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Delaware		1389		72-1503959
(State or other jurisdiction of incorporation or organization)		(Primary Standard Industrial Classification Code Number)		(I.R.S. Employer Identification No.)

Vinson & Elkins L.L.P.		Baker Botts L.L.P.
First City Tower, Suite 2300		One Shell Plaza, 910 Louisiana Street
Houston, Texas 77002		Houston, Texas 77002
(713) 758-2222		(713) 229-1234
Attn: Scott N. Wulfe		Attn: R. Joel Swanson
Attn: Nicole E. Clark		Attn: Felix P. Phillips

Title of Each Class of Securities			Proposed Maximum			Amount of
to be Registered			Aggregate Offering Price(1)(2)			Registration Fee
Common Stock, par value $0.01			$345,000,000			$40,607(3)

(1)	Includes common stock issuable upon the exercise of the underwriters’ over-allotment option.
(2)	Estimated solely for the purpose of calculating the registration fee in accordance with Rule 457(o) under the Securities Act of 1933.
(3)	Subsequent to the date of the initial filing of the registration statement, we increased the Proposed Maximum Aggregate Offering Price from $300,000,000 to $345,000,000. A registration fee of $35,310 relating to the original Proposed Maximum Aggregate Offering Price was paid at the time of the initial filing of the registration statement. The balance of the registration fee will be paid on the date of the filing of this Amendment No. 1.

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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Proceeds to

Underwriting

Complete

Proceeds to

Price to

Discounts and

Production

Selling

Public

Commissions

Services

Stockholders

Per Share

$

$

$

$

Total

$

$

$

$

Credit Suisse First Boston	UBS Investment Bank

	Jefferies

	Johnson Rice & Company L.L.C.

	Raymond James

	Simmons & Company

	International

	Pickering Energy Partners

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		Page
Prospectus Summary			1
Risk Factors			10
Forward-Looking Statements			21
Use of Proceeds			22
Dividend Policy			22
Capitalization			23
Dilution			24
Unaudited Pro Forma Consolidated Financial Data			25
Selected Consolidated Financial Data			30
Management’s Discussion and Analysis of Financial Condition and Results of Operations			33
Business			55
Management			72
Certain Relationships and Related Party Transactions			84
Principal and Selling Stockholders			86
Description of Our Capital Stock			88
Shares Eligible for Future Sale			92
Principal U.S. Federal Tax Consequences to Non-U.S. Holders of Common Stock			94
Underwriting			97
Notice to Canadian Residents			101
Legal Matters			102
Experts			102
Where You Can Find More Information			103
Index to Financial Statements			F-1
Form of Indemnification Agreement
Credit Agreement
2001 Stock Incentive Plan - Integrated Production
2003 Stock Incentive Plan
First Amendment to 2003 Stock Incentive Plan
Second Amendment to 2003 Stock Incentive Plan
2004 Stock Incentive Plan - I.E. Miller Services, Inc.
Amended Integrated Production Services and Parchman Energy Group, Inc. Stock Incentive Plan
Strategic Customer Relationship Agreement
Form of Restricted Stock Grant Agreement (Employee)
Form of Restricted Stock Agreement (Non-Employee Director)
Consent of Grant Thorton LLP
Consent of KPMG LLP

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	Our business depends on the oil and gas industry and particularly on the level of activity for North American oil and gas. Our markets may be adversely affected by industry conditions that are beyond our control.

	•	the supply of and demand for oil and gas;
	•	the level of prices, and expectations about future prices, of oil and gas;
	•	the cost of exploring for, developing, producing and delivering oil and gas;
	•	the expected rates of declining current production;
	•	the discovery rates of new oil and gas reserves;
	•	available pipeline and other transportation capacity;
	•	weather conditions, including hurricanes that can affect oil and gas operations over a wide area;
	•	domestic and worldwide economic conditions;
	•	political instability in oil and gas producing countries;
	•	technical advances affecting energy consumption;
	•	the price and availability of alternative fuels;
	•	the ability of oil and gas producers to raise equity capital and debt financing; and
	•	merger and divestiture activity among oil and gas producers.

	Because the oil and gas industry is cyclical, our operating results may fluctuate.

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	There is potential for excess capacity in our industry.

	We may be unable to employ a sufficient number of skilled and qualified workers.

	Our executive officers and certain key personnel are critical to our business and these officers and key personnel may not remain with us in the future.

	Our operating history may not be sufficient for investors to evaluate our business and prospects.

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	We participate in a capital intensive business. We may not be able to finance future growth of our operations or future acquisitions.

	Our inability to control the inherent risks of acquiring and integrating businesses could adversely affect our operations.

	•	retaining and attracting key employees;
	•	retaining and attracting new customers;
	•	increased administrative burden;
	•	developing our sales and marketing capabilities;
	•	managing our growth effectively;
	•	integrating operations;
	•	operating a new line of business; and
	•	increased logistical problems common to large, expansive operations.

	Our customer base is concentrated within the oil and gas production industry and loss of a significant customer could cause our revenue to decline substantially.

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	Our indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions.

	•	our level of debt increases our vulnerability to general adverse economic and industry conditions;
	•	the covenants that are contained in the agreements that govern our indebtedness limit our ability to borrow funds, dispose of assets, pay dividends and make certain investments;
	•	our debt covenants also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;
	•	any failure to comply with the financial or other covenants of our debt could result in an event of default, which could result in some or all of our indebtedness becoming immediately due and payable;
	•	our level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or other general corporate purposes; and
	•	our business may not generate sufficient cash flow from operations to enable us to meet our obligations under our indebtedness.

	Our business depends upon our ability to obtain key raw materials and specialized equipment from suppliers.

	We may not be able to provide services that meet the specific needs of oil and gas exploration and production companies at competitive prices.

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	Our operations are subject to hazards inherent in the oil and gas industry.

	If we become subject to product liability claims, it could be time-consuming and costly to defend.

	We are subject to extensive and costly environmental laws and regulations that may require us to take actions that will adversely affect our results of operations.

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	•	issuance of administrative, civil and criminal penalties;
	•	denial or revocation of permits or other authorizations;
	•	imposition of limitations on our operations; and
	•	performance of site investigatory, remedial or other corrective actions.

	The nature of our industry subjects us to compliance with other regulatory laws.

	If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud.

	A terrorist attack or armed conflict could harm our business.

	Conservation measures and technological advances could reduce demand for oil and gas.

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	Fluctuations in currency exchange rates in Canada could adversely affect our business.

	We are susceptible to seasonal earnings volatility due to adverse weather conditions in Canada.

	Our operations in Mexico are subject to specific risks, including dependence on Petróleos Mexicanos (“PEMEX”) as the sole customer, exposure to fluctuation in the Mexican peso and workforce unionization.

	Our U.S. operations in the Gulf of Mexico are adversely impacted by the hurricane season, which generally occurs in the third calendar quarter.

	When rig counts are low, our rig relocation customers may not have a need for our services.

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	Increasing trucking regulations may increase our costs and negatively impact our results of operations.

	L.E. Simmons, through SCF, controls the outcome of stockholder voting and may exercise this voting power in a manner adverse to you.

	SCF’s ownership interest and provisions contained in our certificate of incorporation and bylaws could discourage a takeover attempt, which may reduce or eliminate the likelihood of a change of control transaction and, therefore, your ability to sell your shares for a premium.

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	Two of our directors may have conflicts of interest because they are affiliated with SCF. The resolution of these conflicts of interest may not be in our or your best interests.

	We have renounced any interest in specified business opportunities, and SCF and its director nominees on our board of directors generally have no obligation to offer us those opportunities.

	Future sales of shares of our common stock may affect their market price and the future exercise of options may depress our stock price and result in immediate and substantial dilution.

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	Purchasers of common stock will experience immediate and substantial dilution.

	Because we have no current plans to pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us.

	There has been no active trading market for our common stock, and an active trading market may not develop.

	If our stock price fluctuates after the initial public offering, you could lose a significant part of your investment.

	•	changes in securities analysts’ recommendations and their estimates of our financial performance;
	•	the public’s reaction to our press releases, announcements and our filings with the SEC and those of our competitors;
	•	fluctuations in broader stock market prices and volumes, particularly among securities of oil and gas service companies;
	•	changes in market valuations of similar companies;
	•	investor perception of our industry or our prospects;
	•	additions or departures of key personnel;

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	•	commencement of or involvement in litigation;
	•	changes in environmental and other governmental regulations;
	•	announcements by us or our competitors of strategic alliances, significant contracts, new technologies, acquisitions, commercial relationships, joint ventures or capital commitments;
	•	variations in our quarterly results of operations or cash flows or those of other oil and gas service companies;
	•	revenue and operating results failing to meet the expectations of securities analysts or investors in a particular quarter;
	•	changes in our pricing policies or pricing policies of our competitors;
	•	future issuances and sales of our common stock;
	•	demand for and trading volume of our common stock;
	•	domestic and worldwide supplies and prices of and demand for oil and gas; and
	•	changes in general conditions in the domestic and worldwide economies, financial markets or the oil and gas industry.

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	•	a decline in or substantial volatility of oil and gas prices, and any related changes in expenditures by our customers;
	•	the effects of future acquisitions on our business;
	•	changes in customer requirements in markets or industries we serve;
	•	competition within our industry;
	•	general economic and market conditions;
	•	our access to current or future financing arrangements;
	•	our ability to replace or add workers at economic rates;
	•	environmental and other governmental regulations; and
	•	the effects of severe weather on our services centers or equipment.

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	•	on an actual basis; and
	•	on an as adjusted basis to give effect to this offering and the application of our estimated net proceeds from this offering as set forth under “Use of Proceeds” as if the offering occurred on September 30, 2005.

					September 30, 2005
					Actual				As Adjusted
					(In thousands)
Cash and cash equivalents(1)					$	14,377			$	173,243
Total long-term debt, including current portion:
	Notes payable:
		Revolving credit facilities			$	26,134			$	—
		Term loan facility				420,000				370,000
		Other debt				11,756				6,756
			Total			457,890				376,756
Stockholders’ equity:
	Common stock, $0.01 par value, 100,000,000 shares authorized, 27,810,283 shares issued and outstanding;            shares issued and outstanding, as adjusted					278
	Additional paid-in capital					163,475
	Treasury stock, 17,785 shares at cost					(202	)			(202	)
	Deferred compensation					(2,121	)			(2,121	)
	Retained earnings					936				936
	Accumulated other comprehensive income					16,195				16,195
			Total stockholders’ equity			178,561				418,561
			Total capitalization		$	636,451			$	795,317

(1)	Net of bank operating loans.

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Assumed initial public offering price per share		$
Net tangible book value per share as of September 30, 2005		$	(1.20	)
Increase attributable to new public investors		$
As adjusted net tangible book value per share after this offering		$
Dilution in as adjusted net tangible book value per share to new investors		$

			Shares Purchased(1)								Total Consideration
																			Average Price
			Number				Percent				Amount				Percent				Per Share
Existing stockholders(2)				27,810,283				%			$					%			$
New public investors								%								%
	Total							100%			$					100%			$

(1)	The number of shares disclosed for the existing stockholders includes                     shares being sold by the selling stockholders in this offering. The number of shares disclosed for the new investors does not include the                     shares being purchased by the new investors from the selling stockholders in this offering.
(2)	With respect to our executive officers, directors and greater-than-10% stockholders, and assuming the exercise of all outstanding warrants and stock options, the number of shares of common stock purchased from us, the total consideration paid to us, and the average price per share paid by all of those affiliated persons, are as follows:

Shares Purchased(1)

Total Consideration

Average Price

Number

Percent

Amount

Percent

Per Share

Affiliated persons

%

$

%

$

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							Financing
			Complete				Note 3				Consolidated
			(In thousands, except per share data)
			(Unaudited)
Revenue:
	Service		$	434,745			$	—			$	434,745
	Product			90,491				—				90,491
				525,236				—				525,236
Service expenses				266,344				—				266,344
Product expenses				69,968				—				69,968
Selling, general and administrative expenses				75,535				—				75,535
Write-off of deferred financing fees				2,844				(2,570	)(a)			274
Depreciation and amortization				32,902				—				32,902
	Income before interest, taxes and minority interest			77,643				2,570				80,213
Interest expense				15,617				7,560	(b)			23,177
	Income before taxes and minority interest			62,026				(4,990	)			57,036
Taxes				23,734				(1,747	)(c)			21,987
	Income before minority interest			38,292				(3,243	)			35,049
Minority interest				380				—				380
	Net income (loss)		$	37,912			$	(3,243	)		$	34,669
Earnings per share:
	Basic		$	1.39							$	1.27
	Diluted		$	1.28							$	1.17
Weighted average shares:
	Basic			27,282								27,282
	Diluted			29,640								29,640

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							MI Acq.				Financing
			Complete				Note 2				Note 3				Consolidated
			(In thousands, except per share data)
			(Unaudited)
Revenue:
	Service		$	239,427			$	—			$	—			$	239,427
	Product			81,320				—				—				81,320
				320,747				—				—				320,747
Service expenses				157,540				—				—				157,540
Product expenses				58,633				—				—				58,633
Selling, general and administrative expenses				46,077				—				—				46,077
Write-off of deferred financing fees				—				—				3,210	(a)			3,210
Depreciation and amortization				21,616				—				—				21,616
	Income before interest, taxes and minority interest			36,881				—				(3,210	)			33,671
Interest expense				7,471				—				10,500	(b)			17,971
	Income before taxes and minority interest			29,410				—				(13,710	)			15,700
Taxes				10,821				—				(4,799	)(c)			6,022
	Income before minority interest			18,589				—				(8,911	)			9,678
Minority interest (see note 2)				934				(934	)			—				—
	Net income (loss)		$	17,655			$	934			$	(8,911	)		$	9,678
Earnings per share:
	Basic		$	0.98											$	0.54
	Diluted		$	0.97											$	0.53
Weighted average shares:
	Basic			18,002												18,002
	Diluted			18,270												18,270

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1.	Basis of Presentation:

2.	Income Attributable to Minority Interests:

		IPS				IEM				Total
Year ended December 31, 2004		$	378			$	556			$	934

3.	Financing:

		For 2005, to add back $2.8 million of expense recorded as a write-off of deferred financing fees associated with debt facilities retired with the proceeds of our $420.0 million borrowing under the

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		Term B facility on September 12, 2005, partially offset by nine months of amortization of financing fees associated with the Term B facility, assuming the financing occurred on January 1, 2004. For 2004, to record the $2.8 million of expense associated with the deferred financing fees discussed above, assuming the Term B facility was borrowed on January 1, 2004, and amortization of fees associated with this facility for the year ended December 31, 2004.

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				Period from																Nine Months Ended
				May 22 to				Year Ended December 31,												September 30,
				December 31,
				2001				2002				2003				2004				2004				2005
				(In thousands, except per share data)
Statement of Operations Data:
Revenue:
	Completion and production services			$	5,855			$	30,110			$	65,025			$	194,953			$	112,611			$	351,154
	Drilling services				—				—				2,707				44,474				23,820				89,016
	Products sales				—				10,494				35,547				81,320				58,962				85,066
		Total			5,855				40,604				103,279				320,747				195,393				525,236
Expenses:
	Service and product expenses(1)				3,528				28,531				73,124				216,173				132,629				336,312
	Selling, general and administrative				1,563				7,764				16,591				46,077				28,844				75,535
	Depreciation and amortization				402				4,187				7,648				21,616				12,366				32,902
		Operating income			362				122				5,916				36,881				21,554				80,487
Interest expense					176				1,260				2,687				7,471				4,525				15,617
Write-off of deferred financing fees					—				—				—				—				—				2,844
Taxes					86				(477	)			1,506				10,821				6,574				23,734
	Income (loss) before minority interest				100				(661	)			1,723				18,589				10,455				38,292
Minority interest					7				(45	)			162				934				344				380
	Net income (loss)			$	93			$	(616	)		$	1,561			$	17,655			$	10,111			$	37,912
Earnings (loss) per share – basic				$	0.08			$	(0.22	)		$	0.22			$	0.98			$	0.71			$	1.39
Earnings (loss) per share – diluted				$	0.08			$	(0.22	)		$	0.21			$	0.97			$	0.62			$	1.28
Weighted average shares – basic					1,147				2,757				7,055				18,002				14,176				27,282
Weighted average shares – diluted					1,147				2,757				7,272				18,270				16,186				29,640

(1)	Service and product expenses is the aggregate of service expenses and product expenses.

