~~produced by our customers~~We participate in ~~connection with their oil and gas exploration and production activities.~~a capital intensive business. We ~~also generate and dispose~~may not be able to finance future growth of hazardous waste. The generation, handling, transportation, and disposal of these fluids, substances, and waste are regulated by a number of laws, including the Resource Recovery and Conservation Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Clean Water Act; the Safe Drinking Water Act; and analogous state laws. Failure to properly handle, transport, or dispose of these materials or otherwise conduct our operations in accordance with these and other environmental laws could expose us to liability for governmental penalties, cleanup costs associated with releases of such materials, damages to natural resources, and other damages, as well as potentially impair our ability to conduct our operations. We could be exposed to liability for cleanup costs, natural resource damages and other damages under these and other environmental laws as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Environmental laws and regulations have changed in the past, and they are likely to change in the future. If existing regulatory requirements or enforcement policies change, we may be required to make significant unanticipated capital and operating expenditures.

Any failure by us to comply with applicable environmental laws and regulations may result in governmental authorities taking actions against our business that could adversely impact our operations and financial condition, including the:


	•	~~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 effect of environmental laws and regulations on our business is discussed in greater detail under “Environmental Matters” included in Item 1 of this Annual Report onForm 10-K.~~

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

~~Our business is significantly affected~~Historically, we have funded the growth of our operations and our acquisitions from bank debt, private placement of shares, our initial public offering in April 2006, a private placement of debt in December 2006, as well as cash generated by ~~state and federal laws~~our business. In the future, we may not be able to continue to obtain sufficient bank debt at competitive rates or complete equity and other ~~regulations relating~~debt financings. If we do not generate sufficient cash from our business to ~~the oil~~fund operations, our growth could be limited unless we are able to obtain additional capital through equity or debt financings. Our inability to grow as planned may reduce our chances of maintaining and gas industry in general, and more specifically with respect to health and safety, waste management and the manufacture, storage, handling and transportation of hazardous materials and by changes in and the level of enforcement of such laws. The failure to comply with these rules and regulations can result in substantial penalties, revocation of permits, corrective action orders and criminal prosecution. The regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects ourimproving profitability. We may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances. It is impossible for management to predict the cost or impact of such laws and regulations on our future operations.

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

Effective internal controls are necessary for us to provide reliable financial reports and effectively prevent fraud. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. Our efforts to maintain internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective controls or to make effective improvements to our internal controls could harm our operating results.

In 2010, our management approved a plan to implement new accounting software which will replace our existing accounting systems at several of our operating divisions in a phased approach. Two divisions converted during the fourth quarter of 2010 and two divisions will convert during 2011. In addition, we implemented a new chart of accounts which is being adopted as these divisions convert to the new software. Although we believe the new software, once implemented, will enhance our internal control over financial reporting and we believe that we have taken the necessary steps to maintain appropriate internal control over financial reporting during this period of system change, we will continuously monitor controls through and around the system to provide reasonable assurance that controls are effective during and after each step of this implementation process.

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

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and gas. Management cannot predict the impact of the changing demand for oil and gas services and products, and any major changes may have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

We have operations in Canada. As a result, fluctuations in currency exchange rates in Canada could materially and adversely affect our business. For each of the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006,~~2008, our Canadian operations represented approximately 5%~~, 5% and 8%~~ of our revenue from continuing ~~operations, respectively. For the years ended December 31, 2008 and 2007, our~~operations. Our Canadian operations recorded losses from continuing operations before taxes and minority interest of $26.7 million and $13.5 million, respectively, primarily resulting from goodwill impairment charges. For the year ended December 31, 2006, our Canadian operations represented 3% of our net income from continuing operations before taxes of $1.3 million for the year ended December 31, 2010 and ~~minority interest.~~

~~We are susceptible to seasonal earnings volatility due to adverse weather conditions~~recorded losses of $11.1 million and $26.7 million for the years ended December 31, 2009 and 2008, respectively. The loss in ~~Canada.~~

Our operations are directly affected by seasonal differences in weather in Canada. The level of activity in the Canadian oilfield services industry declines significantly in the second calendar quarter, when frost leaves the ground and many secondary roads are temporarily rendered incapable of supporting the weight of heavy equipment. The duration of this period is referred to as “spring breakup” and has2008 primarily resulted from a direct impact on our activity levels in Canada. The timing and duration of “spring breakup” depend on weather patterns but generally “spring breakup” occurs in April and May. Additionally, if an unseasonably warm winter prevents sufficient freezing, we may not be able to access wellsites and our operating results and financial condition may, therefore, be adversely affected. The demand for our services may also be affected by the severity of the Canadian winters. In addition, during excessively rainy periods, equipment moves may be delayed, thereby adversely affecting operating results. The volatility in weather and temperature in the Canadian oilfield can therefore create unpredictability in activity and utilization rates. As a result, full-year results are not likely to be a direct multiple of any particular quarter or combination of quarters.goodwill impairment charge.

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

~~Our~~The majority of our business in Mexico is ~~substantially all~~ performed for PEMEX pursuant to multi-year contracts. These contracts are generally two years in duration, specify an authorized spending amount and are subject to competitive bid for renewal. Any failure by us to renew or extend our existing contracts, or win award of contracts that replace expiring contracts, could have ~~a material~~an adverse effect on our financial condition, results of operations and cash flows. Additionally, PEMEX is experiencing budget limitations that may affect its ability to make timely payments

to us under our existing contracts. Recent regulatory and financial uncertainty regarding PEMEX’s drilling programs and development budget could adversely impact PEMEX’s ability to fulfill certain of its payment obligations under these contracts in a timely manner. A failure of PEMEX to make required payments to us would adversely affect our Mexico-based financial performance.

The PEMEX contracts provide that 70% to 80% of the value of our billings under the contracts is charged to PEMEX in U.S. dollars with the remainder billed in Mexican pesos. The portion billed in U.S. dollars to PEMEX is converted to pesos on the date of payment. Invoices are paid approximately 45 days after the invoice date. As such, we are exposed to fluctuations in the value of the peso. A material decrease in the value of the Mexican peso relative to the U.S. dollar could negatively impact our revenues, cash flows and net income.

Our operations in Mexico are party to a collective labor contract most recently modified on and effective as of October 2008 between Servicios Petrotec S.A. DE C.V., one of our subsidiaries, and Unión Sindical de Trabajadores de la Industria Metálica y Similares, the metal and similar industry workers labor union. We have not experienced work stoppages in the past but cannot guarantee that we will not experience work stoppages in the future. A prolonged work stoppage could negatively impact our revenues, cash flows and net income.

~~Our U.S.~~Mexico has experienced a period of increasing criminal violence and such activities could affect our Mexico-based operations ~~are adversely impacted by the hurricane season in the Gulf of Mexico, which generally occurs in the third calendar quarter.~~and financial performance.

Recently, Mexico has experienced a period of increasing criminal violence, primarily due to the activities of drug cartels and related organized crime. Although the Mexican government has implemented various security measures and strengthened its military and police forces, drug-related crime continues to exist in Mexico and has impacted our ability to safely conduct business in certain areas of the country. Our inability to conduct business in certain areas of Mexico, and the safety risks in the areas of Mexico where we do conduct business, could have a negative impact on our Mexico-based financial performance.

We could be adversely affected by violations of the U.S. Foreign Corrupt Practices Act and similar worldwide anti-bribery laws.

We are subject to the U.S. Foreign Corrupt Practices Act (the “FCPA”), which generally prohibits companies and their intermediaries from making payments tonon-U.S. government officials for the purpose of obtaining or retaining business or securing any other improper advantage. We are also subject to anti-bribery laws in the jurisdictions in which we operate. Although we have policies and procedures designed to ensure that we, our employees and our agents comply with the FCPA and other anti-bribery laws, there is no assurance that such policies or procedures will protect us against liability under the FCPA or other laws for actions taken by our agents, employees and intermediaries with respect to our business or any businesses that we acquire. We do business in countries in which FCPA violations have recently been enforced. Failure to comply with the FCPA, other anti-bribery laws or other laws governing the conduct of business with foreign government entities, including local laws, could disrupt our business and lead to severe criminal and civil penalties, including imprisonment, criminal and civil fines, loss of our export licenses and suspension of our ability to do business with the federal government. Other remedial measures could include further changes or enhancements to our procedures, policies, and controls and potential personnel changesand/or disciplinary actions, any of which could have a material adverse affect on our business, financial condition, results of operations and liquidity. We could also be adversely affected by any allegation that we violated such laws.

Severe weather conditions may affect our operations.

Our business may be materially affected by severe weather conditions in areas where we operate. This may entail the evacuation of personnel and stoppage of services which could adversely affect our financial condition, results of operations and cash flows. Hurricanes and the threat of hurricanes during this period will often result in the shut-down of oil and gas operations in the Gulf of Mexico as well as land operations within the hurricane path. During a shut-down period, we are unable to access wellsites and our services are also shut down. This situation can therefore create unpredictability in activity and utilization rates, which can have a material adverse impact on our business, financial conditions, results of operations and cash flows. In addition, the extreme winter weather

2628

conditions in the first quarter of 2011 have adversely affected our operations in North Dakota, Oklahoma and North Texas.

Our operations are directly affected by seasonal differences in weather in Canada. The level of activity in the Canadian oilfield services industry declines significantly in the second calendar quarter, when the ground thaws and many secondary roads are temporarily rendered incapable of supporting the weight of heavy equipment. The duration of this period is referred to as “spring breakup” and has a direct impact on our activity levels in Canada. The timing and duration of “spring breakup” depend on weather patterns but generally “spring breakup” occurs in April and May. Additionally, if an unseasonably warm winter prevents sufficient freezing, we may not be able to access wellsites and our operating results and financial condition may, therefore, be adversely affected. The demand for our services may also be affected by the severity of the Canadian winters. In addition, during excessively rainy periods, equipment moves may be delayed, thereby adversely affecting operating results. The volatility in weather and temperature in the Canadian oilfield can therefore create unpredictability in activity and utilization rates. As a result, full-year results are not likely to be a direct multiple of any particular quarter or combination of quarters.

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

Many of the major U.S. onshore drilling services contractors have ~~significant~~ capabilities to move their own drilling rigs and related oilfield equipment and to erect rigs. When regional rig counts are high, drilling services contractors exceed their own capabilities and contract for additional oilfield equipment hauling and rig erection capacity. Our rig relocation business activity is highly correlated to the rig count; however, the correlation varies over the rig count range. As rig count drops, some drilling services contractors reach a point where all of their oilfield equipment hauling and rig erection needs can be met by their own fleets. If one or more of our rig relocation customers ~~reach~~reaches this “tipping point,” our revenues attributable to rig relocation will decline much faster than the corresponding overall decline in the rig count. This non-linear relationship between our rig relocation business activity and the rig count in the areas in which we have rig relocation operations can significantly increase ~~significantly~~ our earnings volatility with respect to rig relocation.

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

Among the services we provide, we operate as a motor carrier and therefore are subject to regulation by the U.S. Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size.

Interstate motor carrier operations are subject to safety requirements prescribed by the U.S. Department of Transportation. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations.

From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.

~~Risks Related to Our Relationship with SCF~~

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

SCF owns approximately 13% of our outstanding common stock, excluding shares distributed to SCF’s directors prior to December 31, 2008. L.E. Simmons is the sole owner of L.E. Simmons and Associates, Incorporated, the ultimate general partner of SCF. Accordingly, Mr. Simmons, through his ownership of the ultimate general partner of SCF, may be in a position to influence the outcome of matters requiring a stockholder vote, including the election of directors, adoption of amendments to our certificate of incorporation or bylaws or approval of transactions involving a change of control. The interests of Mr. Simmons may differ from yours, and SCF may vote its common stock in a manner that may adversely affect you.

~~One of our directors may have a conflict of interest because he is affiliated with SCF. The resolution of this conflict of interest may not be in our or your best interests.~~

One of our directors, Andrew L. Waite, is a current officer of L.E. Simmons and Associates, Incorporated, the ultimate general partner of SCF. This may create a conflict of interest because this director has responsibilities to SCF and its owners. His duties as an officer of L.E. Simmons and Associates, Incorporated may conflict with his duties as a director of our company regarding business dealings between SCF and us and other matters. The resolution of this conflict may not always 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.~~

SCF has investments in other oilfield service companies that may compete with us, and SCF and its affiliates, other than our company, may invest in other such companies in the future. We refer to SCF and its other affiliates and its portfolio companies as the SCF group. Our certificate of incorporation provides that, so long as we have a director or officer that is affiliated with SCF (an “SCF Nominee”), we renounce any interest or expectancy in any business opportunity in which any member of the SCF group participates or desires or seeks to participate in and that involves any aspect of the energy equipment or services business or industry, other than (i) 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 and (ii) any business opportunity that is identified by the SCF group solely through the disclosure of information by or on behalf of our company. We are not prohibited from pursuing any business opportunity with respect to which we have renounced any interest.

~~Risks Related to Our Indebtedness, including Our Senior Notes~~

We may not be able to generate sufficient cash to service all of our indebtedness, including the notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

Our ability to make scheduled payments or to refinance our debt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot assure you that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional capital or restructure or refinance our indebtedness, including the notes. We cannot assure you that we would be able to take any of these actions, that these actions would be successful and permit us to meet our scheduled debt service obligations or that these actions would be permitted under the terms of our existing or future debt agreements including our amended revolving credit facility and the indenture that will govern the notes. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our amended revolving credit facility and the indenture that will govern the notes will restrict our ability to dispose of assets and use the proceeds from the disposition. We may not be able to consummate those dispositions or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due.

~~If we cannot make scheduled payments on our debt, we will be in default and, as a result:~~


	•	~~our debt holders could declare all outstanding principal and interest to be due and payable;~~

	•	~~the lenders under our amended revolving credit facility could terminate their commitments to loan us money and foreclose against the assets securing their borrowings; and~~

	•	~~we could be forced into bankruptcy or liquidation.~~

Covenants in our debt agreements restrict our business in many ways.

The indenture governing our senior notes contains various covenants that limit our abilityand/or our restricted subsidiaries’ ability to, among other things:


	•	incur or assume liens or additional debt or provide guarantees in respect of obligations of other persons;

	•	issue redeemable stock and certain preferred stock;

	•	pay dividends or distributions or redeem or repurchase capital stock;

	•	prepay, redeem or repurchase subordinated debt;


	•	make loans and investments;

	•	enter into agreements that restrict distributions from our subsidiaries;

	•	sell assets and capital stock of our subsidiaries;

	•	enter into certain transactions with affiliates;

	•	consolidate or merge with or into, or sell substantially all of our assets to, another person; and

	•	enter into new lines of business.

In addition, our amended revolving credit facility contains restrictive covenants and requires us to maintain ~~specified financial ratios~~a fixed charge coverage ratio based on borrowing base limitations and satisfy other financial condition tests. Our ability to meet those financial ~~ratios and tests~~requirements can be affected by adverse industry conditions and other events beyond our control, and we cannot assure you that we will meet those ~~tests.~~requirements. A breach of any of these covenants could result in a default under our amended revolving credit facilityand/or the notes. Upon the occurrence of an event of default under our amended revolving credit facility, the lenders could elect to declare all amounts outstanding to be immediately due and payable and terminate all commitments to extend further credit. IfWe had no

borrowings outstanding under our amended credit facility at December 31, 2010. However, if we borrowed under this facility and if we were unable to repay those amounts, the lenders under our amended revolving credit facility could proceed against the collateral granted to them to secure that indebtedness. We have pledged a significant portion of our assets as collateral under our amended revolving credit facility. If the lenders under our amended revolving credit facility accelerate the repayment of borrowings, we cannot assure you that we will have sufficient assets to repay indebtedness under our amended revolving credit facility and our other indebtedness, including our senior notes.

~~Our borrowings~~Borrowings under our amended revolving credit facility ~~are, and are expected to continue to be,~~would bear interest at variable rates ~~of interest~~ and could expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income would decrease.

~~If we default on our obligations to pay our indebtedness we may not be able to make payments on our senior notes.~~

Any default under the agreements governing our indebtedness, including a default under our amended revolving credit facility that is not waived by the required lenders, and the remedies sought by the holders of such indebtedness, could render us unable to pay principal, premium, if any, and interest on the notes and substantially decrease the market value of the notes. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness (including covenants in our amended revolving credit facility), we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our amended revolving credit facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. If our operating performance declines, we may in the future need to obtain waivers from the required lenders under our amended revolving credit facility to avoid being in default. If we breach our covenants under our amended revolving credit facility and seek a waiver, we may not be able to obtain a waiver from the required lenders. If this occurs, we would be in default under our amended revolving credit facility, the lenders could exercise their rights, as described above, and we could be forced into bankruptcy or liquidation.

~~We may incur substantially more debt. This could further exacerbate the risks described above.~~

We and our subsidiary guarantors may be able to incur substantial additional indebtedness in the future. The terms of the indenture do not fully prohibit us or our subsidiary guarantors from doing so. If we incur any additional indebtedness, including trade payables, that ranks equally with the notes, the holders of that debt will be entitled to share ratably with the holders of the notes in any proceeds distributed in connection with any insolvency,

liquidation, reorganization, dissolution or other winding up of our company. This may have the effect of reducing the amount of proceeds available to repay the notes. We have a $400 million revolving credit facility with approximately $168.8 million of undrawn availability as of December 31, 2008. All of those borrowings will be secured by substantially all of our assets and will rank effectively senior to the notes and the guarantees. If new debt is added to our current debt levels, the related risks that we and our subsidiary guarantors now face could intensify. The subsidiaries that guarantee our senior notes will also be guarantors under our amended revolving credit facility.

~~As a holding company, Complete’s main source of cash is distributions from its subsidiaries.~~

We conduct our operations primarily through our subsidiaries, and these subsidiaries directly own substantially all of our operating assets. Therefore, our operating cash flow and ability to meet our debt obligations depend principally on the cash flow provided by our subsidiaries in the form of loans, dividends or other payments to us as an equity holder, service provider or lender. The ability of our subsidiaries to make such payments to the parent company will depend on their earnings, tax considerations, legal restrictions and contractual restrictions imposed by their own indebtedness. Although our debt facilities limit the right of certain of our subsidiaries to enter into consensual restrictions on their ability to pay dividends and make other payments to us, these limitations are subject to a number of significant qualifications and exceptions.

In addition, not all of our subsidiaries guarantee our obligation under the senior notes. Creditors of such subsidiaries (including trade creditors) generally will be entitled to payment from the assets of those subsidiaries before those assets can be distributed to us. As a result, our senior notes are effectively subordinated to the prior payment of all of the debts (including trade payables) of our non-guarantor subsidiaries.


Item 1B.	*Unresolved Staff Comments.*

None.


Item 2.	*Properties.*

As of December 31, ~~2008,~~2010, we owned 5657 offices, facilities and yards, of which 1115 were in Texas, 2218 were in Oklahoma, ~~two were~~one was in Arkansas, ~~one was~~three were in North Dakota, one was in Montana, ~~six were~~one was in Wyoming, ~~three~~10 were in Colorado, ~~three were~~one was in Louisiana, three were in Pennsylvania, ~~one was~~two were in Alberta, Canada, ~~one was in Utah,~~ one was in Poza Rica, Mexico and one was in Singapore.

As of December 31, ~~2008,~~2010, we owned or operated 6164 saltwater disposal wells, of which 2829 were in Texas, 32 were in Oklahoma, two were in Colorado, and one was in Arkansas. In addition, we owned one and leased two drilling mud disposal ~~facility~~facilities in Oklahoma and one produced water evaporation facility in Wyoming.

In addition, as of December 31, ~~2008,~~2010, we leased ~~232~~209 offices, facilities and yards, of which 7074 were in Texas, 2825 were in Oklahoma, 2718 were in Wyoming, ~~two~~25 were in ~~Montana, 10~~Colorado, 22 were in Pennsylvania, three were in North Dakota, ~~34 were in Colorado, five~~10 were in Louisiana, ~~six~~three were in Arkansas, ~~five~~two were in Utah, ~~one was in Pennsylvania, 29~~14 were in Alberta, Canada, ~~two were~~one was in British Columbia, Canada, six were in Mexico and ~~seven~~six were in Singapore. ~~As of December 31, 2008, we leased two drilling mud disposal facilities in Oklahoma.~~

~~In addition, we also~~We lease our corporate headquarters in Houston, Texas, as well as administrative offices in Gainesville, Texas; Enid, Oklahoma; Fredrick, Colorado; Eunice, Louisiana; Shelocta, Pennsylvania; Calgary, Alberta, Canada; and additional office space in Houston, Texas.


Item 3.	*Legal Proceedings.*

In the normal course of our business, we are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including warranty and product liability claims and occasional claims by individuals alleging exposure to hazardous materials, on the job injuries and fatalities as a result of our products or operations. Many of the claims filed against us relate to motor vehicle accidents which can result in the loss of life or serious bodily injury. Some of these claims relate to matters occurring prior to our acquisition of businesses. In certain cases, we are entitled to indemnification from the sellers of such businesses.

Although we cannot know or predict with certainty the outcome of any claim or proceeding or the effect such outcomes may have on us, we believe that any liability resulting from the resolution of any of these matters, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our financial position, results of operations or liquidity.

We have historically incurred additional insurance premium related to a cost-sharing provision of our general liability insurance policy, and we cannot be certain that we will not incur additional costs until either existing claims become further developed or until the limitation periods expire for each respective policy year. Any such additional premiums should not have a material adverse effect on our financial position, results of operations or liquidity. ~~We incurred no additional premium related to this cost-sharing provision of our general liability policy in 2008, but paid $1.4 million of additional premium for the year ended December 31, 2007.~~


Item 4.	*~~Submission of Matters to a Vote of Security Holders.~~(Removed and Reserved)*

~~None.~~

3130

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

We have 200,000,000 authorized shares of $0.01 par value common stock, of which 75,555,508 shares were outstanding at December 31, 2008, including 789,191 shares of non-vested restricted stock for which the forfeiture restrictions have not lapsed. At February ~~20, 2009,~~14, 2011, we had ~~76,867,674~~78,592,455 shares of common stock outstanding, of which ~~1,995,398~~1,353,996 shares were non-vested restricted stock subject to forfeiture restrictions. The common shares outstanding at February ~~20, 2009~~14, 2011 were held by 8757 record holders, excluding stockholders for whom shares are held in “nominee” or “street” name. We had 5,000,000 authorized shares of $0.01 par value preferred stock, of which none was issued and outstanding at December 31, ~~2008~~2010 or February ~~20, 2009.~~14, 2011.

~~On April 20, 2006, we entered into an underwriting agreement in connection with our initial public offering and became subject to the reporting requirements of the Securities Exchange Act of 1934.~~ On April 21, 2006, our common stock began trading on the New York Stock Exchange under the symbol “CPX.” On April 26, 2006, we completed our initial public offering.

The following table presents the high and low sales prices of our common stock reported byon the New York Stock Exchange for each of the calendar quarters in ~~2007~~2009 and ~~2008:~~2010:

CPX Stock Price
Period
High Low

Quarter ended March 31, 2007 $ 21.20 $ 17.28
Quarter ended June 30, 2007 $ 27.75 $ 19.45
Quarter ended September 30, 2007 $ 26.17 $ 20.00
Quarter ended December 31, 2007 $ 22.66 $ 17.30
Quarter ended March 31, 2008 $ 22.98 $ 14.13
Quarter ended June 30, 2008 $ 37.50 $ 22.23
Quarter ended September 30, 2008 $ 37.84 $ 18.61
Quarter ended December 31, 2008 $ 20.08 $ 4.04

CPX Stock Price
Period High Low

Quarter ended March 31, 2009 $ 10.10 $ 2.32
Quarter ended June 30, 2009 $ 8.31 $ 3.27
Quarter ended September 30, 2009 $ 11.72 $ 6.78
Quarter ended December 31, 2009 $ 13.48 $ 9.11
Quarter ended March 31, 2010 $ 16.06 $ 10.83
Quarter ended June 30, 2010 $ 15.97 $ 11.33
Quarter ended September 30, 2010 $ 21.69 $ 13.68
Quarter ended December 31, 2010 $ 32.72 $ 20.52

The year-end closing sales price of our common stock was ~~$17.97~~$13.00 on December 31, ~~2007,~~2009, the last trading day of ~~2007,~~2009, and ~~$8.15~~$29.55 on December 31, ~~2008,~~2010, the last trading day of ~~2008.~~2010.

Issuer Purchases of Equity Securities:

In accordance with the provisions of the 2008 Incentive Award Plan, holders of unvested restricted stock were given the option to either remit to us the required withholding taxes associated with the vesting of restricted stock, or to authorize us to repurchase shares equivalent to the cost of the withholding tax and to remit the withholding taxes on behalf of the holder. We made no repurchases of our common stock during the ~~years~~year ended December 31, ~~2008, 2007 or 2006.~~2008. However, pursuant to this provision, we repurchased 18,743 shares in 2009 and 113,330 shares in 2010, of which the following shares were purchased during the quarter ended December 31, 2010:

(d)

Maximum

(c)
Number (or

Total
Approximate

Number of
Dollar Value) of

(a)
Shares Purchased
Shares that May

Total
(b)
as Part of Publicly
Yet Be Purchased

Number of
Average Price
Announced Plans
Under the Plans or

Period �� Shares Purchased Paid per Share or Programs Programs

October 1 — 31, 2010 — — — *
November 1 — 30, 2010 — — — *
December 1 — 31, 2010 436 29.00 436 *
* We do not have a publicly announced stock repurchase program. We had 1,672,854 shares of non-vested restricted stock outstanding at December 31, 2010. The holders of these shares have the option to either remit taxes due related to the vesting of these shares or to authorize us to purchase the shares at the current market value in a sufficient amount to settle the related tax withholding. The amount purchased will depend on the market value at the time and whether or not the holders choose to surrender shares in settlement of the related tax withholding.

31

Equity Compensation Plans:

The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information as set forth in Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” contained herein.

Dividends:

We ~~have~~ paid no dividends on our outstanding $0.01 par value common stock for the years ended December 31, ~~2008, 2007~~2010, 2009 or ~~2006.~~2008. We currently do not intend to pay dividends in the foreseeable future, but rather plan to reinvest such funds in our business. Furthermore, our credit facility and the indenture governing our senior notes contain covenants which restrict us from paying future dividends on our common stock.

Performance Graph:

The information in this section of the Annual Report pertaining to our performance relative to our peers is being furnished but not filed with the SEC, and as such, the information is neither subject to Regulation 14A or 14C or to the liabilities of Section 18 of the Exchange Act of 1934.

The following chart presents a comparative analysis of the stock performance of our common stock (“CPX”) relative to an industry index, the Philadelphia Oil Service Sector Index (“OSX”), and a broader market index, Standard & Poor’s 500 Index (“S&P”). This analysis assumes a $100 investment in the underlying common stock of CPX, OSX and S&P on April 21, 2006, the date of our initial public offering, through December 31, ~~2008.~~2010. This analysis does not purport to be a representation of the actual market performance of our stock or these indexes. This chart has been provided for informational purposes to assist the reader in evaluating the market performance of our common stock compared to other market participants.

