is higher due to capital expenditures made during ~~2006~~2007 and ~~2007~~2008, including the cost to purchase and construct new rigs.

Interest expense ~~increased~~decreased by $~~301~~884,000, or 313%, to $106.50 million for the ~~nine~~six months ended June ~~September~~ 30, ~~2007~~2008 from $106.29 million for the same period in ~~2006~~2007. This ~~increase~~decrease is due primarily to a ~~slightly higher~~ lower average interest rate on our Floating Rate Notes during the ~~nine~~six months ended ~~September~~ June 30, ~~2007~~2008 as compared to the ~~nine~~six months ended ~~September~~June 30, ~~2006~~2007. There ~~was~~has been no change in our debt balance ~~during~~that would ~~the~~have ~~nine~~impacted ~~months~~interest ~~ended~~expense ~~September 30,~~for ~~2007~~either period.

Our income taxes decreased by $1719.6 million to $7737.89 million for the ~~nine~~six months ended ~~September~~ June 30, 2008 ~~2007~~ compared to the same period in ~~2006~~2007. The decrease is primarily due to the lower level of income.

Item 3. Quantitative and Qualitative Disclosure about Market Risk

Interest Rate Risk~~. We are subject to market risk exposure related to changes in interest~~ rates on the Floating Rate Notes and the CIT Facility. The Floating Rate Notes bear interest at a per annum rate which is equal to 3-month LIBOR, adjusted quarterly, minus a spread of 0.05%. We had $125.0 million of the Floating Rate Notes outstanding at September 30, 2007. A 1% change in the interest rate on the Floating Rate Notes would change our interest expense by $1.3 million on an annual basis. However, the annual interest on the Floating Rate Notes will never be below zero or more than 6.00%, which could yield interest expense ranging from zero to $7.5 million on an annual basis. Interest on borrowings under the CIT Facility accrues at a variable rate, using either the prime rate plus 0.25% to 1.50% or LIBOR plus 1.75% to 3.50%, depending upon our debt service coverage ratio for the trailing 12 month period. We have no outstanding balance under the CIT Facility at October 31, 2007 and as such have no exposure under this facility to a change in interest rates.

We are subject to market risk exposure related to changes in interest rates on the Floating Rate Notes and the CIT Facility. The Floating Rate Notes bear interest at a per annum rate which is equal to 3-month LIBOR, adjusted quarterly, minus a spread of 0.05%. We had $125.0 million of the Floating Rate Notes outstanding at June 30, 2008. A 1% change in the interest rate on the Floating Rate Notes would change our interest expense by $1.3 million on an annual basis. However, the annual interest on the Floating Rate Notes will never be below zero or more than 6.00%, which could yield interest expense ranging from zero to $7.5 million on an annual basis. Interest on borrowings under the CIT Facility accrues at a variable rate, using either the prime rate plus 0.25% to 1.50% or LIBOR plus 1.75% to 3.50%, depending upon our debt service coverage ratio for the trailing 12 month period. We have no outstanding balance under the CIT Facility at July 31-, 2008 and as such have no exposure under this facility to a change in interest rates.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of ~~September~~June 30, ~~2007~~2008, under the supervision, and with participation, of management, including our Chief Executive Officer and Chief Financial Officer. Our disclosure controls and procedures are designed to ensure that the information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934, as amended, 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 an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to the issuer’s management including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

-3231-

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We are involved in litigation incidental to the conduct of our business, none of which management believes is, individually or in the aggregate, material to our consolidated financial condition or results of operations. See Note 6 –— Contingencies in Notes to Consolidated Financial Statements.

Item 1a. Risk Factors

There have been no material changes to ~~the~~our risk factors, ~~previously~~except ~~disclosed~~as noted below, since we last reported under Part I, Item 1A, in our Annual Report on Form 10-K for the year ended December 31, 2007.

We have incurred significant transaction costs in connection with the terminated merger with Basic Energy Services, Inc. (“Basic”).

We expect to pay significant transaction costs in connection with the activities of the terminated merger. These transaction costs include investment banking, legal and accounting fees and expenses, expenses associated with the financing of the merger, governmental filing fees, printing expenses, mailing expenses and other related charges. We expect to take a pre-tax charge to earnings of approximately $17.0 million during the third quarter of 2008 related to these transaction costs, including a $5.0 million termination fee paid to Basic. Should we enter into an agreement of similar nature with another company within one year of the termination date of the agreement with Basic, we may be required to pay Basic an additional $25.0 million fee upon consummation of the subsequent transaction.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information relating to Grey Wolf’s repurchase of common ~~shares~~stock during the ~~nine~~three months ended ~~September~~June 30, ~~2007~~2008 (in thousands, except average price paid per share):