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			Period from																Nine Months Ended
			May 22 to				Year Ended December 31,												September 30,
			December 31,
			2001				2002				2003				2004				2004				2005
			(In thousands)
Other Financial Data:
EBITDA(2)			$	764			$	4,309			$	13,564			$	58,497			$	33,920			$	110,545
Cash flows from operating activities				1,683				(8	)			13,965				34,622				15,467				48,471
Cash flows from financing activities				13,320				36,279				55,281				157,630				83,404				58,566
Cash flows from investing activities				(12,538	)			(35,616	)			(66,214	)			(186,776	)			(99,867	)			(99,145	)
Capital expenditures:
	Acquisitions, net of cash acquired(3)			9,860				27,851				54,798				139,362				75,119				18,163
	Property, plant and equipment			2,678				6,799				11,084				46,904				24,748				84,885

		As of December 31,
																		As of September 30,
		2001				2002				2003				2004				2005
		(In thousands)
Balance Sheet Data:
Cash and cash equivalents		$	2,465			$	3,120			$	6,094			$	11,547			$	19,062
Net property, plant and equipment			7,110				47,808				95,217				235,211				340,246
Total assets			18,571				110,596				206,066				515,153				769,870
Long-term debt, excluding current portion			3,443				22,270				50,144				169,190				452,496
Total stockholders’ equity			14,550				60,810				102,207				209,521				178,561

(2)	EBITDA consists of net income (loss) before interest expense, taxes, depreciation and amortization and minority interest. See “Non-GAAP Financial Measures.” EBITDA is included in this prospectus because our management considers it an important supplemental measure of our performance and believes that it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in our industry, some of which present EBITDA when reporting their results. We regularly evaluate our performance as compared to other companies in our industry that have different financing and capital structures and/or tax rates by using EBITDA. In addition, we use EBITDA in evaluating acquisition targets. Management also believes that EBITDA is a useful tool for measuring our ability to meet our future debt service, capital expenditures and working capital requirements, and EBITDA is commonly used by us and our investors to measure our ability to service indebtedness. EBITDA is not a substitute for the GAAP measures of earnings or of cash flow and is not necessarily a measure of our ability to fund our cash needs. In addition, it should be noted that companies calculate EBITDA differently and, therefore, EBITDA has material limitations as a performance measure because it excludes interest expense, taxes, depreciation and amortization and minority interest. The following table reconciles EBITDA with our net income (loss).
(3)	Acquisitions, net of cash required, consists only of the cash component of acquisitions. It does not include common stock and notes issued for acquisitions, nor does it include other non-cash assets issued for acquisitions.

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		Period from																Nine Months Ended
		May 22 to				Year Ended December 31,												September 30,
		December 31,
		2001				2002				2003				2004				2004				2005
		(In thousands)
Net income (loss)		$	93			$	(616	)		$	1,561			$	17,655			$	10,111			$	37,912
Plus: interest expense			176				1,260				2,687				7,471				4,525				15,617
Plus: tax expense			86				(477	)			1,506				10,821				6,574				23,734
Plus: depreciation and amortization			402				4,187				7,648				21,616				12,366				32,902
Plus: minority interest			7				(45	)			162				934				344				380
EBITDA		$	764			$	4,309			$	13,564			$	58,497			$	33,920			$	110,545

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	•	Completion and Production Services. Our completion and production services segment includes: (1) intervention services, which require the use of specialized equipment, such as coiled tubing units, pressure pumping units, nitrogen units, well service rigs and snubbing units, to perform various wellbore services, (2) downhole and wellsite services, such as wireline, production optimization, production testing and rental and fishing services, and (3) fluid handling services that are used to move, store and dispose of fluids that are involved in the development and production of oil and gas reservoirs.
	•	Drilling Services. Through our drilling services segment, we provide land drilling, specialized rig logistics and site preparation for oil and gas exploration and production companies.
	•	Product Sales. Through our product sales segment, we sell oil and gas field equipment, including completion, flow control and artificial lift equipment, as well as tubular goods.

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			Nine Months				Nine Months
			Ended				Ended				Year Ended				Year Ended				Year Ended				Year Ended
BHI Rotary Rig Count:			9/30/05				9/30/04				12/31/04				12/31/03				12/31/02				12/31/01
U.S. Land				1,254				1,077				1,095				924				717				1,003
U.S. Offshore				97				96				97				108				113				153
	Total U.S.			1,351				1,173				1,192				1,032				830				1,156
Canada				416				346				365				372				263				341
Mexico				112				110				110				92				65				54
	Total North America			1,879				1,629				1,667				1,496				1,158				1,551
BHI Workover Rig Count:
United States				1,320				1,215				1,235				1,129				1,010				1,211
Canada				613				574				615				350				261				342
	Total U.S. and Canada			1,933				1,789				1,850				1,479				1,271				1,553

		Average Daily Closing				Average Daily Closing
		Henry Hub Spot Natural				WTI Cushing Spot Oil
Period		Gas Prices ($/mcf)				Price ($/bbl)
1/1/99 - 12/31/99		$	2.27			$	19.30
1/1/00 - 12/31/00			4.30				30.37
1/1/01 - 12/31/01			3.96				25.96
1/1/02 - 12/31/02			3.37				26.17
1/1/03 - 12/31/03			5.49				31.06
1/1/04 - 12/31/04			5.90				41.51
1/1/05 - 9/30/05			7.75				55.46

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	•	Internal Capital Investment. Our internal expansion activities generally consist of adding equipment and qualified personnel in locations where we have established a presence. We expect to grow our operations in each of these locations by expanding services to current customers, attracting new customers and hiring local personnel with local basin-level expertise and leadership recognition. Depending on customer demand, we will consider adding equipment to further increase the capacity of services currently being provided and/or add equipment to expand the services we provide. We invested $64.8 million in equipment additions over the three-year period ended December 31, 2004, which included $46.4 million for the completion and production services segment, $14.5 million for the drilling services segment and $3.9 million for the product sales segment. We invested an additional $84.9 million during the nine months ended September 30, 2005, of which $52.2 million related to the completion and production services segment, $29.3 million related to the drilling services segment, $1.5 million related to the product sales segment and $1.9 million related to general corporate operations.
	•	External Growth. We use strategic acquisitions as an integral part of our growth strategy. We consider acquisitions that will add to our service offerings in a current operating area or that will expand our geographical footprint into a targeted basin. We have completed several acquisitions in recent years. These acquisitions affect our operating performance period to period. Accordingly, comparisons of revenue and operating results are not necessarily comparable and should not be relied upon as indications of future performance. We have invested an aggregate of $336.9 million in acquisitions over the three-year period ended December 31, 2004 and an additional aggregate of $47.0 million during the nine months ended September 30, 2005.

	•	Integrated Production Services Ltd. On July 3, 2002, we acquired Integrated Production Services Ltd., a western Canada-based integrated well service company providing wireline, production testing and production optimization services in western Canada. This acquisition was completed through a series of transactions, in which we paid $29.5 million in cash in July 2002 and an additional $20.0 million in cash in October 2002. This acquisition was an important addition to our completion and production services segment, as it provided a platform to expand our business into the Canadian oilfield services market. We recorded $28.7 million of goodwill related to this acquisition.
	•	BSI. On November 7, 2003, we acquired BSI Holdings Management, LLC and BSI Holdings, L.P. and related parties (“BSI”) for $50.1 million in cash, and issued common stock totaling

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		$8.5 million. This acquisition provided us with a base of business in the Barnett Shale region of north Texas. BSI is an integrated provider of drilling, completion and production services in the oil and gas industry and sells various products used in the production of oil and gas. We recorded $14.4 million of goodwill related to this acquisition.
	•	I.E. Miller. On August 31, 2004, we acquired all the outstanding membership interests of I.E. Miller of Eunice (Texas) No. 2, L.L.C. and certain related entities (“I.E. Miller”) for $13.6 million in cash and issued common stock totaling $12.5 million. This acquisition was an important addition to our drilling services business, as I.E. Miller specializes in rig logistics. We recorded $8.5 million of goodwill associated with this acquisition.
	•	Hyland Enterprises, Inc. On September 3, 2004, we acquired Hyland Enterprises, Inc., a Wyoming-based fluid-handling and oilfield equipment rental company, for $17.7 million in cash, the issuance of common stock totaling $6.6 million and certain additional acquisition costs totaling $1.2 million. This acquisition expanded our completion and production services segment in the U.S. Rocky Mountain region. We recorded $5.5 million of goodwill related to this acquisition.
	•	Hamm Co. On October 14, 2004, we acquired Hamm and Phillips Service Company, Inc. and certain other entities (“Hamm Co.”), an Oklahoma-based fluid-handling, well-servicing and oilfield equipment rental company, for $48.1 million in cash, the issuance of common stock totaling $37.0 million and certain additional acquisition costs totaling $2.8 million. This acquisition expanded our completion and production services segment into the U.S. Mid-Continent region and provided additional heavy equipment hauling capability for the drilling services segment. We recorded $33.8 million of goodwill related to this acquisition.
	•	Parchman Energy Group, Inc. On February 11, 2005, we acquired Parchman Energy Group, Inc. (“Parchman”) for $9.8 million in cash, the issuance of common stock totaling $19.1 million, the issuance of a subordinated note totaling $5.0 million and the potential issuance of 500,000 shares of our common stock based upon certain operating results. Parchman performs intervention services and downhole services including coiled tubing, production testing and wireline services, and operates from locations in Texas, Louisiana and Mexico. We recorded $22.0 million of goodwill related to this acquisition.
	•	Big Mac. On November 1, 2005, we acquired all of the outstanding equity interests of the Big Mac group of companies (Big Mac Transports, LLC, Big Mac Tank Trucks, LLC and Fugo Services, LLC) for $40.8 million in cash. The Big Mac group of companies (“Big Mac”) is based in McAlester, Oklahoma, and provides fluid handling services primarily to customers in eastern Oklahoma and western Arkansas. Big Mac’s principal assets consist of rolling stock and frac tanks. The purchase price, which is subject to a post-closing adjustment for actual working capital and reimbursable capital expenditures as of the closing date, has not yet been finalized. Based on preliminary analysis, we expect to record between $20 million and $25 million of goodwill in connection with this acquisition. We will include the operating results of Big Mac in the completion and production services business segment from the date of acquisition. We believe that this acquisition provides a platform to enter the eastern Oklahoma market and new Fayetteville Shale play in Arkansas.

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	•	Continuity of Interests Accounting. We applied the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 141. “Business Combinations” to account for the formation of Complete. SFAS No. 141 permits us to account for the combination of several predecessor companies using a method similar to a pooling of interests if each is controlled by a common stockholder. In connection with the Combination, we paid a dividend to our stockholders of $5.24 per share and adjusted the number of shares subject to, and exercise price of, outstanding stock options and restricted shares in accordance with Financial Accounting Standards Board (“FASB”) Interpretation No. 44. “Accounting for Certain Transactions Involving Stock Compensation, an Interpretation of Accounting Principles Board (“APB”) Opinion No. 25.” On September 12, 2005, we completed the transaction, pursuant to which CES and IEM stockholders exchanged all of their common stock for common stock of IPS. CES stockholders received 19.704 shares of IPS for each share of CES, and IEM stockholders received 19.410 shares of IPS for each share of IEM. In connection with the Combination, IPS changed its name to Complete Production Services, Inc. We acquired the interests of the minority stockholders in these predecessor companies as of the date of the consummation and accounted for these transactions using the purchase method of accounting, resulting in goodwill of $38.4 million, which represented the excess of the purchase price over the carrying value of the net assets acquired.
	•	Revenue Recognition. We recognize service revenue as services are performed and when realized or earned. Revenue is deemed to be realized or earned when we determine that the following

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		criteria are met: (1) persuasive evidence of an arrangement exists; (2) delivery has occurred or services have been rendered; (3) the fee is fixed or determinable; and (4) collectibility is reasonably assured. These services are generally provided over a relatively short period of time pursuant to short-term contracts at pre-determined day-rate fees, or on a day-to-day basis. Revenue and costs related to drilling contracts are recognized as work progresses. Progress is measured as revenue is recognized based upon day rate charges. For certain contracts, we may receive lump-sum payments from our customers related to the mobilization of rigs and other drilling equipment. Under these arrangements, we defer revenues and the related cost of services and recognize them over the term of the drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Revenues associated with product sales are recorded when product title is transferred to the customer.
	•	Impairment of Long-Lived Assets. We evaluate potential impairment of long-lived assets and intangibles, excluding goodwill and other intangible assets without defined services lives, when indicators of impairment are present, as defined in SFAS No. 144. If such indicators are present, we project the fair value of the assets by estimating the undiscounted future cash in-flows to be derived from the long-lived assets over their remaining estimated useful lives, as well as any salvage value. Then, we compare this fair value estimate to the carrying value of the assets and determine whether the assets are deemed to be impaired. For goodwill and other intangible assets without defined service lives, we apply the provisions of SFAS No. 142, which requires an annual impairment test, whereby we estimate the fair value of the asset by discounting future cash flows at our projected cost of capital rate. If the fair value estimate is less than the carrying value of the asset, an additional test is required whereby we apply a purchase price analysis consistent with that described in SFAS No. 141. If impairment is still indicated, we would record an impairment loss in the current reporting period for the amount by which the carrying value of the intangible asset exceeds its projected fair value. Our industry is highly cyclical and the estimate of future cash flows requires the use of assumptions and our judgment. Periods of prolonged down cycles in the industry could have a significant impact on the carrying value of these assets and may result in impairment charges.
	•	Stock Options. We have issued stock-based compensation to certain employees, officers and directors in the form of stock options. We account for these stock options by applying APB Opinion No. 25, “Accounting for Stock Issued to Employees,” which does not require us to recognize compensation expense related to these employee stock options when the exercise price of the option is at least equal to the market value of the stock on the date of grant. Accordingly, we have not recognized compensation expense related to our stock options issued. We have, however, included potential common shares associated with our stock option awards in the calculation of diluted shares outstanding in order to determine diluted earnings per share. We are not required to account for our stock-based compensation plans using the fair value recognition provision of SFAS No. 123, “Accounting for Stock-Based Compensation.” Accounting for these stock options using the fair value recognition provisions of SFAS No. 123 would negatively impact our financial position and results of operations, as it requires that the fair value of stock options issued be estimated using pricing models, which require the application of highly subjective assumptions that have an inherent degree of uncertainty, and require us to expense over the vesting period of the related options. In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment,” which revises SFAS No. 123 and supercedes APB Opinion No. 25. SFAS No. 123R will require us to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award, with limited exceptions. SFAS No. 123R becomes effective for us as of January 1, 2006. We are currently evaluating the impact that this statement will have on our financial position, results of operations and cash flows. We expect to incur expenses related to our stock options for each reporting period subsequent to our adoption of SFAS No. 123R in the first quarter of 2006.

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	•	Allowance for Bad Debts and Inventory Obsolescence. We record trade accounts receivable at billed amounts, less an allowance for bad debts. Inventory is recorded at cost, less an allowance for obsolescence. To estimate these allowances, management reviews the underlying details of these assets as well as known trends in the marketplace, and applies historical factors as a basis for recording these allowances. If market conditions are less favorable than those projected by management, or if our historical experience is materially different from future experience, additional allowances may be required.
	•	Property, Plant and Equipment. We record property, plant and equipment at cost less accumulated depreciation. Major betterments to existing assets are capitalized, while repairs and maintenance costs that do not extend the service lives of our equipment are expensed. We determine the useful lives of our depreciable assets based upon historical experience and the judgment of our operating personnel. We generally depreciate the historical cost of assets, less an estimate of the applicable salvage value, on the straight-line basis over the applicable useful lives, except office furniture and computers, which are depreciated using the declining balance method. Upon disposition or retirement of an asset, we record a gain or loss if the proceeds from the transaction differ from the net book value of the asset at the time of the disposition or retirement. If our depreciation estimates are not correct, we may record a disproportionate amount of gains or losses upon disposition of these assets. We believe our estimates of useful lives are materially correct.
	•	Deferred Income Taxes. Our income tax expense includes income taxes related to the United States, Canada and other foreign countries, including local, state and provincial income taxes. We account for tax ramifications using SFAS No. 109, “Accounting for Income Taxes.” Under SFAS No. 109, we record deferred income tax assets and liabilities based upon temporary differences between the carrying amount and tax basis of our assets and liabilities and measure tax expense using enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect of a change in tax rates is recognized in income in the period of the change. Furthermore, SFAS No. 109 requires us to record a valuation allowance for any net deferred income tax assets which we believe are likely to not be used through future operations. As of September 30, 2005, we had recorded a total valuation allowance of $0.7 million related to certain deferred tax assets in Canada. If our estimates and assumptions related to our deferred tax position change in the future, we may be required to record additional valuation allowances against our deferred tax assets and our effective tax rate may increase, which could result in a material adverse effect on our financial position, results of operations and cash flows. As of December 31, 2004, no deferred U.S. income taxes have been provided on the approximately $7.3 million of undistributed earnings of foreign subsidiaries in which we intend to indefinitely reinvest. Upon distribution of these earnings in the form of dividends or otherwise, we may be subject to U.S. income taxes and foreign withholding taxes.