Notwithstanding anything to the contrary set forth in our previous filings under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, which might incorporate future filings made by us under those statutes, the following Stock Performance Graph will not be deemed incorporated by reference into any future filings made by us under those statutes.

COMPARISON OF 3256 MONTH CUMULATIVE TOTAL RETURN*

Among Complete Production Services, Inc, ~~The~~the S ~~& P~~&P 500 Index

And The PHLX Oil Service Sector Index


*	$100 invested on 4/21/06 in stock or on 3/31/06 in ~~index-including~~index, including reinvestment of dividends. Fiscal year ending December 31.


Item 6.	*Selected Financial Data.*

The following table presents selected historical consolidated financial and operating data for the periods shown. The selected consolidated financial data as of December 31, ~~2004, 2005,~~ 2006, 2007, 2008, 2009 and ~~2008~~2010 and for each of the years then ended have been derived from our audited consolidated financial statements for those dates and periods, adjusted for discontinued operations, as indicated. The following information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes included elsewhere in this Annual Report.


														For the Year Ended December 31,
	For the Year Ended December 31,													2006			2007			2008			2009			2010
	2004		2005(3)		2006			2007			2008			(In thousands)
	(In thousands)
Statement of Operations Data:
Revenue:
Completion and production services	$	190,267	$	502,517	$	860,508		$	1,242,314		$	1,545,348		$	860,508		$	1,238,126		$	1,541,709		$	897,584		$	1,354,797
Drilling services		37,584		115,771		194,517			212,272			234,104			194,517			212,272			234,104			114,729			172,821
Products sales		8,178		11,290		29,586			40,857			59,102			29,586			40,857			59,102			44,081			33,775

Total		236,029		629,578		1,084,611			1,495,443			1,838,554			1,084,611			1,491,255			1,834,915			1,056,394			1,561,393
Expenses:
Service and product expenses(2)		153,274		383,502		629,346			874,563			1,133,799
Service and product expenses(1)															630,195			875,570			1,136,488			725,365			1,011,040
Selling, general and administrative		37,930		99,431		144,432			179,027			198,252			144,503			179,508			198,200			181,420			175,445
Depreciation and amortization		19,838		46,484		75,902			131,353			181,097			75,902			131,399			181,197			200,732			181,823
Impairment loss(4)		—		—		—			13,094			272,006
Fixed asset and other intangibles impairment loss(2)															—			—			—			38,646			—
Goodwill impairment loss(2)															—			13,094			272,006			97,643			—

Operating income from continuing operations before interest, taxes and minority interest		24,987		100,161		234,931			297,406			53,400
Operating income from continuing operations before interest, taxes and non-controlling interest															234,011			291,684			47,024			(187,412	)		193,085
Write-off of deferred financing fees		—		3,315		170			—			—			170			—			—			528			—
Interest expense		7,471		24,460		40,645			61,328			59,729			40,645			61,328			59,729			56,895			57,669
Interest income		—		—		(1,387	)		(325	)		(301	)		(1,387	)		(325	)		(301	)		(79	)		(322	)
Taxes		7,148		28,606		70,516			86,851			74,568			70,184			84,833			72,305			(63,088	)		51,580

Income (loss) from continuing operations before minority interest		10,368		43,780		124,987			149,552			(80,596	)
Minority interest		4,705		384		(49	)		(569	)		—
Income (loss) from continuing operations before non-controlling interest															124,399			145,848			(84,709	)		(181,668	)		84,158
Non-controlling interest															(49	)		(569	)		—			—			—

Income (loss) from continuing operations		5,663		43,396		125,036			150,121			(80,596	)		124,448			146,417			(84,709	)		(181,668	)		84,158
Income (loss) from discontinued operations (net of tax expense of $3,673, $5,114, $9,359, $6,890 and $3,865, respectively)(1)		8,221		10,466		14,050			11,443			(4,859	)
Income (loss) from discontinued operations (net of tax expense of $9,359, $6,890, $3,865, $0 and $0, respectively)(3)															14,050			11,443			(4,859	)		—			—

Net income (loss)	$	13,884	$	53,862	$	139,086		$	161,564		$	(85,455	)	$	138,498		$	157,860		$	(89,568	)	$	(181,668	)	$	84,158

Income (loss) from continuing operations per diluted share	$	0.19	$	0.87	$	1.84		$	2.05		$	(1.10	)	$	1.83		$	2.00		$	(1.15	)	$	(2.42	)	$	1.08


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

(2)		For the year ended December 31, 2009, we recorded a fixed asset impairment in our drilling services segment of $36,158 and an intangible asset impairment in our completion and production services segment totaling $2,488. We also recorded a goodwill impairment charge of $97,643 associated with several of our reportable units at December 31, 2009. We recorded an impairment loss of $272,006 associated with goodwill for various reporting units as of December 31, 2008. For the year ended December 31, 2007, we recorded an impairment


		loss of $13,094 associated with our Canadian reporting unit. For a further discussion, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this Annual Report.

(3)		In May 2008, our Board of Directors authorized and committed to a plan to sell certain operations in the Barnett Shale region of north Texas, consisting primarily of our supply store business, as well as certain non-strategic drilling logistics assets and other completion and production services assets. On May 19, 2008, we sold these operations to a company owned by a former officer of one of our subsidiaries. In August 2006, our Board of Directors authorized and committed to a plan to sell certain manufacturing and production enhancement product sales operations of a subsidiary located in Alberta, Canada, which includes certain assets located in south Texas. This sale was completed on October 31, 2006. We ~~accounted for these disposal groups as held for sale in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” We~~ revised our financial statements ~~pursuant to SFAS No. 144,~~ and reclassified the assets and liabilities of these


		disposal groups as held for sale as of the date of each balance sheet presented and removed the results of operations of the disposal group from net income from continuing operations, and presented these separately as income (loss) from discontinued operations, net of tax, for each of the accompanying statements of operations. We ceased depreciating the assets when each disposal group was reclassified as held for sale, and we adjusted the net assets to the lower of carrying value or fair value less selling costs. For a further discussion, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this Annual Report.

~~(2)~~		~~Service and product expenses is the aggregate of service expenses and product expenses.~~

~~(3)~~		We paid a dividend of $2.62 per share to our stockholders as of September 12, 2005 in conjunction with the Combination. Our current debt obligations restrict us from paying dividends on our common stock and we have not paid any other dividends in the past five fiscal years.

~~(4)~~		We recorded an impairment loss of $272.0 million associated with goodwill for various reporting units as of December 31, 2008 in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets.” For the year ended December 31, 2007, we recorded an impairment loss of $13.1 million associated with our Canadian reporting unit. For a further discussion, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this Annual Report.


	As of December 31,															For the Year Ended December 31,
	2004			2005			2006			2007			2008			2006			2007			2008			2009			2010
	(In thousands)															(In thousands)

Other Financial Data:
EBITDA(5)	$	44,825		$	143,331		$	310,663		$	441,853		$	506,503
Adjusted EBITDA(4)																$	309,743		$	436,177		$	500,227		$	149,081		$	374,908
Cash flows from operating activities		34,622			76,427			187,743			338,560			350,448			187,635			338,415			350,409			285,204			216,158
Cash flows from financing activities		157,630			112,139			471,376			66,643			27,990			471,376			66,643			27,990			(207,991	)		(174,088	)
Cash flows from investing activities		(186,776	)		(188,358	)		(650,863	)		(408,795	)		(374,137	)		(650,863	)		(409,189	)		(374,098	)		(18,128	)		6,817
Capital expenditures:
Acquisitions, net of cash acquired~~(6)~~(5)		139,362			67,689			369,606			50,406			180,154			369,606			50,406			180,154			—			33,721
Property, plant and equipment		46,904			127,215			303,922			372,554			253,815			303,922			368,053			253,776			38,487			169,919


	For the Year Ended December 31,										As of December 31,
	2004		2005		2006		2007		2008		2006		2007		2008		2009		2010
	(In thousands)										(In thousands)

Balance Sheet Data:
Cash and cash equivalents	$	11,547	$	11,405	$	19,874	$	13,624	$	19,090	$	19,766	$	13,034	$	18,500	$	77,360	$	126,681
Net property, plant and equipment		227,406		371,337		752,648		1,013,190		1,166,453		752,648		1,013,539		1,166,686		941,133		956,028
Goodwill		139,322		280,961		541,313		549,130		341,592		541,313		549,130		341,592		243,823		250,533
Total assets		515,153		937,653		1,740,324		2,054,759		1,994,877		1,739,198		2,050,633		1,987,353		1,588,854		1,800,576
Long-term debt, excluding current portion		169,178		509,981		750,311		825,985		843,842		750,311		825,985		843,842		650,002		650,000
Total stockholders�� equity		172,080		250,761		735,221		930,323		869,116
Total stockholders’ equity												734,633		926,031		860,711		698,890		805,834


~~(5)~~(4)		Adjusted EBITDA consists of net income (loss) from continuing operations before net interest expense, taxes, depreciation and amortization, ~~minority~~non-controlling interest and impairment loss. ~~See “Non-GAAP~~Adjusted EBITDA is a non-GAAP measure of performance. We use Adjusted EBITDA as the primary internal management measure for evaluating performance and allocating additional resources. The calculation of Adjusted EBITDA is different from the calculation of “EBITDA,” as defined and used in our credit facilities. For a discussion of the calculation of “EBITDA” as defined under our existing credit facilities, as recently amended, see Note 11,


		“Long-term debt” in the Notes to Consolidated Financial ~~Measures.”~~Statements. Adjusted EBITDA is included in this Annual Report onForm 10-K 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 Adjusted EBITDA. In addition, we use Adjusted EBITDA in evaluating acquisition targets. Management also believes that Adjusted EBITDA is a useful tool for measuring our ability to meet our future debt service, capital expenditures and working capital requirements, and Adjusted EBITDA is commonly used by us and our investors to measure our ability to service indebtedness. Adjusted 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~~non-controlling interest. The following table reconciles Adjusted EBITDA with our net ~~income.~~

~~Reconciliation of EBITDA~~

For the Year Ended December 31,
2004 2005 2006 2007 2008
(In thousands)

Net income (loss) $ 13,884 $ 53,862 $ 139,086 $ 161,564 $ (85,455 )
Plus: interest expense, net 7,471 24,460 39,258 61,003 59,428
Plus: tax expense 7,148 28,606 70,516 86,851 74,568
Plus: depreciation and amortization 19,838 46,484 75,902 131,353 181,097
Plus: minority interest 4,705 384 (49 ) (569 ) —
Plus: impairment loss — — — 13,094 272,006
Minus: income (loss) from discontinued operations (net of tax expense of $3,673, $5,114, $9,359, $6,890 and $3,865, respectively) 8,221 10,465 14,050 11,443 (4,859 )

EBITDA $ 44,825 $ 143,331 $ 310,663 $ 441,853 $ 506,503

income (loss).
~~(6)~~
(5) Acquisitions, net of cash acquired, 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.
Reconciliation of Adjusted EBITDA

For the Year Ended December 31,
2006 2007 2008 2009 2010
(In thousands)

Net income (loss) $ 138,498 $ 157,860 $ (89,568 ) $ (181,668 ) $ 84,158
Plus: interest expense, net 39,258 61,003 59,428 56,816 57,347
Plus: tax expense (benefit) 70,184 84,833 72,305 (63,088 ) 51,580
Plus: depreciation and amortization 75,902 131,399 181,197 200,732 181,823
Plus: non-controlling interest (49 ) (569 ) — — —
Plus: impairment loss — 13,094 272,006 136,289 —
Minus: income (loss) from discontinued operations (net of tax expense of $9,359, $6,890, $3,865, $0 and $0, respectively) 14,050 11,443 (4,859 ) — —

Adjusted EBITDA $ 309,743 $ 436,177 $ 500,227 $ 149,081 $ 374,908

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included within this Annual Report. This discussion contains forward-looking statements based on our current expectations, assumptions, estimates and projections about us and the oil and gas industry. See “Forward-Looking Statement” contained in Item 1. “Business.” These forward-looking statements involve risks and uncertainties that may be outside of our control and could cause actual results to differ materially from those in the forward-looking statements. For examples of those risks and uncertainties, see the cautionary statements contained in Item 1A. “Risk Factors.” Factors that could cause or contribute to such differences include, but are not limited to: market prices for oil and gas, the level of oil and gas drilling, economic and competitive conditions, capital expenditures, regulatory changes and other uncertainties. In light of these risks, uncertainties and assumptions, the forward-looking events discussed below may not occur. Unless otherwise required by law, we undertake no obligation to publicly update ~~publicly~~ any forward-looking statements, even if new information becomes available or other events occur in the future.

36

The words “believe,” “may,” “will,” “estimate,” “continue,” “anticipate,” “intend,” “plan,” “expect” and similar expressions are intended to identify forward-looking statements. All statements other than statements of current or historical fact contained in this Annual Report are forward-looking statements.

Overview

We are a leading provider of specialized completion and production services and products focused on helping oil and gas companies develop hydrocarbon reserves, reduce operating costs and enhance production. We focus on basins within North America that we believe have attractive long-term potential for growth, and we deliver targeted, value-added services and products required by our customers within each specific basin. We believe our range of services and products positions us to meet the many needs of our customers at the wellsite, from drilling and completion through production and eventual abandonment. We manage our operations from regional field service facilities located throughout the U.S. Rocky Mountain region, Texas, Oklahoma, Louisiana, Arkansas, Pennsylvania, western Canada, Mexico and Southeast Asia.

We operate in three business segments:

Completion and Production Services. Through our completion and production services segment, we establish, maintain and enhance the flow of oil and gas throughout the life of a well. This segment is divided into the following primary service lines:


	•	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.

	•	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.~~

	•	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.

Drilling Services. Through our drilling services segment, we provide services and equipment that initiate or stimulate oil and gas production by providing land drilling and specialized rig logistics ~~and site preparation throughout our service area. Our drilling rigs currently operate primarily in and around the Barnett Shale region of north Texas.~~services.

Product Sales. We provide oilfield service equipment and refurbishment of used equipment through our Southeast Asian business, and we provide repair work and fabrication services for our customers at a business located in Gainesville, Texas.

Substantially all service and rental revenue we earn is based upon a charge for a period of time (an hour, a day, a week) for the actual period of time the service or rental is provided to our customer, or on a fixed per-stage-completed ~~fee.~~fee or pursuant to a long-term contract which may includetake-or-pay provisions. Product sales are recorded when the actual sale occurs and title or ownership passes to the customer.

Our customers include large multi-national and independent oil and gas producers, as well as smaller independent producers and the major land-based drilling contractors in North America (see “Customers” in Item 1 of this Annual Report onForm 10-K). The primary ~~factor~~factors influencing demand for our services and products isare the level of drilling ~~complexity~~ and workover activity of our customers and the complexity of such activity, which in turn, depends on current and anticipated future oil and gas prices, production depletion rates and the resultant levels of cash flows generated and allocated by our customers to their drilling and workover budgets. As a result, demand for our services and products is cyclical, substantially depends on activity levels in the North American oil and gas industry and is highly sensitive to current and expected oil and natural gas prices. The following tables summarize average North American drilling and well service rig activity, as measured by Baker Hughes Incorporated (“BHI”) and the ~~Weatherford/~~

Cameron International Corporation/Guiberson/AESC Service Rig Count for “Active Rigs,” respectively, and historical commodity prices as provided by Bloomberg:

AVERAGE RIG COUNTS


	Year Ended												Year Ended
	12/31/03		12/31/04		12/31/05		12/31/06		12/31/07		12/31/08		12/31/06		12/31/07		12/31/08		12/31/09		12/31/10

BHI Rotary Rig Count:
U.S. Land		924		1,095		1,290		1,559		1,695		1,814		1,559		1,695		1,814		1,046		1,514
U.S. Offshore		108		97		93		90		73		65		90		73		65		44		31

Total U.S.		1,032		1,192		1,383		1,649		1,768		1,879		1,649		1,768		1,879		1,090		1,545
Canada		372		365		455		471		343		382		471		343		382		222		348

Total North America		1,404		1,557		1,838		2,120		2,111		2,261		2,120		2,111		2,261		1,312		1,893

Source: BHI(~~www.BakerHughes.com)~~www.BakerHughes.com)

~~North American rotary rig count was 2,000 at December 31, 2008 and 1,701 at February 20, 2009.~~


	Year Ended												Year Ended
	12/31/03		12/31/04		12/31/05		12/31/06		12/31/07		12/31/08		12/31/06		12/31/07		12/31/08		12/31/09		12/31/10

Weatherford/AESC Service Rig Count (Active Rigs):
Cameron International Corporation/Guiberson/AESC Well Service Rig Count (Active Rigs):
United States		1,967		2,064		2,222		2,364		2,388		2,515		2,364		2,388		2,515		1,722		1,854
Canada		710		755		795		779		596		686		779		596		686		457		534

Total U.S. and Canada		2,677		2,819		3,017		3,143		2,984		3,201		3,143		2,984		3,201		2,179		2,388

Source: ~~Weatherford/~~Cameron International Corporation/Guiberson/AESC Well Service Rig Count for “Active ~~Rigs”~~Rigs.”

~~Average~~ Service rig counts for active rigs for December ~~2008 and January 2009 were 2,939 and 2,787, respectively,~~2010 was 2,682 according to the ~~Weatherford/~~Cameron International Corporation/Guiberson/AESC Well Service Rig Count for “Active ~~Rigs.”~~Rigs” and was 2,713 as of January 31, 2011.

AVERAGE OIL AND GAS PRICES


	Average Daily Closing		Average Daily Closing		Average Daily Closing		Average Daily Closing
	Henry Hub Spot Natural		WTI Cushing Spot Oil		Henry Hub Spot Natural		WTI Cushing Spot Oil
Period	Gas Prices ($/mcf)		Price ($/bbl)		Gas Prices ($/mcf)		Price ($/bbl)

1/1/99 — 12/31/99	$	2.27	$	19.30
1/1/00 — 12/31/00		4.31		30.37
1/1/01 — 12/31/01		3.97		25.96	$	3.99	$	25.96
1/1/02 — 12/31/02		3.37		26.17		3.37		26.17
1/1/03 — 12/31/03		5.49		31.06		5.49		31.06
1/1/04 — 12/31/04		5.90		41.51		5.90		41.51
1/1/05 — 12/31/05		8.89		56.56		8.89		56.56
1/1/06 — 12/31/06		6.73		66.09		6.73		66.09
1/1/07 — 12/31/07		6.97		72.23		6.97		72.23
1/1/08 — 12/31/08		8.89		99.92		8.89		99.92
1/1/09 — 12/31/09						3.94		61.99
1/1/10 — 12/31/10						4.38		79.48

Source: Bloomberg NYMEX prices.

The closing spot price of a barrel of WTI Cushing oil at December 31, ~~2008~~2010 was ~~$44.60~~$91.38 and the closing spot price for Henry Hub natural gas ($/mcf) was ~~$5.63.~~$4.41. At February ~~20, 2009,~~14, 2011, the closing spot price of a barrel of WTI Cushing oil was ~~$39.44~~$84.81 and the closing spot price for Henry Hub natural gas was ~~$4.22.~~$3.92.

We consider the drilling and well service rig counts to be an indication of spending by our customers in the oil and gas industry for exploration and development of new and existing hydrocarbon reserves. These spending levels are a primary driver of our business, and we believe that our customers tend to invest more in these activities when oil and gas prices are at higher levels or are increasing. ~~We evaluate the~~The utilization of our assets ~~as a measure~~and the performance of ~~operating performance. This utilization~~our business can be impacted by these and other external and internal factors. See Item 1A. “Risk Factors.”

We generally charge for our services either on a dayrate or per-stage-completed basis. Depending on the specific service, charges may include one or more of these components: (1) aset-up charge, (2) an hourly service rate based on equipment and labor, (3) a ~~stage- completed~~stage-completed charge, (4) an equipment rental charge, (5) a consumables charge, and (6) a mileage and fuel charge. We generally determine the rates charged through a competitive process on ajob-by-job basis. Typically, work is performed on a “call out” basis, whereby the customer requests services on a job-specific basis, but does not guarantee work levels beyond the specific job bid. For contract drilling services, fees are charged based on standard dayrates or, to a lesser extent, as negotiated by footage contracts. Product sales ~~are~~ generated through our Southeast Asian business ~~and through wholesale distributors, using a purchase order process and~~are typically based on a pre-determined price book.

We have entered into long-term take or pay contracts on the majority of our pressure pumping capacity. These agreements are typically for three-year terms and require our customers to pay us a minimum daily rate for not less than five days per week and provide for an option to operate seven days per week. We are typically paid within 30 — 60 days for services provided during the previous month. The contracts typically provide incentives to compensate us for better efficiencies and services provided at higher pressures, extended pump times and flow rates. We are also able to pass-through increases in costs associated with certain consumables used in pressure pumping operations. Our customers would be required to pay us substantial fees for the early termination of the contracts.

Outlook

~~Since our initial public offering, which became effective in April 2006, our~~Our growth strategy ~~has been~~is focused on internal growth in the basins in which we currently operate, ~~as we sought to maximize our~~maximizing equipment utilization, ~~add~~adding additional like-kind equipment and ~~expand~~expanding our service and product offerings. ~~In addition, we have sought~~We seek new basins in which to replicate this approach and ~~augmented~~augment our internal growth with strategic acquisitions. ~~Throughout 2008, we continued to execute this strategy while evaluating the market trends~~Our business is impacted by changes in the oil and gas ~~industry and communicating with our customers. In late 2008, we noticed a decline in drilling and exploration expenditures by our customers following the significant decline in oil~~cycle. Oil and gas commodity ~~prices. Although~~prices rose steadily throughout the decade culminating in 2008, then declined sharply in late 2008 and the early part of 2009, primarily due to the global financial crisis. Oil prices recovered through the remainder of 2009 and continued a gradual improvement during the course of 2010 along with the global economy. The price of natural gas in North America has remained subdued as a result of storage levels remaining above historical averages caused primarily by increasing gas production from unconventional resource plays. As a result, exploration and production companies are shifting a greater portion of their activities into emerging oil and liquid-rich plays and our business has shifted from a predominantly gas-oriented business, to a majority oil and liquids-oriented business.

In 2010, we ~~do not know the extent of this downturn for 2009, we expect~~remained disciplined with our financial investments in capital expenditures, targeted specific acquisitions, which were additive to ~~decrease~~ our ~~level of internal capital investment for 2009 relative to recent years,~~business objectives and ~~to implement cost-saving measures throughout 2009, while remaining responsive~~responded to our customers’ needs for quality ~~services.~~services in the emerging oil and liquid-rich plays. We redeployed equipment and personnel into the emerging basins while continuing to maintain a strong presence in our historical markets.


	•	Internal Capital Investment. Our internal expansion activities have generally consisted of adding equipment and qualified personnel in locations where we have established a presence. We have grown our operations in many 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 providedand/or add equipment to expand the services we provide. We invested ~~$930.3~~$462.2 million in equipment additions over the three-year period ended December 31, ~~2008,~~2010, which included ~~$752.0~~$399.4 million for the completion and production services segment, ~~$152.4~~$51.9 million for the drilling services segment, ~~$19.9~~$6.8 million for the product sales segment and ~~$6.0~~$4.1 million related to general corporate operations. ~~We expect to invest significantly less in capital equipment during~~For the year ended December 31, ~~2009.~~2010, we invested $169.9 million in capital expenditures.

	•	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 from period to period. Accordingly, ~~comparisons of~~ revenue and operating results in different periods are not necessarily comparable and should not be relied upon as indications of future performance. We ~~have~~ invested an aggregate of ~~$600.2~~$213.9 million in acquisitions over the three-year period ended December 31, ~~2008.~~2010. Of this amount, we invested an aggregate of $33.7 million to acquire 3 businesses during 2010, including a well servicing platform acquisition in the Eagle Ford Shale of south Texas, and $180.2 million to acquire 4 businesses during ~~2008 and $49.7 million to acquire 7 businesses~~2008. We did not complete any business acquisitions during ~~2007.~~the year ended December 31, 2009. See “— Significant ~~Acquisitions.~~Transactions.”

Natural gas prices have declined from historical highs in 2008 and rotary rig counts have recently begun to decline. The recent change in activity levels are likely the result of a number of macro-economic factors, such as an excess supply of natural gas, lower demand for oil and gas, market expectations of weather conditions and the utilization of heating fuels, the cyclical nature of the oil and gas industry and other general market conditions for the U.S. economy, including the current global financial crisis, which has contributed to significant reductions in available capital and liquidity from banks and other providers of credit. We have experienced a significant decline in utilization of our assets during late 2008 and thus far in 2009, andFor 2011, we anticipate that ~~lower commodity prices and~~ activity levels will ~~continue~~remain strong and a greater percentage of activity will be directed at increasingly more service intensive, multi-stage, horizontal wells. Current oil prices are encouraging increased investments in oil plays and in gas fields that have meaningful natural gas liquids content. Additionally, drilling and completion activity required to ~~adversely impact our near-term performance results due~~retain leases and service capacity shortages, which have led to ~~pricing pressure and lower utilization rates. Due~~a backlog of wells to be completed, should support activity in dry gas basins through the ~~deteriorating market conditions, we recorded~~first half of the year.

As a ~~non-cash impairment charge of $272.0 million at December 31, 2008 related to the write-down of goodwill for various~~result of our reporting units. In 2007, we recorded a non-cash goodwill impairment charge of $13.1 million for our Canadian reporting unit. Although we cannot determine the depth or duration of the decline in activity in the oil and gas industry, we believe the overall long-termpositive outlook for North ~~American oilfield activity~~America in 2011 we have expanded our capital expenditure program which includes: (1) roughly 170,000 hydraulic horse power of pressure pumping equipment; (2) five larger-diameter coiled tubing units with extended reach capabilities; and (3) meaningful investments in fluid handling and well servicing assets. Additionally, we continue to seek strategic acquisitions to enhance service offerings and extend our ~~business remains favorable, especially~~presence in ~~the basins in which we operate.~~

~~Our business continues to be impacted by seasonality and inclement weather including the effects of the normal second quarter Canadian“break-up,~~ ~~“ as well as the impact of Gulf of Mexico tropical weather systems.~~new service areas.

We, and many of our competitors, ~~have invested~~are investing in new equipment, some of which requires long ~~lead times~~lead-times to manufacture. As more of this equipment is available to be placed into service ~~and oilfield activities decline,~~ there ~~will~~could be additional excess capacity in the industry, which ~~we believe~~ may negatively impact ~~our~~ utilization rates and pricing ~~for certain service offerings . In addition, as new equipment enters the market, we must compete for employees to crew~~

~~the equipment, which puts~~and put inflationary pressure on labor costs. ~~Our equipment fleet is relatively new, as~~To improve efficiencies for us and our customers and due to the concern associated with excess capacity we have ~~made significant investments in new equipment over~~entered into long-termtake-or-pay contracts on the ~~past few years. We~~majority of our pressure pumping capacity. Additionally, we continue to monitor our equipment utilization and poll our customers to assess demand levels. As equipment enters the marketplace or competition for existing customers increases, we believe our customers will rely upon service providers ~~with local knowledge~~who provide quality services and ~~expertise,~~have positioned themselves to be responsive to customer’s needs which we believe we have and which constitutes a fundamental aspect of our growth strategy.