					Total Number of	~~Total Number of~~	Approximate		~~Approximate~~
					Shares		Dollar Value of		~~Dollar Value of~~
					Purchased as		Shares that May		~~Shares that May~~
	Total Number of			Average	Part of Publicly				Yet be Purchased
	Total Number		Average		Part of Publicly		Yet be Purchased
	Shares		Price Paid		Announced				Under the
	of Shares		Price Paid per		Announced		Under the
Period	Purchased(1)		~~per~~ Share		Program		Program(2)		~~Program(2)~~
January 1, 2007 to January 31, 2007		1,219	$	6.59		1,219			$	27,161
April 1, 2008 to April 30, 2008		3	$	7.09	—		$	28,070
February 1, 2007 to February 28, 2007		97	$	6.62		—			$	27,161
May 1, 2008 to May 31, 2008		4	$	7.82	—		$	28,070
March 1, 2007 to March 31, 2007		426	$	6.51		425			$	24,408
June 1, 2008 to June 30, 2008		1	$	9.38	—		$	28,070
April 1, 2007 to April 30, 2007		3	$	6.87		—			$	24,408
May 1, 2007 to May 31, 2007		4	$	7.93		—			$	24,408
June 1, 2007 to June 30, 2007		—	$	—		—			$	24,408
July 1, 2007 to July 31, 2007		—	$	8.07		—			$	24,408
August 1, 2007 to August 31, 2007		1,517	$	6.68		1,514			$	14,290
September 1, 2007 to September 30, 2007		54	$	6.49		54			$	63,939

(1)		Our employees ~~elected~~may elect to have shares of stock withheld to cover payroll taxes when shares of restricted stock vest. We then pay the taxes on their behalf and hold the shares withheld as treasury stock. We had approximately ~~108~~8,000 of such treasury share purchases during the ~~nine~~three months ended ~~September~~June 30, ~~2007~~2008. These share repurchases are not covered under a publicly announced program.
(2)		On May 25, 2006, ~~the~~we ~~Company~~ announced that ~~its~~our Board of Directors approved a plan authorizing the repurchase of up to $100.0 million of Grey Wolf common stock in open market or in privately negotiated block-trade transactions. On September 25, 2007, ~~the~~we ~~Company~~ announced that ~~its~~our Board of Directors authorized a $50.0 million increase in ~~the~~our ~~Company’s~~ common stock repurchase program for a total of $150.0 million. The number of shares to be purchased and the timing of purchases will be based on several factors, including the price of the common stock, general market conditions, available cash and alternate investment opportunities. The stock repurchase program is subject to termination prior to completion.

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Item 3. Defaults Upon Senior Securities

None.

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

None.

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Item 5. Other Information

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this report are forward-looking statements, including statements regarding the following:

• business strategy; • demand for our services; • spending by our customers; • projected rig activity; • increases in rig supply and its effects on us; • projected dayrates; • projected interest expense; • projected tax rate; • rigs expected to be engaged in turnkey operations; • cost of building new rigs, delivery times and deployment destinations of these rigs; • the ability to recover the purchase price of rigs from term contracts; • the availability and financial terms of term contracts; • wage rates and retention of employees; • sufficiency of our capital resources and liquidity; • projected depreciation and capital expenditures; • future common stock repurchases by us; ~~and~~ • projected sources and uses of cash; and • matters discussed in Item 2 under the caption “Financial Outlook.”

Although we believe the forward-looking statements are reasonable, we cannot assure you that these statements will prove to be correct. We have based these statements on assumptions and analyses in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate when the statements are made. Important factors that could cause actual results to differ materially from our expectations include:

	•		fluctuations in prices and demand for oil and natural gas;

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

	•		fluctuations in demand for contract land drilling services;

	•		fluctuations in interest rates;

	•		the existence and competitive responses of our competitors;

	•		uninsured or underinsured casualty losses;

	•		technological changes and developments in the industry;

	•		the existence of operating risks inherent in the contract land drilling industry;

	•		U.S. and global economic conditions;

	•		the availability and terms of insurance coverage;

	•		the ability to attract and retain qualified personnel;

	•		unforeseen operating costs such as cost for environmental remediation and turnkey cost overruns; and

	•		weather conditions.

~~Our forward~~-looking statements speak only as of the date specified in such statements or, if no date is stated, as of the date of this report. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward33-~~looking statement contained~~ in this report to reflect any change in our expectations or with regard to any change in events, conditions or circumstances on which our forward-looking statements are based. Please refer to our Annual Report on Form 10-K for the year ended December 31, 2006 filed with the Securities and Exchange Commission for additional information concerning risk factors that could cause actual results to differ from the forward-looking statements.

Our forward-looking statements speak only as of the date specified in such statements or, if no date is stated, as of the date of this report. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement contained in this report to reflect any change in our expectations or with regard to any change in events, conditions or circumstances on which our forward-looking statements are based. Please refer to our Annual Report on Form 10-K for the year ended December 31, 2007 filed with the Securities and Exchange Commission for additional information concerning risk factors that could cause actual results to differ from the forward-looking statements.