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Description		Estimates/Assumptions Used		Variability in Accounting
Revenue Recognition		We recognize revenue when realizable and earned as services are performed or as risk of ownership and physical possession passes to the buyer. We defer unearned revenue until earned. Any reimbursements of mobilization charges are amortized over the contract involved.		There is a risk that we may not record revenue in the proper period.
Impairment of Long-lived Assets		We evaluate the recoverability of assets periodically, but at least annually for goodwill and intangible assets with indefinite lives, by reviewing operational performance and expected cash flows. Our management estimates future cash flows for this purpose and for intangible assets, discounts these cash flows at an applicable rate.		There is a risk that management’s estimates of future performance may not approximate actual performance or that rates used for discounting cash flows are not consistent with the actual discount rates. Our assets could be overstated if impairment losses are not identified timely.
Allowance for Bad Debts and Obsolete Inventory		We estimate the recoverability of receivables and inventory on an individual basis based upon historical experience and management’s judgement.		There is a risk that management may not detect uncollectible accounts or unsalvageable inventory in the correct accounting period.
Property, Plant and Equipment		Our management estimates useful lives of depreciable equipment and salvage values. The depreciation method used is generally the straight-line method, except for furniture and office equipment which is depreciated on an accelerated basis.		GAAP permits various depreciation methods to recognize the use of assets. Use of a different depreciation method or different depreciable lives could result in materially different results. The estimated useful lives are consistent with industry averages. There is a risk that the asset’s useful life used for our depreciation calculation will not approximate the actual useful life of the asset.

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Description		Estimates/Assumptions Used		Variability in Accounting
Valuation Allowance for Income Taxes		We apply the provisions of SFAS No. 109 to account for income taxes. Differences between depreciation methods used for financial reporting purposes compared to tax purposes as well as other items, including loss carry forwards and valuation allowances against deferred tax assets, require management’s judgment related to the realizability of deferred tax accounts.		There is a risk that estimates related to the use of loss carry forwards and the realizability of deferred tax accounts may be incorrect, and that the result could materially impact our financial position and results of operations. In addition, future changes in tax laws could result in additional valuation allowances.
Stock Options		We apply the provisions of APB No. 25 to account for stock options and estimate compensation expense that would be required to be recognized under SFAS No. 123 for pro forma footnote disclosures. The determination of the fair value of stock options requires subjective estimates of variables used in a pricing model, including stock volatility, dividend rate, risk-free interest rate and expected term of options.		GAAP permits the use of various models to determine the fair value of stock options and the variables used for the model are highly subjective. The use of different assumptions or a different model may have a material impact on our financial disclosures.

																			Percent								Percent
															Change				Change				Change				Change
															2004/				2004/				2003/				2003/
			2004				2003				2002				2003				2003				2002				2002
Revenue:
Completion and production services			$	194,953			$	65,025			$	30,110			$	129,928				200	%		$	34,915				116	%
Drilling services				44,474				2,707				—				41,767				NM				2,707				NM
Product sales				81,320				35,547				10,494				45,773				129	%			25,053				239	%
	Total		$	320,747			$	103,279			$	40,604			$	217,468				211	%		$	62,675				154	%
EBITDA:
Completion and production services			$	38,349			$	9,134			$	3,058			$	29,215				320	%		$	6,076				199	%
Drilling services				10,093				712				—				9,381				NM				712				NM
Product sales				12,924				4,951				1,251				7,973				161	%			3,700				296	%
Corporate				(2,869	)			(1,233	)			—				(1,636	)			133	%			(1,233	)			NM
	Total		$	58,497			$	13,564			$	4,309			$	44,933				331	%		$	9,255				215	%

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			Nine				Nine								Percent
			Months				Months				Change				Change
			Ended				Ended				2005/				2005/
			9/30/05				9/30/04				2004				2004
Revenue:
Completion and production services			$	351,154			$	112,611			$	238,543				212	%
Drilling services				89,016				23,820				65,196				274	%
Product sales				85,066				58,962				26,104				44	%
	Total		$	525,236			$	195,393			$	329,843				169	%
EBITDA:
Completion and production services			$	82,615			$	21,939			$	60,676				277	%
Drilling services				27,658				5,104				22,554				442	%
Product sales				11,131				10,199				932				9	%
Corporate				(10,859	)			(3,322	)			(7,537	)			227	%
	Total		$	110,545			$	33,920			$	76,625				226	%

	Revenue

	•	Completion and Production Services. Segment revenue increased $238.5 million and resulted primarily from: (1) the acquisition of Hyland Enterprises, Inc. in September 2004, which contributed $44.4 million in 2005; (2) the acquisition of Hamm Co. in October 2004, which contributed $57.9 million; (3) the acquisition of Parchman in February 2005, which contributed $54.8 million; (4) several other smaller acquisitions in late 2004, which contributed revenues for a full nine-month period in 2005; and (5) an incremental increase in revenues earned as a result of additional capital investment in the well servicing, rental and fluid-handling businesses, as well as an improved pricing environment for our services and products.
	•	Drilling Services. Segment revenue increased $65.2 million, primarily related to an increase associated with acquisitions of $45.2 million, substantially contributed by the acquisition of IEM in September 2004. In addition, the segment benefited from increased prices for our services and increased oilfield activity, which provided incremental revenues of $20.0 million, achieved in part

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		through additional investment in drilling rigs and drilling logistics equipment for operations located in the Barnett Shale region of north Texas.
	•	Product Sales. Segment revenue increased $26.1 million, fueled by an incremental increase in supply store sales of $14.5 million, a $8.9 million incremental increase in sales of surface production equipment in Canada, improved sales in other international locations and an increase in the sale of flow control products. These increased product sales reflect the overall improved market conditions.

	Service and Product Expenses

	Selling, General and Administrative Expenses

	Depreciation and Amortization

	Interest Expense

	Taxes

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	Revenue

	•	Completion and Production Services. Segment revenue increased $129.9 million and resulted primarily from: (1) the acquisition of BSI in late 2003, which contributed $40.2 million of incremental revenues in 2004, of which $20.9 million was derived from a full-year’s operation in 2004 and $16.1 million was derived from investment in capital equipment; (2) the acquisition of eleven smaller companies throughout 2004 which contributed to 2004 revenue totals but did not contribute to operating results in 2003; and (3) a general increase in the use of our services attributable to more favorable oilfield activity levels associated with rising commodity prices.
	•	Drilling Services. Segment revenue increased $41.8 million. Of this increase, $18.9 million was provided through acquisitions, and more specifically, the acquisition of BSI in late 2003, which contributed $17.7 million of incremental revenues in 2004, and the Hamm Co. acquisition completed in late 2004, which provided an additional $1.2 million of drilling revenues. The remaining revenue increase in 2004 relative to 2003 was due to additional investment in drilling rigs for operations located in the Barnett Shale region of north Texas.
	•	Product Sales. Segment revenue increased $45.8 million, of which $31.2 million was derived from the product sales component of BSI’s acquisition and a general increase in product sales from existing operations as a result of improved market conditions in the oil and gas industry, including higher international sales and, in particular, sales of surface production equipment in Canada, and increased sales of flow control equipment.

	Service and Product Expenses

	Selling, General and Administrative Expenses

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	Depreciation and Amortization

	Interest Expense

	Taxes

	Revenue

	•	Completion and Production Services. Segment revenue increased $34.9 million and resulted primarily from: (1) the acquisition of Integrated Production Services Ltd. in July 2002, which contributed incremental revenues of $22.5 million in 2003; (2) the acquisition of BSI in late-2003, which contributed $3.2 million of revenue included in the 2003 results; and (3) a general increase in demand by our customers for our wireline services in the U.S. Gulf Coast region and higher Canadian activity levels.
	•	Drilling Services. Segment revenue was $2.7 million in 2003. Prior to 2003, we did not provide drilling services. We began offering these services with the acquisition of BSI in late 2003.
	•	Product Sales. Segment revenue increased $25.1 million, of which $20.2 million represented an incremental increase in product sales due to the acquisition of Integrated Production Services Ltd. in July 2002, the acquisition of BSI in November 2003, and the acquisition of Canadian-based Ess-Ell Tools, a provider of flow control products, in March 2003.

	Service and Product Expenses

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	Selling, General and Administrative Expenses

	Depreciation and Amortization

	Interest Expense

	Taxes

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			Nine Months Ended
			September 30,								Year Ended December 31,
			2005				2004				2004				2003				2002
Cash flows provided by (used in):
	Operating activities		$	48,471			$	15,467			$	34,622			$	13,965			$	(8	)
	Financing activities			58,566				83,404				157,630				55,281				36,279
	Investing activities			(99,145	)			(99,867	)			(186,776	)			(66,214	)			(35,616	)

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	Dividends

	Description of Our Indebtedness

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	•	EBITDA (as defined in the Credit Agreement) to Interest Expense (as defined in the Credit Agreement) of not less than 3.0 to 1.0;
	•	total debt to EBITDA of not more than 4.25 to 1.0 through September 30, 2006, 4.00 to 1.0 from December 31, 2006 through September 30, 2007, and 3.75 to 1.0 thereafter; and
	•	total senior secured debt to EBITDA of not more than 3.75 to 1.0 through March 31, 2006, 3.5 to 1.0 from June 30, 2006 through September 30, 2006, 3.25 to 1.0 from December 31, 2006 to September 30, 2007, 3.00 to 1.0 from December 31, 2007 through September 30, 2008, and 2.50 to 1.0 thereafter.

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	•	failure to pay any principal when due or any interest, fees or other amount within certain grace periods;
	•	breach of representations in the Credit Agreement or other loan documents;
	•	failure to perform or otherwise comply with the covenants in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods;
	•	default by us and any of our subsidiaries on the payment of any other indebtedness in excess of $10.0 million, any other event or condition shall occur or exist with respect to such indebtedness beyond the applicable grace period if the effect of such event or condition is to permit or cause the acceleration of the indebtedness, or such indebtedness shall be declared due and payable prior to its scheduled maturity;
	•	bankruptcy or insolvency events involving us or our subsidiaries;
	•	the entry of one or more adverse judgments in excess of $10.0 million (excluding applicable insurance proceeds) against which enforcement proceedings are brought or that are not stayed pending appeal; and
	•	the occurrence of a change of control (as defined in the Credit Agreement).

	Acquisition of Big Mac

	Other Arrangements

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	Outstanding Debt and Operating Lease Commitments

				Payments Due by Period
Contractual Obligations				Total				2005				2006-2007				2008-2009				Thereafter
Long-term debt, including capital (finance) lease obligations				$	449,406			$	4,287			$	8,554			$	8,515			$	428,050
	Purchase obligations(1)				19,840				19,840				—				—				—
	Operating lease obligations				36,303				10,408				15,626				9,566				703
	Other long-term obligations(2)				8,450				—				—				3,450				5,000
		Total contractual obligations		$	513,999			$	34,535			$	24,180			$	21,531			$	433,753

(1)	Purchase obligations were pursuant to inventory and equipment purchase orders outstanding as of September 30, 2005. We have no significant purchase orders which extend beyond one year.
(2)	Other long-term obligations include amounts due under subordinated note arrangements with maturity dates beginning in 2009.

	Off-Balance Sheet Arrangements

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	•	Intervention Services. Well intervention requires the use of specialized equipment to perform an array of wellbore services. Our fleet of intervention service equipment includes coiled tubing units, pressure pumping units, nitrogen units, well service rigs, snubbing units and a variety of support equipment. Our intervention services provide customers with innovative solutions to increase production of oil and gas. For example, in the Barnett Shale region of north Texas we operate advanced coiled tubing units that have electric-line conductors within the units’ coiled tubing string. These specially configured units can deploy perforating guns, logging tools and plugs, without a separate electric-line unit in high inclination and “horizontal” wells that are prevalent throughout that basin.
	•	Downhole and Wellsite Services. Our downhole and wellsite services include electric-line, slickline, production optimization, production testing, rental and fishing services. We also offer several proprietary services and products that we believe create significant value for our customers. Examples of these proprietary services and products include: (1) our Green Flowback system, which permits the flow of gas to our customers while performing drill-outs and flowback operations, increasing production, accelerating time to production and eliminating the need to flare gas, and (2) our patented plunger lift system that, when combined with our diagnostic and installation

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		services, removes fluids from gas wells resulting in increased production and the extension of the life of the well.
	•	Fluid Handling. We provide a variety of services to help our customers obtain, move, store and dispose of fluids that are involved in the development and production of their reservoirs. Through our fleet of specialized trucks, frac tanks and other assets, we provide fluid transportation, heating, pumping and disposal services for our customers.

	•	Higher demand for natural gas in North America. We believe that natural gas will be in high demand in North America over the next several years because of the growing popularity of this clean-burning fuel. According to the International Energy Association’s 2004 World Energy Outlook, natural gas demand in North America (United States, Canada and Mexico) is projected to grow by approximately 45% from 2002 to 2030.
	•	Constrained North American gas supply. Although the demand for natural gas is projected to increase, supply is likely to be constrained as North American natural gas basins are becoming more mature and experiencing increased decline rates. Even though the number of wells drilled in North America has increased significantly in recent years, a corresponding increase in domestic production has not occurred. As a result, producers are required to increase drilling just to maintain flat production. To supply the growing demand for natural gas, the primary alternatives are to increase drilling, enhance recovery rates or import LNG from overseas. To date minimal increases have occurred, although many forecasts anticipate a material increase of LNG imports.

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		Average Daily Closing				Average Daily Closing
		Henry Hub Spot Natural				WTI Cushing Spot Oil
Period		Gas Prices ($/mcf)				Price ($/bbl)
1/1/99 - 12/31/99		$	2.27			$	19.30
1/1/00 - 12/31/00			4.30				30.37
1/1/01 - 12/31/01			3.96				25.96
1/1/02 - 12/31/02			3.37				26.17
1/1/03 - 12/31/03			5.49				31.06
1/1/04 - 12/31/04			5.90				41.51
1/1/05 - 9/30/05			7.75				55.46

	Trend toward drilling and developing unconventional North American natural gas resources. Due to the maturity of conventional North American oil and gas reservoirs and their accelerating production decline rates, unconventional oil and gas resources will comprise an increasing proportion of future North American oil and gas production. Unconventional resources include tight sands, shales and coalbed methane. These resources require more wells to be drilled and maintained, frequently on tighter acreage spacing. The appropriate technology to recover unconventional gas resources varies from region to region; therefore, knowledge of local conditions and operating procedures, and selection of the right technologies is key to providing customers with appropriate solutions.
	The advent of the resource play. A “resource play” is a term used to describe an accumulation of hydrocarbons known to exist over a large area which, when compared to a conventional play, has lower commercial development risks and a lower average decline rate. Once identified, resource plays have the potential to make a material impact because of their size and low decline rates. The application of appropriate technology and program execution are important to obtain value from resource plays. Resource play developments occur over long periods of time, well by well, in large-scale developments that repeat common tasks in an assembly-line fashion and capture economies of scale to drive down costs.
	Increasingly complex technologies. Increasing prices and the development of unconventional oil and gas resources are driving the need for complex, new technologies to help increase recovery rates, lower production costs and accelerate field development. We believe that the increasing complexity of technology used in the oil and gas development process coupled with limited engineering resources will require production companies to increase their reliance on service companies to assist them in developing and applying these technologies.