Our business continues to be impacted by seasonality and inclement weather, including the effects of harsh winter weather conditions which occurred during the past few months in North Dakota, Oklahoma and north Texas, the normal second quarter Canadian“break-up,” as well as the impact of Gulf of Mexico tropical weather systems.

We believe our customers will continue to rely upon service providers with local knowledge and a proven ability to effectively execute complex services on more service intensive, longer-lateral horizontal wells, particularly in oil and liquid-rich basins. We believe we are well positioned in high-growth basins and our core services, which include pressure pumping, coiled tubing, well servicing and fluid handling, will benefit from these secular trends.

Significant ~~Acquisitions~~Transactions

During 2010, we acquired substantially all the assets or all of the equity interests in three oilfield service companies, for $33.7 million in cash, resulting in goodwill of approximately $6.9 million.


	•	On May 11, 2010, we acquired certain assets of a provider of gas lift services based in Oklahoma City, Oklahoma. The total purchase price for the assets was $1.4 million in cash. We recorded goodwill totaling $1.0 million in conjunction with this acquisition which has been allocated entirely to the completion and production services business segment. We believe this acquisition supplements our plunger lift service offering for the completion and production services business segment.

	•	On September 3, 2010, we purchased the assets of a well service and fluid handling service provider based in Carrizo Springs, Texas. The total purchase price for the assets was $20.8 million and included goodwill of $4.9 million, all of which was allocated to the completion and production services business segment. We believe this acquisition enhances our position in the Eagle Ford Shale in south Texas.


	•	On December 1, 2010, we acquired all of the outstanding common stock of a disposal well operator located in Colorado for $12.6 million in cash, subject to an additional $0.5 million holdback. We recorded goodwill totaling $1.5 million in conjunction with this acquisition which has been allocated entirely to the completion and production services business segment. We believe this acquisition will enhance our position in the Denver-Julesburg Basin in Colorado.

During 2008, we acquired substantially all the assets or all of the equity interests in four oilfield service companies, for $180.2 million in cash, resulting in goodwill of approximately $71.2 million. ~~Several of these acquisitions are subject to final working capital adjustments.~~


	•	On February 29, 2008, we acquired substantially all of the assets of KR Fishing & Rental, Inc. for $9.5 million in cash, resulting in goodwill of $6.4 million. KR Fishing & Rental, Inc. is a provider of fishing, rental and foam unit services in the Piceance Basin and the Raton Basin, and is located in Rangely, Colorado. We believe this acquisition ~~complements~~complemented our completion and production services business in the Rocky Mountain region.

	•	On April 15, 2008, we acquired all the outstanding common stock of Frac Source Services, Inc., a provider of pressure pumping services to customers in the Barnett Shale of north Texas, for $62.4 million in cash, net of cash acquired, which includes a working capital adjustment of $1.6 million, and recorded goodwill of $15.4 million. Upon closing this transaction, we entered into a contract with one of our major customers to provide pressure pumping services in the Barnett Shale utilizing three frac fleets under a contract with a term that extends up to three years from the date each fleet is placed into service. We spent an additional $20.0 million in 2008 on capital equipment related to these contracted frac fleets. Thus, our total investment in this operation was approximately $82.4 million. We believe this acquisition ~~expands~~expanded our pressure pumping business in north Texas and that the related contract ~~provides~~provided a stable revenue stream from which to expand our pressure pumping business outside of this region.

	•	On October 3, 2008, we acquired all of the membership interests of TSWS Well Services, LLC, a limited liability corporation which held substantially all of the well servicing and heavy haul assets of TSWS, Inc., a company based in Magnolia, Arkansas, which provides well servicing and heavy haul services to customers in northern Louisiana, east Texas and southern Arkansas. As consideration, we paid $57.2 million in cash and prepaid an additional $1.0 million related to an employee retention bonus pool. We also recorded goodwill totaling $21.9 million. ~~The purchase price allocation associated with this acquisition has not yet been completed.~~ We believe this acquisition ~~extends~~extended our geographic reach into the Haynesville Shale area.

	•	On October 4, 2008, we acquired substantially all of the assets of Appalachian ~~Wells~~Well Services, Inc. and its wholly-owned subsidiary, each of which is based in Shelocta, Pennsylvania. This business provides pressure pumping,e-line and coiled tubing services in the Appalachian region, and includes a service area which extends through portions of Pennsylvania, West Virginia, Ohio and New York. As consideration for the purchase, we paid $50.1 million in cash and issued 588,292 unregistered shares of our common stock, valued at $15.04 per share. We ~~expect to invest~~invested an additional $6.5 million to complete a frac fleet at this location and have an option to purchase real property for approximately $0.6 million. In addition, we ~~have~~ entered into an agreement ~~under which we may be~~that could have required us to pay up to an additional $5.0 million in cash consideration during the earn-out period. This earn-out period ~~which extends through~~ended in 2010 ~~based upon the results of operations of various service lines acquired. The purchase price allocation associated~~ with ~~this acquisition has not yet been finalized.~~no additional consideration paid. We recorded goodwill of approximately $27.5 million associated with this ~~acquisition. We believe~~acquisition, however, this goodwill was deemed impaired in 2009 and expensed as of December 31, 2009. This acquisition ~~creates~~created a platform for future growth for our pressure pumping and other completion and production service lines in the Marcellus Shale.

~~Other recent acquisitions which are deemed to be significant include:~~


	•	~~Arkoma.~~ On June 30, 2006, we acquired certain operating assets of J&M Rental Tool, Inc dba Arkoma Machine & Fishing Tools, Arkoma Machine Shop, Inc. and N&M Supply, LLC, collectively referred to as “Arkoma”, a provider of rental tools, machining and fishing services in the Fayetteville Shale and Arkoma


		Basin, located in Ft. Smith, Arkansas. We paid $18.0 million in cash to acquire Arkoma and recorded goodwill totaling $9.0 million, which has been allocated entirely to the completion and production services business segment. This acquisition provided a platform to further expand our presence in the Fayetteville Shale and Arkoma Basin and supplements our completion and production services business in that region.


	•	~~Turner.~~ On July 28, 2006, we acquired all of the outstanding equity interests of the Turner group of companies (Turner Energy Services, LLC, Turner Energy SWD, LLC, T. & J. Energy, LLC, T. & J. SWD, LLC and Loyd Jones Well Service, LLC) for $54.3 million in cash, after a final working capital adjustment. The Turner Group of Companies (“Turner”) is based in the Texas panhandle in Canadian, Texas, and owns a fleet of well service rigs, and provides other wellsite services such as fishing, equipment rental, fluid handling and salt water disposal services. We recorded goodwill totaling $16.0 million associated with this purchase. We have included the accounts of Turner in our completion and production services business segment from the date of acquisition. We believe this acquisition supplements our completion and production services business in the Mid-continent region.

	•	~~Pinnacle.~~ On August 1, 2006, we acquired substantially all of the assets of Pinnacle Drilling Co., L.L.C. (“Pinnacle”), a drilling company located in Tolar, Texas, for $32.8 million in cash, which includes $1.1 million related to equipment refurbishment. Pinnacle operates three drilling rigs, two in the Barnett Shale region of north Texas and one in east Texas. We recorded goodwill totaling $1.0 million associated with this purchase. We finalized our purchase price allocation for Pinnacle during 2007 and received $0.6 million from the seller related to pre-acquisition contingencies which resulted in a reduction of goodwill of $0.6 million. We have included the accounts of Pinnacle in our drilling services business segment from the date of acquisition. This acquisition increases our presence in the Barnett Shale of north Texas and the Bossier Trend of east Texas and expands our capacity to drill deep and horizontal wells, which are sought by our customers in this region.

	•	~~Femco.~~ On October 19, 2006, we acquired substantially all of the assets of Femco Services, Inc., R&S Propane, Inc. and Webb Dozer Service, Inc. (collectively, “Femco”), a group of companies located in Lindsay, Oklahoma for $36.0 million in cash. Femco provides fluid handling, frac tank rental, propane distribution and fluid disposal services throughout southern central Oklahoma. We recorded goodwill totaling $11.2 million associated with this purchase. We have included the accounts of Femco in our completion and production services business segment from the date of acquisition. We believe this acquisition expands our presence in the Fayetteville Shale and enhances our completion and production services business in the Mid-continent region.

	•	~~Pumpco.~~ On November 8, 2006, we acquired all the outstanding equity interests of Pumpco, a company located in Gainesville, Texas for approximately $144.6 million in cash, net of cash acquired, and 1,010,566 shares of our common stock. We also assumed approximately $30.3 million of debt outstanding under Pumpco’s existing credit facility. Pumpco provides pressure pumping, stimulation and cementing services used in the development and completion of gas and oil wells in the Barnett Shale play of north Texas. We recorded goodwill totaling $148.6 million associated with this acquisition. The purchase price allocation for Pumpco was finalized in 2007 which resulted in a reclassification of $2.0 million from goodwill to other intangible assets, and a reduction of goodwill of $3.1 million related the deferred tax liabilities acquired which were deemed unnecessary based on our 2006 tax return filings in 2007. We have included the accounts of Pumpco in our completion and production services business from the date of acquisition. This acquisition expanded our presence in the Barnett Shale and expands the service offerings of our completion and product services business to include pressure pumping.

In addition, we completed several other smaller acquisitions in 2007 and 2006, each of which has contributed to the expansion of our business into new geographic regions or enhanced our service and product offerings.

We have accounted for our acquisitions using the purchase method of accounting, whereby the purchase price is allocated to the fair value of net assets acquired, including intangibles and property, plant and equipment at depreciated replacement costs with the excess to goodwill. Results of operations related to each of the acquired companies have been included in our ~~combined~~accounts and results of operations as of the date of acquisition.

In March 2009, our Canadian subsidiary exchanged certain non-monetary assets with a net book value of $9.3 million related to our production testing business for certaine-line assets of a competitor. We recorded a non-cash loss on the transaction of $4.9 million, which represented the difference between the carrying value and the fair

market value of the assets surrendered. We believe thee-line assets will generate incremental future cash flows compared to the production testing assets exchanged.

In May 2008, our Board of Directors authorized and committed to a plan to sell certain operations in the Barnett Shale region of north Texas, consisting primarily of our supply store business, as well as certain non-strategic drilling logistics assets and other completion and production services assets. On May 19, 2008, we sold these operations to Select Energy Services, L.L.C., a company owned by a former officer of one of our subsidiaries, for which we received proceeds of $50.2 million in cash and assets with a fair market value of $8.0 million. The carrying value of the net assets sold was approximately $51.4 million, excluding $11.1 million of allocated goodwill associated with the combination that formed Complete Production Services, Inc. in September 2005. We recorded a loss on the sale of this disposal group totaling approximately $6.9 million, which included $2.6 million related to income taxes. In accordance with the sales agreement, we ~~agreed to~~ sublet office space to Select Energy Services, L.L.C. and ~~to provide~~provided certain administrative services for an initial term of one year, at anagreed-upon rate.

On October 31, 2006, we completed the sale of ~~another~~a disposal group which included certain manufacturing and production enhancement ~~product~~ operations of a subsidiary located in Alberta, Canada, as well as operations in south Texas, for approximately $19.3 million in cash, with an additional amount subject to a working capital adjustment, and a $2.0 million Canadian dollar denominated note which matures on October 31, 2009 and accrues interest at a specified Canadian bank prime rate plus 1.50% per annum.Texas. We sold this disposal group to ~~Paintearth Energy Services, Inc.,~~ an oilfield service company located in Calgary, Alberta, ~~Canada,~~Canada. In conjunction with this asset disposal, the buyer issued a note to us for $2.0 million denominated in Canadian dollars. During the second quarter of 2010, we were notified that ~~employs two of~~the seller was in default on a term loan and security agreement which was senior to our ~~former employees as key managers. The carrying value of the related net assets was $21.7 million on October 31, 2006. We~~note. Therefore, management recorded a ~~loss on the sale~~provision of ~~this disposal group totaling approximately $0.6~~$1.9 million ~~which included a transaction gain associated with the release of cumulative translation adjustment~~for bad debt associated with this ~~business, and~~note as of June 30, 2010, but we will continue to pursue our interest in this note to the extent a ~~$1.0 million charge to expense related to capital taxes~~portion may be recoverable in ~~Canada. The sales agreement allowed Paintearth Energy Services, Inc. to use our subsidiary’s trade name for~~ a period of 120 days from November 1, 2006 through February 28, 2007. On January 30, 2008, we amended the terms of the Paintearth note receivable to extend the maturity date through October 2011 and amended the interest rate for each of the calendar years within the remaining term.future period.

~~Marketing~~Market Environment

We operate in a highly competitive industry. Our competition includes many large and small oilfield service companies. As such, we price our services and products to remain competitive in the markets in which we operate, adjusting our rates to reflect current market conditions as necessary. We examine the rate of utilization of our equipment as one measure of our ability to compete in the current market environment.

Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements in conformity with ~~GAAP~~Generally Accepted Accounting Principles (“GAAP”) requires the use of estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, and provide a basis for making judgments about the carrying value of assets and liabilities that are not readily available through open market quotes. Estimates and assumptions are reviewed periodically, and actual results may differ from those estimates under different assumptions or conditions. We must use our judgment related to uncertainties in order to make these estimates and assumptions.

In the selection of our critical accounting policies, the objective is to properly reflect our financial position and results of operations for each reporting period in a consistent manner that can be understood by the reader of our financial statements. Our accounting policies and procedures are explained in ~~note 1 of the~~Note 2, “Significant accounting policies,” in our notes to ~~the~~ consolidated financial statements ~~contained~~included elsewhere in this Annual ~~Report onForm 10-K.~~Report. We consider an estimate to be critical if it is subjective and if changes in the estimate using different assumptions would result in a material impact on our financial position or results of operations.

We have identified the following as the most critical accounting policies and estimates, and have provided: (1) a description, (2) information about variability and (3) our historical experience, including a sensitivity analysis, if applicable.

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 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 dayrate fees, or on aday-to-day basis. Revenue and costs related to drilling contracts are recognized as work progresses. Progress is measured as revenue is recognized based upon dayrate 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.

Under current GAAP, revenue is to be recognized when it is realized or realizable and earned. The SEC’s rules and regulations provide additional guidance for revenue recognition under specific circumstances, including bill and hold transactions. There is a risk that our results of operations could be misstated if we do not record revenue in the proper accounting period.

The nature of our business has been such that we generally bill for services over a relatively short period of time or bill for services on a stage-completed basis under a longer-term contract withtake-or-pay provisions and record revenues as products are sold. We did not record material adjustments resulting from revenue recognition issues for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006.~~2008.

Impairment of Long-Lived Assets

WeBased on guidance from the Financial Accounting Standards Board (“FASB”) regarding accounting for the impairment or disposal of long-lived assets, we evaluate potential impairment of long-lived assets and intangibles, excluding goodwill and other intangible assets without defined ~~services~~service lives, when indicators of impairment are ~~present, as defined in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.”~~present. 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, “Goodwill and Other Intangible Assets,” which requires~~perform an annual impairment test, whereby we estimate the fair value of the asset by discounting future cash flows at a 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.~~similar to a purchase price allocation for a business combination. 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. If our estimates do not approximate actual performance or if the rates we used to discount cash flows vary significantly from actual discount rates, we could overstate our assets and an impairment loss may not be timely identified.

We tested goodwill for impairment for each of the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006.~~2008. Management prepared a discounted cash flow analysis to determine the fair market value of ~~each~~the reportable ~~unit~~units as of the annual testing ~~date, October 1 of each year.~~date. Projected cash flows were based on certain management assumptions related to expected growth, capital investment and terminal value, discounted at a market-participant weighted average cost of capital, refined to reflect our current and anticipated capital structure. Based on this analysis, management determined that goodwill was not impaired as of our annual testing date in 2010, but was impaired in ~~2008~~2009 and ~~2007.~~2008. In accordance with ~~SFAS No. 142,~~the FASB’s guidance for goodwill, management performed a step-two analysis to calculate the amount by which the carrying value of the reporting units exceeded the projected fair market value of such units as of the respective annual testing date. As a result of this testing in 2007, management recorded an impairment charge which reduced goodwill in Canada by $13.4 million. This annual testing was performed in 2008 and yielded another impairment for this Canadian subsidiary as of the test date. However, due to a decline in the overall U.S. debt and equity markets and concerns over the availability of credit, we determined that a “triggering event,” as that term is defined in SFAS No. 142, had occurred during the

~~fourth quarter of 2008. Therefore, we~~dates. We performed our impairment calculations ~~again~~ as of December 31, 2008, incorporating our ~~most recent~~ assumptions of future earnings and cash flows. Based on this testing, we determined that the goodwill associated with most of our reporting units had been impaired. We recorded an impairment charge of $272.0 million at December 31, 2008. In calculating this impairment charge, management made assumptions about future earnings by reportable unit, which may differ from actual future earnings for these operations. In 2009, management performed additional analysis and determined that further write-downs were necessary. We recorded a

goodwill impairment charge of $97.6 million associated with several of our reportable units at December 31, 2009. In addition, pursuant to an undiscounted cash flow analysis, we recorded a fixed asset impairment in our drilling services segment of $36.2 million and an intangible asset impairment in our completion and production services segment totaling $2.5 million during 2009. A significant decline in expected future cash flow, a further erosion of market conditions or alower-than-expected recovery of the oil and gas industry activity levels in future years, could result in an additional impairment charge. ~~A 10% impairment of total goodwill at December 31, 2008 would have decreased our operating income by $34.2 million for the year then ended.~~

Stock Options and Other Stock-Based Compensation

We have issued stock-based compensation to certain employees, officers and directors in the form of stock options and ~~non-vested~~ restricted stock. ~~We adopted SFAS No. 123R, “Share-Based Payment,” on January 1, 2006, which impacted our accounting treatment of employee stock options. As required by SFAS No. 123R,~~In accordance with U.S. GAAP, we ~~continue to~~ account ~~for stock-based compensation~~ for grants made prior to September 30, 2005, the date of our initial filing with the SEC, using the minimum value method, ~~prescribed by APB No. 25,~~ whereby no compensation expense is recognized for stock-based compensation grants that have an exercise price equal to the fair value of the stock on the date of grant. ~~However, for~~For grants of stock-based compensation between October 1, 2005 and December 31, 2005, ~~(prior to adoption of SFAS No. 123R),~~ we ~~have~~ utilized the modified prospective transition method to record expense associated with these ~~options. Under this transition method,~~options, whereby we did not record compensation expense associated with these ~~stock option~~ grants during the period October 1, 2005 through December 31, 2005 but ~~will provide~~provided pro forma disclosure of this expense, ~~as appropriate. However, we will recognize~~and, then began recognizing compensation expense related to these grants over the remaining vesting period after December 31, 2005 based upon a calculated fair value. These grants were fully vested as of December 31, 2009. For grants of stock-based compensation on or after January 1, 2006, ~~we apply the prospective transition method under SFAS No. 123R, whereby~~ we recognize expense associated with new awards of stock-based compensation, as determined using a Black-Scholes pricing model over the expected term of the award. In addition, we record compensation expense associated with ~~non-vested~~ restricted stock which has been granted to certain of our directors, officers and employees. In accordance with ~~SFAS No. 123R,~~current U.S. GAAP, we calculate compensation expense on the date of grant (number of options granted multiplied by the fair value of our common stock on the date of grant) and recognize this expense, adjusted for forfeitures, ratably over the applicable vesting period.

U.S. 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. For purposes of determining compensation expense associated with stock options granted after January 1, 2006, we are required to determine the fair value of the stock options by applying a pricing model which includes assumptions for expected term, discount rate, stock volatility, expected forfeitures and a dividend rate. The use of different assumptions or a different model may have a material impact on our financial disclosures.

For the years ended ~~on or before~~ December 31, ~~2005,~~2010, 2009 and 2008, we determined the value of our stock options by applying the minimum value method permitted by APB No. 25 and, in connection with estimating compensation expense that would be required to be recognized under SFAS No. 123, “Accounting for Stock-Based Compensation,” we usedapplied a Black-Scholes model ~~including~~with similar assumptions for expected term ~~(ranging~~(based on a probability analysis and ranging from 32.2 to ~~4.5 years as of December 31, 2005)~~5.1 years), ~~risk-~~risk free rate (based upon published rates for U.S. Treasury ~~notes with a similar term)~~notes), zero dividend rate and ~~a volatility rate of zero. For the years ended December 31, 2007 and 2006, we applied a Black-Scholes model with similar assumptions, except we estimated our~~ stock volatility, ~~by examining~~which we determined based on our historical common stock volatility for grants after June 2008 and estimated based on the historical volatility rates of several peer companies prior to that time. In addition, we estimated a forfeiture rate based upon our historical experience and we estimated the expected term of the options using a probability analysis. Beginning in July 2008, we used our historical volatility rate as an assumption to determine the grant date fair value of ourexperience. We have recorded compensation expense associated with stock option and restricted stock grants ~~during the third~~totaling $11.6 million, $12.2 million and ~~fourth quarters of 2008. For~~$12.4 million for the years ended December 31, 2010, 2009 and 2008, and 2007, we have recorded compensation expense totaling $5.4 million and $4.4 million, respectively, related to our stock option grants and $6.9 million and $3.1 million, respectively, related to our non-vested restricted stock.respectively.

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.

There is a risk that management may not detect uncollectible accounts or unsalvageable inventory in the correct accounting period.

Bad debt expense (recovery) has been less than 1% of sales for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006.~~2008. If bad debt expense had increased by 1% of sales, ~~for the years ended December 31, 2008, 2007 and 2006,~~ net income would have ~~declined~~decreased by $9.7 million for the year ended December 31, 2010 and net loss would have increased by $7.8 million and $11.9 million ~~$9.7 million~~for the years

ended December 2009 and ~~$6.9 million,~~2008, respectively. Our obsolescence and other inventory reserves were approximately 2%7%, 7%2% and 4%2% of our inventory balances at December 31, ~~2008, 2007~~2010, 2009 and ~~2006,~~2008, respectively. A 1% increase in inventory reserves, from 2%7% to 3%8%, at December 31, ~~2008~~2010 would have decreased net income by ~~$0.3~~$0.2 million for the year then ended.

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. 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.

U.S. 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. If our depreciation estimates are not correct, we could over- or understate our results of operations, such as recording a disproportionate amount of gains or losses upon disposition of assets. There is also a risk that the useful lives we apply for our depreciation calculation will not approximate the actual useful life of the asset. We believe our estimates of useful lives are materially correct and that these estimates are consistent with industry averages.

We evaluate property, plant and equipment for impairment when there are indicators of impairment. We did not record any significant impairment charges related to our long-term assets for the year ended December 31, 2010. During September 2009, we evaluated the fair market value of assets in our contract drilling business with the assistance of a third-party appraiser and determined that the carrying value of certain of these drilling rigs exceeded the fair market value estimates. We projected the undiscounted cash flows associated with these rigs, including an estimate of salvage value, and compared these expected future cash flows to the carrying amount of the rigs. If the undiscounted cash flows exceeded the carrying amount, no further testing was performed and the rig was deemed to not be impaired. If the undiscounted cash flows did not exceed the carrying value, we estimated the fair market value of the equipment based on management estimates and general market data obtained by the third-party appraiser using the sales comparison market approach, which included the analysis of recent sales and offering prices of similar equipment to arrive at an indication of the most probable net sales proceeds for the equipment. The result of this analysis was a calculated fixed asset impairment of $36.2 million, which was recorded as an impairment loss in September 30, 2009. This impairment charge was allocated entirely to the drilling services business segment. This impairment was deemed necessary due to an overall decline in oil and gas exploration and production activity in late 2008 which extended throughout 2009, as well as management’s expectation of future operating results for this business segment. There ~~have been~~were no significant impairment charges related to our long-term assets during the ~~years~~year ended December 31, ~~2008, 2007 and 2006.~~2008. Depreciation and amortization expense for the years ended December 31, ~~2008~~2010 and ~~2007~~2009 represented ~~16% and 15%~~19% of the average depreciable asset base for ~~the respective years.~~each year. An increase in depreciation expense relative to the depreciable base of 1%, from ~~16%~~19% to ~~17%~~20%, would have reduced net income by approximately ~~$7.1~~$5.9 million for the year ended December 31, ~~2008.~~2010.

Self Insurance

On January 1, 2007, we began a self-insurance program to pay claims associated with health care benefits provided to certain of our employees in the United States. Pursuant to this program, we have purchased a stop-loss insurance policy from an insurance company. Our accounting policy for this self-insurance program is to accrue expense based upon the number of employees enrolled in the plan at pre-determined rates. As claims are processed and paid, we compare our claims history to our expected claims in order to estimate incurred but not reported claims. If our estimate of claims incurred but not reported exceeds our current accrual, we record additional expense during the current period. There is a risk that we may not estimate our incurred but not reported claims correctly or that our stop-loss provision may not be adequate to insure us against ~~material~~ losses in the future. At December 31, ~~2008,~~2010, we accrued ~~$4.4~~$4.7 million pursuant to this self-insurance program. A 10% increase in this self-insurance accrual would reduce our net income for the year ended December 31, ~~2008~~2010 by ~~$0.3~~$0.4 million.

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~~pursuant to U.S. GAAP for ~~Income Taxes.” Under SFAS No. 109, we~~income taxes and 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~~we 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 December 31, ~~2008, 2007~~2010, 2009 and ~~2006,~~2008, we recorded a valuation allowance of less than $1.0 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 adversely affect our financial results. As of December 31, ~~2008,~~2010, we did not provide deferred U.S. income taxes on approximately ~~$12.0~~$28.6 million of undistributed earnings of our 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. On January 1, 2007, we adopted ~~Financial Interpretation No. 48 (“FIN 48”), which~~the FASB interpretation that provides guidance to account for uncertain tax positions. ~~During 2008,~~Annually, we ~~performed~~perform an evaluation of our tax positions. We have evaluated our tax positions ~~pursuant to Financial Interpretation No. 48 (“FIN 48”)~~at December 31, 2010 and ~~determined that this pronouncement did not have a material impact on our financial position, results of operations and cash flows.~~believe these positions are deemed appropriate for all significant matters.

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 or GAAP requirements could result in additional valuation allowances or the recognition of additional tax liabilities.

Historically, we have utilized net operating loss carry forwards to partially offset current tax expense, and we have recorded a valuation allowance to the extent we expect that our deferred tax assets will not be utilized through future operations. Deferred income tax assets totaled ~~$20.0~~$30.5 million at December 31, ~~2008,~~2010, against which we recorded a valuation allowance of $0.3 million, leaving a net deferred tax asset of ~~$19.7~~$30.2 million deemed realizable. Changes in our valuation allowance would affect our net income on a dollar for dollar basis.