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Item 6. Exhibits

	3.1		Amended and Restated Articles of Incorporation of Grey Wolf, Inc., ~~as amended~~ (incorporated herein by reference to Exhibit 3.1 to Form 8-K filed May 21, 2007).
	3.2		By-Laws of Grey Wolf, Inc., as amended (incorporated herein by reference to Exhibit 99.1 to Form 8-K dated March 23, 1999).
	4.1		Rights Agreement dated as of September 21, 1998 by and between the Company and American Stock Transfer and Trust Company as Rights Agent (incorporated herein by reference to Exhibit 4.1 to Form 8-K filed September 22, 1998).
	4.2		Indenture, dated as of May 7, 2003, relating to the 3.75% Contingent Convertible Senior Notes due 2023 between the Company, the Guarantors, and JPMorgan Chase Bank, a New York Banking Corporation, as Trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-3 No. 333-106997 filed July 14, 2003).
	4.3		Supplemental Indenture, dated as of May 22, 2003, relating to the 3.75% Contingent Convertible Senior Notes due 2023 between the Company, the Guarantors, and JPMorgan Chase Bank, a New York Banking Corporation, as Trustee (incorporated herein by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-3 No. 333-106997 filed July 14, 2003).
	4.4		Indenture, dated as of March 31, 2004, relating to the Floating Rate Contingent Convertible Senior Notes Due 2024 between the Company, the Guarantors, and J.P. Morgan Chase Bank, a New York banking corporation, as Trustee (incorporated by reference to Exhibit 4.1 to Form 10-Q dated May 5, 2004).
	4.5		Registration Rights Agreement as of March 31, 2004 by and between Grey Wolf, Inc., the Guarantors, and the Initial Purchasers of the Floating Rate Contingent Convertible Senior Notes due 2024 (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q filed May 5, 2004).
	4.6		Second Supplemental Indenture, dated as of March 31, 2004, relating to the 3.75% Contingent Convertible Senior Notes due 2023 between the Company, the Guarantors, and JP Morgan Chase Bank, a New York Banking Corporation, as Trustee (incorporated by reference to Exhibit 4.3 to the Quarterly Report on Form 10-Q filed May 5, 2004).
	* 31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a)
	*31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a)
	* 31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a)
	*31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a)
	** 32.1		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Thomas P. Richards, Chairman, President and Chief Executive Officer and David W. Wehlmann, Executive Vice President and Chief Financial Officer.
	**32.1		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Thomas P. Richards, Chairman, President and Chief Executive Officer and David W. Wehlmann, Executive Vice President and Chief Financial Officer.


*		Filed herewith

**		Furnished, not filed, in accordance with Item 601(b)(32) of Regulation S-K.

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SIGNATURES

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.

	GREY WOLF, INC.
Date: November 5, 2007	By:	/s/ David W. Wehlmann
Date: August 6, 2008	By:	/s/ David W. Wehlmann
		David W. Wehlmann
		Executive Vice President and Chief Financial Officer
Date: November 5, 2007	By:	/s/ Kent D. Cauley
		Kent D. Cauley
		Vice President and Controller

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EXHIBIT INDEX

Exhibits		DESCRIPTION OF EXHIBITS
3.1		Articles of Incorporation of Grey Wolf, Inc., as amended (incorporated herein by reference to Exhibit 3.1 to Form 8-K filed May 21, 2007).
3.2		By-Laws of Grey Wolf, Inc., as amended (incorporated herein by reference to Exhibit 99.1 to Form 8-K dated March 23, 1999).
4.1		Rights Agreement dated as of September 21, 1998 by and between the Company and American Stock Transfer and Trust Company as Rights Agent (incorporated herein by reference to Exhibit 4.1 to Form 8-K filed September 22, 1998).
4.2		Indenture, dated as of May 7, 2003, relating to the 3.75% Contingent Convertible Senior Notes due 2023 between the Company, the Guarantors, and JPMorgan Chase Bank, a New York Banking Corporation, as Trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-3 No. 333-106997 filed July 14, 2003).
4.3		Supplemental Indenture, dated as of May 22, 2003, relating to the 3.75% Contingent Convertible Senior Notes due 2023 between the Company, the Guarantors, and JPMorgan Chase Bank, a New York Banking Corporation, as Trustee (incorporated herein by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-3 No. 333-106997 filed July 14, 2003).
4.4		Indenture, dated as of March 31, 2004, relating to the Floating Rate Contingent Convertible Senior Notes Due 2024 between the Company, the Guarantors, and J.P. Morgan Chase Bank, a New York banking corporation, as Trustee (incorporated by reference to Exhibit 4.1 to Form 10-Q dated May 5, 2004).
4.5		Registration Rights Agreement as of March 31, 2004 by and between Grey Wolf, Inc., the Guarantors, and the Initial Purchasers of the Floating Rate Contingent Convertible Senior Notes due 2024 (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q filed May 5, 2004).
4.6		Second Supplemental Indenture, dated as of March 31, 2004, relating to the 3.75% Contingent Convertible Senior Notes due 2023 between the Company, the Guarantors, and JP Morgan Chase Bank, a New York Banking Corporation, as Trustee (incorporated by reference to Exhibit 4.3 to the Quarterly Report on Form 10-Q filed May 5, 2004).
*31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a)
*31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a)
**32.1		Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Thomas P. Richards, Chairman, President and Chief Executive Officer and David W. Wehlmann, Executive Vice President and Chief Financial Officer.

*		Filed herewith
**		Furnished, not filed, in accordance with Item 601(b)(32) of Regulation S-K.

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