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	•	clear business direction;
	•	thorough planning process;
	•	clearly defined targets and accountabilities;
	•	close performance monitoring;
	•	strong performance incentives for management and employees; and
	•	effective communication.

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Gulf

Western

Coast/

Central &

DJ

Western

North

Canadian

South

South

East

North

Western

Basin

Slope

SW

Western

Rockies

Sedimentary

Product/Service Offering

Mexico

Louisiana

Texas

Texas

Texas

Oklahoma

(CO)

(CO & UT)

Wyoming

Wyoming

(MT & ND)

Basin

Completion and Production Services:

Coiled Tubing

ü

ü

ü

ü

ü

ü

ü

Well Servicing

ü

ü

ü

ü

ü

ü

Snubbing

ü

ü

ü

Electric-line

ü

ü

ü

Slickline

ü

ü

ü

ü

ü

Production Optimization

ü

ü

ü

ü

ü

ü

ü

ü

Production Testing

ü

ü

ü

ü

ü

ü

ü

Rental Equipment

ü

ü

ü

ü

ü

Pressure Testing

ü

ü

ü

Fluid Handling

ü

ü

ü

ü

ü

ü

ü

Drilling Services:

Contract Drilling

ü

Drilling Logistics

ü

ü

ü

ü

ü

ü

ü

ü

Product Sales:

Supply Stores

ü

ü

ü

Production Enhancement Products

ü

ü

ü

“ü”	denotes a service or product currently offered by us in this area.

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	Completion and Production Services (67% of Revenue for the Nine Months Ended September 30, 2005)

	Intervention Services

	•	Completion Services. As newly drilled oil and gas wells are prepared for production, our operations may include selectively perforating the well casing to access producing zones, stimulating and testing these zones and installing downhole equipment. We provide intervention services and products to assist in the performance of these services. The completion process typically lasts from a few days to several weeks, depending on the nature and type of the completion. Oil and gas producers use our intervention services to complete their wells because we have well trained employees, the experience necessary to perform such services and a strong record for safety and reliability.
	•	Workover Services. Producing oil and gas wells occasionally require major repairs or modifications, called “workovers.” These services include extensions of existing wells to drain new formations either through deepening wellbores to new zones or by drilling horizontal lateral wellbores to improve reservoir drainage patterns. In less extensive workovers, we provide services and products to seal off depleted zones in existing wellbores and access previously bypassed productive zones. Other workover services which we provide include: major subsurface repairs, such as casing repair or replacement; recovery of tubing and removal of foreign objects in the wellbore; repairing downhole equipment failures; plugging back the bottom of a well to reduce the amount of water being produced; cleaning out and recompleting a well if production has declined; and repairing leaks in the tubing and casing.
	•	Maintenance Services. Maintenance services are required throughout the life of most producing oil and gas wells to ensure efficient and continuous operation. We provide services that include mechanical repairs necessary to maintain production from the well, such as repairing inoperable pumping equipment or replacing defective tubing, and removing debris from the well. Other services include pulling rods, tubing, pumps and other downhole equipment out of the wellbore to identify and repair a production problem.

	Coiled Tubing and Pressure Pumping Units

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	Well Service Rigs

	Snubbing Units

	Downhole and Wellsite Services

	•	Perforating Services. Perforating involves positioning a perforating gun that contains explosive jet charges down the wellbore next to a productive zone. A detonator is fired and primer cord is ignited, which then detonates the jet charges. The resulting explosion burns a hole through the wellbore casing and cement and into the formation, thus allowing the formation fluid to flow into the wellbore and be produced to the surface. The perforating gun may be deployed in a number of ways. The gun can be conveyed by a conventional wireline cable if the wellbore geometry allows, it may be conveyed on coiled tubing, it may be conveyed on conventional tubing or the gun may be “pumped-down” to the correct depth in the wellbore.
	•	Logging Services. Cased hole logging requires the use of a single or multi-conductor, braided steel cable (electric-line), mounted on a hydraulically operated drum, and a specialized logging truck. Electronic instruments are attached to the end of the cable and lowered to the bottom of the well and the line is slowly pulled out of the well transmitting wellbore data up the cable to the surface

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		where the information is processed by a surface computer system and displayed on a paper graph in a logging format. This information is used by customers to analyze different downhole formation structures, to detect the presence of oil, gas and water and to check the integrity of the casing or the cement behind the pipe. Logs are also run to detect gas or fluid migration between zones or to the surface.
	•	Slickline Services. Slickline services are used primarily for well maintenance. The line used for this application is generally a small single steel line. Typical applications of this service would include bottom hole pressure surveys, running temperature gradients, setting tubing plugs, opening and closing sliding sleeves, fishing operations, plunger lift installations, gas lift installations and other maintenance services that the well would require during its lifecycle.

	•	Plunger Lift Services and Products. We provide plunger lift candidate selection, installation and maintenance services which may incorporate the use of our patented Pacemaker Plunger Lift System. Plunger lift systems facilitate the removal of fluids that restrict the production of natural gas wells. Removing fluids that accumulate in wells increases production and in many cases slows decline rates. The proprietary design of our Pacemaker Plunger Lift System incorporates a large bypass area which allows it to make more trips per day and remove more wellbore fluids, versus other plunger lift designs, in wells with certain characteristics.
	•	Acoustic Pressure Surveys. We provide acoustic pressure surveys which are an analytical technique that assists our customers in determining static reservoir pressure and the existence of near wellbore formation damage.
	•	Dynamometer Analysis. Our dynamometer analysis services include the analysis of reciprocating rod pumping systems (pumpjacks) to determine pump performance and provide our customers with critical information for well performance used to optimize the production and recovery of oil and gas.
	•	Fluid Level Analysis. We provide fluid level analysis services which record an acoustic pulse as it travels down the wellbore in order to determine the fluid depth.

	•	Well clean-ups or flowbacks are done shortly after completing or stimulating a well and are designed to remove damaging drilling fluids, completion fluids, sand and other debris. This “clean-up” prevents damage to the permanent production facilities and flowlines, thereby improving production. Our clean-up offering includes our Green Flowback services, which permit the flow of gas to our customers while performing drill- outs and flowback operations, increasing production, accelerating time to production and eliminating the need to flare gas;

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	•	Exploration well testing measures how a reservoir performs under various flow conditions. These measurements allow reservoir and production engineers, and geologists to understand a well’s or reservoir’s production capability. Exploration testing jobs can last from a few days to several months; and
	•	In-line production testing measures a well’s flow rates, oil, gas and water composition, pressure and temperature. These measurements are used by engineers to identify and solve well and reservoir problems. In-line production testing is performed after a well has been completed and is already producing. In-line tests can run from several hours to more than several months.

	•	Rental Equipment and Services. We rent specialized tools, equipment and tubular goods for the drilling, completion and workover of oil and gas wells. Items rented include pressure control equipment, drill string equipment, pipe handling equipment, fishing and downhole tools, and other equipment, including stabilizers, power swivels and bottom-hole assemblies.
	•	Fishing Services. We provide highly skilled downhole services, including fishing, milling and cutting services, which consist of removing or otherwise eliminating “fish” or “junk” (a piece of equipment, a tool, a part of the drill string or debris) in a well that is causing an obstruction. We also install whipstocks to sidetrack wells, provide plugging and abandonment services, pipe recovery and wireline recovery services, foam services and casing patch installation.
	•	Pressure Testing Services. We provide specialized pressure testing services which involve the use of truck mounted equipment designed to carry small fluid volumes with high pressure pumps and hydraulic torque equipment. This equipment is primarily used to perform pressure tests on flow line, pressure vessels, lubricators, well heads, casings and tubing strings. The units are also used to assemble and disassemble BOPs for the drilling and work over sector. We have developed specialized, multi-service pressure testing units that enable one or two employees to complete multiple services simultaneously. As of September 30, 2005, we had 30 multi-service pressure testing units that we operated in Colorado, Utah and Wyoming.

	Fluid Handling

	•	Fluid Transpiration. As of September 30, 2005, we operated over 600 specialized transport trucks to deliver, transport and dispose of fluids safely and efficiently. We transport fresh water, completion fluids, produced water, drilling mud and other fluids to and from our customers’ wellsites. Our assets include U.S. Department of Transportation certified equipment for transportation of hazardous waste.
	•	Frac Tank Rental. As of September 30, 2005, we operated a fleet of over 1,250 frac tanks that are often used during hydraulic fracturing operations. We use our fleet of fluid transport assets to fill and empty these tanks and we deliver and remove these tanks from the wellsite with our fleet of winch trucks.
	•	Fluid Disposal. As of September 30, 2005, we owned 14 salt water disposal wells in Oklahoma and Texas and one produced water evaporation facility in Wyoming. These facilities are used to dispose of water from fracturing operations and from fluids produced during the routine production

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		of oil and gas. In addition, we also operated two mud disposal facilities that are used to store and ultimately dispose of drilling mud.
	•	Other Services. We own and operate a fleet of hot oilers and superheaters, which are assets capable of heating high volumes of fluids. We also sell fluids used during well completions, such as fresh water and potassium chloride, and drilling mud, which we move to our customers’ wellsites using our fluid transportation services.

	Drilling Services (17% of Revenue for the Nine Months Ended September 30, 2005)

	Contract Drilling

	Drilling Logistics

	•	Drilling Rig Moving. Through our owned and operated fleet of over 200 specialized trucks as of September 30, 2005, we provide drilling rig mobilization services primarily in Louisiana, Texas, Oklahoma, Arkansas and Wyoming. Our capabilities allow us to move the largest rigs in the United States. Our operations are strategically located in regions where approximately 50% of the land drilling rigs in the United States are located. We believe we have a leading market position in the Gulf Coast region of Texas and Louisiana. We believe our highly skilled personnel position us as one of the leading rig moving companies in the industry.
	•	Wellsite Preparation and Remediation. We provide equipment and services to build and reclaim drilling wellsites before and after the drilling operations take place. We build roads, dig pits, clear land, move earth and provide a host of construction services to drilling contractors and to oil and gas producers. Our wellsite preparation and remediation services are in Texas, Colorado and Wyoming.

	Product Sales (17% of Revenue for the Nine Months Ended September 30, 2005)

	Supply Stores

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	Production Enhancement Products

	•	Flow Control Products. We are a leading independent supplier of subsurface flow control equipment to the North American oil and gas market. Our product line includes downhole blanking plugs, landing nipples, sliding sleeves, flapper valves and bottom-hole chokes. Through our flow control business, we also provide a proprietary thermo chemical metal treatment process known as HARD KOTEtm that increases the useful life of downhole equipment by providing enhanced resistance to abrasion, adhesion, erosion and corrosion.
	•	Well Completion Products. We offer a comprehensive line of well completion products, which include packers, tubing anchors, plugs, retainers and other completion accessories.
	•	Artificial Lift Systems. Our line of artificial lift system accessories is designed to optimize the performance of rod pump and progressive cavity (“PC”) or screw pump systems. We are a leader in tools designed to prevent the counter rotation of PC pumps, particularly during high-volume operation, and we hold eight patents in this area. Other accessories include tubing centralizers and downhole gas separators installed below the pump. Downhole gas separators remove the natural gas from the reservoir fluid before it enters the pump, thus improving pump efficiency.

	Manufacturing

	Overseas Operations

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	•	personal injury or loss of life;
	•	damage or destruction of property, equipment and the environment; and
	•	suspension of operations.

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Name		Age				Position
Andrew L. Waite			44			Chairman of the Board
Joseph C. Winkler			54			Director, President and Chief Executive Officer
J. Michael Mayer			49			Senior Vice President and Chief Financial Officer
James F. Maroney, III			54			Vice President, Secretary and General Counsel
Kenneth L. Nibling			54			Vice President, Human Resources and Administration
Robert L. Weisgarber			53			Vice President — Accounting and Controller
David C. Baldwin			42			Director
Robert S. Boswell			55			Director
Harold G. Hamm			59			Director
R. Graham Whaling			51			Director
James D. Woods			73			Director
Ronald Boyd			49			President Mid-Continent Division
Lee Daniel, III			59			President Rockies Division
Brian K. Moore			48			President IPS Operations
John D. Schmitz			45			President Texas Division

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	•	Class I – Messrs. Joseph C. Winkler, Andrew L. Waite and R. Graham Whaling;
	•	Class II – Messrs. Harold G. Hamm and James D. Woods; and
	•	Class III – Messrs. David C. Baldwin and Robert S. Boswell.

	Audit Committee

	•	to review our external financial reporting;

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	•	to engage our independent auditors; and
	•	to review our procedures for internal auditing and the adequacy of our internal accounting controls.

	Nominating and Corporate Governance Committee

	•	to recommend to the board of directors proposed nominees for election to the board of directors by the stockholders at annual meetings, including an annual review as to the renominations of incumbents and proposed nominees for election by the board of directors to fill vacancies that occur between stockholder meetings; and
	•	to make recommendations to the board of directors regarding corporate governance matters and practices.

	Compensation Committee

	•	to administer our stock plans and incentive compensation plans, including our stock incentive plans, and in this capacity, make all option grants or awards to our directors and employees under such plans;
	•	to make recommendations to the board of directors with respect to the compensation of our chief executive officer and our other executive officers; and
	•	to review key employee compensation policies, plans and programs.

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															Options
Name and Principal Position			Year				Salary				Bonus				Granted
Joseph C. Winkler(1)				2004			$	—			$	—				—
	President and Chief			2003				—				—				—
	Executive Officer			2002				—				—				—
J. Michael Mayer(2)				2004			$	106,298			$	89,186				62,572
	Senior Vice President and			2003				—				—				—
	Chief Financial Officer			2002				—				—				—
James F. Maroney, III(3)				2004			$	—			$	—				—
	Vice President, Secretary and			2003				—				—				—
	General Counsel			2002				—				—				—
Kenneth L. Nibling(4)				2004			$	—			$	—				—
	Vice President,			2003				—				—				—
	Human Resources and			2002				—				—				—
	Administration
Robert L. Weisgarber(5)				2004			$	141,667			$	13,513				46,929
	Vice President — Accounting			2003				—				—				—
	and Controller			2002				—				—				—
Andrew L. Waite(6)				2004			$	—			$	—				—
	Chairman of the Board			2003				—				—				—
	and Former Chief			2002				—				—				—
	Executive Officer

(1)

Upon the completion of the Combination, Mr. Winkler became our Chief Executive Officer, President and director. See “– Employment Agreements” below for a description of the terms of Mr. Winkler’s employment. Mr. Winkler was employed by CES as Chief Executive Officer and President and appointed as a director of CES in June 2005. The stockholders of CES prior to the Combination held a majority ownership in us following the Combination. In addition, former directors

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	of CES represent a majority of the directors of our board of directors. Accordingly, CES is treated as the accounting acquirer in the Combination.

(2)	Upon the completion of the Combination, Mr. Mayer became our Senior Vice President and Chief Financial Officer. Mr. Mayer was employed by CES as Vice President and Chief Financial Officer in May 2004.
(3)	On October 3, 2005, Mr. Maroney became our Vice President, Secretary and General Counsel.
(4)	On October 3, 2005, Mr. Nibling became our Vice President, Human Resources and Administration.
(5)	Upon the completion of the Combination, Mr. Weisgarber became our Vice President — Accounting and Controller. Mr. Weisgarber was employed by CES as Vice President — Accounting in April 2004.
(6)	Mr. Waite is the Chairman of our board of directors and served as the Chief Executive Officer of CES prior to the hiring of Mr. Winkler in June 2005. Mr. Waite served as the Chief Executive Officer of CES from November 7, 2003 until June 20, 2005. Mr. Waite did not receive compensation from CES for his services as Chief Executive Officer. Mr. Waite is a Managing Director of L.E. Simmons and Associates, Incorporated. L.E. Simmons and Associates, Incorporated received certain consideration from CES in connection with its provision of support services to CES. For a description of these services, see “Certain Relationships and Related Party Transactions.”