Discontinued Operations

We account for discontinued operations in accordance with ~~SFAS No. 144, “Accounting~~the FASB guidance on accounting for the ~~Impairment~~impairment or ~~Disposal~~disposal of ~~Long-Lived Assets.” SFAS No. 144~~long-lived assets. U.S. GAAP requires that we classify the assets and liabilities of a disposal group as held for sale if the following criteria are met: (1) management, with appropriate authority, commits to a plan to sell a disposal group; (2) the asset is available for immediate sale in its current condition; (3) an active program to locate a buyer and other actions to complete the sale have been initiated; (4) the sale is probable; (5) the disposal group is being actively marketed for sale at a reasonable price; and (6) actions required to complete the plan of sale indicate it is unlikely that significant changes to the plan of sale will occur or that the plan will be withdrawn. Once deemed held for sale, we no longer depreciate the assets of the disposal group. Upon sale, we calculate the gain or loss associated with the disposition by comparing the carrying value of the assets less direct costs of the sale with the proceeds received. In conjunction with the sale, we settle inter-company balances between us and the disposal group and allocate interest expense to the disposal group for the period the assets were held for sale. In the statement of operations, we present discontinued operations, net of tax effect, as a separate caption below net income from continuing operations.

Results of Operations for the Years Ended December 31, ~~2008~~2010 and ~~2007~~2009

The following tables set forth our results of continuing operations, including amounts expressed as a percentage of total revenue, for the periods indicated (in thousands, except percentages).


										Percent												Percent
	Year			Year			Change			Change			Year			Year			Change			Change
	Ended			Ended			2008/			2008/			Ended			Ended			2010/			2010/
	12/31/08			12/31/07			2007			2007			12/31/10			12/31/09			2009			2009
	(In thousands)												(In thousands)

Revenue:
Completion and production services	$	1,545,348		$	1,242,314		$	303,034			24	%	$	1,354,797		$	897,584		$	457,213			51	%
Drilling services		234,104			212,272			21,832			10	%		172,821			114,729			58,092			51	%
Product sales		59,102			40,857			18,245			45	%		33,775			44,081			(10,306	)		(23	)%

Total	$	1,838,554		$	1,495,443		$	343,111			23	%	$	1,561,393		$	1,056,394		$	504,999			48	%

EBITDA:
Adjusted EBITDA:
Completion and production services	$	473,376		$	398,628		$	74,748			19	%	$	369,826		$	165,787		$	204,039			123	%
Drilling services		58,743			61,418			(2,675	)		(4	)%		38,973			9,641			29,332			304	%
Product sales		12,677			9,943			2,734			27	%		5,197			7,966			(2,769	)		(35	)%
Corporate		(38,293	)		(28,136	)		(10,157	)		36	%		(39,088	)		(34,313	)		(4,775	)		(14	)%

Total	$	506,503		$	441,853		$	64,650			15	%	$	374,908		$	149,081		$	225,827			151	%

“Corporate” includes amounts related to corporate personnel costs, other general expenses and stock-based compensation charges.

“Adjusted EBITDA” consists of net income (loss) from continuing operations before net interest expense, taxes, depreciation and amortization, ~~minority~~non-controlling interest and impairment loss. Adjusted EBITDA is a ~~non-cash~~non-GAAP measure of performance. We use Adjusted EBITDA as the primary internal management measure for evaluating performance and allocating additional resources. ~~See the discussion of EBITDA at Note 3 under Item 6 (“Selected Financial Data”) of this Annual Report.~~ The following table reconciles Adjusted EBITDA for the years ended December 31, ~~2008~~2010 and ~~2007~~2009 to the most comparable U.S. GAAP measure, operating income (loss). The calculation of Adjusted EBITDA is different from the calculation of “EBITDA,” as defined and used in our credit facilities. For a discussion of the calculation of “EBITDA” as defined under our existing credit facilities, as recently amended, see Note 11, “Long-term debt” in our notes to consolidated financial statements included elsewhere in this Annual Report.

Reconciliation of Adjusted EBITDA to Most Comparable GAAP Measure — Operating Income (Loss)

Completion and
Drilling
Product

Year Ended December 31, 2008
Production Services Services Sales Corporate Total

EBITDA, as defined $ 473,376 $ 58,743 $ 12,677 $ (38,293 ) $ 506,503
Depreciation and amortization $ 156,198 $ 19,961 $ 2,537 $ 2,401 $ 181,097
Impairment loss $ 243,203 $ 27,410 $ 1,393 $ — $ 272,006

Operating income (loss) $ 73,975 $ 11,372 $ 8,747 $ (40,694 ) $ 53,400

Year Ended December 31, 2007

EBITDA, as defined $ 398,628 $ 61,418 $ 9,943 $ (28,136 ) $ 441,853
Depreciation and amortization $ 112,836 $ 14,572 $ 2,064 $ 1,881 $ 131,353
Impairment loss $ 13,094 $ — $ — $ — $ 13,094

Operating income (loss) $ 272,698 $ 46,846 $ 7,879 $ (30,017 ) $ 297,406

(In thousands)

Completion and
Drilling
Product

Year Ended December 31, 2010 Production Services Services Sales Corporate Total

Adjusted EBITDA, as defined $ 369,826 $ 38,973 $ 5,197 $ (39,088 ) $ 374,908
Depreciation and amortization $ 159,110 $ 18,480 $ 2,211 $ 2,022 $ 181,823

Operating income (loss) $ 210,716 $ 20,493 $ 2,986 $ (41,110 ) $ 193,085

Year Ended December 31, 2009

Adjusted EBITDA, as defined $ 165,787 $ 9,641 $ 7,966 $ (34,313 ) $ 149,081
Depreciation and amortization $ 174,929 $ 21,067 $ 2,460 $ 2,276 $ 200,732
Write-off of deferred financing fees $ — $ — $ — $ (528 ) $ (528 )
Fixed asset and other intangible impairment loss $ 2,488 $ 36,158 $ — $ — $ 38,646
Goodwill impairment loss $ 97,643 $ — $ — $ — $ 97,643

Operating income (loss) $ (109,273 ) $ (47,584 ) $ 5,506 $ (36,061 ) $ (187,412 )

47

Reconciliation of Net Income (Loss) to Adjusted EBITDA

For the Year Ended December 31,
2010 2009 2008
(In thousands)

Net income (loss) $ 84,158 $ (181,668 ) $ (89,568 )
Plus: interest expense, net 57,347 56,816 59,428
Plus: tax expense (benefit) 51,580 (63,088 ) 72,305
Plus: depreciation and amortization 181,823 200,732 181,197
Plus: impairment loss — 136,289 272,006
Minus: income (loss) from discontinued operations (net of tax expense of $0, $0 and $3,865, respectively) — — (4,859 )

Adjusted EBITDA $ 374,908 $ 149,081 $ 500,227

Below is a detailed discussion of our operating results by segment for these periods.

Year Ended December 31, ~~2008~~2010 Compared to the Year ended December 31, ~~2007~~2009

Revenue

Revenue from continuing operations for the year ended December 31, ~~2008~~2010 increased by ~~$343.1~~$505.0 million, or ~~23%~~48%, to ~~$1,838.6~~$1,561.4 million from ~~$1,495.4~~$1,056.4 million for the year ended December 31, ~~2007.~~2009. This increase by segment was as follows:

• Completion and Production Services.  Segment revenue increased ~~$303.0~~$457.2 million, or ~~24%~~51%, primarily due to ~~revenues earned as a result~~an increase in demand for our services and an overall increase in activity levels for the oil and gas industry during 2010 compared to 2009, resulting in higher utilization of ~~additional capital investment~~our equipment. Activity levels and pricing in ~~our pressure pumping, coiled tubing, well servicing, rental~~some service lines and ~~fluid handling businesses in 2007~~select geographic areas began to improve during the latter part of the fourth quarter of 2009 and ~~2008. We experienced favorable results~~continued improving throughout 2010. The segment continued to benefit from increased horizontal drilling and completion related activity within resource plays, particularly for our pressure pumping, fluid handling ~~well service~~ and U.S. ~~and Mexican~~ coiled tubing businesses, ~~when comparing 2008 to 2007. Revenues for our~~Our pressure pumping business ~~increased due to: (1)~~also benefitted from the ~~successful integration~~deployment of ~~a business acquired in April 2008, and (2) the expansion~~approximately 43,000 hydraulic horse power of ~~services~~new pressure pumping equipment into the Eagle Ford and Bakken Shale area of North Dakota. During 2007 and 2008, we completed a series of small acquisitions which provided incremental revenues for 2008 compared to 2007 due to the timing of those acquisitions. Revenue increases were partially offset by a general decline in oilfield activity which began during the fourth quarter of 2008 and pricing pressures in certain service offeringsshales during the latter ~~half~~part of ~~2007 and throughout 2008.~~2010.

• Drilling Services.  Segment revenue increased ~~$21.8~~$58.1 million, or ~~10%~~51%, for the year, primarily due to ~~higher~~improved utilization ~~rates~~ and ~~additional capital invested in our contract drilling business in 2007 and 2008. In early 2008, we experienced lower~~ pricing ~~for our drilling services and lower utilization rates~~ in our rig ~~logistics operations primarily due to an increase in equipment placed~~relocation and contract drilling businesses. The rig relocation business also benefitted from long rig moves as customers reactivated and repositioned assets from dry gas basins into ~~service by our competitors. However, utilization improved during~~emerging oil and liquid-rich markets such as the ~~second~~Bakken, Niobrara and ~~third quarters of 2008, before declining in the fourth quarter due to a general decline in oilfield activity by our customers.~~Eagle Ford shales.

• Product Sales.  Segment revenue ~~increased $18.2~~decreased $10.3 million, or ~~45%~~23%, for the year, primarily due to ~~the sales mix and the timing of product sales and equipment refurbishment for our Southeast Asian business, which tends to be project-specific. We also had a larger volume of~~lower third-party sales at our repair and fabrication shop in north Texas as several large projects were completed during ~~2008 as compared to 2007.~~the first quarter of 2009, while results for our Southeast Asian business remained relatively constant for the years ended December 31, 2010 and 2009.

Service and Product Expenses

Service and product expenses include labor costs associated with the execution and support of our services, materials used in the performance of those services and other costs directly related to the support and maintenance of equipment. These expenses increased ~~$259.2~~$285.7 million, or ~~30%~~39%, to ~~$1,133.8~~$1,011.0 million for the year ended December 31, ~~2008~~2010 from ~~$874.6~~$725.4 million for the year ended December 31, ~~2007.~~2009. The increase in service and product expenses was consistent with an overall increase in revenues resulting from improvements in oilfield activity in the

48

U.S. and Canada in 2010. The following table summarizes service and product expenses as a percentage of revenues for the years ended December 31, ~~2008~~2010 and ~~2007:~~2009:

Service and Product Expenses as a Percentage of Revenue


	Years Ended									Years Ended
Segment:	12/31/08			12/31/07			Change			12/31/10			12/31/09			Change

Completion and Production services		61	%		58	%		3	%		64	%		68	%		(4	)%
Drilling services		67	%		61	%		6	%		70	%		75	%		(5	)%
Product sales		71	%		68	%		3	%		77	%		75	%		2	%
Total		62	%		58	%		4	%		65	%		69	%		(4	)%

Service and product expenses as a percentage of revenue ~~increased~~improved to ~~62%~~65% for the year ended December 31, ~~2008~~2010 compared to ~~58%~~69% for the year ended December 31, ~~2007.~~2009. Margins by business segment were impacted primarily by ~~acquisitions, pricing~~utilization and ~~utilization.~~pricing.


	•	Completion and Production Services. Service and product expenses as a percentage of revenue for this business segment decreased when comparing the year ended December 31, 2010 to the same period in 2009. Theyear-over-year favorable margin improvement was attributable to an increase in overall oilfield activity, improved pricing and service mix, with an increase in sales for historically higher-margin offerings, partially offset by some increases in labor costs and other inflationary factors. We enacted certain cost-saving measures in 2009, including headcount reductions and payroll concessions which were substantially reinstated during 2010.

	•	Drilling Services.The ~~increase~~decrease in service and product expenses as a percentage of revenue for this business segment ~~reflects pricing pressure for many of our service lines throughout 2008,~~


		~~resulting in less favorable operating margins on ayear-over-year~~ basis. We incurred higher labor and fuel costs during 2008, although fuel costs began to decline in the fourth quarter of 2008, and we incurred higher sand and cement costs in our pressure pumping business.~~Start-up~~ costs associated with mobilizing a frac fleet in the Bakken Shale area of North Dakota also impacted our operating margins. Cost increases were partially offset by the mix of services provided in 2008 compared to 2007, a full-year’s benefit of capital invested throughout 2007, additional equipment placed into service during 2008 and several acquisitions. In late 2008, we experienced lower utilization rates and an increase in pricing pressure in several service lineswas primarily due to ~~a general decline in oilfield activity which may stem from lower commodity prices~~increased asset utilization and ~~concerns over the broader U.S. economy and the availability of credit for investment by our customers.~~


	•	~~Drilling Services.~~ The increase in service and product expenses as a percentage of revenue for this business segment represented a decline in margin during 2008 compared to 2007 due to: (1) lower pricing for our contract drilling and drilling logistics businesses on a~~year-over-year~~ ~~basis; (2) higher operating costs associated primarily with labor and fuel; and (3) lower utilization of our equipment due primarily to more market competition.~~improved pricing.

	•	Product Sales. The increase in service and product expenses as a percentage of revenue for the products segments was primarily due to the mix of products sold ~~specifically~~for the ~~timing~~relative periods. Additionally, on ayear-over-year basis, a larger proportion of ~~equipment~~the revenues and related costs for the product sales ~~and refurbishment associated with~~segment for the year ended December 31, 2010 were provided by our Southeast Asian ~~operations~~business, for which sales tend to be project specific and ~~can fluctuate between periods depending upon~~are subject to fluctuations in activity levels in the ~~nature of the projects in process, and third-party repair and fabrication work performed at our shop in north Texas.~~region.

Selling, General and Administrative Expenses

Selling, general and administrative expenses include salaries and other related expenses for our selling, administrative, finance, information technology and human resource functions. Selling, general and administrative expenses ~~increased $19.3~~decreased $6.0 million, or ~~11%~~3%, to $175.4 million for the year ended December 31, ~~2008 to $198.3~~2010 from $181.4 million ~~from $179.0 million during~~for the year ended December 31, ~~2007. These expense increases included: (1) costs~~2009. The results for 2009 included incremental bad debt charges associated with ~~businesses acquired~~specifically-identified uncollectible accounts of $10.9 million, incremental losses on the retirement of fixed assets of $12.8 million and certain insignificant inventory adjustments. In addition, we recorded a loss on the non-monetary exchange of certain assets in ~~2008, including additional employee headcount, property rental expense and insurance expense; (2) costs associated with 2007 acquisitions,~~Canada during the first quarter of 2009 which ~~provided a full-year of~~totaled $4.9 million. The overall decrease in selling, general and administrative expense ~~for 2008; (3)~~in 2010 was partially offset by higher incentive compensation based on earnings, increased payroll costs, higher insurance costs and the write-off of a $1.9 million note receivable in Canada. Excluding the impact of the non-monetary asset exchange in Canada, the incremental ~~costs of approximately $5.0 million related~~charges to ~~stock-based compensation in 2008 compared to the prior year;~~bad debt expense and ~~(4) costs associated with~~losses on the retirement of ~~an executive officer during the fourth quarter of 2008 and other severance costs. As~~fixed assets, as a percentage of revenues, selling, general and administrative expense ~~declined to~~was 11% and 14% for the ~~year~~years ended December 31, ~~2008 as compared to 12% for the year ended December 31, 2007.~~2010 and 2009, respectively.

Depreciation and Amortization

Depreciation and amortization expense ~~increased $49.7~~decreased $18.9 million, or ~~38%~~9%, to ~~$181.1~~$181.8 million for the year ended December 31, ~~2008~~2010 from ~~$131.4~~$200.7 million for the year ended December 31, ~~2007.~~2009. The ~~increase~~decrease in depreciation and amortization expense was attributable to the ~~result~~normal run-off of ~~equipment placed into service~~depreciation associated with existing assets, asset retirements in ~~2008,~~2009, a ~~portion~~$36.2 million impairment of ~~which was purchased~~our drilling rigs as of September 30, 2009, sale-leaseback transactions associated with our small vehicle fleet as well as a facility in ~~2007. Capital~~Wyoming and an impairment charge in

late 2009 related to certain intangible assets acquired in 2008. Although we increased our capital expenditures ~~for equipment~~ in ~~2008 totaled $253.8 million. In addition, we recorded~~2010 compared to 2009, approximately half of those additions were incurred during the second half of the year, resulting in overall lower depreciation and amortization expense related to businesses acquired in 2007 and 2008, as well as assets purchased and placed into service throughout 2007, which contributed a full year of depreciation expense in 2008 compared to a partial year of depreciation expense in 2007. In addition, we incurred incremental amortization expense associated with intangible assets related to businesses acquired in 2008, particularly customer relationship intangibles which totaled $14.0 million.year-over-year. As a percentage of revenue, depreciation and amortization expense ~~increased~~decreased to ~~10%~~12% from 19% for the ~~year~~years ended December 31, ~~2008 compared to 9% for the year ended December 31, 2007.~~2010 and 2009, respectively.

Fixed Asset and Other Intangible Impairment Loss

We did not record any impairment charges in 2010. For the year ended December 31, 2009, we recorded a fixed asset and other intangible impairment loss of $38.6 million. We recorded a charge of $36.2 million related to our contract drilling business in the third quarter of 2009 after determining that the carrying value of certain of these drilling rigs exceeded the undiscounted cash flows associated with these assets and the fair market value estimates for these assets. In the fourth quarter of 2009, we recorded an impairment ~~loss~~ of ~~$272.0~~intangible assets of $2.5 million related to our completion and production business.

Goodwill Impairment Loss

We did not record any goodwill impairment in 2010. For the ~~write-down~~year ended December 31, 2009, we recorded a goodwill impairment loss of $97.6 million. The write-downs of goodwill was associated with several of our reporting units ~~as defined in SFAS No. 142,~~and was based upon several valuation techniques including a discounted cash flow analysis of expected future earnings associated with these businesses. ~~This~~Our analysis of future cash flows was impacted significantly by the overall decline in oilfield activity in late 2008 and the expected slowdown in activities in the short-term, due in part to concerns of excess supply of commodities, a general decline in the U.S. economy and concerns over the availability of credit for

our customers to continue investment in drilling and exploration activities in the short-term. We recorded an impairment charge of $13.1 million for the year ended December 31, 2007 related to our Canadian operations.

~~Interest Expense~~

Interest expense was $59.7 million and $61.3 million for the years ended December 31, 2008 and 2007, respectively. The decrease in interest expense was attributable primarily to a decline in the average borrowing rate in 2008 for variable rate borrowings, primarily our revolving credit facilities in the U.S. and Canada. This decline in interest rates was partially offset by an increase in the average debt balance outstandingwhich continued throughout 2008 compared to 2007. These borrowings were used primarily for business acquisitions and equipment purchases during 2008. The weighted-average interest rate of borrowings outstanding at December 31, 2008 and 2007 was approximately 7.0% and 7.7%, respectively.2009.

Taxes

Tax expense (benefit) is comprised of current income taxes and deferred income taxes. The current and deferred taxes added together provide an indication of an effective rate of income tax.

~~Our~~We recorded a tax provision of $51.6 million, at an effective rate of 38%, for the year ended December 31, ~~2008~~2010 compared to a tax benefit of $63.1 million for the year ended December 31, 2009 at an effective rate of approximately 25.8%. The lower effective tax rate in 2009 was ~~impacted significantly by a $272.0 million~~primarily due to the impairment of goodwill ~~which had a~~with limited tax ~~basis, as the majority of the goodwill arose through stock purchase transactions with little or no tax~~ basis. ~~We received no tax benefit from the $13.1 million impairment of goodwill recorded at December 31, 2007.~~ Excluding the impact of the goodwill impairment charges, our effective tax ~~rates~~rate for the ~~years~~year ended December 31, ~~2008 and 2007~~2009 would have been 35.5% and 34.8%, respectively. The difference in the tax rates was attributable to the impact of the domestic production activities deduction and the effect of changes in earnings in the various tax jurisdictions in which we operate.33.9%.

~~Minority Interest~~

Prior to December 31, 2007, an unrelated third party owned a 50% interest in the assets of Premier Integrated Technologies, Inc. (“Premier”), a company that we acquired on January 1, 2005, and have consolidated in our accounts since the date of acquisition. This amount represents the minority owner’s share of Premier’s earnings for the applicable periods. On December 31, 2007, we acquired the remaining 50% interest in this company.

Results of Operations for the Years Ended December 31, ~~2007~~2009 and ~~2006~~2008

The following tables set forth our results of continuing operations, including amounts expressed as a percentage of total revenue, for the periods indicated (in thousands, except percentages).


										Percent												Percent
	Year			Year			Change			Change			Year			Year			Change			Change
	Ended			Ended			2007/			2007/			Ended			Ended			2009/			2009/
	12/31/07			12/31/06			2006			2006			12/31/09			12/31/08			2008			2008
	(In thousands)												(In thousands)

Revenue:
Completion and production services	$	1,242,314		$	860,508		$	381,806			44	%	$	897,584		$	1,541,709		$	(644,125	)		(42	)%
Drilling services		212,272			194,517			17,755			9	%		114,729			234,104			(119,375	)		(51	)%
Product sales		40,857			29,586			11,271			38	%		44,081			59,102			(15,021	)		(25	)%

Total	$	1,495,443		$	1,084,611		$	410,832			38	%	$	1,056,394		$	1,834,915		$	(778,521	)		(42	)%

EBITDA:
Adjusted EBITDA:
Completion and production services	$	398,628		$	252,621		$	146,007			58	%	$	165,787		$	467,100		$	(301,313	)		(65	)%
Drilling services		61,418			70,428			(9,010	)		(13	)%		9,641			58,743			(49,102	)		(84	)%
Product sales		9,943			8,536			1,407			16	%		7,966			12,677			(4,711	)		(37	)%
Corporate		(28,136	)		(20,922	)		(7,214	)		34	%		(34,313	)		(38,293	)		3,980			10	%

Total	$	441,853		$	310,663		$	131,190			42	%	$	149,081		$	500,227		$	(351,146	)		(70	)%

“Corporate” includes amounts related to corporate personnel costs, other general expenses and stock-based compensation charges.

“Adjusted EBITDA” consists of net income (loss) from continuing operations before net interest expense, taxes, depreciation and amortization, ~~minority~~non-controlling interest and impairment loss. Adjusted EBITDA is a ~~non-cash~~non-GAAP measure of performance. We use Adjusted EBITDA as the primary internal management measure for evaluating performance and allocating additional resources. ~~See the discussion of EBITDA at Note 3 under Item 6 (“Selected Financial Data”) of this Annual Report.~~ The following table reconciles Adjusted EBITDA for the years ended December 31, ~~2007~~2009 and ~~2006~~2008 to the most comparable U.S. GAAP measure, operating income (loss). The calculation of Adjusted EBITDA is different from the calculation of “EBITDA,” as defined and used in our credit facilities. For a discussion of the calculation of “EBITDA” as defined under our existing credit facilities, as

recently amended, see Note 11, “Long-term debt,” in our notes to consolidated financial statements included elsewhere in this Annual Report.

Reconciliation of Adjusted EBITDA to Most Comparable GAAP Measure — Operating Income (Loss)

Completion and
Drilling
Product

Production Services Services Sales Corporate Total

Year Ended December 31, 2007

EBITDA, as defined $ 398,628 $ 61,418 $ 9,943 $ (28,136 ) $ 441,853
Depreciation and amortization $ 112,836 $ 14,572 $ 2,064 $ 1,881 $ 131,353
Impairment loss $ 13,094 $ — $ — $ — $ 13,094

Operating income (loss) $ 272,698 $ 46,846 $ 7,879 $ (30,017 ) $ 297,406

Year Ended December 31, 2006

EBITDA, as defined $ 252,621 $ 70,428 $ 8,536 $ (20,922 ) $ 310,663
Depreciation and amortization $ 64,393 $ 9,069 $ 834 $ 1,606 $ 75,902
Write-off of deferred costs $ — $ — $ — $ (170 ) $ (170 )

Operating income (loss) $ 188,228 $ 61,359 $ 7,702 $ (22,358 ) $ 234,931

(In thousands)

Completion and
Drilling
Product

Production Services Services Sales Corporate Total

Year Ended December 31, 2009

Adjusted EBITDA, as defined $ 165,787 $ 9,641 $ 7,966 $ (34,313 ) $ 149,081
Depreciation and amortization $ 174,929 $ 21,067 $ 2,460 $ 2,276 $ 200,732
Write-off of deferred financing fees $ — $ — $ — $ (528 ) $ (528 )
Fixed asset and other intangible impairment losses $ 2,488 $ 36,158 $ — $ — $ 38,646
Goodwill impairment loss $ 97,643 $ — $ — $ — $ 97,643

Operating income (loss) $ (109,273 ) $ (47,584 ) $ 5,506 $ (36,061 ) $ (187,412 )

Year Ended December 31, 2008

Adjusted EBITDA, as defined $ 467,100 $ 58,743 $ 12,677 $ (38,293 ) $ 500,227
Depreciation and amortization $ 156,298 $ 19,961 $ 2,537 $ 2,401 $ 181,197
Goodwill impairment losses $ 243,203 $ 27,410 $ 1,393 $ — $ 272,006

Operating income (loss) $ 67,599 $ 11,372 $ 8,747 $ (40,694 ) $ 47,024

Below is a detailed discussion of our operating results by segment for these periods.

Year Ended December 31, ~~2007~~2009 Compared to the Year ended December 31, ~~2006~~2008

Revenue

Revenue from continuing operations for the year ended December 31, ~~2007 increased~~2009 decreased by ~~$410.8~~$778.5 million, or ~~38%~~42%, to ~~$1,495.4~~$1,056.4 million from ~~$1,084.6~~$1,834.9 million for the year ended December 31, ~~2006.~~2008. This ~~increase~~decrease by segment was as follows:

• Completion and Production Services.  Segment revenue ~~increased $381.8~~decreased $644.1 million, or ~~44%~~42%, primarily due ~~to: (1) higher activity levels~~to an overall decline in investment by our customers in oil and gas exploration and development activities resulting from lower oil and gas commodity prices and concerns over the ~~U.S.~~availability of capital for such investment. We experienced lower utilization and ~~Mexico; (2)~~pricing for each of our service offerings on ayear-over-year basis, except for our coiled tubing business in Mexico which provided a positive contribution to 2009 results. In the fourth quarter of 2009, we experienced an increase in revenues ~~earned as a result of additional capital investments in the coiled tubing, well servicing, pressure pumping, rental~~ and fluid-handling businesses in 2007, as well as the benefit of a full-year of operations for equipment placed into service throughout 2006; (3) investment in acquisitions during 2006, each of which provided incremental revenues for 2007margins compared to ~~2006; and (4) a series~~the third quarter of ~~acquisitions during the year ended December 31, 2007 which contributed to the overall 2007 results. These favorable results were partially offset by a decline in the general activity level~~2009 as market conditions showed signs of ~~the oil and gas industry in Canada throughout 2007. We began to experience some pricing pressures in certain service offerings during the latter half of 2007.~~improvement.

• Drilling Services.  Segment revenue ~~increased $17.8~~decreased $119.4 million, or 9%51%, for the year, primarily due to ~~additional capital invested~~the overall decline in ~~contract drilling and our drilling logistics businesses during 2006 and into 2007, somewhat offset by lower pricing and lower utilization of our equipment in 2007~~oilfield service activities throughout the year compared to ~~2006, due primarily~~2008. Lower utilization rates and pricing pressure impacted our rig logistics and drilling businesses, however revenues were up slightly in the fourth quarter of 2009 compared to anthe third quarter of 2009 as we experienced a slight increase in ~~new equipment placed into service by our competitors in the markets that we serve.~~customer activity.

• Product Sales.  Segment revenue ~~increased $11.3~~decreased $15.0 million, or ~~38%~~25%, for the year, ~~fueled~~ primarily ~~by increased~~due to a decline in our Southeast Asian business resulting from a change in the sales mix and the timing of product sales and equipment refurbishment, ~~attributable~~which tends to be project-specific. Partially offsetting this decrease were the consistent revenues earned at our fabrication business in ~~Southeast Asia.~~north Texasyear-over-year, which included a work-over rig project completed in the first quarter of 2009 and sales of low margin equipment to third-parties.

5152

Service and Product Expenses

Service and product expenses include labor costs associated with the execution and support of our services, materials used in the performance of those services and other costs directly related to the support and maintenance of equipment. These expenses ~~increased $245.2~~decreased $411.1 million, or ~~39%~~36%, to ~~$874.6~~$725.4 million for the year ended December 31, ~~2007~~2009 from ~~$629.3~~$1,136.5 million for the year ended December 31, ~~2006.~~2008. The decline in service and product expenses was primarily due to significantly lower activity levels and cost-saving measures we began implementing in late 2008, including headcount reductions, payroll concessions and reduced product and service costs from outside vendors. The following table summarizes service and product expenses as a percentage of revenues for the years ended December 31, ~~2007~~2009 and ~~2006:~~2008:

Service and Product Expenses as a Percentage of Revenue


	Years Ended									Years Ended
Segment:	12/31/07			12/31/06			Change			12/31/09			12/31/08			Change

Completion and Production services		58	%		59	%		(1	)%		68	%		61	%		7	%
Drilling services		61	%		54	%		7	%		75	%		67	%		8	%
Product sales		68	%		56	%		12	%		75	%		71	%		4	%
Total		58	%		58	%		—			69	%		62	%		7	%

Service and product expenses as a percentage of revenue ~~were consistent~~increased to 69% for the ~~years~~year ended December 31, ~~2007 and 2006. However, margins~~2009 compared to 62% for the year ended December 31, 2008. Margins by business segment were impacted primarily by ~~acquisitions,~~ pricing and utilization.


	•	Completion and Production Services. ~~The decline in service~~Service and product expenses as a percentage of revenue for this business segment ~~reflects: (1) a full-year’s benefit~~increased when comparing the year ended December 31, 2009 to the same period in 2007 of capital invested throughout 2006, with additional equipment placed into service during 2007 and (2) the benefit of a full-year of margin contribution from our pressure pumping business in 2007 compared to only two-months contribution in 2006 due to timing of the acquisition. We experienced favorable margins in 2007 compared to 2006 for our well service, coiled tubing, fluid handling and rental businesses. However, in late 2007, we began to experience lower pricing for certain of these services in some of our operating regions, as well as a general2008. The overall decline in activity levels in ~~Canada~~the oil and gas industry, which ~~impacted our operating margins, reducing our overall margin improvements to only 1%year-over-year.~~ ~~In addition, we experienced higher labor~~began in late 2008 and ~~fuel costs which partially offset~~continued throughout most of the ~~incremental margin contribution~~year in 2009, resulted in lower utilization of our ~~completion~~equipment and ~~production~~ services, ~~businesses during 2007 compared to 2006.~~and pricing pressure from competitors. Partially defraying the impact of this overall decline in activity levels were cost-saving measures we began implementing in late 2008.

	•	Drilling Services. The increase in service and product expenses as a percentage of revenue for this business segment ~~represented a decline in margin during 2007 compared~~was primarily due to ~~2006 due to: (1) lower pricing for our contract drilling and drilling logistics businesses, and (2)~~ lower utilization of our equipment ~~specifically impacting our drilling rigs business,~~ due to ~~downtime associated with maintenance,~~significantly reduced activity levels by our customers, and ~~more market competition, as our competitors deployed additional rigs into the markets we serve. In addition, we incurred costs associated with relocating~~lower pricing on a ~~portion of our rig logistics business to areas with more favorable market conditions.~~year-over-year basis, partially offset by cost-saving measures.

	•	Product Sales. The increase in service and product expenses as a percentage of revenue for the products segments was primarily due to the mix of products sold ~~and~~for the ~~timing of equipment sales and refurbishment~~relative periods, as the 2008 results included several higher margin projects associated with our Southeast Asian operations aswhen compared to the ~~results~~year ended December 31, 2009. Additionally, on ayear-over-year basis, a larger proportion of the revenues and related costs for the product sales segment for the year ended December 31, ~~2006~~2009 were ~~impacted~~provided by ~~several higher-margin projects which were completed prior~~our repair and fabrication facility in north Texas at lower margins relative to ~~2007.~~our Southeast Asian business, including the sale of a large inventory item.

Selling, General and Administrative Expenses

~~approximately $3.2 million related to stock-based compensation~~ the non-monetary asset exchange in ~~2007 compared to 2006; and (5) a charge of approximately $1.4 million associated with the cost-sharing provision of a general liability insurance policy. As~~Canada, as a percentage of revenues, selling, general and administrative expense ~~declined to 12%~~was 17% and 11% for the ~~year~~years ended December 31, ~~2007 compared to 13% for the year ended December 31, 2006.~~2009 and 2008, respectively.

Depreciation and Amortization

Depreciation and amortization expense increased ~~$55.5~~$19.5 million, or ~~73%~~11%, to ~~$131.4~~$200.7 million for the year ended December 31, ~~2007~~2009 from ~~$75.9~~$181.2 million for the year ended December 31, ~~2006.~~2008. The increase in depreciation and amortization expense was the result of the following: (1) depreciation of equipment placed into service ~~in 2007, a portion of which was~~throughout 2008, as well as additional equipment purchased in ~~2006 and throughout 2007. Capital expenditures for equipment in 2007 totaled $372.6 million. In addition, we recorded~~2009; (2) depreciation and amortization expense related to assets associated with businesses acquired in ~~2006 and 2007, as well as assets purchased and placed into service throughout 2006,~~2008, some of which ~~contributed a~~did not contribute depreciation expense for the full year ended December 31, 2008 due to the timing of ~~depreciation~~the acquisitions; and (3) an increase in amortization expense associated with intangible assets acquired in ~~2007 compared to a partial year of depreciation expense~~business combinations in ~~2006.~~2008. As a percentage of revenue, depreciation and amortization expense increased to 9%19% from 10% for the years ended December 31, 2009 and 2008, respectively. We expected depreciation and amortization expense as a percentage of revenue to remain higher than in recent periods due to the significant investment in capital expenditures made throughout the last three years and the overall decline in activity levels that began in late 2008.

Fixed Asset and Other Intangible Impairment Loss

For the year ended December 31, ~~2007 compared~~2009, we recorded a fixed asset and other intangible impairment loss of $38.6 million. We recorded a charge of $36.2 million related to 7%our contract drilling business in the third quarter of 2009 after determining that the carrying value of certain of these drilling rigs exceeded the undiscounted cash flows associated with these assets and the fair market value estimates for these assets. In the ~~year ended December 31, 2006.~~fourth quarter of 2009, we recorded an impairment of intangible assets of $2.5 million related to our completion and production business. We recorded no such impairment charges in 2008.

Goodwill Impairment Loss

We recorded ana goodwill impairment loss of ~~$13.1~~$97.6 million ~~related~~for the year ended December 31, 2009 compared to ~~the write-down~~$272.0 million recorded in 2008. These write-downs of goodwill in both 2008 and 2009 were associated with several of our ~~Canadian operations during 2007~~reporting units and were based upon several valuation techniques including a discounted cash flow analysis of expected future earnings associated with ~~this business.~~these businesses. Our analysis of future cash flows was impacted significantly by the overall decline in oilfield activity in late 2008 which continued throughout 2009.

Interest Expense

Interest expense was ~~$61.3~~$56.9 million and ~~$40.6~~$59.7 million for the years ended December 31, ~~2007~~2009 and ~~2006,~~2008, respectively. ~~The increase~~This 5% decrease in interest expense was attributable primarily to ~~an increase~~a decrease in the average amount of debt outstanding ~~including amounts borrowed~~during the year ended December 31, 2009 and lower interest rates in 2009 compared to ~~fund acquisitions, capital expenditures,~~2008 on our ~~semi-annual interest payments associated with the 8% senior notes and our quarterly tax payments. In addition, during December 2006, we issued our 8% senior notes and used the proceeds to retire all~~ outstanding borrowings under ~~the term loan portion~~revolving credit facilities, which were fully repaid as of ~~our credit facility. These senior notes required interest at higher fixed interest rates compared to the lower variable rates on the previously outstanding term loan facility.~~June 30, 2009. The weighted-average interest rate of borrowings outstanding at December 31, ~~2007~~2009 and ~~2006~~2008 was approximately ~~7.7%~~8.0% and ~~7.8%~~7.0%, respectively.

~~Interest Income~~

Interest income was $0.3 million and $1.4 million for the years ended December 31, 2007 and 2006. In 2007, interest income was earned primarily on excess cash invested in overnight securities throughout the year. For 2006, interest income was earned on the investment of proceeds from our initial public offering in a bond fund prior to use of the proceeds for acquisitions, capital investments in equipment and other general corporate purposes.

Taxes

Tax expense (benefit) is comprised of current income taxes and deferred income taxes. The current and deferred taxes added together provide an indication of an effective rate of income tax.

~~Tax~~We recorded a tax benefit of $63.1 million for the year ended December 31, 2009 at an effective rate of approximately 25.8% compared to a tax expense of $72.3 million for the year ended December 31, 2008. The lower effective tax rate in 2009 was ~~36.7% and 36.1%~~due to the impairment of ~~pretax income~~goodwill with limited tax basis. Our tax rate for the year ended December 31, 2008 was impacted significantly by a $272.0 million impairment of goodwill which had a limited tax basis, as the majority of the goodwill arose through stock purchase transactions with little or no tax basis. Excluding the impact of the goodwill impairment charges, our effective tax rates for the years ended December 31, ~~2007~~2009 and 2006, respectively. The effective tax rate for 2007 was impacted by the impairment loss of $13.1 million in Canada, which was not deductible for tax purposes. Excluding the impact of the impairment loss, the effective tax rate for 20072008 would have been ~~34.8%. The decline in the effective tax rate in 2007, as adjusted, compared to 2006, was due to lower state tax rates, lower income tax rates in Canada, return to actual adjustments in 2007~~33.9% and ~~the incremental benefit of the domestic production activities deduction.~~35.5%.

5354

~~Minority Interest~~

Minority interest was comprised entirely of an ownership interest by an unrelated third party in the assets of Premier Integrated Technologies, Inc. (“Premier”), a company that we acquired on January 1, 2005. We have consolidated Premier in our accounts since the date of acquisition and record minority interest to reflect the ownership held by this third party. On December 31, 2007, we acquired the remaining 50% interest in this company.

Liquidity and Capital Resources

~~The recent~~As of December 31, 2010, we had working capital, net of cash, of $276.8 million and ~~unprecedented disruption~~cash and cash equivalents of $126.7 million, compared to working capital, net of cash, of $200.8 million and cash and cash equivalents of $77.4 million at December 31, 2009. This increase in ~~the current credit markets has had a significant adverse impact on a number~~working capital was primarily due to an increase in accounts receivable, partially offset by an increase in accounts payable, associated with favorable operating results, and an increase in accrued expenses due to higher earnings-based incentive compensation accruals. We also received net tax refunds of financial institutions. At this point in time, our liquidity has not been materially impacted by the current credit environment. We are not currently a party to any interest rate swaps, currency hedges or derivative contracts of any type and have no exposure to commercial paper or auction rate securities markets. We will continue to closely monitor our liquidity and the overall health of the credit markets. However, we cannot predict with any certainty the impact that any further disruption in the credit environment would have on us.approximately $31.1 million during 2010.

Our primary liquidity needs are to fund capital expenditures and general working ~~capital needs.~~capital. In addition, we have historically obtained capital to fund strategic business acquisitions. Our primary sources of funds have ~~historically~~ been cash flow from operations, proceeds from borrowings under bank credit facilities and a private placement of debt ~~which~~that was subsequently exchanged for publicly registered ~~debt and the issuance of equity securities in our initial public offering.~~

On April 26, 2006, we sold 13,000,000 shares of our $.01 par value common stock in an initial public offering at an initial offering price to the public of $24.00 per share, which provided proceeds of approximately $292.5 million net of underwriters’ fees. We used these funds to retire principal and interest outstanding under our U.S. revolving credit facility on April 28, 2006 totaling approximately $127.5 million, to pay transaction costs of approximately $3.9 million and invested the remaining funds in tax-free and tax-advantaged municipal bonds and similar financial instruments. Of this amount, we utilized $141.6 million associated with acquisitions, including Arkoma, Turner and Pinnacle, and the remainder was used for other general corporate purposes. As of September 2006, all proceeds from our initial public offering had been utilized.debt.

We anticipate that ~~we will rely on~~our cash generated from operations and our current cash balance will be sufficient to fund the majority of our cash requirements for the next twelve months, however borrowings under our amended revolving credit facility, future debt offeringsand/or future public equity offerings may also be used to fund future acquisitions or to satisfy our other liquidity needs. We believe that funds from these sources ~~should~~will be sufficient to meet both our short-term working capital requirements and our long-term capital requirements. ~~We believe that our operating cash flows and availability under our amended revolving credit facility will be sufficient to fund our operations for the next twelve months.~~ If our plans or assumptions change, or are inaccurate, or if we make further acquisitions, we may have to raise additional capital. Our ability to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance, and more broadly, on the availability of equity and debt financing, which will be affected by prevailing economic conditions in our industry, and general financial, business and other factors, some of which are beyond our control. In addition, new debt obtained could include service requirements based on higher interest paid and shorter maturities and could impose a significant burden on our results of operations and financial condition. The issuance of additional equity securities could result in significant dilution to stockholders.

On October 13, 2009, we completed an amendment to our existing revolving credit facilities (the “Third Amendment”) which modified the structure of the credit facility to an asset-based facility subject to borrowing base restrictions. This amendment provided us with less restrictive financial debt covenants and reduced borrowing capacity under the facility.

The following table summarizes cash flows by type for the periods indicated (in thousands):


	Year Ended December 31,									Year Ended December 31,
	2008			2007			2006			2010			2009			2008

Cash flows provided by (used in):
Operating activities	$	350,448		$	338,503		$	187,743		$	216,158		$	285,204		$	350,409
Investing activities		(374,137	)		(408,795	)		(650,863	)		(174,088	)		(18,128	)		(374,098	)
Financing activities		27,990			66,643			471,376			6,817			(207,991	)		27,990

Net cash provided by operating activities ~~increased $11.9~~decreased $69.0 million for the year ended December 31, ~~2008~~2010 compared to the year ended December 31, ~~2007,~~2009, and ~~increased $150.8~~decreased $65.2 million for the year ended December 31, ~~2007~~2009 compared to the year ended December 31, ~~2006. These increases~~2008. The decrease in ~~net~~operating cash ~~provided by operating activities~~

~~were~~flows for the year ended December 31, 2010 compared to the year ended December 31, 2009 was primarily due to ~~increases~~an increase in ~~gross~~trade receivables resulting from a favorable increase in oilfield activity partially offset by an increase in payables and the collection of a large income tax receivable. During 2010, cash receipts ~~as a result of increased revenues. Our gross receipts increased throughout the three years ended December 31, 2008 as demand for our services grew, we invested~~activity remained favorable, but with an increase in more equipment and logged incremental billable hours, while we continued to expand our current business and enter new markets through acquisitions. We expect to continue to evaluate acquisition opportunities for the foreseeable future. This analysis will entail a review of available funds which will include our currentsales there was an increase in outstanding receivables. The decrease in operating cash flows ~~as well as other factors.~~for 2009 compared to 2008 reflects the overall decline in oilfield activity in late 2008 and throughout 2009.

Net cash used in investing activities ~~decreased $34.7~~increased $156.0 million for the year ended December 31, ~~2008~~2010 compared to the ~~prior~~ year ended December 31, 2009 and decreased ~~$242.1~~$356.0 million for the year ended December 31, ~~2007~~2009 compared to the year ended December 31, ~~2006, primarily~~2008. Of this increase in 2010, $145.0 million was due to ~~declines~~an increase in capital expenditures, which was only $37.4 million for the ~~use of funds for acquisitions.~~year ended December 31, 2009. We decreased our overall capital expenditures in 2009 in response to the decline in commodity prices and lower activity levels. In addition, we invested ~~$180.2 million, $50.4 million and $369.6~~$33.7 million in business acquisitions ~~for the years ended December 31,~~in 2010, with no corresponding business acquisitions in 2009. The

decrease in 2009 compared to 2008 2007 and 2006, respectively. During 2008, these acquisitions were relatively large operations in recently active basins such as the Marcellus Shale and Haynesville Shale, as well as a targeted acquisition of a pressure pumping business in north Texas. For 2007, our acquired businesses were generally smaller, niche companies which complemented our existing operations. For 2006, we used a portion of the proceeds from our initial public offering to purchase businesses that expanded our geographic reach in areas where we have operations and into new basins within North America. In addition, we invested heavily in new equipment throughout this three-year period, but to a lesser extent during 2008was due to ~~concerns~~investment in capital expenditures of ~~over-capacity in the industry and a general slowdown in oilfield activity in late 2008. We sold non-strategic businesses in 2008 and 2006 and received proceeds of $50.2~~$253.8 million and ~~$19.3 million, respectively. In addition, in 2006 we invested $165.0~~acquisitions of $180.2 million in short-term investments, which were sold and used for the following purposes: (1) to acquire a series of businesses; (2) to make scheduled principal and interest payments on our credit facility; (3) to pay estimated federal income taxes; and (4) for other general corporate purposes. Significant capital equipment expenditures in 2008 included pressure pumping equipment, well service rigs, coiled tubing equipment and two drilling rigs. Significant capital equipment expenditures in 2007 included five coiled tubing units and over forty well service rigs, as well as additional pressure pumping units. Significant capital equipment expenditures in 2006 included coiled tubing units, pressure pumping equipment, well services rigs, fluid-handling equipment, rental equipment and drilling rigs. See “— Significant Acquisitions” above.2008.

Net cash provided by financing activities ~~decreased by $38.7~~was $6.8 million for the year ended December 31, ~~2008~~2010 compared to $208.0 million of cash used for financing activities for the ~~prior~~ year ended December 31, 2009, and ~~declined $404.7~~compared to cash provided by financing activities of $28.0 million for the year ended December 31, ~~2007 compared to 2006.~~2008. In 2009, we focused on eliminating obligations under our credit facility and building cash. We repaid long-term borrowings under our debt facilities totaling $200.6 million and only borrowed $3.2 million during 2009. The primary source of these funds in 2009 was cash flow from financing activities for 2008 was net borrowings under our revolving credit facilities of $20.8 million, as well as funds obtained from the issuance of our common stock in connection with employee stock option exercises. The primary source of funds from financing activities in 2007 was net borrowings under our revolving credit facilities to fund capital expenditures, acquisitions, semi-annual interest payments on our senior notes and quarterly federal income tax payments. However, in 2006, the primary source of funds from financing activities was the receipt of the net proceeds from our initial public offering in April 2006, which provided approximately $288.6 million. In addition, we received net proceeds of $636.6 million from the issuance of 8.0% senior notes in December 2006, and we borrowed under our revolving credit facilities to fund various business acquisitions. The primary use of funds from financing activities was to repay $127.5 million outstanding under our U.S. revolving credit facility as of April 2006, with subsequent borrowings and repayments under this revolving credit facility throughout the year ended December 31, 2006, and the repayment of $419.0 million under our term loan facility in 2006, the majority of which was repaid in December 2006 from the proceeds of our senior note issuance.operations. Our long-term debt balances, including current maturities, were ~~$847.6 million~~$650.0 and ~~$826.4~~$650.2 million as of December 31, ~~2008~~2010 and ~~2007,~~2009, respectively.

~~We expect to spend~~In 2010, we invested significantly ~~less~~more on capital expenditures and acquisitions than we ~~have in recent years for investment in capital expenditures, excluding~~did during 2009. We will continue to evaluate acquisitions ~~during the year ended December 31, 2009.~~of complementary companies. We believe that our operating cash flows and borrowing capacity will be sufficient to fund our operations and capital expenditures for the next 12 months.

In addition, we do not anticipate completing acquisitions for cash consideration until market conditions stabilize, but will continue to evaluate acquisitions of complementary companies. We will evaluate each acquisition opportunity based upon the circumstances and our financing capabilities at that time.

Dividends

We did not pay dividends on our $0.01 par value common stock during the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006.~~2008. We do not intend to pay dividends in the foreseeable future, but rather plan to reinvest such funds in our business. Furthermore, our credit facility contains restrictive debt covenants which preclude us from paying future dividends on our common stock.

Description of Our Indebtedness

Senior ~~Notes~~Notes.

On December 6, 2006, we issued 8.0% senior notes with a face value of $650.0 million through a private placement of debt. These notes ~~have a maturity of~~mature in 10 years, ~~with a maturity date of~~on December 15, 2016, and require semi-annual interest payments, paid in arrears and calculated based on an annual rate of 8.0%, on June 15 and December 15, of each year, ~~commencing~~which commenced on June 15, 2007. There was no discount or premium associated with the issuance of these notes. The senior notes are guaranteed ~~on a senior unsecured basis,~~ by all of our current domestic subsidiaries. The senior notes have covenants which, among other things: (1) limit the amount of additional indebtedness we can incur; (2) limit restricted payments such as a dividend; (3) limit our ability to incur liens or encumbrances; (4) limit our ability to purchase, transfer or dispose of significant assets; (5) limit our ability to purchase or redeem stock or subordinated debt; (6) limit our ability to enter into transactions with affiliates; (7) limit our ability to merge with or into other companies or transfer all or substantially all of our assets; and (8) limit our ability to enter into sale and leaseback transactions. We have the option to redeem all or part of these notes on or after December 15, 2011. ~~We can redeem 35% of these notes on or before December 15, 2009 using the proceeds of certain equity offerings.~~ Additionally, we may redeem some or all of the notes prior to December 15, 2011 at a price equal to 100% of the principal amount of the notes plus a make-whole premium. We paid semi-annual interest payments of $26.0 million on June 15 and December 15, 2008 related to these notes, and $27.3 million and $26.0 million on June 15, 2007 and December 15, 2007, respectively.

Pursuant to a registration rights agreement with the holders of our 8.0% senior notes, on June 1, 2007, we filed a registration statement onForm S-4 with the ~~Securities and Exchange Commission~~SEC which enabled these holders to exchange their notes for publicly registered notes with substantially identical terms. These holders exchanged 100% of the notes for publicly traded notes on July 25, 2007.

On August 28, 2007, we entered into a supplement to the indenture governing the 8.0% senior notes, whereby additional domestic subsidiaries became guarantors under the indenture. Effective April 1, 2009, we entered into a second supplement to this indenture whereby additional domestic subsidiaries became guarantors under the indenture.

Credit ~~Facility~~Facility.

~~On December 6, 2006, we amended and restated our existing~~We maintain a senior secured ~~credit~~ facility (the “Credit Agreement”) with Wells Fargo Bank, National Association, as U.S. Administrative Agent, HSBC Bank Canada, as Canadian Administrative Agent, and certain other financial institutions. ~~The~~On October 13, 2009, we entered into the Third Amendment (the Credit Agreement ~~initially provided~~after giving effect to the Third Amendment, the “Amended Credit Agreement”) and modified the structure of our existing credit facility to an asset-based facility subject to borrowing base restrictions. In connection with the Third Amendment, Wells Fargo Capital Finance, LLC (formerly known as Wells Fargo Foothill, LLC) replaced Wells Fargo Bank,

National Association, as U.S. Administrative Agent and also serves as U.S. Issuing Lender and U.S. Swingline Lender under the Amended Credit Agreement. The Amended Credit Agreement provides for a ~~$310.0 million~~ U.S. revolving credit facility of up to $225 million that ~~will mature~~matures in December 2011 and a ~~$40.0 million~~ Canadian revolving credit facility of up to $15 million (with Integrated Production Services Ltd., one of our wholly-owned subsidiaries, as the borrower ~~thereof)~~thereof (“Canadian Borrower”)) that ~~will mature~~matures in December 2011. ~~In addition, certain~~The Amended Credit Agreement includes a provision for a “commitment increase”, as defined therein, which permits us to effect up to two separate increases in the aggregate commitments under the Amended Credit Agreement by designating one or more existing lenders or other banks or financial institutions, subject to the bank’s sole discretion as to participation, to provide additional aggregate financing up to $75 million, with each committed increase equal to at least $25 million in the U.S., or $5 million in Canada, and in accordance with other provisions as stipulated in the Amended Credit Agreement. Certain portions of the credit facilities are available to be borrowed in U.S. ~~Dollars,~~dollars, Canadian ~~Dollars, Pounds Sterling, Euros~~dollars and other currencies approved by the lenders.

Our U.S. borrowing base is limited to: (1) 85% of U.S. eligible billed accounts receivable, less dilution, if any, plus (2) the lesser of 55% of the amount of U.S. eligible unbilled accounts receivable or $10.0 million, plus (3) the lesser of the “equipment reserve amount” and 80% times the most recently determined “net liquidation percentage”, as defined in the Amended Credit Agreement, times the value of our and the U.S. subsidiary guarantors’ equipment, provided that at no time shall the amount determined under this clause exceed 50% of the U.S. borrowing base, minus (4) the aggregate sum of reserves established by the U.S. Administrative Agent, if any. The “equipment reserve amount” means $50.0 million upon the effective date of the Third Amendment, less $0.6 million for each subsequent month, not to be reduced below zero in the aggregate.