																			Potential Realizable
																			Value at Assumed
																			Annual Rates of
																			Stock Price
																			Appreciation for
Individual Grants																			Options Term
			Number of				Percent of Total
			Securities				Options/SARs
			Underlying				Granted to				Exercise or
			Option/SARs				Employees in				Base Price				Expiration
Name			Granted				Fiscal Year				Per Share				Date				5%				10%
Joseph C. Winkler				—				—				—				—				—				—
	President and Chief
	Executive Officer
J. Michael Mayer				62,572				11.1%			$	4.00(1)				06/2009			$	69,070			$	152,627
	Senior Vice President and
	Chief Financial Officer
James F. Maroney, III				—				—				—				—				—				—
	Vice President, Secretary
	and General Counsel
Kenneth L. Nibling				—				—				—				—				—				—
	Vice President, Human
	Resources and
	Administration
Robert L. Weisgarber				46,929				8.3%				9.59(1)				11/2009			$	124,340			$	274,760
	Vice President —
	Accounting
	and Controller
Andrew L. Waite				—				—				—				—				—				—
	Chairman of the Board
	Former Chief Executive
	Officer

(1)	Option price has been adjusted pursuant to FIN 44 to take into account the impact of the approximate $147.0 million Dividend paid to our stockholders following the Combination.

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		Number of Shares Underlying								Value of Unexercised
		Unexercised Options at								In-the-Money Options at
		December 31, 2004								December 31, 2004
		Exercisable				Unexercisable				Exercisable				Unexercisable
Joseph C. Winkler			—				—				—
J. Michael Mayer			—				62,572							$
James F. Maroney, III			—				—				—				—
Kenneth L. Nibling			—				—				—				—
Robert L. Weisgarber			—				46,929							$
Andrew L. Waite			—				—				—

	2001 Stock Incentive Plan

	2003 Stock Incentive Plan

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	2004 Stock Incentive Plan

	Parchman Stock Incentive Plan

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	(A) his base salary when otherwise due through the date of the termination,
	(B) a bonus, in an amount determined in good faith by our board of directors in accordance with the performance criteria established under the employment agreement, prorated through and including the date of termination,
	(C) an amount equal to two times the sum of his base salary and average annual bonus (deemed to be 100% of his base salary for this purpose), payable in a lump-sum within 30 days following the date of termination,
	(D) all restricted shares, restricted stock units, performance shares, and performance units and stock options held by Mr. Winkler will vest immediately at the time of the termination, and
	(E) additional benefits, such as health and disability coverage, outplacement services and an automobile allowance, for up to two years.

	(A) his base salary when otherwise due through the date of the termination,
	(B) a bonus, in an amount determined in good faith by our board of directors in accordance with the performance criteria established under the employment agreement, prorated through and including the date of termination,
	(C) an amount equal to three times the sum of his base salary and average annual bonus (deemed to be 100% of his base salary for this purpose), payable in a lump-sum within 30 days following the date of termination,
	(D) all restricted shares, restricted stock units, performance shares, performance units and stock options held by Mr. Winkler will vest immediately at the time of the termination,

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	(E) Mr. Winkler will become fully vested in accrued benefits under benefit plans maintained by us; provided, that, if such acceleration is prohibited by law or would require accelerated vesting for all participants in such plans, we will instead make a lump-sum payment to Mr. Winker equal to the present value of such unvested accrued benefits, and
	(F) additional benefits, such as health and disability coverage and benefits, outplacement services and an automobile allowance, for up to three years.

	•	a severance payment equal to 150% of his annual base salary;
	•	all unvested stock options and restricted stock will immediately vest; and
	•	a bonus for the year during which his employment is terminated, prorated for the days served.

	•	a severance payment equal to his annual base salary; and
	•	all unvested stock options and restricted stock will immediately vest; and
	•	a bonus for the year during which his employment is terminated, prorated for the days served.

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	•	each person who is known by us to own beneficially 5% or more of our outstanding common stock;
	•	each of our named executive officers;
	•	each of our directors;
	•	all of our executive officers and directors as a group (11 persons); and
	•	each selling stockholder.

Shares

Shares

Beneficially

Beneficially

Owned After

Owned After

Offering

Offering

Maximum No.

(Assuming No

(Assuming

Shares Beneficially

of Shares to

Exercise of Over-

Exercise of Over-

Owned Prior

be Sold Upon

Allotment

Allotment Option

to this Offering

Number of Shares

Exercise of

Option)

in Full)

to be Sold in

Over-Allotment

Number

Percent

Offering

Option(1)

Number

Percent

Number

Percent

SCF-IV, L.P.(2)

19,698,378

70.0

%

Andrew L. Waite(3)(7)

2,145

*

Joseph C. Winkler(7)

117,654

*

J. Michael Mayer(4)(7)

69,261

*

James F. Maroney, III(7)

28,960

*

Kenneth L. Nibling(7)

28,960

*

Robert L. Weisgarber(4)

28,945

*

David C. Baldwin(5)(7)

2,145

*

Robert S. Boswell(4)(7)

14,082

*

Harold G. Hamm(6)(7)

2,029,133

7.3

%

R. Graham Whaling(4)(7)

13,083

*

James D. Woods(4)(7)

5,855

*

Directors and Executive Officers as a Group (11 persons) (3)(4)(5)(6)(7)

2,340,223

8.4

%

1	We will add the selling stockholders to the table once they have been determined.

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	*	Less than one percent.

(1)	Assuming the over-allotment option is exercised in full.
(2)	L.E. Simmons is the natural person who has voting and investment control over the securities owned by SCF-IV, L.P. Mr. Simmons serves as chairman of the Board and President of L.E. Simmons and Associates, Incorporated, the ultimate general partner of SCF-IV, L.P.

(3)	Mr. Waite serves as Managing Director of L.E. Simmons and Associates, Incorporated, the ultimate general partner of SCF-IV, L.P. As such, Mr. Waite may be deemed to have voting and dispositive power over the shares beneficially owned by SCF-IV, L.P. Mr. Waite disclaims beneficial ownership of the shares owned by SCF-IV, L.P.

(4)	Includes shares that may be acquired within 60 days through the exercise of options to purchase shares of our common stock as follows: Messrs. Mayer – 20,857; Weisgarber – 15,643; Boswell – 2,085; Whaling – 1,233; and Woods – 3,710.
(5)	Mr. Baldwin serves as Managing Director of L.E. Simmons and Associates, Incorporated, the ultimate general partner of SCF-IV, L.P. As such, Mr. Baldwin may be deemed to have voting and dispositive power over the shares beneficially owned by SCF-IV, L.P. Mr. Baldwin disclaims beneficial ownership of the shares owned by SCF-IV, L.P.
(6)	Includes an aggregate of 2,026,988 shares owned by Harold G. Hamm GRAT 4, Harold G. Hamm GRAT 6, and Harold G. Hamm GRAT 8, each of which is an estate planning trust (collectively, the “Hamm Trusts”). Mr. Hamm serves as the trustee of each of the Hamm Trusts. As such, Mr. Hamm may be deemed to have voting and dispositive power over the shares beneficially owned by the Hamm Trusts.
(7)	Includes restricted common stock as follows: Waite – 2,145; Winkler – 58,827; Mayer – 19,704; Maroney – 7,510; Nibling – 7,510; Baldwin – 2,145; Boswell – 2,145; Hamm – 2,145; Whaling – 2,145; Woods – 2,145.

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	•	dividends as may be declared by our board of directors; and
	•	all of our assets available for distribution to holders of our common stock in liquidation, pro rata, based on the number of shares held.

	•	to issue up to 5,000,000 shares of preferred stock in one or more series; and
	•	to fix the rights, preferences, privileges and restrictions of our preferred stock, including provisions related to dividends, conversion, voting, redemption, liquidation and the number of shares constituting the series or the designation of that series, which may be superior to those of our common stock.

	Written Consent of Stockholders

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	Special Meetings of Stockholders

	Advance Notice Procedure for Director Nominations and Stockholder Proposals

	Classified Board of Directors

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	•	any business opportunity that is brought to the attention of an SCF Nominee solely in such person’s capacity as a director or officer of our company and with respect to which no other member of the SCF group independently receives notice or otherwise identifies such opportunity; or
	•	any business opportunity that is identified by the SCF group solely through the disclosure of information by or on behalf of us.

	•	for any breach of the duty of loyalty to us or our stockholders;
	•	for acts or omissions not in good faith or involving intentional misconduct or a knowing violation of law;
	•	for unlawful payment of a dividend or unlawful stock purchases or redemptions; or
	•	for any transaction from which the director derived an improper personal benefit.

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	Management Rights

	Demand Registration Rights

	Piggyback Registration Rights

	Registration Procedures and Expenses

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	•	1% of the then outstanding shares of common stock; and
	•	the average weekly trading volume in the common stock on the NYSE during the four calendar weeks immediately preceding the date on which the notice of the sale on Form 144 is filed with the SEC.

92

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93

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	•	an individual who is a citizen or resident of the United States;
	•	a corporation (or other entity taxed as a corporation for U.S. federal income tax purposes) created or organized in the United States or under the laws of the United States, any state thereof or the District of Columbia;
	•	an estate whose income is subject to U.S. federal income taxation regardless of its source; or
	•	a trust whose administration is subject to the primary supervision of a U.S. court and which has one or more U.S. persons who have the authority to control all substantial decisions of the trust, or a trust in existence on August 20, 1996 that has elected to continue to be treated as a “United States person” (as defined for U.S. federal income tax purposes).

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	•	the gain is not effectively connected with the conduct of a trade or business in the United States by the Non-U.S. Holder (or, if an income tax treaty applies, is not attributable to the Non-U.S. Holder’s permanent establishment in the United States);
	•	if the Non-U.S. Holder is an individual, the Non-U.S. Holder either is not present in the United States for 183 days or more in the taxable year of disposition or does not have a “tax home” in the United States for U.S. federal income tax purposes and meets certain other requirements;
	•	the Non-U.S. Holder is not subject to tax under the provisions of the Internal Revenue Code regarding the taxation of certain former citizens or former long-term residents of the United States; and
	•	we are not and have not been a U.S. real property holding corporation for U.S. federal income tax purposes at any time during the shorter of the Non-U.S. Holder’s holding period of our common stock and the five-year period ending on the date of disposition.

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	•	a U.S. person;
	•	a “controlled foreign corporation” for U.S. federal income tax purposes;
	•	a foreign person 50% or more of whose gross income from a specified period is effectively connected with the conduct of a U.S. trade or business; or
	•	a foreign partnership if at any time during its tax year either (i) one or more of its partners are U.S. persons who in the aggregate hold more than 50% of the income or capital interests in the partnership, or (ii) the foreign partnership is engaged in a U.S. trade or business,

96

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			Number of
Underwriter			Shares
Credit Suisse First Boston LLC
UBS Securities LLC
Banc of America Securities LLC
Jefferies & Company, Inc.
Johnson Rice & Company L.L.C.
Raymond James & Associates, Inc.
Simmons & Company International
Pickering Energy Partners, Inc.
	Total

Per Share

Total

Without

With

Without

With

Over-allotment

Over-allotment

Over-allotment

Over-allotment

Underwriting discounts and commissions paid by us

$

$

$

$

Expenses payable by us

$

$

$

$

Underwriting discounts and commissions paid by selling stockholders

$

$

$

$

97

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98

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	•	the information included in this prospectus and otherwise available to the underwriters;
	•	market conditions for initial public offerings;
	•	the history of and prospects for our business and our past and present operations;
	•	the history of and prospects for the industry in which we compete;
	•	our past and present earnings and current financial position;
	•	an assessment of our management;
	•	the market of securities of companies in businesses similar to ours; and
	•	the general condition of the securities markets.

	•	Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.
	•	Over-allotment involves sales by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of shares over-allotted by the underwriters is not greater than the number of shares that they may purchase in the over-allotment option. In a naked short position, the number of shares involved is greater than the number of shares in the over-allotment option. The underwriters may close out any covered short position by either exercising their over-allotment option and/or purchasing shares in the open market.
	•	Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the over-allotment option. If the underwriters sell more shares than could be covered by the over- allotment option, a naked short position, the position can only be closed out by buying shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

99

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	•	Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

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	•	the purchaser is entitled under applicable provincial securities laws to purchase the common stock without the benefit of a prospectus qualified under those securities laws;
	•	where required by law, that the purchaser is purchasing as principal and not as agent; and
	•	the purchaser has reviewed the text above under “– Resale Restrictions.”

101

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102

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103

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			Page
Unaudited Interim Consolidated Financial Statements
	Consolidated Balance Sheets as of September 30, 2005 and December 31, 2004			F-2
	Consolidated Statements of Operations and Consolidated Statements of Comprehensive Income for the Nine Months Ended September 30, 2005 and 2004			F-3
	Consolidated Statement of Stockholders’ Equity for the Nine Months Ended September 30, 2005			F-4
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2005 and 2004			F-5
	Notes to Consolidated Financial Statements			F-6
Audited Consolidated Financial Statements
	Report of Independent Registered Public Accounting Firm			F-20
	Report of Independent Registered Public Accounting Firm			F-21
	Report of Independent Registered Public Accounting Firm			F-22
	Report of Independent Registered Public Accounting Firm			F-23
	Consolidated Balance Sheets as of December 31, 2004 and 2003			F-24
	Consolidated Statements of Operations (Loss) and Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2004, 2003 and 2002			F-25
	Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2004, 2003 and 2002			F-26
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002			F-27
	Notes to Consolidated Financial Statements			F-28

F-1

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				2005				2004
				(In thousands, except
				share data)
ASSETS
Current assets:
	Cash and cash equivalents			$	19,062			$	11,547
	Trade accounts receivable, net				137,121				85,801
	Inventory				38,937				21,910
	Prepaid expenses				12,820				5,825
	Deferred tax asset				849				870
		Total current assets			208,789				125,953
Property, plant and equipment, net					340,246				235,211
Intangible assets, net of accumulated amortization of $1,888, and other					5,648				4,073
Deferred financing costs, net of accumulated amortization of $623					4,198				4,467
Goodwill					210,989				145,449
	Total assets			$	769,870			$	515,153
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Bank operating loans			$	4,685			$	21,745
	Current maturities of long-term debt				5,394				28,493
	Convertible debentures				—				4,150
	Accounts payable				44,424				27,688
	Accrued liabilities				23,345				18,848
	Unearned revenue				7,400				—
	Notes payable				1,532				2,735
	Taxes payable				447				1,081
		Total current liabilities			87,227				104,740
Long-term debt					452,496				169,190
Deferred income taxes					49,234				26,225
Minority interest					2,352				5,477
	Total liabilities				591,309				305,632
Commitments and contingencies
Stockholders’ equity:
	Common stock, $0.01 par value per share, 100,000,000 shares authorized, 27,810,283 (2004 – 25,107,341) issued				278				251
	Additional paid-in capital				163,475				177,015
	Retained earnings				936				18,690
	Treasury stock, 17,785 shares at cost				(202	)			—
	Deferred compensation				(2,121	)			(932	)
	Accumulated other comprehensive income				16,195				14,497
	Total stockholders’ equity				178,561				209,521
		Total liabilities and stockholders’ equity		$	769,870			$	515,153

F-2

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			2005				2004
			(In thousands, except
			per share data)
Revenue:
	Service		$	434,745			$	136,431
	Product			90,491				58,962
				525,236				195,393
Service expenses				266,344				91,018
Product expenses				69,968				41,611
Selling, general and administrative expenses				75,535				28,844
Write-off of deferred financing fees				2,844				—
Depreciation and amortization				32,902				12,366
	Income before interest, taxes and minority interest			77,643				21,554
Interest expense				15,617				4,525
	Income before taxes and minority interest			62,026				17,029
Taxes				23,734				6,574
	Income before minority interest			38,292				10,455
Minority interest				380				344
	Net income		$	37,912			$	10,111
Earnings per share:
	Basic		$	1.39			$	0.71
	Diluted		$	1.28			$	0.62
Weighted average shares:
	Basic			27,282				14,176
	Diluted			29,640				16,186

			2005				2004
			(In thousands)
Net income			$	37,912			$	10,111
Change in cumulative translation adjustment				1,698				1,021
	Comprehensive income		$	39,610			$	11,132