The Canadian borrowing based is limited to: (1) 80% of Canadian eligible billed accounts receivable, plus (2) if the Canadian Borrower has requested credit for equipment under the Canadian borrowing base, the lesser of (a) $15.0 million, and (b) 80%timesthe most recently determined “net liquidation percentage”, as defined in the Amended Credit Agreement, times the value (calculated on a basis consistent with our historical accounting practices) of our and the US subsidiary guarantors’ equipment, minus (3) the aggregate amount of reserves established by our Canadian Administrative Agent, if any.

Subject to certain limitations set forth in the Amended Credit Agreement, we have the ability to elect how interest under the Amended Credit Agreement will be computed. Interest under the Amended Credit Agreement may be determined by reference to (1) the London Inter-bank Offered Rate, or LIBOR, plus an applicable margin between ~~0.75%~~3.75% and ~~1.75%~~4.25% per annum (with the applicable margin depending upon our ~~ratio of total debt to EBITDA (as~~“excess availability amount”, as defined in the ~~agreement)),~~Amended Credit Agreement) or (2) the ~~Base Rate (i.e.,~~“Base Rate” (which means the higher of the ~~Canadian bank’s prime rate or~~Prime Rate, Federal Funds Rate plus 0.50%,3-month LIBOR plus 1.00% and 3.50%), plus the ~~CDOR rate plus 1.0%, in~~applicable margin, as described above. For the ~~case of Canadian loans or~~period from the ~~greater~~effective date of the ~~prime rate and~~Third Amendment until the ~~federal funds rate plus 0.5%, in~~six month anniversary of the ~~case~~effective date of ~~U.S. loans), plus~~the Third Amendment, interest was computed with an applicable margin ~~between 0.00% and 0.75% per annum.~~rate of 4.00%. If an event of default exists or continues under the Amended Credit Agreement, advances will bear interest as described above with an applicable margin rate of 4.25% plus 2.00%. Additionally, if an event of default exists under the Amended Credit Agreement, ~~advances will bear interest at~~as defined therein, the ~~then-applicable rate plus 2%.~~lenders could accelerate the maturity of the obligations outstanding thereunder and exercise other rights and remedies. Interest is payable quarterly for base rate loans and at the end of applicable interest periods for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest will be paid at the end of each three-month period.

The Credit Agreement also contains various covenants that limit our and our subsidiaries’ ability to: (1) grant certain liens; (2) make certain loans and investments; (3) make capital expenditures; (4) make distributions; (5) make acquisitions; (6) enter into hedging transactions; (7) merge or consolidate; or (8) engage in certain asset dispositions. Additionally, the Credit Agreement limits our and our subsidiaries’ ability to incur additional indebtedness if: (1) we are not in pro forma compliance with all terms under the Credit Agreement, (2) certain covenants of the additional indebtedness are more onerous than the covenants set forth in the Credit Agreement, or (3) the additional indebtedness provides for amortization, mandatory prepayment or repurchases of senior unsecured or subordinated debt during the duration of the Credit Agreement with certain exceptions. The Credit Agreement also limits additional secured debt to 10% of our consolidated net worth (i.e., the excess of our assets over the sum of our liabilities plus the minority interests). The Credit Agreement contains covenants which, among other things, require us and our subsidiaries, on a consolidated basis, to maintain specified ratios or conditions as follows (with such ratios tested at the end of each fiscal quarter): (1) total debt to EBITDA, as defined in the Credit Agreement, of not more than 3.0 to 1.0 and (2) EBITDA, as defined, to total interest expense of not less than 3.0 to 1.0. We were in compliance with all debt covenants under the amended and restated Credit Agreement as of December 31, 2008. However, there can be no assurance as to our future compliance in light of the very uncertain industry conditions. See “Risk Factors — Risks Related to Our Business and Our Industry” and “Risk Factors — Risk Related to Our Indebtedness, including Our Senior Notes.”monthly.

Under the Amended Credit Agreement, we are permitted to prepay our ~~borrowings.~~borrowings and we have the right to terminate, in whole or in part, the unused portion of the U.S. commitments in $1.0 million increments upon written notice to the U.S. Administrative Agent. If all of the U.S. facility is terminated, the Canadian facility must also be terminated.

All of the obligations under the U.S. portion of the Amended Credit Agreement are secured by first priority liens on substantially all of our assets and the assets of our U.S. subsidiaries as well as a pledge of approximately 66% of the stock of our first-tier foreign subsidiaries. Additionally, all of the obligations under the U.S. portion of the Amended Credit Agreement are guaranteed by substantially all of our U.S. subsidiaries. ~~All of the~~The obligations under the Canadian ~~portions~~portion of the Amended Credit Agreement are secured by first priority liens on substantially all of our assets and the assets of our ~~subsidiaries.~~subsidiaries (other than our Mexican subsidiary). Additionally, all of the obligations under the Canadian ~~portions~~portion of the Amended Credit Agreement are guaranteed by us as well as certain of our subsidiaries.

The Amended Credit Agreement also contains various covenants that limit our and our subsidiaries’ ability to: (1) grant certain liens; (2) incur additional indebtedness; (3) make certain loans and investments; (4) make capital expenditures; (5) make distributions; (6) make acquisitions; (7) enter into hedging transactions; (8) merge or consolidate; or (9) engage in certain asset dispositions. The Amended Credit Agreement contains one financial maintenance covenant which requires us and our subsidiaries, on a consolidated basis, to maintain a “fixed charge coverage ratio”, as defined in the Amended Credit Agreement, of not less than 1.10 to 1.00. This covenant is only tested if our “excess availability amount”, as defined under the Amended Credit Agreement, plus certain qualified cash and cash equivalents (collectively “Liquidity”) is less than $50.0 million for a period of 5 consecutive days and continues only until such time as our Liquidity has been greater than or equal to $50.0 million for a period of 90 consecutive days or greater than or equal to $75.0 million for a period of 45 consecutive days.

~~If an event~~Our fixed charge coverage ratio covenant is calculated, for fiscal quarters ending after September 30, 2009, as the ratio of ~~default exists under~~“EBITDA” calculated for the four fiscal quarter period ended after September 30, 2009 minus capital expenditures made with cash (to the extent not already incurred in a prior period) or incurred during such four quarter period, compared to “fixed charges”, calculated for the four quarters then ended. “EBITDA” is defined in the Amended Credit Agreement as ~~defined,~~consolidated net income for the ~~lenders may accelerate~~period plus, to the ~~maturity~~extent deducted in determining our consolidated net income, interest expense, taxes, depreciation, amortization and other non-cash charges for such period, provided that EBITDA shall be subject to pro forma adjustments for acquisitions and non-ordinary course asset sales assuming that such transactions occurred on the first day of the ~~obligations outstanding under~~determination period, which adjustments shall be made in accordance with the Credit Agreement and exercise other rights and remedies. While an event of default is continuing, advances will bear interest at the then-applicable rate plus 2%. For a description of an event of default, see our Credit Agreement which was filed withguidelines for pro forma presentations set forth by the Securities and Exchange ~~Commission on December 8, 2006 as an exhibit to a Current Report onForm 8-K.~~

~~On June 29, 2007, we amended our Credit Agreement in conjunction with the restructuring of certain legal entities for tax purposes with no material changes to the financial provisions or covenants.~~

Effective October 19, 2007, we amended certain terms of our Credit Agreement including: (1) a provision to increase the borrowing capacity of the U.S. revolving portion of the facility from $310.0 million to $360.0 million; and (2) a provision to include a “commitment increase” clause,Commission. “Fixed charges”, as defined in ~~our~~the Amended Credit Agreement, ~~which permits us~~include interest expense, among other things, reduced by the amortization of transaction fees associated with the Third Amendment.

We were not subject to ~~effect up to two separate increases~~the fixed charge coverage ratio covenant in the ~~aggregate commitments under~~Amended Credit Agreement as of December 31, 2010 since the facility by designating a participating lender to increase its commitment, by mutual agreement, in increments of at least $50.0 million with the aggregate of such commitment increases not to exceed $100.0 million and in accordance with other provisionsExcess Availability Amount plus Qualified Cash Amount (each as ~~stipulated~~defined in the ~~amendment. In addition, the amendment specifies the terms for prepayment of outstanding advances and new borrowings and replaces Schedule II~~Amended Credit Agreement) exceeded $50 million. If we were subject to the ~~amended Credit Agreement which allocates the commitments amongst the member financial institutions.~~fixed charge coverage ratio covenant, we would have been in compliance as of December 31, 2010.

~~Borrowings of $186.0 million and $7.5 million~~There were no revolving borrowings outstanding under ~~the~~our U.S. ~~and~~or Canadian revolving credit facilities atas of December 31, ~~2008, respectively.~~2010. The U.S. revolving credit facility bore interest at 3.50% at December 31, 2008, and the Canadian revolving credit facility bore interest at rates ranging from 3.75% to 4.00%, or a weighted average of 3.8% at December 31, 2008. For the year ended December 31, 2008, the weighted average interest rate ~~on borrowings under~~for our revolving credit facilities during the ~~amended Credit Agreement~~twelve months ended December 31, 2010 was ~~approximately 3.92%~~8.0%. ~~In addition, there~~There were letters of credit outstanding ~~which totaled $37.7 million~~ under the U.S. revolving portion of the facility ~~that~~totaling $26.4 million, which reduced the available borrowing capacity as of December 31, 2010. We incurred fees related to our letters of credit as of December 31, 2010 at 3.75% per annum. For the twelve months ended December 31, 2010, fees related to our letters of credit were calculated using a360-day provision, at 4.0% per annum. The net excess availability under our borrowing base calculations for the U.S. and Canadian revolving facilities at December 31, ~~2008 to $136.3 million. The available borrowing capacity under the Canadian revolving portion of the facility~~2010 was ~~$32.5~~$187.4 million ~~at December 31, 2008. In addition, we incurred fees of 1.25% of the total amount outstanding under our letter of credit arrangements. During October~~

~~2008, we borrowed approximately $106.0~~and $8.4 million, ~~under our U.S. revolving credit facility to purchase two businesses. As of February 13, 2009, we had $126.8 million outstanding under our Credit Agreement.~~

In accordance with the subordinated notes issued in conjunction with the acquisition of Parchman in February 2005, all principal and interest under these note arrangements totaling $5.0 million was repaid as of May 2, 2006.respectively.

~~Other Arrangements~~

We received $7.4 million from customers in 2005 as advance payments on the construction and operation of two drilling rigs for our contract drilling operations in north Texas. The drilling rigs were completed and placed into service in October 2005 and January 2006. Revenue was recognized over the agreed service contract. All revenue under these contracts was recognized prior to December 31, 2006.

Outstanding Debt and Operating Lease Commitments

The following table summarizes our known contractual obligations as of December 31, ~~2008~~2010 (in thousands):


	Payments Due by Period										Payments Due by Period
Contractual Obligations	Total		2009		2010-2011		2012-2013		Thereafter		Total		2011		2012-2013		2014-2015		Thereafter

Long-term debt, including capital (finance) lease obligations	$	843,931	$	164	$	193,767	$	—	$	650,000	$	650,000	$	—	$	—	$	—	$	650,000
Interest on 8% senior notes issued December 6, 2006		411,667		52,000		104,000		104,000		151,667		307,667		52,000		104,000		104,000		47,667
Purchase obligations(1)		41,196		41,196		—		—		—		45,376		45,376		—		—		—
Operating lease obligations		70,513		20,849		26,766		14,732		8,166		92,945		27,287		39,162		15,441		11,055
Other long-term obligations(2)		3,714		3,639		75		—		—

Total contractual obligations	$	1,371,021	$	117,848	$	324,608	$	118,732	$	809,833	$	1,095,988	$	124,663	$	143,162	$	119,441	$	708,722


(1)		Purchase obligations were pursuant to non-cancelable equipment purchase orders outstanding as of December 31, ~~2008.~~2010. 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 and loans relating to equipment purchases which mature at various dates through September 2010.

We have entered into agreements to purchase certain equipment for use in our business, which are included as purchase obligations in the table above to the extent that these obligations represent firm non-cancelable commitments. The manufacture of this equipment requires lead-time and we generally are committed to accept this equipment at the time of delivery, unless arrangements have been made to cancel delivery in accordance with the purchase agreement terms. We spent ~~$253.8~~$169.9 million for equipment purchases and other capital expenditures during the year ended December 31, ~~2008, which does not include amounts paid in connection with acquisitions.~~2010.

We expect to continue to acquire complementary companies and evaluate potential acquisition targets. We may use cash from operations, proceeds from future debt or equity offerings and borrowings under our amended revolving credit facility for this purpose.

Off-Balance Sheet Arrangements

We have entered into operating lease arrangements for our light vehicle fleet, certain of our specialized equipment and for our office and field operating locations in the normal course of business. The terms of the facility leases range from monthly to five years. The terms of the light vehicle leases range from three to four years. The terms of the specialized equipment leases range from two to six years. Annual payments pursuant to these leases are included above in the table under “— Outstanding Debt and Operating Lease Commitments.”

Recent Accounting Pronouncements and Authoritative Literature

~~In February 2007,~~The FASB has addressed the ~~FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment~~issue of FASB Statement No. 115.” This pronouncement permits entities to use the fair value method to measure certain financial assets and liabilities by electing an irrevocable option to use the fair value method at specified election dates. After election of the option, subsequent changes in fair value would result in the recognition of unrealized gains or losses as period costsbusiness combinations during the period the change occurred. SFAS No. 159 became effective on January 1, 2008. We have not elected to adopt the fair value option prescribed by SFAS No. 159 for assets and liabilities held as of December 31, 2008, but we will consider the provisions of SFAS No. 159 and may elect to apply the fair value option for assets or liabilities associated with future transactions.

recent years. In December 2007, the FASB issued ~~SFAS No. 160, “Non-controlling Interests in Consolidating Financial Statements — an Amendment of ARB No. 51.” This pronouncement establishes accounting~~guidance regarding business combinations that substantially replaced previously existing guidance, while maintaining the precepts prescribed therein, and reporting standards for non-controlling interests, commonly referred to as minority interests. Specifically, this statement requires that the non-controlling interest be presented as a component of equity on the balance sheet, and that net income be presented prior to adjustment for the non-controlling interests’ portion of earnings with the portion of net income attributable to the parent company and the non-controlling interest both presented on the face of the statement of operations. In addition, this pronouncement provides a single method of accounting for changes in the parent’s ownership interest in the non-controlling entity, and requires the parent to recognize a gain or loss in net income when a subsidiary with a non-controlling interest is deconsolidated. Additional disclosure items are required related to the non-controlling interest. This pronouncement becomes effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. The statement should be applied prospectively as of the beginning of the fiscal year that the statement is adopted. However, the disclosure requirements must be applied retrospectively for all periods presented. We are currently evaluating the impact that SFAS No. 160 may have on our financial position, results of operations and cash flows.

In December 2007, the FASB revised SFAS No. 141, “Business Combinations” which will replace that pronouncement in its entirety. While the revised statement will retain the fundamental requirements of SFAS No. 141, it will also requirefurther requiring that all assets and liabilities and non-controlling interests of an acquired business be measured at their fair value, with limited exceptions, including the recognition of acquisition-related costs and anticipated restructuring costs separate from the acquired net assets. In addition, ~~the statement provides guidance for recognizing~~entities must recognize pre-acquisition contingencies, ~~and states that an acquirer must recognize~~as well as assets and liabilities assumed arising from contractual contingencies as of the acquisition date, measured at acquisition-date fair values, ~~but~~and must recognize all other contractual contingencies as of the acquisition date, measured at their acquisition-date fair values only if it is more likely than not that these contingencies meet the definition of an asset or ~~liability in FASB Concepts Statement No. 6, “Elements of Financial Statements.” Furthermore,~~liability. In addition, this ~~statement~~standard provides guidance for measuring goodwill and recording a bargain purchase, defined as a business combination in which total acquisition-date fair value of the identifiable net assets acquired exceeds the fair value of the consideration transferred plus any non-controlling interest in the acquiree, and ~~it requires~~states that the ~~acquirer~~acquiring entity must recognize that excess in earnings as a gain attributable to the acquirer. The FASB amended this guidance in April 2009 as it relates to accounting for assets and liabilities assumed in a business combination which arise from contingencies. This ~~statement becomes~~amendment requires that contingent assets acquired and liabilities assumed in a business combination to be recognized at fair value on the acquisition date if fair value can be reasonably estimated during the measurement period. If fair value cannot be reasonably estimated during the measurement period, the contingent asset or liability would be recognized as a contingency, in accordance with existing U.S. GAAP, with reasonable estimation of the amount of loss, if any. This amendment also eliminated the specific subsequent accounting guidance for contingent assets and liabilities, without significantly revising the original guidance. However, contingent consideration arrangements of an acquiree assumed by the acquirer in a business combination would still be initially and subsequently measured at fair value. We originally adopted the revised guidance for business combinations when it became effective aton January 1, 2009, and the amendment thereto, subsequently in 2009. In December 2010, the FASB updated this guidance to require each public entity that presents comparative financial statements to disclose the revenue and earnings of the combined entity as if the business combination that occurred during the current year had occurred as of the beginning of the ~~first~~comparable prior annual reporting period ~~beginning~~only. In addition, this amendment expands the supplemental pro forma disclosures related to such a business combination to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. This most recent amendment should be accounted for prospectively for business combinations for which the acquisition date is on or after January 1, 2011, for calendar-year reporting entities. Early adoption is permitted. Although we did not early adopt this standard, we do not expect this guidance to have a material impact on our financial position, results of

operations or cash flows. We will comply with this update for business combinations that have a material impact on our financial results.

In May 2009, the FASB issued a standard regarding subsequent events that provides guidance as to when an entity should recognize events or transactions occurring after a balance sheet date in its financial statements and the necessary disclosures related to these events. Specifically, the entity should recognize subsequent events that provide evidence about conditions that existed at the balance sheet date, including significant estimates used to prepare financial statements. Originally, this standard required entities to disclose the date through which subsequent events had been evaluated and whether that date was the date the financial statements were issued or the date the financial statements were available to be issued. We adopted this accounting standard effective June 30, 2009 and applied its provisions prospectively. In February 2010, the FASB modified this standard to eliminate the requirement for publicly-traded entities to disclose the date through which subsequent events have been evaluated.

In January 2010, the FASB issued “Fair Value Measurements and Disclosure (Topic 820)” which clarified the disclosure requirements of existing U.S. GAAP related to fair value measurements. This standard requires additional disclosures about recurring and non-recurring fair value measurements as follows: (1) for transfers in and out of Level 1 and Level 2 fair value measurements, as those terms are currently defined in existing authoritative literature, a reporting entity is required to disclose the amount of the movement between levels and an explanation for the movement; (2) for activity at Level 3, primarily fair value measurements based on unobservable inputs, a reporting entity is required to present separately information about purchases, sales, issuances and settlements, as opposed to presenting such transactions on a net basis; (3) in the event of a disaggregation, a reporting entity is required to provide fair value measurement disclosure for each class of assets and liabilities; and (4) a reporting entity is required to provide disclosures about the valuation techniques and inputs used to measure fair value for both recurring and non-recurring fair value measurements for items that fall in either Level 2 or Level 3. These disclosure requirements are effective for interim and annual reporting periods beginning after December 15, ~~2008,~~2009, except for disclosures about purchases, sales, issuances and ~~must be applied prospectively.~~settlements in the roll forward of activity in Level 3 fair value measurements for which disclosure becomes effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years.

On March 30, 2010, the President of the United States signed the Health Care and Education Reconciliation Act of 2010, which is a reconciliation bill that amends the Patient Protection and Affordable Care Act that was signed by the President on March 23, 2010. Certain provisions of this law became effective during 2010. We have reviewed our health insurance plan provisions with third-party consultants and continue to evaluate our position relative to the changes in the law. We do not believe that the provisions which have taken effect will have a significant impact on the operation of our existing health insurance plan. However, future provisions under the law which become effective in subsequent periods may impact our health insurance plan and our overall financial position. We are ~~currently~~ evaluating these provisions as they become effective and continue to seek guidance from the ~~impact~~FASB and SEC related to the implications of this new legislation on accounting and disclosure requirements. We expect that this ~~statement may~~legislation will have an impact on our financial position, results of operations and cash ~~flows.~~flows, but we cannot determine the extent of the impact at this time.

In ~~June 2008,~~December 2010, the FASB issued additional guidance related to accounting for intangible assets and goodwill. The amendments in this update modify Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a ~~FASB Staff Position (“FSP”)No. EITF 03-6-1,~~ ~~“Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” which states~~goodwill impairment exists. In determining whether it is more likely than not that ~~unvested share-based awards which have non-forfeitable rights to participate in dividend distributions~~a goodwill impairment exists, an entity should ~~be considered participating securities in order to calculate earnings per share in accordance~~consider whether there are any adverse qualitative factors indicating that an impairment may exist. The qualitative factors are consistent with the ~~“Two - Class Method” described in SFAS No. 128, “Earnings per Share.”~~existing guidance and examples, which require that goodwill of a reporting unit be tested for impairment between annual test dates if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. This ~~guidance becomes~~update is effective for public entities with fiscal years beginning after December 15, ~~2008, with retrospective application to prior periods.~~2010 and interim periods within those years. Early adoption is not permitted. ~~We are currently evaluating the impact that this guidance may have on our financial position, results of operations and cash flows.~~

~~In September 2008, the FASB issued an FSPNo. FAS 144-d,~~ “Amending the Criteria for Reporting a Discontinued Operation,” which clarifies the definition of a discontinued operation as either: (1) a component of an entity which has been disposed of or classified as held for sale which meets the criteria of an operating segment as

defined under SFAS No. 131, or (2) as a business, as such term is defined in SFAS No. 141R which becomes effective on January 1, 2009, which meets the criteria to be classified as held for sale on acquisition. This proposed guidance further modifies certain disclosure requirements. We are currently evaluating the effect this proposed guidance may have on our financial position, results of operations and cash flows.

~~In January 2009, the FASB issued FSP No.FAS 107-b~~ ~~and APB28-a,~~ which would amend SFAS No. 107, “Disclosures About Fair Value of Financial Instruments” and APB Opinion No. 28, “Interim Financial Reporting,” to require disclosure of the fair value of financial instruments in interim financial statements as well as annual financial statements. In addition, entities would be required to disclose the method and significant assumptions used to estimate the fair value of financial instruments. If ratified, this proposed guidance would become effective for interim and annual periods ending after March 15, 2009. We are currently evaluating the effect this proposed guidance may have on our financial position, results of operations and cash flows.


Item 7A.	*Quantitative and Qualitative Disclosures About Market Risk.*

The demand, pricing and terms for oil and gas services provided by us are largely dependent upon the level of activity for the U.S. and Canadian gas industry. Industry conditions are influenced by numerous factors over which we have no control, including, but not limited to: 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; domestic and worldwide economic conditions; political instability in oil-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.

The level of activity in the U.S. and Canadian oil and gas exploration and production industry is volatile. No assurance can be given that our expectations of trends in oil and gas production activities will reflect actual future activity levels or that demand for our services will be consistent with the general activity level of the industry. Any prolonged substantial reduction in oil and gas prices would likely affect oil and gas exploration and development efforts and therefore affect demand for our services. A material decline in oil and gas prices or U.S. and Canadian activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flows.

For the years ended December 31, ~~2008~~2010 and ~~2007,~~2009, approximately ~~5% and~~ 5% of our revenues from continuing operations ~~respectively,~~ and ~~3% and 6%~~4% of our total assets ~~respectively,~~ were denominated in Canadian dollars, our functional currency in Canada. As a result, a material decrease in the value of the Canadian dollar relative to the U.S. dollar may negatively impact our revenues, cash flows and net income. Each one percentage point change in the value of the Canadian dollar would have impacted our revenues for the year ended December 31, ~~2008~~2010 by approximately ~~$0.9~~$0.8 million, or ~~$0.6~~$0.5 million net of tax. We do not currently use hedges or forward contracts to offset this risk.

Our Mexican operation uses the U.S. dollar as its functional currency, and as a result, all transactions and translation gains and losses are recorded currently in the financial statements. The balance sheet amounts are translated into U.S. dollars at the exchange rate at the end of the month and the income statement amounts are translated at the average exchange rate for the month. We estimate that a hypothetical one percentage point change in the value of the Mexican peso relative to the U.S. dollar would have impacted our revenues for the year ended December 31, ~~2008~~2010 by approximately ~~$0.6~~$0.5 million, or ~~$0.4~~$0.3 million, net of tax. Currently, we conduct a portion of our business in Mexico in the local currency, the Mexican peso.

Approximately 23% of our debt at December 31, 2008 is structured under floating rate terms and, as such, our interest expense is sensitive to fluctuations in the prime rates in the U.S. and Canada. Based on the debt structure in place as of December 31, 2008, a 100 basis point increase in interest rates relative to our floating rate obligations would increase interest expense by approximately $1.9 million per year and reduce operating cash flows by approximately $1.2 million, net of tax.


Item 8.	*Financial Statements and Supplementary Data.*

6061

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders
~~Stockholders of~~ Complete Production Services, Inc.:

We have audited the accompanying consolidated balance sheets of Complete Production Services, Inc. ~~and subsidiaries~~ as of December 31, ~~2008~~2010 and ~~2007,~~2009, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, ~~2008.~~2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the ~~consolidated~~ financial position of Complete Production Services, Inc. as of December 31, ~~2008~~2010 and ~~2007,~~2009, and the ~~consolidated~~ results of their operations and their cash flows for each of the three years in the period ended December 31, ~~2008,~~2010, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Complete Production Services, Inc. ~~and its subsidiaries’~~’s internal control over financial reporting as of December 31, ~~2008,~~2010, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February ~~27, 2009,~~18, 2011, expressed an unqualified opinion that Complete Production Services, Inc. ~~and subsidiaries~~ maintained, in all material respects, effective internal control over financial reporting.

/s/ Grant Thornton LLP

Houston, Texas
February ~~27, 2009~~18, 2011

6162

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

~~Stockholders of~~ Complete Production Services, Inc.:

We have audited Complete Production Services, ~~Inc’s.~~Inc.’s internal control over financial reporting as of December 31, ~~2008,~~2010, based on criteria established inInternal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Complete Production Services, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying ~~Management~~Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Complete Production Services, Inc.’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

In our opinion, Complete Production Services, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2008,~~2010, based on criteria established inInternal Control — Integrated Frameworkissued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Complete Production Services, Inc. ~~and subsidiaries~~ as of December 31, ~~2008~~2010 and ~~2007,~~2009, and the related consolidated statements of operations, ~~and~~ comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, ~~2008,~~2010, and our report dated February ~~27, 2009~~18, 2011 expressed an unqualified opinion on those consolidated financial statements.