F-3

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																											Accumulated
											Additional																Other
			Number				Common				Paid-In				Treasury				Retained				Deferred				Comprehensive
			of Shares				Stock				Capital				Stock				Earnings				Compensation				Income				Total
			(In thousands, except share data)
Balance at December 31, 2004				25,107,341			$	251			$	177,015			$	—			$	18,690			$	(932	)		$	14,497			$	209,521
Net income				—				—				—				—				37,912				—				—				37,912
Cumulative translation adjustment				—				—				—				—				—				—				1,698				1,698
Issuance of common stock:
	Acquisition of Parchman			1,500,000				15				19,050				—				—				—				—				19,065
	Acquisition of RSI			68,222				1				1,159				—				—				—				—				1,160
	Acquisition of Spindletop			45,182				—				1,053				—				—				—				—				1,053
	Exercise of warrants			1,024,250				10				9,990				—				—				—				—				10,000
	For cash			75,532				1				1,199				—				—				—				—				1,200
	Exercise of stock options			7,541				—				79				—				—				—				—				79
Purchase of warrants				—				—				(256	)			—				—				—				—				(256	)
Issuance of restricted stock				—				—				1,641				—				—				(1,641	)			—				—
Amortization of deferred compensation				—				—				—				—				—				452				—				452
Purchase of minority interest				—				—				43,769				—				—				—				—				43,769
Dividend paid				—				—				(91,224	)			—				(55,666	)			—				—				(146,890	)
Repurchase of common stock				(17,785	)			—				—				(202	)			—				—				—				(202	)
Balance at September 30, 2005				27,810,283			$	278			$	163,475			$	(202	)		$	936			$	(2,121	)		$	16,195			$	178,561

F-4

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				2005				2004
				(In thousands)
Cash provided by (used in):
Operating activities:
	Net income			$	37,912			$	10,111
	Items not affecting cash:
		Depreciation and amortization			32,902				12,366
		Deferred income taxes			19,276				14,647
		Minority interest			380				344
		Write-off of deferred financing fees			2,844				—
		Other			1,362				180
	Net change in working capital				(46,205	)			(22,181	)
					48,471				15,467
Financing activities:
	Issuances of long-term debt				634,109				109,823
	Repayments of long-term debt				(413,055	)			(51,811	)
	Net borrowings (repayments) under lines of credit				(17,060	)			6,744
	Issuances (repayments) of notes payable				(1,203	)			17,925
	Repayment of convertible debenture				(4,069	)			—
	Proceeds from issuances of common stock				11,268				3,956
	Repurchase of common stock/warrants				(458	)			—
	Dividends paid				(146,890	)			—
	Deferred financing costs				(4,076	)			(3,233	)
					58,566				83,404
Investing activities:
	Business acquisitions, net of cash acquired				(18,163	)			(75,119	)
	Additions to property, plant and equipment				(84,885	)			(24,748	)
	Proceeds from disposal of capital assets				3,903				—
					(99,145	)			(99,867	)
Effect of exchange rate changes on cash					(377	)			(9	)
Change in cash and cash equivalents					7,515				(1,005	)
Cash and cash equivalents, beginning of period					11,547				6,094
Cash and cash equivalents, end of period				$	19,062			$	5,089

F-5

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	(a) Nature of operations:

	(b) Basis of presentation:

F-6

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	(a) The Combination:

			IPS				IEM				Total
Common stock to minority interest			$	58,284			$	15,773			$	74,057
Minority interest in fair value of net assets acquired				30,848				4,792				35,640
	Amount recorded as goodwill		$	27,436			$	10,981			$	38,417

	(b) Parchman Energy Group, Inc. (“Parchman”):

F-7

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Net assets acquired:
	Non-cash working capital		$	3,401
	Property, plant and equipment			48,688
	Intangible assets			459
	Goodwill (no tax basis)			21,975
	Long-term debt			(32,017	)
	Deferred income taxes			(8,608	)
Net assets acquired			$	33,898
Consideration:
	Cash, net of cash and cash equivalents acquired		$	9,833
	Subordinated note			5,000
	Issuance of common stock (1,500,000 shares)			19,065
Consideration			$	33,898

	(c) Premier Integrated Technologies (“Premier”):

Net assets acquired:
	Non-cash working capital		$	2,390
	Property, plant and equipment			2,164
	Goodwill			997
	Long-term debt			(750	)
	Minority interest			(1,902	)
Net assets acquired			$	2,899
Consideration:
	Non-cash working capital		$	1,559
	Property, plant and equipment			1,340
Consideration			$	2,899

F-8

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	(d) Roustabout Specialties Inc. (“RSI”):

Net assets acquired:
	Non-cash working capital		$	1,718
	Property, plant and equipment			4,900
	Goodwill			2,294
Net assets acquired			$	8,912
Consideration:
	Cash, net of cash and cash equivalents acquired		$	7,752
	Issuance of common stock (68,222 shares)			1,160
Consideration			$	8,912

	(e) Spindletop Production Services, Ltd. (“Spindletop”):

F-9

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Net assets acquired:
	Non-cash working capital		$	(9	)
	Property, plant and equipment			686
	Goodwill			613
Net assets acquired			$	1,290
Consideration:
	Cash, net of cash and cash equivalents acquired		$	237
	Issuance of common stock (45,182 shares)			1,053
Consideration			$	1,290

3.	Inventory:

		2005				2004
Finished goods		$	34,203			$	19,929
Manufacturing parts and materials			6,337				3,344
			40,540				23,273
Inventory reserves			1,603				1,363
		$	38,937			$	21,910

		2005				2004
Trade		$	129,542			$	80,980
Unbilled revenue			7,264				4,152
Notes receivable			713				183
Other			711				1,029
			138,230				86,344
Allowance for doubtful accounts			1,109				543
		$	137,121			$	85,801

F-10

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		2005				2004
Land		$	3,770			$	848
Building			4,814				6,577
Field equipment			358,557				238,948
Vehicles			24,242				18,610
Office furniture and computers			4,001				2,254
Leasehold improvements			3,638				1,556
Construction in progress			5,516				—
			404,538				268,793
Accumulated depreciation and amortization			64,291				33,582
		$	340,247			$	235,211

F-11

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	(a) Authorized:

	(b) Dividend:

F-12

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	(c) Warrants:

	(d) Employee stock incentive plans:

F-13

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		Options Outstanding
						Weighted
						Average
						Exercise
		Number				Price
Balance at December 31, 2004			1,129,698			$	7.20
Granted			639,286				11.90
Exercised			(7,541	)			8.23
Cancelled			(255,004	)			7.62
Balance at September 30, 2005			1,506,439			$	9.03

	(e) Stock-based compensation:

			2005				2004
Net income:
	As reported		$	37,912			$	10,111
	Add: Compensation expense recorded related to stock-based compensation, net of tax			294				5
	Deduct: Impact of stock-based compensation expense determined under fair value method, net of tax			(348	)			(58	)
	Pro forma net income		$	37,858			$	10,058
Basic earnings per share:
	As reported		$	1.39			$	0.71
	Pro forma		$	1.39			$	0.71
Diluted earnings per share:
	As reported		$	1.28			$	0.62
	Pro forma		$	1.28			$	0.62

F-14

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			2005				2004
Weighted average fair value			$	2.15			$	0.70
Assumptions:
	Risk free interest rate			3.8% to 4.9	%			4.9	%
	Dividend yield			—				—
	Expected life (in years)			3 to 4.5				3

	(f) Per share amounts:

	(g) Repurchase of common stock:

Balance at December 31, 2004			$	145,449
Acquisition of:
	Parchman Energy Group			21,975
	Premier Integrated Technologies Ltd.			997
	Roustabout Specialties Inc.			2,294
	Spindletop			613
Purchase of minority interest				38,417
Impact of foreign currency translation and other				1,243
	Balance at September 30, 2005		$	210,988

F-15

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F-16

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						Drilling				Product
Nine Months Ended September 30, 2005		C&PS				Services				Sales				Corporate				Total
Revenue from external customers		$	351,154			$	89,016			$	85,066			$	—			$	525,236
EBITDA, as defined		$	82,615			$	27,658			$	11,131			$	(10,859	)		$	110,545
Depreciation and amortization		$	27,100			$	3,968			$	1,204			$	630			$	32,902
Operating income (loss)		$	55,515			$	23,690			$	9,927			$	(11,489	)		$	77,643
Capital expenditures		$	52,172			$	29,316			$	1,459			$	1,938			$	84,885
September 30, 2005
Segment assets		$	521,356			$	111,532			$	65,768			$	71,214			$	769,870
Goodwill		$	151,649			$	15,025			$	6,147			$	38,168			$	210,989

						Drilling				Product
Nine Months Ended September 30, 2004		C&PS				Services				Sales				Corporate				Total
Revenue from external customers		$	112,611			$	23,820			$	58,962			$	—			$	195,393
EBITDA, as defined		$	21,939			$	5,104			$	10,199			$	(3,322	)		$	33,920
Depreciation and amortization		$	9,514			$	1,401			$	856			$	595			$	12,366
Operating income (loss)		$	12,425			$	3,703			$	9,343			$	(3,917	)		$	21,554
Capital expenditures		$	18,717			$	4,374			$	1,243			$	414			$	24,748
December 31, 2004
Segment assets		$	384,014			$	72,839			$	53,751			$	4,549			$	515,153
Goodwill		$	124,197			$	15,022			$	6,230			$	—			$	145,449

		United								Other
Nine Months Ended September 30, 2005		States				Canada				International				Total
Revenue by sale origin to external customers		$	421,471			$	73,776			$	29,989			$	525,236
Net income before taxes and minority interest		$	52,399			$	4,612			$	5,015			$	62,026
September 30, 2005
Long-lived assets		$	631,384			$	100,467			$	38,019			$	769,870

		United								Other
Nine Months Ended September 30, 2004		States				Canada				International				Total
Revenue by sale origin to external customers		$	132,862			$	51,320			$	11,211			$	195,393
Income before taxes and minority interest		$	14,653			$	539			$	1,837			$	17,029
December 31, 2004
Long-lived assets		$	432,093			$	79,662			$	3,398			$	515,153

F-17

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			2005				2004
Changes in:
	Accounts receivable		$	(43,718	)		$	(12,556	)
	Inventory			(16,489	)			(3,242	)
	Prepaid expenses			(6,901	)			(3,467	)
	Accounts payable			16,265				2,084
	Accrued liabilities			5,600				(11,133	)
	Other			(962	)			6,133
			$	(46,205	)		$	(22,181	)
Cash interest paid			$	15,776			$	3,599
Cash taxes paid			$	5,924			$	585
Common stock issued on acquisitions			$	21,278			$	41,737
Acquisition of minority interest			$	38,417				—
Notes issued for acquisitions			$	5,000			$	4,150
Non-cash assets as acquisition consideration			$	2,899				—

F-18

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F-19

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F-20

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F-21

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F-22

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F-23

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				2004				2003
				(In thousands, except
				share data)
ASSETS
Current assets:
	Cash and cash equivalents			$	11,547			$	6,094
	Trade accounts receivable, net				85,801				27,255
	Inventory				21,910				12,294
	Prepaid expenses				5,825				1,820
	Deferred tax asset				870				—
		Total current assets			125,953				47,463
Property, plant and equipment, net					235,211				95,217
Intangible assets, net					4,073				2,445
Deferred financing costs, net					4,467				1,645
Goodwill					145,449				59,296
		Total assets		$	515,153			$	206,066
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Bank operating loans			$	21,745			$	5,929
	Current maturities of long-term debt				28,493				13,699
	Convertible debentures				4,150				—
	Accounts payable				27,688				12,369
	Accrued liabilities				18,848				8,134
	Notes payable				2,735				57
	Taxes payable				1,081				396
		Total current liabilities			104,740				40,584
Long-term debt					169,190				50,144
Convertible debentures					—				3,862
Deferred income taxes					26,225				4,456
Minority interest					5,477				4,813
		Total liabilities			305,632				103,859
Commitments and contingencies
Stockholders’ equity:
	Common stock, $0.01 par value per share, 100,000,000 shares authorized, 25,107,341 (2003 - 11,922,260) issued				251				119
	Additional paid-in capital				177,015				90,770
	Retained earnings				18,690				1,035
	Deferred compensation				(932	)			(180	)
	Accumulated other comprehensive income				14,497				10,463
		Total stockholders’ equity			209,521				102,207
Total liabilities and stockholders’ equity				$	515,153			$	206,066

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			2004				2003				2002
			(In thousands, except per share data)
Revenue:
	Service		$	239,427			$	67,732			$	30,110
	Product			81,320				35,547				10,494
				320,747				103,279				40,604
Service expenses				157,540				47,329				21,153
Product expenses				58,633				25,795				7,378
Selling, general and administrative expenses				46,077				16,591				7,764
Depreciation and amortization				21,616				7,648				4,187
	Income before interest, taxes and minority interest			36,881				5,916				122
Interest expense				7,471				2,687				1,260
	Income (loss) before taxes and minority interest			29,410				3,229				(1,138	)
Taxes				10,821				1,506				(477	)
	Income (loss) before minority interest			18,589				1,723				(661	)
Minority interest				934				162				(45	)
	Net income (loss)		$	17,655			$	1,561			$	(616	)
Earnings (loss) per share:
	Basic		$	0.98			$	0.22			$	(0.22	)
	Diluted		$	0.97			$	0.21			$	(0.22	)
Weighted average shares:
	Basic			18,002				7,055				2,757
	Diluted			18,270				7,272				2,757

			2004				2003				2002
			(In thousands)
Net income (loss)			$	17,655			$	1,561			$	(616	)
Change in cumulative translation adjustment				4,034				10,143				320
	Comprehensive income (loss)		$	21,689			$	11,704			$	(296	)

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																							Accumulated
											Additional												Other
			No. of				Dollar				Paid-In				Retained				Deferred				Comprehensive				Partners’
			Shares				Amounts				Capital				Earnings				Compensation				Income				Equity				Total
			(In thousands, except share amounts)
Balance at December 31, 2001				1,445,000			$	1			$	9,962			$	90			$	—			$	—			$	20,000			$	30,053
Net loss				—				—				—				(616	)			—				—				—				(616	)
Cumulative translation adjustment				—				—				—				—				—				320				—				320
Issuance of common stock:
	Acquisition of IPSL			4,694,010				60				50,993				—				—				—				(20,000	)			31,053
Balance at December 31, 2002				6,139,010				61				60,955				(526	)			—				320				—				60,810
Net income				—				—				—				1,561				—				—				—				1,561
Cumulative translation adjustment				—				—				—				—				—				10,143				—				10,143
Issuance of common stock:
	Acquisitions			5,703,497				57				29,281				—				—				—				—				29,338
	Exercise of options			28,095				—				320				—				—				—				—				320
	For cash			6,433				—				73				—				—				—				—				73
Issuance of restricted stock				59,112				1				299				—				(300	)			—				—				—
Amortization of deferred compensation				—				—				—				—				120				—				—				120
Repurchase of common stock				(13,887	)			—				(158	)			—				—				—				—				(158	)
Balance at December 31, 2003				11,922,260				119				90,770				1,035				(180	)			10,463				—				102,207
Net income				—				—				—				17,655				—				—				—				17,655
Cumulative translation adjustment				—				—				—				—				—				4,034				—				4,034
Issuance of common stock:
	Acquisitions			12,616,207				126				81,204				—				—				—				—				81,330
	Exercise of options			40,590				—				185				—				—				—				—				185
	For cash			328,284				4				1,756				—				—				—				—				1,760
	Exercise of warrants			200,000				2				2,123				—				—				—				—				2,125
Issuance of restricted stock				—				—				977				—				(977	)			—				—				—
Amortization of deferred compensation				—				—				—				—				225				—				—				225
Balance at December 31, 2004				25,107,341			$	251			$	177,015			$	18,690			$	(932	)		$	14,497			$	—			$	209,521

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				2004				2003				2002
				(In thousands)
Cash provided by (used in):
Operating activities:
	Net income (loss)			$	17,655			$	1,561			$	(616	)
	Items not affecting cash:
		Depreciation and amortization			21,616				7,648				4,187
		Deferred income taxes (benefit)			9,267				728				(599	)
		Minority interest			934				162				(45	)
		Other			(44	)			125				—
	Net change in working capital				(14,806	)			3,741				(2,935	)
					34,622				13,965				(8	)
Financing activities:
	Issuances of long-term debt				121,639				35,878				31,534
	Repayments of long-term debt				(9,859	)			(7,275	)			(24,250	)
	Net borrowings (repayments) under lines of credit				32,500				6,429				(2,786	)
	Proceeds from issuances of common stock				16,611				21,075				32,015
	Issuances (repayments) of notes payable				376				(18	)			—
	Deferred financing costs				(3,637	)			(808	)			(234	)
					157,630				55,281				36,279
Investing activities:
	Business acquisitions, net of cash acquired				(139,362	)			(54,798	)			(27,851	)
	Additions to property, plant and equipment				(46,904	)			(11,084	)			(6,799	)
	Proceeds on disposal of other assets				489				652				(825	)
	Additions to intangible assets				(999	)			(984	)			(141	)
					(186,776	)			(66,214	)			(35,616	)
Effect of exchange rate changes on cash					(23	)			(58	)			—
Change in cash and cash equivalents					5,453				2,974				655
Cash and cash equivalents, beginning of year					6,094				3,120				2,465
Cash and cash equivalents, end of year				$	11,547			$	6,094			$	3,120

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	Complete Energy Services, Inc.

	Integrated Production Services, Inc. (formerly Saber Energy Services, Inc. (“Saber”))

	I.E. Miller Services, Inc.

	(a) Basis of preparation:

	(b) Foreign currency translation:

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	(c) Revenue recognition:

	(d) Cash and cash equivalents:

	(e) Trade accounts receivable:

	(f) Inventory:

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	(g) Property, plant and equipment:

Asset			Basis		Rate
Buildings			straight-line		39 years
Field Equipment
	Wireline, optimization and coiled tubing equipment		straight-line		10 years
	Gas testing equipment		straight-line		15 years
	Drilling rigs		straight-line		20 years
	Well-servicing rigs		straight-line		25 years
Office furniture and computers			declining balance		30%
Leasehold improvements			straight-line		5 years
Vehicles and other equipment			straight-line		3 to 10 years

	(h) Intangible assets:

	(i) Impairment of long-lived assets:

	(j) Asset retirement obligations:

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	(k) Deferred financing costs:

	(l) Goodwill:

	(m) Deferred income taxes:

	(n) Financial instruments:

	(o) Per share amounts:

	(p) Stock-based compensation:

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			2004				2003				2002
Net income (loss):
	As reported		$	17,655			$	1,561			$	(616	)
	Impact of stock-based compensation expense determined under fair value method, net of tax			(298	)			(202	)			(96	)
	Pro forma net income (loss)		$	17,357			$	1,359			$	(712	)
Basic earnings (loss) per share:
	As reported		$	0.98			$	0.22			$	(0.22	)
	Pro forma		$	0.96			$	0.19			$	(0.26	)
Diluted earnings (loss) per share:
	As reported		$	0.97			$	0.21			$	(0.22	)
	Pro forma		$	0.95			$	0.19			$	(0.26	)

			2004				2003				2002
Weighted average fair value			$	1.52			$	1.84			$	1.74
Assumptions:
	Risk free interest rate			4.9	%			6	%			6	%
	Dividend yield			—				—				—
	Expected life (in years)			3.0				3.0				3.0

	(q) Research and development:

	(r) Contingencies:

	(s) Measurement uncertainty:

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	(t) Comparative figures:

2.	Business combinations:

	(a) IPS 2004 Acquisitions:

			Double Jack				Nortex				MGM				Total
Non-cash working capital			$	0.8			$	—			$	2.6			$	3.4
Property, plant and equipment				2.5				0.8				0.9				4.2
Goodwill				7.5				1.0				5.2				13.7
Deferred income taxes				(0.6	)			—				(0.8	)			(1.4	)
Net assets acquired			$	10.2			$	1.8			$	7.9			$	19.9
Consideration:
	Cash		$	8.0			$	1.8			$	6.7			$	16.5
	Issuance of common stock			1.9				—				1.2				3.1
	Cash contingent consideration			0.3				—				—				0.3
Total consideration			$	10.2			$	1.8			$	7.9			$	19.9

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	(b) CES 2004 Acquisitions:

			LEED				Salmon				A&W				MWS				Hyland				Hamm				Price				Total
Current assets			$	6.9			$	0.5			$	1.4			$	0.8			$	7.1			$	7.4			$	0.4			$	24.5
Property, plant and equipment				14.4				3.6				5.5				7.0				21.9				48.7				0.7				101.8
Other assets				0.6				0.2				0.5				0.3				0.4				0.1				0.3				2.4
Intangible assets				0.3				—				0.2				0.3				0.3				0.4				—				1.5
Goodwill				5.5				0.4				8.8				5.7				5.5				33.8				1.2				60.9
Liabilities				(6.8	)			—				(1.4	)			(0.4	)			(9.7	)			(2.5	)			(1.2	)			(22.0	)
Net assets acquired			$	20.9			$	4.7			$	15.0			$	13.7			$	25.5			$	87.9			$	1.4			$	169.1
Consideration:
	Cash and seller notes		$	14.4			$	4.0			$	6.6			$	6.6			$	17.7			$	48.1			$	0.2			$	97.6
	Issuance of common stock			5.9				0.5				7.9				6.6				6.6				37.0				1.2				65.7
	Acquisition costs			0.6				0.2				0.5				0.5				1.2				2.8				—				5.8
Total consideration			$	20.9			$	4.7			$	15.0			$	13.7			$	25.5			$	87.9			$	1.4			$	169.1

	(c) I.E. Miller 2004 Acquisitions:

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Net assets acquired:
	Current assets		$	8,641
	Property, plant and equipment			12,250
	Goodwill (no tax basis)			8,543
	Current liabilities			(3,361	)
Net assets acquired			$	26,073
Consideration:
	Cash		$	13,573
	Issuance of common stock (2,426,250 common shares)			12,500
Total Consideration			$	26,073

	(d) CES 2003 Acquisitions:

Current assets			$	12,226
Property, plant and equipment				36,160
Intangible assets				1,048
Goodwill				14,411
Current liabilities				(5,252	)
Net assets acquired			$	58,593
Consideration:
	Cash		$	50,093
	Issuance of common stock (1,688,948 common shares)			8,500
Total consideration			$	58,593

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	(e) IPS 2003 Acquisitions:

Net assets acquired:
	Non-cash working capital		$	528
	Property, plant and equipment			167
	Goodwill (no tax basis)			4,062
	Long-term debt			(54	)
Net assets acquired			$	4,703
Consideration:
	Cash, net of cash acquired		$	3,863
	Issuance of common stock (73,749 common shares)			840
Total consideration			$	4,703

	(f) IPS 2002 Combination:

	(g) IPS 2002 Acquisition:

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Net assets acquired:
	Cash and cash equivalents		$	2,279
	Non-cash working capital			9,827
	Property, plant and equipment			37,899
	Intangible assets (amortized over 5 to 10 years)			510
	Other assets			693
	Goodwill (no tax basis)			28,706
	Bank operating loan			(4,802	)
	Long-term debt			(17,831	)
	Convertible debentures			(3,174	)
	Deferred income taxes			(4,599	)
Net assets acquired			$	49,508
Consideration:
	Cash purchase on July 3, 2002		$	29,508
	Cash purchase on October 16, 2000			20,000
Total consideration			$	49,508

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	(h) Goodwill:

Balance at December 31, 2001		$	7,001
Acquisitions			28,706
Foreign currency translation			(23	)
Balance at December 31, 2002			35,684
Acquisitions			18,473
Tax valuation adjustment			(1,400	)
Foreign currency translation			6,539
Balance at December 31, 2003			59,296
Acquisitions			83,183
Contingency adjustment			250
Foreign currency translation			2,720
Balance at December 31, 2004		$	145,449

3.	Accounts receivable:

		2004				2003
Trade		$	80,980			$	27,287
Unbilled revenue			4,152				677
Notes receivable			183				10
Other			1,029				368
			86,344				28,342
Allowance for doubtful accounts			543				1,087
		$	85,801			$	27,255

4.	Inventory:

		2004				2003
Finished goods		$	18,566			$	10,813
Manufacturing parts and materials			3,344				1,481
		$	21,910			$	12,294

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5.	Property, plant and equipment:

						Accumulated
						Depreciation
						and				Net
December 31, 2004		Cost				Amortization				Book Value
Land		$	848			$	—			$	848
Building			6,577				340				6,237
Field equipment			238,948				29,314				209,634
Vehicles			18,610				2,232				16,378
Office furniture and computers			2,254				775				1,479
Leasehold improvements			1,556				921				635
		$	268,793			$	33,582			$	235,211

December 31, 2003
Land		$	138			$	—			$	138
Building			1,009				226				783
Field equipment			102,814				12,575				90,239
Vehicles			2,743				106				2,637
Office furniture and computers			856				320				536
Leasehold improvements			1,548				664				884
		$	109,108			$	13,891			$	95,217

6.	Intangible assets:

			As of December 31, 2004																As of December 31, 2003
			Term				Historical				Accumulated				Net Book				Historical				Accumulated				Net Book
Description			(in months)				Cost				Amortization				Value				Cost				Amortization				Value
Patents and trademarks				60			$	2,049			$	461			$	1,588			$	2,049			$	249			$	1,800
Contractual agreements and other				60 to 120				3,031				546				2,485				645				—				645
	Totals			60			$	5,080			$	1,007			$	4,073			$	2,694			$	249			$	2,445

7.	Deferred financing costs:

						Accumulated				Net
December 31, 2004		Cost				Amortization				Book Value
Deferred financing costs		$	5,763			$	1,296			$	4,467

December 31, 2003
Deferred financing costs		$	2,170			$	525			$	1,645

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8.	Taxes:

			2004				2003				2002
Domestic:
	Franchise taxes		$	171			$	172			$	—
	Current income taxes			218				—				—
	Deferred income taxes (benefit)			8,015				(594	)			(405	)
				8,404				(422	)			(405	)
Foreign:
	Capital taxes			197				344				(84	)
	Current income taxes			968				262				203
	Deferred income taxes (benefit)			1,252				1,322				(191	)
				2,417				1,928				(72	)
Tax expense (benefit)			$	10,821			$	1,506			$	(477	)

			2004				2003				2002
Expected provision (benefit) for taxes:			$	9,999			$	1,098			$	(387	)
Increase (decrease) resulting from
	Foreign tax rate differential			(396	)			(297	)			156
	Foreign capital taxes			197				344				(84	)
	State franchise taxes			631				172				(61	)
	Non-deductible expenses			200				122				(78	)
	Other, net			190				67				(23	)
Tax expense (benefit)			$	10,821			$	1,506			$	(477	)

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			2004				2003
Deferred income tax assets:
	Net operating loss		$	11,062			$	6,695
	Intangible assets			443				785
	Research and development credits			154				143
	Restricted stock compensation costs			18				41
	Investment tax credits			190				117
				11,867				7,781
	Less valuation allowance			(877	)			(168	)
				10,990				7,613
Deferred income tax liabilities:
	Property, plant and equipment			(33,159	)			(12,058	)
	Goodwill			(2,432	)			—
	Other			(754	)			(11	)
				(36,345	)			(12,069	)
Net deferred income tax liability			$	(25,355	)		$	(4,456	)

		2004				2003
Domestic		$	(18,566	)		$	604
Foreign			(6,789	)			(5,060	)
		$	(25,355	)		$	(4,456	)

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9.	Bank operating loans:

10.	Long-term debt:

		2004				2003
Reducing Canadian term facility(a)		$	22,552			$	22,750
Reducing U.S. term facility(a)			17,168				7,275
Term loan(b)			120,650				30,600
Revolving line of credit(b)			19,850				2,800
Subordinated seller notes(c)			3,450				—
Term loan(d)			9,274				—
Subordinated note(e)			4,383				—
Capital leases(f)			356				418
			197,683				63,843
Less: current maturities			(28,493	)			(13,699	)
		$	169,190			$	50,144

(a)		At December 31, 2004, the Company had a syndicated credit facility which included four separate facilities secured by a common security package. The two operating facilities are described in Note 9. The agreement also included a Canadian reducing term facility (“CTF”) and a U.S. reducing term facility (“UTF”). The CTF had been fully drawn and was repayable in equal quarterly installments of C$1,370 and $175. The UTF had also been fully drawn and was repayable in equal quarterly installments of C$954. The facilities were to mature on June 30, 2007 and bore interest from prime

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		plus 0.25% to prime plus 1.50% per annum on a grid based on certain financial ratios. At December 31, 2004, Canadian and U.S. prime were 4.25% and 5.25% (2003 – 4.5% and 4.0%, 2002 – 4.5% and 4.25%), respectively. The Company was in compliance with all of the terms of these facilities at December 31, 2004.
		Effective February 11, 2005, in conjunction with the acquisition of Parchman Energy Group, Inc. (see Note 20), the Company and a group of banks entered into a new credit facility replacing the current credit facility. The new credit facility was comprised of five separate facilities secured by a common security package including a first charge against the Company’s assets. There are two operating facilities ($20,000 and C$15,000), each of which was to mature on February 10, 2008, which replaced the existing operating facilities. There were two reducing term facilities ($20,000 and C$30,000) which were to mature on February 10, 2010 and which required quarterly payments of $1,000 and C$1,500 respectively. Each of these four facilities bore interest from prime plus 0.25% to prime plus 1.50% per annum on a grid based on certain financial ratios. The fifth term facility was in the amount of $35,000, was to mature on February 10, 2011, required quarterly payments of $88, and bore interest at LIBOR plus 3.5%. Each of the three term facilities were drawn in full on February 11, 2005. The credit facilities required maintenance of certain financial ratios and other covenants.
(b)		In November 2003, the Company established a secured $30,600 term loan and an $8,000 secured revolving line of credit. During 2004, the Company amended the term loan and revolving line of credit several times to facilitate the acquisitions described in note 2, which resulted in increasing the Company’s total borrowing capacity to $120,650 and $30,000, respectively, and extension of the maturity dates. At December 31, 2004, the Company did not have any remaining borrowing capacity on the term loan and $10,200 of remaining capacity on the revolving line of credit.
		Substantially all of CES’s real and personal property and a pledge of the ownership interest of present and future subsidiaries secure both the term loan and the revolving line of credit. The term loan and revolving line of credit bore interest at either the lead bank’s prime rate plus a margin of 1.75% to 2.25% or the LIBOR plus a margin of 2.75% to 3.25%, depending on the Company’s leverage ratio, as defined. The interest rate on the term loan in 2004 averaged 5.75% (2003 – 6.25%). The interest rate on the revolving loan in 2004 averaged 6.13% (2003 – 6.25%).
		There are quarterly principal payments on the term loan in the amount of $4,350 with final maturity on August 31, 2009. The revolving line of credit was due on August 31, 2007. The Company must pay a commitment fee in the amount of 0.50% on the unused revolving line of credit capacity.
		The Company was required to maintain certain financial ratios and other financial conditions. In addition, the Company was prohibited from making certain investments, advances or loans. The term loan and credit agreements restrict substantial asset sales, capital expenditures and cash dividends. The Company was in compliance with all covenants and conditions as of December 31, 2004.
(c)		The subordinated seller note was unsecured, bore interest at 6.0% and was to mature in March 2009.
(d)		In August 2004, the Company entered into a Senior Secured Agreement (“the Agreement”) with a group of financial institutions with a maximum commitment of $12,000 and a maturity date of August 31, 2008. Quarterly principal payments of $464 are required under the facility. As part of the Agreement, the Company entered into a Revolving Note Agreement (“Revolver”) providing for borrowings of up to $8,000 with a maturity date of August 31, 2007. At December 31, 2004, there were no outstanding borrowings under the Revolver. Pursuant to the Agreement, interest on the borrowings was calculated using a variable base rate plus a margin. The margin ranges from 0.25% to 1.25% for base rate advances and from 2.50% to 3.50% for LIBOR loans depending on IEM’s leverage ratio. The interest rate averaged approximately 5.18% for the four months ended December 31, 2004. In addition to interest, the banks receive various fees, including a commitment fee. The commitment fee varies from 0.375% to 0.50% of average unused commitment amount on the Revolver, depending on IEM’s leverage ratio. The note was subject to restrictive covenants. The

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		Company was in compliance with all covenants during 2004. The Agreement was secured by substantially all of IEM’s assets.
(e)		On August 31, 2004, the Company entered into a Subordinate Credit Agreement with a maximum term commitment of $20,000 and maturity of August 31, 2009. Principal plus accrued interest was to be due at maturity. Pursuant to the credit agreement, interest on borrowings was calculated using a variable base rate equal to the greater of the agent bank’s Prime Rate or the Federal Funds Rate plus 0.5% plus a margin. The margin ranges from 2.0% to 4.0% depending on IEM’s leverage ratio. The interest rate for the four months ended December 31, 2004 was approximately 7.25%. The note was subject to restrictive covenants. The Company was in compliance with all covenants during 2004.
(f)		At December 31, 2004, the Company’s capital leases are collateralized by specific assets and bear interest at various rates averaging 10.29% (2003 – 7.0%).
(g)		Concurrent with the completion of the Combination (Note 20(b)), the Company entered into a syndicated senior secured credit facility (the “Credit Facility”) pursuant to which all bank debt held by each of IPS, CES and IEM was repaid and replaced with the proceeds from the Credit Facility. The Credit Facility is comprised of a $420,000 Term B term loan credit facility that will mature in September 2012, a U.S. revolving credit facility of $130,000 that will mature in September 2010, and a $30,000 revolving credit facility that will mature in September 2010. Interest on the Credit Facility is determined by reference to LIBOR plus a margin of 1.25% to 2.75% (dependent on the ratio of total debt to EBITDA, as defined in the Agreement) for revolving advances and a margin of 2.75% for Term B term loan advances. Interest on advances under the Canadian revolving facility is calculated at the Canadian Prime Rate plus a margin of 0.25% to 1.75%. The revolving facility includes a commitment fee ranging from 0.25% to 0.50% (dependent on the ratio of total debt to EBITDA, as defined in the Agreement). Quarterly principal repayments of 0.25% of the original principal amount are required for the Term B term loans commencing December 2005. The Credit Facility contains covenants restricting the levels of certain transactions, including entering into certain loans, the granting of certain liens, capital expenditures, acquisitions, distributions to shareholders, certain asset dispositions and operating leases. The Credit Facility is secured by substantially all of the assets of the Company.