/s/ Grant Thornton LLP

Houston, Texas

February ~~27, 2009~~

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Consolidated Balance Sheets~~

~~December 31, 2008 and 2007~~

2008 2007
(In thousands, except share data)

ASSETS
Current assets:
Cash and cash equivalents $ 19,090 $ 13,624
Trade accounts receivable, net of allowance for doubtful accounts of $5,976 and $5,487, respectively 343,353 305,682
Inventory, net of obsolescence reserve of $710 and $1,670, respectively 41,891 29,877
Prepaid expenses 21,472 23,743
Tax receivable 21,328 5,092
Current assets of discontinued operations — 50,307

Total current assets 447,134 428,325
Property, plant and equipment, net 1,166,453 1,013,190
Intangible assets, net of accumulated amortization of $9,985 and $5,762, respectively 23,262 10,606
Deferred financing costs, net of accumulated amortization of $4,186 and $2,455, respectively 12,463 14,194
Goodwill 341,592 549,130
Other long-term assets 3,973 6,264
Long-term assets of discontinued operations — 33,050

Total assets $ 1,994,877 $ 2,054,759

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current maturities of long-term debt $ 3,803 $ 398
Accounts payable 57,483 56,407
Accrued liabilities 37,585 52,572
Accrued payroll and payroll burdens 31,293 24,050
Accrued interest 2,754 4,553
Notes payable 1,353 15,354
Taxes payable — 6,506
Current deferred tax liabilities 1,289 —
Current liabilities of discontinued operations — 9,705

Total current liabilities 135,560 169,545
Long-term debt 843,842 825,985
Deferred income taxes 146,359 126,821
Long-term liabilities of discontinued operations — 2,085

Total liabilities 1,125,761 1,124,436
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.01 par value per share, 200,000,000 shares authorized, 74,766,317 (2007 — 72,509,511) issued 748 725
Preferred stock, $0.01 par value per share, 5,000,000 shares authorized, no shares issued and outstanding — —
Additional paid-in capital 623,988 581,404
Retained earnings 232,080 317,535
Treasury stock, 35,570 shares at cost (202 ) (202 )
Accumulated other comprehensive income 12,502 30,861

Total stockholders’ equity 869,116 930,323

Total liabilities and stockholders’ equity $ 1,994,877 $ 2,054,759

~~See accompanying notes to consolidated financial statements.~~18, 2011

63

COMPLETE PRODUCTION SERVICES, INC.

Consolidated Balance Sheets
December 31, 2010 and 2009

~~Consolidated Statements of Operations~~

~~Years Ended December 31, 2008, 2007 and 2006~~

Year Ended December 31,
2008 2007 2006
(In thousands, except per share data)

Revenue:
Service $ 1,779,452 $ 1,454,586 $ 1,055,025
Product 59,102 40,857 29,586

1,838,554 1,495,443 1,084,611
Service expenses 1,091,885 846,942 612,800
Product expenses 41,914 27,621 16,546
Selling, general and administrative expenses 198,252 179,027 144,432
Depreciation and amortization 181,097 131,353 75,902
Impairment loss 272,006 13,094 —

Income from continuing operations before interest, taxes and minority interest 53,400 297,406 234,931
Interest expense 59,729 61,328 40,645
Interest income (301 ) (325 ) (1,387 )
Write-off of deferred financing costs — — 170

Income (loss) from continuing operations before taxes and minority interest (6,028 ) 236,403 195,503
Taxes 74,568 86,851 70,516

Income (loss) from continuing operations before minority interest (80,596 ) 149,552 124,987
Minority interest — (569 ) (49 )

Income (loss) from continuing operations (80,596 ) 150,121 125,036
Income (loss) from discontinued operations (net of tax expense of $3,865, $6,890 and $9,359, respectively) (4,859 ) 11,443 14,050

Net income (loss) $ (85,455 ) $ 161,564 $ 139,086

Earnings (loss) per share information:
Continuing operations $ (1.10 ) $ 2.09 $ 1.90
Discontinued operations $ (0.06 ) $ 0.15 $ 0.21

Basic earnings (loss) per share $ (1.16 ) $ 2.24 $ 2.11

Continuing operations $ (1.10 ) $ 2.05 $ 1.84
Discontinued operations $ (0.06 ) $ 0.15 $ 0.20

Diluted (loss) earnings per share $ (1.16 ) $ 2.20 $ 2.04

Weighted average shares:
Basic 73,600 71,991 65,843
Diluted 73,600 73,352 68,075

2010 2009
(In thousands, except share data)

ASSETS
Current assets:
Cash and cash equivalents $ 126,681 $ 77,360
Accounts receivable, net of allowance for doubtful accounts of $4,160 and $12,564, respectively 345,648 171,284
Inventory, net of obsolescence reserve of $2,453 and $888, respectively 33,536 37,464
Prepaid expenses 18,700 17,943
Income tax receivable 23,462 57,606
Current deferred tax assets 2,499 8,158
Other current assets 1,384 111

Total current assets 551,910 369,926
Property, plant and equipment, net 956,028 941,133
Intangible assets, net of accumulated amortization of $21,293 and $15,476, respectively 9,209 13,243
Deferred financing costs, net of accumulated amortization of $9,316 and $6,266, respectively 9,694 12,744
Goodwill 250,533 243,823
Restricted cash 17,000 —
Other long-term assets 6,202 7,985

Total assets $ 1,800,576 $ 1,588,854

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current maturities of long-term debt $ — $ 228
Accounts payable 75,099 31,745
Accrued liabilities 44,291 41,102
Accrued payroll and payroll burdens 26,568 13,559
Accrued interest 2,446 3,206
Notes payable — 1,069
Income taxes payable — 813

Total current liabilities 148,404 91,722
Long-term debt 650,000 650,002
Deferred income taxes 190,422 148,240
Other long-term liabilities 5,916 —

Total liabilities 994,742 889,964
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.01 par value per share, 200,000,000 shares authorized, 76,443,926 (2009 — 75,278,406) issued 764 752
Preferred stock, $0.01 par value per share, 5,000,000 shares authorized, no shares issued and outstanding — —
Additional paid-in capital 657,993 636,904
Retained earnings 126,165 42,007
Treasury stock, 167,643 (2009 — 54,313) shares at cost (1,765 ) (334 )
Accumulated other comprehensive income 22,677 19,561

Total stockholders’ equity 805,834 698,890

Total liabilities and stockholders’ equity $ 1,800,576 $ 1,588,854

See accompanying notes to consolidated financial statements.

64

COMPLETE PRODUCTION SERVICES, INC.

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

Years Ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006~~2008

Year Ended December 31,
2008 2007 2006
(In thousands)

Net income (loss) $ (85,455 ) $ 161,564 $ 139,086
Change in cumulative translation adjustment (18,359 ) 15,129 (808 )

Comprehensive income (loss) $ (103,814 ) $ 176,693 $ 138,278

Year Ended December 31,
2010 2009 2008
(In thousands, except per share data)

Revenue:
Service $ 1,527,618 $ 1,012,313 $ 1,775,813
Product 33,775 44,081 59,102

1,561,393 1,056,394 1,834,915
Service expenses 985,093 692,164 1,094,574
Product expenses 25,947 33,201 41,914
Selling, general and administrative expenses 175,445 181,420 198,200
Depreciation and amortization 181,823 200,732 181,197
Fixed asset and other intangibles impairment loss — 38,646 —
Goodwill impairment loss — 97,643 272,006

Income (loss) from continuing operations before interest and taxes 193,085 (187,412 ) 47,024
Interest expense 57,669 56,895 59,729
Interest income (322 ) (79 ) (301 )
Write-off of deferred financing costs — 528 —

Income (loss) from continuing operations before taxes 135,738 (244,756 ) (12,404 )
Taxes 51,580 (63,088 ) 72,305

Income (loss) from continuing operations 84,158 (181,668 ) (84,709 )
Loss from discontinued operations (net of tax expense of $0, $0, and $3,865, respectively) — — (4,859 )

Net income (loss) $ 84,158 $ (181,668 ) $ (89,568 )

Earnings (loss) per share information:
Continuing operations $ 1.11 $ (2.42 ) $ (1.15 )
Discontinued operations — — (0.07 )

Basic earnings (loss) per share $ 1.11 $ (2.42 ) $ (1.22 )

Continuing operations $ 1.08 $ (2.42 ) $ (1.15 )
Discontinued operations — — (0.07 )

Diluted earnings (loss) per share $ 1.08 $ (2.42 ) $ (1.22 )

Weighted average shares:
Basic 76,048 75,095 73,600
Diluted 77,684 75,095 73,600

See accompanying notes to consolidated financial statements.

65

COMPLETE PRODUCTION SERVICES, INC.

Consolidated ~~Statement~~Statements of ~~Stockholders’ Equity~~Comprehensive Income (Loss)

Years Ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006~~2008

Accumulated

Additional
Other

Number
Common
Paid-in
Retained
Treasury
Deferred
Comprehensive

of Shares Stock Capital Earnings Stock Compensation Income Total
(In thousands, except share data)

Balance at December 31, 2005 55,531,510 $ 555 $ 220,786 $ 16,885 $ (202 ) $ (3,803 ) $ 16,540 $ 250,761
Adoption of SFAS No. 123R — — (3,803 ) — — 3,803 — —
Net income — — — 139,086 — — — 139,086
Cumulative translation adjustment — — — — — — (808 ) (808 )
Issuance of common stock:
Net proceeds from initial public offering 13,000,000 130 288,505 — — — — 288,635
Acquisition of Parchman 1,000,000 10 23,490 — — — — 23,500
Acquisition of MGM 164,210 2 3,857 — — — — 3,859
Acquisition of Pumpco 1,010,566 10 21,414 — — — — 21,424
Exercise of stock options 506,405 5 1,810 — — — — 1,815
Expense related to employee stock options — — 1,848 — — — — 1,848
Excess tax benefit from share-based compensation — — 2,333 — — — — 2,333
Vested restricted stock 205,782 2 (2 ) — — — — —
Amortization of non-vested restricted stock — — 2,768 — — — — 2,768

Balance at December 31, 2006 71,418,473 $ 714 $ 563,006 $ 155,971 $ (202 ) $ — $ 15,732 $ 735,221
Net income — — — 161,564 — — — 161,564
Cumulative translation adjustment — — — — — — 15,129 15,129
Issuance of common stock:
Exercise of stock options 934,094 9 4,170 — — — — 4,179
Expense related to employee stock options — — 4,426 — — — — 4,426
Excess tax benefit from share-based compensation — — 6,662 — — — — 6,662
Vested restricted stock 156,944 2 (2 ) — — — — —
Amortization of non-vested restricted stock — — 3,142 — — — — 3,142

Balance at December 31, 2007 72,509,511 $ 725 $ 581,404 $ 317,535 $ (202 ) $ — $ 30,861 $ 930,323
Net loss — — — (85,455 ) — — — (85,455 )
Cumulative translation adjustment — — — — — — (18,359 ) (18,359 )
Issuance of common stock:
Acquisition of AWS 588,292 6 8,848 — — — — 8,854
Acquisition — Double Jack shares 7,234 — 225 — — — — 225
Exercise of stock options 1,238,819 13 12,001 — — — — 12,014
Expense related to employee stock options — — 5,436 — — — — 5,436
Excess tax benefit from share-based compensation — — 9,144 — — — — 9,144
Vested restricted stock 422,461 4 (4 ) — — — — —
Amortization of non-vested restricted stock — — 6,934 — — — — 6,934

Balance at December 31, 2008 74,766,317 $ 748 $ 623,988 $ 232,080 $ (202 ) $ — $ 12,502 $ 869,116

Year Ended December 31,
2010 2009 2008
(In thousands)

Net income (loss) $ 84,158 $ (181,668 ) $ (89,568 )
Change in cumulative translation adjustment 3,116 7,059 (18,359 )

Comprehensive income (loss) $ 87,274 $ (174,609 ) $ (107,927 )

See accompanying notes to consolidated financial statements.

66

COMPLETE PRODUCTION SERVICES, INC.

Consolidated ~~Statements~~Statement of ~~Cash Flows~~Stockholders’ Equity

Years Ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006~~2008

Year Ended December 31,
2008 2007 2006
(In thousands)

Cash provided by:
Net income (loss) $ (85,455 ) $ 161,564 $ 139,086
Items not affecting cash:
Depreciation and amortization 183,091 135,961 79,813
Deferred income taxes 24,738 38,099 30,907
Impairment loss 272,006 13,094 —
Write-off of deferred financing fees — — 170
Loss on sale of discontinued operations 6,935 — 603
Minority interest — (569 ) (49 )
Excess tax benefit from share-based compensation (9,144 ) (6,662 ) (2,333 )
Non-cash compensation expense 12,370 7,568 4,616
Provision for bad debt expense 4,344 7,277 2,329
Other 5,734 3,391 1,564
Changes in operating assets and liabilities, net of effect of acquisitions:
Accounts receivable (22,433 ) (29,255 ) (105,203 )
Inventory (10,522 ) (11,132 ) (11,511 )
Prepaid expenses and other current assets 6,376 1,520 (1,201 )
Accounts payable (10,199 ) (8,063 ) 14,819
Accrued liabilities and other (27,393 ) 25,710 34,133

Net cash provided by operating activities 350,448 338,503 187,743
Investing activities:
Business acquisitions, net of cash acquired (180,154 ) (50,406 ) (369,606 )
Additions to property, plant and equipment (253,815 ) (367,659 ) (303,922 )
Purchase of short-term securities — — (165,000 )
Proceeds from sale of short-term securities — — 165,000
Proceeds from sale of fixed assets 7,666 9,270 3,355
Collection of notes receivable 2,016 — —
Proceeds from sale of disposal group 50,150 — 19,310

Net cash used in investing activities (374,137 ) (408,795 ) (650,863 )
Financing activities:
Issuances of long-term debt 350,115 343,790 608,703
Repayments of long-term debt (329,282 ) (268,769 ) (1,053,789 )
Repayments of notes payable (14,001 ) (18,846 ) (13,589 )
Borrowings under senior notes — — 650,000
Proceeds from issuances of common stock 12,014 4,179 291,674
Deferred financing fees — (373 ) (13,956 )
Excess tax benefit from share-based compensation 9,144 6,662 2,333

Net cash provided by financing activities 27,990 66,643 471,376
Effect of exchange rate changes on cash 1,165 (2,601 ) 213

Change in cash and cash equivalents 5,466 (6,250 ) 8,469
Cash and cash equivalents, beginning of period 13,624 19,874 11,405

Cash and cash equivalents, end of period $ 19,090 $ 13,624 $ 19,874

Supplemental cash flow information:
Cash paid for interest, net of interest capitalized $ 58,812 $ 59,164 $ 35,947
Cash paid for taxes $ 71,365 $ 56,468 $ 40,132
Significant non-cash investing and financing activities:
Common stock issued for acquisitions $ 9,079 $ — $ 48,783
Assets received as proceeds from sale of disposal group $ 7,987 $ — $ —
Debt acquired in acquisition $ 429 $ — $ 30,784
Capital expenditures in accrued payables/expenses $ — $ 4,895 $ —

Accumulated

Additional
Other

Number
Common
Paid-in
Retained
Treasury
Comprehensive

of Shares Stock Capital Earnings Stock Income Total
(In thousands, except share data)

Balance at December 31, 2007 72,509,511 $ 725 $ 581,404 $ 313,243 $ (202 ) $ 30,861 $ 926,031
Net loss — — — (89,568 ) — — (89,568 )
Change in cumulative translation adjustment — — — — — (18,359 ) (18,359 )
Issuance of common stock:
Acquisition of AWS 588,292 6 8,848 — — — 8,854
Acquisition — Double Jack shares 7,234 — 225 — — — 225
Exercise of stock options 1,238,819 13 12,001 — — — 12,014
Expense related to employee stock options — — 5,436 — — — 5,436
Excess tax benefit from share-based compensation — — 9,144 — — — 9,144
Vested restricted stock 422,461 4 (4 ) — — — —
Amortization of non-vested restricted stock — — 6,934 — — — 6,934

Balance at December 31, 2008 74,766,317 $ 748 $ 623,988 $ 223,675 $ (202 ) $ 12,502 $ 860,711
Net loss — — — (181,668 ) — — (181,668 )
Change in cumulative translation adjustment — — — — — 7,059 7,059
Exercise of stock options 123,858 496 — — — 496
Expense related to employee stock options — — 3,987 — — — 3,987
Excess tax benefit from share-based compensation — — 215 — — — 215
Purchase of treasury shares (18,743 ) — — — (132 ) — (132 )
Vested restricted stock 406,974 4 (4 ) — — — —
Amortization of non-vested restricted stock — — 8,222 — — — 8,222

Balance at December 31, 2009 75,278,406 $ 752 $ 636,904 $ 42,007 $ (334 ) $ 19,561 $ 698,890
Net income — — — 84,158 — — 84,158
Change in cumulative translation adjustment — — — — — 3,116 3,116
Exercise of stock options 599,035 6 8,076 — — — 8,082
Expense related to employee stock options — — 2,321 — — — 2,321
Excess tax benefit from share-based compensation — — 1,465 — — — 1,465
Purchase of treasury shares (113,330 ) (1 ) 1 — (1,431 ) — (1,431 )
Vested restricted stock 679,815 7 (7 ) — — — —
Amortization of non-vested restricted stock — — 9,233 — — — 9,233

Balance at December 31, 2010 76,443,926 $ 764 $ 657,993 $ 126,165 $ (1,765 ) $ 22,677 $ 805,834

See accompanying notes to consolidated financial statements.

67

COMPLETE PRODUCTION SERVICES, INC.

Consolidated Statements of Cash Flows
Years Ended December 31, 2010, 2009 and 2008

Year Ended December 31,
2010 2009 2008
(In thousands)

Cash provided by:
Net income (loss) $ 84,158 $ (181,668 ) $ (89,568 )
Items not affecting cash:
Depreciation and amortization 181,823 200,732 183,191
Deferred income taxes 47,841 (7,567 ) 20,827
Fixed asset and other intangibles impairment loss — 38,646 —
Goodwill impairment loss — 97,643 272,006
Write-off of deferred financing fees — 528 —
Loss on sale of discontinued operations — — 6,935
Excess tax benefit from share-based compensation (1,465 ) (215 ) (9,144 )
Non-cash compensation expense 11,554 12,209 12,370
(Gain) loss on non-monetary asset exchange (493 ) 4,868 —
Provision for (recoveries of) bad debt expense (159 ) 10,770 4,344
Loss on retirement of fixed assets 839 10,284 3,778
Provision for write-off of note receivable 1,926 — —
Other 2,995 2,081 1,956
Changes in operating assets and liabilities, net of effect of acquisitions:
Accounts receivable (173,328 ) 155,303 (18,873 )
Inventory 3,585 4,339 (8,653 )
Prepaid expenses and other current assets (1,095 ) 11,292 8,118
Accounts payable 25,831 (24,544 ) (10,199 )
Income taxes 34,093 (30,892 ) (13,873 )
Restricted cash (17,000 ) — —
Accrued liabilities and other 15,053 (18,605 ) (12,806 )

Net cash provided by operating activities 216,158 285,204 350,409
Investing activities:
Business acquisitions, net of cash acquired (33,721 ) — (180,154 )
Additions to property, plant and equipment (145,023 ) (37,431 ) (253,776 )
Proceeds from sale of fixed assets 5,482 20,800 7,666
Proceeds from sale of disposal group — — 50,150
Other (826 ) (1,497 ) 2,016

Net cash used in investing activities (174,088 ) (18,128 ) (374,098 )
Financing activities:
Issuances of long-term debt — 3,194 350,115
Repayments of long-term debt (230 ) (200,609 ) (329,282 )
Repayments of notes payable (1,069 ) (8,244 ) (14,001 )
Proceeds from issuances of common stock 8,082 496 12,014
Deferred financing fees — (2,911 ) —
Treasury stock purchased (1,431 ) (132 ) —
Excess tax benefit from share-based compensation 1,465 215 9,144

Net cash (used in) provided by financing activities 6,817 (207,991 ) 27,990
Effect of exchange rate changes on cash 434 (225 ) 1,165

Change in cash and cash equivalents 49,321 58,860 5,466
Cash and cash equivalents, beginning of period 77,360 18,500 13,034

Cash and cash equivalents, end of period $ 126,681 $ 77,360 $ 18,500

Supplemental cash flow information:
Cash paid for interest, net of capitalized interest $ 54,301 $ 52,686 $ 58,812
Cash paid (refund received) for taxes $ (31,067 ) $ (25,414 ) $ 71,365
Significant non-cash investing and financing activities:
Non-cash capital expenditures $ 25,952 $ 1,056 $ —
Note issued to finance insurance premiums $ — $ 7,960 $ —
Common stock issued for acquisitions $ — $ — $ 9,079
Assets received as proceeds from sale of disposal group $ — $ — $ 7,987
Debt acquired in acquisition $ — $ — $ 429
See accompanying notes to consolidated financial statements.

68

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements

(In thousands, except share and per share data)


1.	General:


*~~(a)~~*	*~~Nature of operations:~~*

(a) Nature of operations:

Complete Production Services, Inc. is a provider of specialized services and products focused on developing hydrocarbon reserves, reducing operating costs and enhancing production for oil and gas companies. Complete Production Services, Inc. focuses its operations on basins within North America and manages its operations from regional field service facilities located throughout the U.S. Rocky Mountain region, Texas, Oklahoma, Louisiana, Arkansas, Pennsylvania, western Canada, Mexico and Southeast Asia.

References to “Complete”, the “Company”, “we”, “our” and similar phrases are used throughout these financial statements and relate collectively to Complete Production Services, Inc. and its consolidated affiliates.

On April 20, 2006, we entered into an underwriting agreement in connection with our initial public offering and became subject to the reporting requirements of the Securities Exchange Act of 1934. On April 21, 2006, our common stock began trading on the New York Stock Exchange under the symbol “CPX”. On April 26, 2006, we completed our initial public offering. See Note 12, ~~Stockholders’ Equity.~~“Stockholders’ equity”.


*~~(b)~~*	*~~Basis of presentation:~~*

(b) Basis of presentation:

Our consolidated financial statements are expressed in U.S. dollars and have been prepared by us in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). In preparing financial statements, we make informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, we review our estimates, including those related to impairment of long-lived assets and goodwill, contingencies and income taxes. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

These audited consolidated financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary for a fair statement of the financial position of Complete as of December 31, ~~2008~~2010 and ~~2007~~2009 and the statements of operations, the statements of comprehensive income (loss), the statements of stockholders’ equity and the statements of cash flows for each of the three years in the period ended December 31, ~~2008.~~2010. We believe that these financial statements contain all adjustments necessary so that they are not misleading. Certain reclassifications have been made ~~to 2006 and 2007 amounts~~ in order to present ~~these~~ results on a comparable basis with amounts for 2008, including a reclassification of certain payroll benefits and related burdens. For the years ended December 31, 2007 and 2006, we reclassified $13,466 and $7,723, respectively, from selling, general and administrative expense to cost of services. This reclassification was made to allocate payroll benefit costs to the cost of services in an effort to insure that these costs and their impact on gross margin were aligned consistently throughout our operating units. In addition, we changed the presentation of capitalized interest at one of our subsidiaries for the year ended December 31, 2007, which resulted in a decrease in interest income and an offsetting decrease in interest expense totaling $1,311. This change had no impact on net interest expense as previously disclosed.2009.

In May 2008, our Board of Directors authorized and committed to a plan to sell certain operations in the Barnett Shale region of north Texas, consisting primarily of our supply store business, as well as certain non-strategic drilling logistics assets and other completion and production services assets. On May 19, 2008, we sold these operations to a company owned by a former officer of one of our subsidiaries, for which we received proceeds of $50,150 and assets with a fair market value of $7,987. In August 2006, our Board of Directors authorized and committed to a plan to sell certain manufacturing and production enhancement operations of a subsidiary located in Alberta, Canada, which includes certain assets located in south Texas. Accordingly, we have revised our financial statements for ~~all periods presented~~the year ended December 31, 2008 to classify the related results of operations of ~~these~~this disposal ~~groups~~group as discontinued operations. See Note 14, ~~Discontinued Operations.~~

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~“Discontinued operations”.


2.	Significant accounting policies:


*~~(a)~~*	*~~Basis of preparation:~~*

(a) Basis of preparation:

Our consolidated financial statements include the accounts of the legal entities discussed above and their wholly owned subsidiaries. All material inter-company balances and transactions have been eliminated in consolidation.

COMPLETE PRODUCTION SERVICES, INC.


*~~(b)~~*	*~~Foreign currency translation:~~*

Notes to Consolidated Financial Statements — (Continued)

(b) Foreign currency translation:

Assets and liabilities of foreign subsidiaries, whose functional currencies are the local currency, are translated from their respective functional currencies to U.S. dollars at the balance sheet date exchange rates. Income and expense items are translated at the average rates of exchange prevailing during the ~~year.~~period. Foreign exchange gains and losses resulting from translation of account balances are included in income or loss in the year in which they occur. The adjustment resulting from translating the financial statements of such foreign subsidiaries into U.S. dollars is reflected as a separate component of stockholders’ equity.


*~~(c)~~*	*~~Revenue recognition:~~*

(c) Revenue recognition:

We recognize service revenue when it is realized and earned. We consider revenue to be realized and earned when the services have been provided to the customer, the product has been delivered, the sales price ~~has been~~is fixed or determinable and collectibility is reasonably assured. Generally, services are provided over a relatively short time.

Revenue and costs on drilling contracts are recognized as work progresses. Progress is measured and revenues recognized based upon agreed day-rate charges. For certain contracts, we may receive additional lump-sum payments for the mobilization of rigs and other drilling equipment. Consistent with the drilling contract day-rate revenues and charges, revenues and related direct costs incurred for the mobilization are deferred and recognized over the term of the related 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.

We recognize revenue under service contracts as services are performed. We had no significant unearned revenues associated with long-term service contracts as of December 31, ~~2008~~2010 and ~~2007.~~2009.


*~~(d)~~*	*~~Cash and cash equivalents:~~*

(d) Cash and cash equivalents:

Short-term investments with maturities of less than three months are considered to be cash equivalents and are recorded at cost, which approximates fair market value. For purposes of the consolidated statements of cash flows, we consider all investments in highly liquid debt instruments with original maturities of three months or less to be cash equivalents. We invest excess cash in overnight investments which are accounted for as cash. At December 31, 2010, our cash ~~equivalents.~~and cash equivalents exceeded what is federally insured.


*~~(e)~~*	*~~Trade accounts receivable:~~*

(e) Trade accounts receivable:

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses incurred in our existing accounts receivable. We determine the allowance based on historical write-off experience, account aging and our assumptions about the oil and gas industry economic cycle. We review our allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. All other balances are reviewed on a pooled basis. Account balances are charged off against the allowance after all appropriate means of collection have been exhausted and the potential for recovery is considered remote. Considering our customer base, we do not believe that we have any significant concentrations of credit risk other than our concentration in the oil and gas industry. We have no significant off balance-sheet credit exposure related to our customers.