2005		$	7,189
2006			4,297
2007			4,257
2008			4,264
2009			7,701

11.	Convertible debentures:

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12.	Share capital:

	(a) Authorized:

	100,000,000 voting common shares with par value of $0.01 per share, and 5,000,000 preferred shares with a par value of $0.01 per share.

	(b) Stock split:

	(c) Warrants:

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	(d) Employee stock incentive plan:

		Options Outstanding
						Weighted
						Average
						Exercise
		Number				Price
Balance at December 31, 2001			42,500			$	10.00
Granted			292,187				10.89
Cancelled			(4,743	)			11.39
Balance at December 31, 2002			329,944				10.77
Granted			98,207				7.89
Exercised			(28,095	)			11.39
Cancelled			(21,532	)			11.39
Balance at December 31, 2003			378,524				9.94
Granted			559,428				8.28
Exercised			(40,590	)			4.57
Cancelled			(8,006	)			11.39
Balance at December 31, 2004			889,356			$	9.15

		Options Outstanding												Options Exercisable
						Weighted				Weighted								Weighted
		Outstanding at				Average				Average				Exercisable at				Average
		December 31,				Remaining				Exercise				December 31,				Exercise
Range of Exercise Price		2004				Life (months)				Price				2004				Price
$5.08-5.58			310,250				53			$	5.18				19,704			$	5.58
$10.00			148,141				20				10.00				136,260				10.00
$11.39			265,944				39				11.39				107,846				11.39
$12.18			165,021				48				12.18				—				—
			889,356				42			$	9.15				263,810			$	10.24

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	(e) Per share amounts:

13.	Supplemental cash flow information:

		2004				2003				2002
Change in:
Trade accounts receivable		$	(20,585	)		$	(687	)		$	(3,695	)
Inventory			(7,936	)			(1,959	)			625
Prepaid expenses			(3,480	)			(614	)			(428	)
Accounts payable			5,032				1,635				285
Accrued liabilities			10,706				5,244				—
Taxes payable			388				122				278
Notes payable			1,069				—				—
		$	(14,806	)		$	3,741			$	(2,935	)
Cash interest paid		$	6,756			$	2,415			$	1,260
Cash taxes paid		$	1,136			$	778			$	119
Common stock issued for acquisitions		$	81,329			$	29,338			$	—
Notes issued for acquisitions		$	4,150			$	—			$	—

14.	Segment information:

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	Operational segments:

						Drilling				Product
Year Ended December 31, 2004		C&PS				Services				Sales				Corporate				Total
Revenue from external customers		$	194,953			$	44,474			$	81,320			$	—			$	320,747
EBITDA, as defined		$	38,349			$	10,093			$	12,924			$	(2,869	)		$	58,497
Depreciation and amortization		$	16,750			$	2,737			$	907			$	1,222			$	21,616
Operating income (loss)		$	21,599			$	7,356			$	12,017			$	(4,091	)		$	36,881
Capital expenditures		$	32,004			$	11,840			$	2,944			$	116			$	46,904

December 31, 2004
Segment assets		$	384,014			$	72,839			$	53,751			$	4,549			$	515,153
Goodwill		$	124,197			$	15,022			$	6,230			$	—			$	145,449

						Drilling				Product
Year Ended December 31, 2003		C&PS				Services				Sales				Corporate				Total
Revenue from external customers		$	65,025			$	2,707			$	35,547			$	—			$	103,279
EBITDA, as defined		$	9,134			$	712			$	4,951			$	(1,233	)		$	13,564
Depreciation and amortization		$	6,147			$	130			$	644			$	727			$	7,648
Operating income (loss)		$	2,987			$	582			$	4,307			$	(1,960	)		$	5,916
Capital expenditures		$	7,474			$	2,623			$	987			$	—			$	11,084

December 31, 2003
Segment assets		$	148,165			$	23,547			$	34,177			$	177			$	206,066
Goodwill		$	48,456			$	4,940			$	5,900			$	—			$	59,296

						Drilling				Product
Year Ended December 31, 2002		C&PS				Services				Sales				Corporate				Total
Revenue from external customers		$	30,110			$	—			$	10,494			$	—			$	40,604
EBITDA, as defined		$	3,058			$	—			$	1,251			$	—			$	4,309
Depreciation and amortization			3,559				—				213				415				4,187
Operating income (loss)		$	(501	)		$	—			$	1,038			$	(415	)		$	122
Capital expenditures		$	6,799			$	—			$	—			$	—			$	6,799

	Geographic information:

		United								Other
Year Ended December 31, 2004		States				Canada				International				Total
Revenue by sale origin to external customers		$	231,509			$	73,743			$	15,495			$	320,747
Income before taxes and minority interest		$	22,786			$	4,048			$	2,576			$	29,410

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December 31, 2004
Long-lived assets		$	306,140			$	79,662			$	3,398			$	389,200

		United								Other
Year Ended December 31, 2003		States				Canada				International				Total
Revenue by sale origin to external customers		$	28,129			$	62,376			$	12,774			$	103,279
Income (loss) before taxes and minority interest		$	(771	)		$	2,211			$	1,789			$	3,229

December 31, 2003
Long-lived assets		$	79,067			$	76,604			$	2,932			$	158,603

		United								Other
Year Ended December 31, 2002		States				Canada				International				Total
Revenue by sale origin to external customers		$	13,243			$	21,968			$	5,393			$	40,604
Income (loss) before taxes and minority interest		$	(1,012	)		$	(805	)		$	679			$	(1,138	)

15.	Financial instruments:

	(a) Interest rate risk:

	(b) Foreign currency rate risk:

	(c) Credit risk:

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16.	Commitment and contingences:

2005		$	6,993
2006			4,444
2007			2,872
2008			2,217
2009			1,330
		$	17,856

17.	Related party transactions:

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18.	Retirement plans:

19.	Recent accounting pronouncements:

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20.	Subsequent events:

	(a) Parchman Energy Group, Inc. (“Parchman”):

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Net assets acquired:
	Non-cash working capital		$	3,401
	Property, plant and equipment			48,688
	Intangible assets			459
	Goodwill (no tax basis)			21,975
	Long-term debt			(32,017	)
	Deferred income taxes			(8,608	)
Net assets acquired			$	33,898
Consideration:
	Cash, net of cash and cash equivalents acquired		$	9,833
	Subordinated note			5,000
	Issuance of common stock (1,500,000 shares)			19,065
Total consideration			$	33,898

	(b) Combination:

	(c) Dividend:

	(d) Authorized share capital:

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ITEM 13.	Other Expenses of Issuance and Distribution

SEC registration fee			$	40,607
NASD filing fee				35,000
NYSE listing fee
Printing and engraving expenses
Legal fees and expenses
Accounting fees and expenses
Blue sky fees and expenses (including legal fees)
Transfer agent and registrar fees
Miscellaneous
	Total		$

ITEM 14.	Indemnification of Directors and Officers

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	•	us, except for:

	•	claims regarding the indemnitee’s rights under the indemnification agreement;
	•	claims to enforce a right to indemnification under any statute or law; and
	•	counter-claims against us in a proceeding brought by us against the indemnitee; or

	•	any other person, except for claims approved by our board of directors.

ITEM 15.	Recent Sales of Unregistered Securities

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ITEM 16.	Exhibits and Financial Statement Schedules

	1	.1		—		Form of Underwriting Agreement
	3	.1**		—		Form of Amended and Restated Certificate of Incorporation
	3	.2**		—		Form of Amended and Restated Bylaws
	4	.1		—		Specimen Stock Certificate representing common stock
	5	.1		—		Opinion of Vinson & Elkins L.L.P.
	10	.1*		—		Form of Indemnification Agreement
	10	.2**		—		Employment Agreement dated as of June 22, 2005 with Joseph C. Winkler
	10	.3		—		Amended and Restated Stockholders’ Agreement dated as of September 12, 2005 by and among Complete Production Services, Inc. and the stockholders listed therein
	10	.4**		—		Combination Agreement dated as of August 9, 2005, with Complete Energy Services, Inc., I.E. Miller Services, Inc. and Complete Energy Services, LLC and I.E. Miller Services, LLC
	10	.5*		—		Credit Agreement, dated as of September 12, 2005 by and among Complete Production Services, Inc., as U.S. Borrower, Integrated Production Services Ltd., as Canadian Borrower, Wells Fargo Bank, National Association, as U.S. Administrative Agent, U.S. Issuing Lender and US Swingline Lender, HSBC Bank Canada, as Canadian Administrative Agent, Canadian Issuing Lender and Canadian Swingline Lender, and the Lenders party thereto, Wells Fargo Bank, National Association as Sole Book Runner and Co-Lead Arranger, UBS Securities LLC, as Co-Lead Arranger and Syndication Agent and Amegy Bank N.A. and Comerica Bank, as Co-Documentation Agents
	10	.6*		—		Integrated Production Services, Inc. 2001 Stock Incentive Plan
	10	.7*		—		Complete Energy Services, Inc. 2003 Stock Incentive Plan
	10	.8*		—		First Amendment to the Complete Energy Services, Inc. 2003 Stock Incentive Plan
	10	.9*		—		Second Amendment to the Complete Energy Services, Inc. 2003 Stock Incentive Plan
	10	.10*		—		I.E. Miller Services, Inc. 2004 Stock Incentive Plan
	10	.11*		—		Amended and Restated Integrated Production Services and Parchman Energy Group, Inc. Stock Incentive Plan
	10	.12*		—		Strategic Customer Relationship Agreement, dated as of October 14, 2004, by and among Complete Energy Services, Inc., CES Mid-Continent Hamm, Inc. and Continental Resources, Inc.
	10	.13		—		Form of Non-Qualified Option Grant Agreement (Executive Officer)
	10	.14		—		Form of Non-Qualified Option Grant Agreement (Non-Employee Director)
	10	.15*		—		Form of Restricted Stock Grant Agreement (Employee)
	10	.16*		—		Form of Restricted Stock Agreement (Non-Employee Director)
	21	.1		—		Subsidiaries of Complete Production Services, Inc.
	23	.1*		—		Consent of Grant Thornton LLP
	23	.2*		—		Consent of KPMG LLP
	23	.3		—		Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
	24	.1		—		Power of Attorney (included on signature page)

	*	Filed herewith

**	Filed previously

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ITEM 17.	Undertakings

	(a) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the Registrant pursuant to the provisions described in Item 14, or otherwise, the Registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.
	(b) To provide to the underwriters at the closing specified in the underwriting agreement, certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.
	(c) For purpose of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in the form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.
	(d) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

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	COMPLETE PRODUCTION SERVICES, INC.

	By:	/s/ Joseph C. Winkler

	Name: Joseph C. Winkler

	Title:	President, Chief Executive Officer and Director

Signature				Position		Date
/s/ Joseph C. Winkler   Joseph C. Winkler				President, Chief Executive Officer and Director (Principal Executive Officer)		November 14, 2005
/s/ J. Michael Mayer   J. Michael Mayer				Senior Vice President and Chief Financial Officer (Principal Financial Officer		November 14, 2005
/s/ Robert L. Weisgarber   Robert L. Weisgarber				Vice President-Accounting and Controller (Principal Accounting Officer		November 14, 2005
/s/ Andrew L. Waite*   Andrew L. Waite				Chairman of the Board		November 14, 2005
/s/ David C. Baldwin*   David C. Baldwin				Director		November 14, 2005
/s/ Robert Boswell*   Robert Boswell				Director		November 14, 2005

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Signature				Position		Date
/s/ Harold G. Hamm*   Harold G. Hamm				Director		November 14, 2005
/s/ R. Graham Whaling*   R. Graham Whaling				Director		November 14, 2005
/s/ James D. Woods*   James D. Woods				Director		November 14, 2005
*By:		/s/ J. Michael Mayer   J. Michael Mayer Pursuant to a Power of Attorney previously filed as Exhibit 24.1 to this Registration Statement

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	1	.1		—		Form of Underwriting Agreement
	3	.1**		—		Form of Amended and Restated Certificate of Incorporation
	3	.2**		—		Form of Amended and Restated Bylaws
	4	.1		—		Specimen Stock Certificate representing common stock
	5	.1		—		Opinion of Vinson & Elkins L.L.P.
	10	.1*		—		Form of Indemnification Agreement
	10	.2**		—		Employment Agreement dated as of June 22, 2005 with Joseph C. Winkler
	10	.3		—		Amended and Restated Stockholders’ Agreement dated as of September 12, 2005 by and among Complete Production Services, Inc. and the stockholders listed therein
	10	.4**		—		Combination Agreement dated as of August 9, 2005, with Complete Energy Services, Inc., I.E. Miller Services, Inc. and Complete Energy Services, LLC and I.E. Miller Services, LLC
	10	.5*		—		Credit Agreement, dated as of September 12, 2005 by and among Complete Production Services, Inc., as U.S. Borrower, Integrated Production Services Ltd., as Canadian Borrower, Wells Fargo Bank, National Association, as U.S. Administrative Agent, U.S. Issuing Lender and US Swingline Lender, HSBC Bank Canada, as Canadian Administrative Agent, Canadian Issuing Lender and Canadian Swingline Lender, and the Lenders party thereto, Wells Fargo Bank, National Association as Sole Book Runner and Co-Lead Arranger, UBS Securities LLC, as Co-Lead Arranger and Syndication Agent and Amegy Bank N.A. and Comerica Bank, as Co-Documentation Agents
	10	.6*		—		Integrated Production Services, Inc. 2001 Stock Incentive Plan
	10	.7*		—		Complete Energy Services, Inc. 2003 Stock Incentive Plan
	10	.8*		—		First Amendment to the Complete Energy Services, Inc. 2003 Stock Incentive Plan
	10	.9*		—		Second Amendment to the Complete Energy Services, Inc. 2003 Stock Incentive Plan
	10	.10*		—		I.E. Miller Services, Inc. 2004 Stock Incentive Plan
	10	.11*		—		Amended and Restated Integrated Production Services and Parchman Energy Group, Inc. Stock Incentive Plan
	10	.12*		—		Strategic Customer Relationship Agreement, dated as of October 14, 2004, by and among Complete Energy Services, Inc., CES Mid-Continent Hamm, Inc. and Continental Resources, Inc.
	10	.13		—		Form of Non-Qualified Option Grant Agreement (Executive Officer)
	10	.14		—		Form of Non-Qualified Option Grant Agreement (Non-Employee Director)
	10	.15*		—		Form of Restricted Stock Grant Agreement (Employee)
	10	.16*		—		Form of Restricted Stock Agreement (Non-Employee Director)
	21	.1		—		Subsidiaries of Complete Production Services, Inc.
	23	.1*		—		Consent of Grant Thornton LLP
	23	.2*		—		Consent of KPMG LLP
	23	.3		—		Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
	24	.1		—		Power of Attorney (included on signature page)

*	Filed herewith
**	Filed previously