~~COMPLETE PRODUCTION SERVICES, INC.~~
(f) Inventory:

~~Notes to Consolidated Financial Statements — (Continued)~~


*~~(f)~~*	*~~Inventory:~~*

Inventory, which consists of finished goods, ~~and~~ materials and supplies held for resale, work in process and bulk fuel, is carried at the lower of cost ~~and~~or market. Market is defined as net realizable value for finished goods and as replacement cost for manufacturing parts and materials. Cost is determined on afirst-in, first-out basis for refurbished parts and an average cost basis for all other inventories and includes the cost of raw materials and labor

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

for finished goods. We record a reserve for excess and obsolete inventory based upon specific identification of items based on periodic reviews of inventory on hand.


*~~(g)~~*	*~~Property, plant and equipment:~~*

(g) Property, plant and equipment:

Property, plant and equipment are carried at cost less accumulated depreciation. Major betterments are capitalized. Repairs and maintenance that do not extend the useful life of equipment are expensed.

Depreciation is provided over the estimated useful life of each asset as follows:


Asset	Basis		Rate

Buildings		straight-line		39 years
Field ~~Equipment~~	Equipment:
Wireline, optimization and coiled tubing equipment		straight-line		10 years
~~Gas~~Production testing equipment		straight-line		15 years
Drilling rigs		straight-line		20 years
Well-servicing rigs		straight-line		10 to 25 years
Pressure pumping equipment		straight-line		10 years
Office furniture and computers		straight-line		3 to 7 years
Leasehold improvements		straight-line		Shorter of 5 years or the life of the lease
Vehicles and other equipment		straight-line		3 to 10 years


*~~(h)~~*	*~~Intangible assets:~~*

(h) Intangible assets:

Intangible assets, consisting of acquired customer relationships, service marks, non-compete agreements, acquired patents and technology, are carried at cost less accumulated amortization, which is calculated on a straight-line basis over a period of 2 to 10 years depending on the asset’s estimated useful life. The weighted average amortization period for these intangible assets was approximately 4 years as of December 31, ~~2008.~~2010.

��

(i) Impairment of long-lived assets:


*~~(i)~~*	*~~Impairment of long-lived assets:~~*

~~In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144,~~We review long-lived assets ~~such as~~including property, plant and equipment and ~~purchased intangibles subject to amortization, are reviewed~~intangible assets with definite lives for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. When assets are determined to be held for sale, they are separately presented in the appropriate asset and liability sections of the balance sheet and reported at the lower of the carrying amount or fair value less cost to sell, and are no longer depreciated. We recorded a fixed asset and other intangibles impairment loss of $38,646 for the year ended December 31, 2009. See Note 6, “Property, plant and equipment.”

~~COMPLETE PRODUCTION SERVICES, INC.~~
(j) Asset retirement obligations:

~~Notes to Consolidated Financial Statements — (Continued)~~


*~~(j)~~*	*Asset ~~retirement obligations:~~*

~~We account for asset~~ retirement obligations ~~in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations”, pursuant to which we would record the~~are recorded at fair value ~~of an asset retirement obligation~~ as a liability in the period in which a legal obligation is incurred associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development,and/or normal use of the ~~assets.~~assets in accordance with U.S. GAAP. Furthermore, ~~we would record~~ a corresponding asset ~~to depreciate~~is recorded and depreciated over the contractual term of the underlying asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation ~~would be~~is adjusted at the end of each period to reflect the passage of time and

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

changes in the estimated future cash flows underlying the obligation. ~~There were no~~We recorded asset retirement obligations of $5,022 as of December 31, 2010 related to the expected cost to plug our saltwater disposal wells at the end of the service lives of the assets, as well as other retirement commitments. We did not have significant retirement obligations recorded at December 31, ~~2008~~2009 and ~~2007.~~2008.


*~~(k)~~*	*~~Deferred financing costs:~~*

(k) Deferred financing costs:

Deferred financing costs associated with long-term debt under our revolving credit facilities and senior notes are carried at cost and are expensed over the term of the applicable long-term debt facility or the term of the notes.


*~~(l)~~*	*~~Goodwill:~~*

(l) Goodwill:

Goodwill represents the excess of costs over the fair value of the assets and liabilities of businesses acquired. ~~We apply the provisions of SFAS No. 142, which~~U.S. GAAP requires an impairment test at least annually, or more frequently if indicators of impairment are present, whereby we estimate the fair value of the asset by discounting future cash flows at a 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~~allocation consistent with ~~that described in SFAS No. 141.~~authoritative guidance pertaining to business combinations. 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 implied fair ~~value, as described in SFAS No. 142.~~value. We did not record a goodwill impairment for the year ended 2010. We recorded angoodwill impairment ~~loss~~losses for each of the years ended December 31, ~~2008~~2009 and ~~2007.~~2008. See (t) “Fair value measurements” and Note 15, ~~Segment Information and Note 2, Significant Accounting Policies — Fair Value Measurement. Based upon this testing, goodwill was not deemed to be impaired during the year ended December 31, 2006.~~“Segment information.”


*(m)*	*Deferred income taxes:*

We follow the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are determined based upon temporary differences between the carrying amount and tax basis of our assets and liabilities and measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect on deferred tax assets and liabilities of a change in the tax rates is recognized in income in the period in which the change occurs. We record a valuation ~~reserve~~allowance when we believe that it is more likely than not that ~~any~~a deferred tax asset ~~created~~ will not be realized.

In assessing the realizability of deferred income tax assets, management considers whether it is more likely than not that some portion or all of the deferred income tax assets will not be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.


*~~(n)~~*	*~~Financial instruments:~~*

(n) Financial instruments:

The financial instruments recognized in the balance sheet consist of cash and cash equivalents, trade accounts receivable, ~~bank operating loans,~~revolving credit facilities, accounts payable and accrued liabilities, long-term debt ~~convertible debentures~~ and senior notes. The fair value of ~~all~~our financial instruments ~~approximates~~approximate their carrying amounts due to their current maturities or market rates of interest, except the senior notes which were issued in December 2006 with a fixed 8% coupon rate. At December 31, ~~2008~~2010 and ~~2007,~~2009, the fair value of these notes was ~~$409,500~~$669,500 and ~~$627,250,~~$641,875, respectively, based on the published closing ~~price.~~prices for the applicable day.

~~COMPLETE PRODUCTION SERVICES, INC.~~
(o) Per share amounts:

~~Notes to Consolidated Financial Statements — (Continued)~~


*~~(o)~~*	*~~Per share amounts:~~*

WeIn accordance with U.S. GAAP, we use the treasury stock method ~~described in SFAS No. 128~~ to calculate the dilutive effect of stock options ~~stock warrants, convertible debentures~~ and non-vested restricted ~~stock.~~stock on our earnings per share calculations. This method requires that we compare the presumed proceeds from the exercise of options and other dilutive instruments, including the expected tax benefit to us, to the exercise price of the instrument, and assume that we used the net proceeds to purchase shares of our common stock at the average price during the period. These assumed shares are then included in the

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

calculation of the diluted weighted average shares outstanding for the period, if such instruments are not deemed to be anti-dilutive.


*~~(p)~~*	*~~Stock-based compensation:~~*

(p) Stock-based compensation:

We have stock-based compensation plans for our employees, officers and directors to acquire common stock. For stock option grants ~~of stock options~~made prior to January 1, 2006, ~~stock options were accounted for under Accounting Principles Board (“APB”) No. 25, “Accounting for Stock Issued to Employees,” whereby~~ no compensation expense was recorded if the stock options were issued at fair value on the date of grant. Accordingly, we did not recognize compensation expense associated with these stock option ~~grants which would have been required under SFAS No. 123. We adopted SFAS No. 123R on~~grants. Subsequent to January 1, ~~2006. Pursuant to SFAS No. 123R,~~2006, we 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, by using an option pricing model to determine fair value. We applied the modified-prospective transition method to account for grants of stock options between September 30, 2005, the date of our initial filing with the Securities and Exchange Commission, and December 31, 2005. For stock options granted on or after January 1, 2006, we use the prospective transition method ~~of SFAS No. 123R~~ to account for these grants and record compensation expense. See Note 12, ~~Stockholders’ Equity.~~“Stockholders’ equity”.


*~~(q)~~*	*~~Research and development:~~*

(q) Research and development:

Research and development costs are charged to income as period costs when incurred.


*~~(r)~~*	*~~Contingencies:~~*

(r) Contingencies:

Liabilities for loss contingencies, including environmental remediation costs not within the scope of ~~SFAS No. 143 arising~~FASB guidance provided with regard to asset retirement obligations and which arise from claims, assessments, litigation, fines, and penalties and other sources, are recorded when it is probable that a liability has been incurred and the amount of the assessmentand/or remediation can be reasonably estimated.


*~~(s)~~*	*~~Measurement uncertainty:~~*

(s) Measurement uncertainty:

Our consolidated financial statements are prepared in accordance with U.S. GAAP. The preparation of the consolidated financial statements in accordance with U.S. GAAP necessarily requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We evaluate our estimates including those related to bad debts, inventory obsolescence, useful lives of property, plant and equipment, ~~useful lives,~~ goodwill, intangible assets, income taxes, contingencies and litigation on an ongoing basis. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances. Under different assumptions or conditions, the actual results could differ, possibly materially, from those previously estimated. Many of the conditions impacting these assumptions are estimates outside of our control.


*~~(t)~~*	*~~Fair Value Measurement:~~*

(t) Fair value measurement:

~~In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” a pronouncement which provides guidance for using~~We evaluate fair value measurements in accordance with U.S. GAAP, which requires us to ~~measure assets and liabilities by providing~~base our estimates on assumptions that a ~~definition of fair value, stating that fair value should be based upon assumptions~~ market ~~participants would~~participant might use to price an asset or liability, and

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes~~ to ~~Consolidated Financial Statements — (Continued)~~

~~establishing~~establish a hierarchy that prioritizes the information used to determine fair value, whereby quoted market prices in active markets ~~would be~~are given highest priority with lowest priority given to data provided by the reporting entity based on unobservable facts. ~~SFAS No. 157~~U.S. GAAP requires disclosure of significant fair value measurements by level within the prescribed hierarchy. ~~We adopted SFAS No. 157 on January 1, 2007, and have applied its guidance prospectively.~~

We generally apply fair value valuation techniques on a non-recurring basis associated with: (1) valuing assets and liabilities acquired in connection with business combinations ~~accounted for pursuant~~and other transactions; (2) valuing potential impairment loss related to ~~SFAS No. 141; (2)~~long-lived assets; and (3) valuing potential impairment loss related to goodwill and indefinite-lived intangible ~~assets accounted for pursuant to SFAS No. 142; and (3) valuing potential impairment loss related to long-lived assets accounted for pursuant to SFAS No. 144.~~assets. We generally do not hold a significant investment in trading securities, and we

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

were not party to significant derivative contract arrangements during the years ended December 31, ~~2008~~2010, 2009 or 2008.

Business combinations and ~~2007.~~ other transactions:

We acquired several businesses during ~~2008.~~the years ended December 31, 2010 and 2008, but did not complete any such business combinations during the year ended December 31, 2009. To determine the fair value of the assets acquired, primarily fixed assets, we ~~obtained~~generally obtain assistance from an independent appraiser to ~~compare~~determine the fair value of the assets toacquired based upon the value of comparable assets in the market ~~to determine the fair value~~ as of the date of the acquisition. ~~Furthermore,~~For one business acquired in late 2010, the assets were recently constructed and cost was deemed to approximate fair value at the date of acquisition. In addition, we applied an income method approach to value identifiable intangible assets associated with ~~these~~our acquisitions, as applicable, including customer relationships, trade names and non-compete agreements. ~~These~~For working capital items, including receivables, payables and inventory, carrying value was deemed to approximate fair value. During the year ended December 31, 2010, we recorded an insignificant non-monetary exchange of assets which resulted in a gain on the transaction of $493. The fair value of the assets received in the exchange was $914 and was more readily determinable based upon the seller’s price for such equipment received in the exchange. For the year ended December 31, 2009, we acquired certain property, plant and equipment at a subsidiary in Canada through a non-monetary exchange of assets, as further described in Note 6, “Property, plant and equipment.” We determined that this transaction had economic substance and that the assets received should be recorded at the fair value of the assets surrendered in the exchange. To determine the fair value of these assets, management obtained assistance from a third-party appraiser and used the orderly-liquidation value of the assets surrendered as an estimate of fair value. This transaction resulted in a loss of $4,868 for the year ended December 31, 2009.

Long-lived assets:

We reviewed our tangible fixed assets and ~~definite-lived~~ intangible assets with definite lives at December 31, 2010 and noted no significant indicators of impairment. Therefore, no impairment losses related to long-lived assets were ~~evaluated pursuant to SFAS No. 144, “Accounting~~recorded for the ~~Impairment or Disposal~~year ended December 31, 2010. In September 2009, we evaluated the fair value of ~~Long-Lived Assets,”~~assets in our contract drilling business with the assistance of a third-party appraiser and determined that the carrying value of certain of these drilling rigs exceeded the fair value estimates. We projected the undiscounted cash flows associated with these rigs, including an estimate of salvage value, and compared these expected future cash flows to the carrying amount of the rigs. If the undiscounted cash flows exceeded the carrying amount, no further testing was performed and the rig was deemed to not be ~~impaired~~impaired. If the undiscounted cash flows did not exceed the carrying value, we estimated the fair market value of the equipment based on management estimates and general market data obtained by the third-party appraiser using the sales comparison market approach, which included the analysis of recent sales and offering prices of similar equipment to arrive at an indication of the most probable selling price for the equipment. The result of this analysis was a calculated fixed asset impairment of $36,158, which was recorded as an impairment loss in the accompanying statement of operations for the year ended December 31, 2009. This impairment charge was allocated entirely to the Drilling Services business segment. This impairment was deemed necessary due to an overall decline in oil and gas exploration and production activity in late 2008 which extended throughout 2009, as well as management’s expectation of future operating results for this business segment for the foreseeable future. We continue to evaluate the remaining useful lives of our drilling rigs, and have considered our depreciation methodology and these estimates of useful lives in our projected future cash flows associated with these assets.

In addition, we evaluated certain long-term intangible assets with definite lives in accordance with U.S. GAAP as of December 31, ~~2008.~~ 2009. Based on our review, we believe that impairment was indicated at one of our businesses due tolower-than-expected results, revised expected future cash flows for the business and changes in local management. Therefore, with the assistance of a third-party appraiser, we determined that certain non-compete agreements and customer relationship intangibles were impaired at December 31, 2009. We recorded an

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

impairment charge related to these intangible assets totaling $2,488 in the accompanying statement of operations for the year ended December 31, 2009.

Goodwill:

We evaluated our goodwill and indefinite-lived intangible assets in accordance with the recoverability tests prescribed by ~~SFAS No. 142~~U.S. GAAP as of our annual testing date in 2010. With the assistance of a third-party valuation specialist, we prepared several valuation models including a discounted cash flow analysis, a market multiples approach and a review of precedent transactions. We weighted these valuation methodologies, with greatest weight given to our discounted cash flow projections, which included assumptions related to organic growth, capital investment, working capital needs, residual value and other assumptions. Based on this analysis, we determined that our goodwill and indefinite-lived intangible assets were not impaired as of the annual testing date for the year ended December 31, 2010. For the year ended December 31, 2009, we determined that goodwill associated with ~~one~~three of our reporting units was ~~deemed~~impaired as of the testing date. For the year ended December 31, 2008, we performed this test at the annual testing date and impairment of goodwill was indicated for most of our reporting units. Then, due to ~~be impaired. However, due~~ a ~~general~~significant decline in the overall U.S. debt and equity markets ~~during the fourth quarter of 2008, we determined that~~which was deemed a triggering event, ~~had occurred as of December 31, 2008, as defined in SFAS No. 142. As such,~~ we performed the ~~impairment testing as of~~test at December 31, 2008 and ~~determined that several~~impairment was indicated. We update our assumptions used in the preparation of our ~~reportable units were deemed to be impaired~~discounted cash flow analysis each year based largely upon unobservable inputs from management, which represent our best estimates of actual results over a long-term period, appropriately discounted as of ~~that~~the test date. Although the assumptions used vary fromyear-to-year based upon our perception of market conditions, the valuation methodology used to value goodwill was consistent for the years ended December 31, 2010, 2009 and 2008.

For the years ended December 31, 2009 and 2008, we performed step two of the goodwill impairment test as prescribed by U.S. GAAP. In performing the two-step goodwill impairment test, ~~prescribed by SFAS No. 142,~~ we compared the fair value of each of our reportable units to its carrying value. We estimated the fair value of our reportable units by considering both the income approach and market approach. Under the market approach, the fair value of the reportable unit is based on market multiple and recent transaction values of peer companies. Under the income approach, the fair value of the reportable unit is based on the present value of estimated future cash flows using the discounted cash flow method. The discounted cash flow method is dependent on a number of unobservable inputs including projections of the amounts and timing of future revenues and cash flows, assumed discount rates and other assumptions. Based upon this initial testing, we determined that goodwill associated with several of our reporting units within ~~each of~~ our completion and production services business segments ~~was~~were impaired, which triggered step two. For step two, we calculated the implied fair value of goodwill and compared it to the carrying amount of that goodwill, by examining the fair value of the tangible and intangible property of these reportable units. The inputs for this model were largely unobservable estimates from management based on historical performance. ~~Due~~We retained the assistance of a third-party appraiser to ~~modifications and~~collect market data for a sample of assets from each of these reporting units to assess the ~~highly customized nature~~market value of the property, plant and equipment of ~~this~~these reportable ~~unit, collecting specific market price data~~units, and the results were extrapolated to ~~assess~~ the ~~fair value of these assets was not feasible, although general market data was obtained.~~asset population. Thus, the primary source for our assessment of value was based on management’s estimates and projections. The result of this analysis was a calculated goodwill impairment of ~~$272,284, of~~$97,643 which ~~$272,006 was~~is recorded ~~as an impairment loss~~ in the accompanying statement of operations at December 31, ~~2008.~~2009. This impairment charge of $97,643 was allocated ~~$243,481~~ to the completion and production services business segment ~~$27,410 to the drilling services business segment and $1,393 to the products business segment. This impairment was~~in 2009. These impairments were deemed necessary due to an overall decline in oil and gas exploration and production activity ~~in late 2008 and relatively low activity expected during~~throughout 2009. For the ~~short-term. We intend to continue to hold our investment in these reportable units for the foreseeable future.~~

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

~~The following tabular presentation is presented in accordance with SFAS No. 157 for quantitative presentation of our significant fair value measurements at~~year ended December 31, ~~2008:~~

Quoted Prices in

Carrying Value
Active Markets for
Significant Other
Significant

Prior to Impairment
Identical Assets
Observable Inputs
Unobservable Inputs
Total Gains
Description
Charge (Level 1) (Level 2) (Level 3) (Losses)

Goodwill 613,876 — — $ 341,592 $ (272,284 )

613,876 — — $ 341,592 $ (272,284 )

~~In accordance with SFAS No. 142,~~2008, goodwill with a carrying amount of $613,876 was written down to its implied fair value of $341,592, resulting in an impairment charge of $272,284, of which $272,006 was recorded as an impairment loss and $277 was recorded as a charge to cumulative translation adjustment in the accompanying balance sheet as of December 31, 2008. ~~For~~We continue to hold an investment in each of these reportable units for which impairment losses were recorded in 2009 and 2008.

75

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

The following tabular presentation is presented for quantitative presentation of our significant fair value measurements for the ~~year~~years ended December 31, ~~2007,~~2010, 2009 and 2008:

Quoted Prices in
Significant Other
Significant

Active Markets for
Observable
Unobservable

Balance at
Identical Assets
Inputs
Inputs
Total Gains

Description Year End (Level 1) (Level 2) (Level 3) (Losses)

As of December 31, 2010:
Non-monetary exchange $ 914 — $ 914 $ — $ 493
Goodwill 250,533 — — 250,533 —

$ 251,447 — $ 914 $ 250,533 $ 493

As of December 31, 2009:
Non-monetary exchange $ 4,487 — $ 4,487 $ — $ (4,868 )
Property, plant and equipment 100,820 — — 100,820 (36,158 )
Definite-lived intangible assets 187 — — 187 (2,488 )
Goodwill 243,823 — — 243,823 (97,643 )

$ 349,317 — $ 4,487 $ 344,830 $ (141,157 )
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As of December 31, 2008:
Goodwill $ 613,876 — $ — $ 341,592 $ (272,284 )

(u)  Investment in Unconsolidated Subsidiaries
We constructed a salt water disposal well for a customer during 2009 at a cost of $1,497. In exchange for this service, we ~~recorded an impairment charge of $13,360, of which $13,094 was recorded~~received a non-controlling interest in the company that owns and operates the well. In accordance with U.S. GAAP, we account for our interest in this company as an ~~impairment loss and $266 was~~equity investment in an unconsolidated subsidiary, whereby we have recorded our initial investment as a ~~charge to cumulative translation adjustment~~long-term asset in the accompanying balance sheet ~~as of~~at December 31, ~~2007.~~2009, and record our portion of earnings or losses associated with this well as equity in earnings of unconsolidated subsidiaries, a component of income or expense in the current period. We have evaluated this ownership interest and determined that it does not constitute a variable interest entity, as that term is defined in current U.S. GAAP guidance. This well did not begin operating until late 2009, and we did not record any significant earnings or loss associated with these operations during the years ended December 31, 2009 or 2010.

3.   Business combinations:

We did not acquire any businesses during the year ended December 31, 2009. However, we did execute several business acquisitions for the years ended December 31, 2010 and 2008, as described below, and expect to complete more transactions in the future, depending on the circumstances and the availability of financing.
(a)  Acquisitions During the Year Ended December 31, 2010:
During the year ended December 31, 2010, we acquired assets or all of the equity interests in various service companies, for $33,721 in cash, resulting in tax deductible goodwill of $6,710.
(i) On May 11, 2010, we acquired certain assets of a provider of gas lift services based in Oklahoma City, Oklahoma. The total purchase price for the assets was $1,440 in cash. We recorded goodwill totaling $1,017 in conjunction with this acquisition which has been allocated entirely to the completion and production services business segment. We believe this acquisition supplements our plunger lift service offering for the completion and production services business segment.

76

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

(ii) On September 3, 2010, we completed the purchase of a well service and fluid handling service provider based in Carrizo Springs, Texas. The total purchase price for the assets was $20,767 and included goodwill of $4,046, all of which was allocated to the completion and production services business segment. We believe this acquisition enhances our position in the Eagle Ford Shale in south Texas.

(iii) On December 1, 2010, we completed the purchase of all of the outstanding common stock of a disposal well operator located in Colorado for $11,514 in cash, subject to an additional $500 holdback. We recorded goodwill totaling $1,457 in conjunction with this acquisition which has been allocated to the completion and production services business segment. We believe this acquisition will enhance our position in the Denver-Julesburg Basin in Colorado.

We accounted for these acquisitions using the purchase method of accounting, whereby the purchase price was allocated to the fair value of net assets acquired, including definite-lived intangible assets and property, plant and equipment, with the excess recorded as goodwill. Results for each of these acquisitions were included in our accounts and results of operations since the date of acquisition. The following table summarizes the preliminary purchase price allocations for these acquisitions as of December 31, 2010:

Totals

Net assets acquired:
Accounts receivable $ 209
Inventory and other current assets 428
Property, plant and equipment 23,960
Payables and accrued liabilities (106 )
Intangible assets 2,520
Goodwill 6,710

Net assets acquired $ 33,721

Consideration:
Cash, net of cash and cash equivalents acquired $ 33,721

We determined the fair value of assets and liabilities acquired through these business acquisitions as of the acquisition date by retaining third-party consultants to perform valuation techniques related to identifiable intangible assets and to evaluate property, plant and equipment acquired based upon, at minimum, the replacement cost of the assets, except for the two saltwater disposal wells in Colorado which were newly constructed just prior to acquisition. Working capital items were deemed to have a fair market value equal to book value. Of the total intangible assets acquired, $1,670 related to customer relationship intangibles determined by applying an income approach over the expected term, allowing for customer attrition at an assumed rate.
~~(a)~~(b) Acquisitions During the Year Ended December 31, 2008:

During the year ended December 31, 2008, we acquired substantially all the assets or all of the equity interests in four oilfield service companies, for $180,154 in cash, resulting in goodwill of $71,209. Several of these acquisitions ~~are~~were subject to final working capital adjustments.

(i) On February 29, 2008, we acquired substantially all of the assets of KR Fishing & Rental, Inc. (“KR Fishing & Rental”) for $9,464 in cash, resulting in goodwill of $6,411. KR Fishing & Rental, Inc. is a provider of fishing, rental and foam unit services in the Piceance Basin and the Raton Basin, and is located in Rangely, Colorado. We believe this acquisition complements our completion and production services business in the Rocky Mountain region.

77

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

(ii) On April 15, 2008, we acquired all the outstanding common stock of Frac Source Services, Inc. (“Frac Source”), a provider of pressure pumping services to customers in the Barnett Shale of north Texas, for $62,359 ~~million~~ in cash, net of cash acquired, which includes a working capital adjustment of $1,600 and recorded goodwill of $15,431. Upon closing this transaction, we entered into a contract with one of our major customers to provide pressure pumping services in the Barnett Shale utilizing three frac fleets under a contract with a term that extends up to three years from the date each fleet is placed into service. We spent an additional $20,000 in 2008 on capital equipment related to these contracted frac fleets. Thus, our total investment in this operation was approximately $82,400. ~~We believe this~~This acquisition ~~expands~~expanded our pressure pumping business in north Texas and ~~that~~ the related contract provides a stable revenue stream from which to expand our pressure pumping business outside of this region.

(iii) On October 3, 2008, we acquired all of the membership interests of TSWS Well Services, LLC (“TSWS”), a limited liability corporation which held substantially all of the well servicing and heavy haul assets of TSWS, Inc., a company based in Magnolia, Arkansas, which provides well servicing and heavy haul services to customers in northern Louisiana, east Texas and southern Arkansas. As consideration, we paid $57,163 in cash and prepaid an additional $1,000 related to an employee retention bonus pool. We also recorded goodwill totaling $21,911. ~~The purchase price allocation associated with this~~This acquisition ~~has not yet been completed. We believe this acquisition extends~~extended our geographic reach ~~into~~in the Haynesville Shale area.

(iv) On October 4, 2008, we acquired substantially all of the assets of Appalachian Well Services, Inc. and its wholly-owned subsidiary (“AWS”), each of which is based in Shelocta, Pennsylvania. This business provides pressure pumping,e-line and coiled tubing services in the Appalachian region, and includes a service

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

area which extends through portions of Pennsylvania, West Virginia, Ohio and New York. As consideration for the purchase, we paid $50,168 in cash and issued 588,292 unregistered shares of our common stock, valued at $15.04 per share. We ~~expect to invest~~invested an additional $6,500 to complete a frac fleet at this location and have an option to purchase real property for approximately $600. In addition, we ~~have~~ entered into an agreement under which we ~~may~~might be required to pay up to an additional $5,000 in cash consideration during the earn-out period. The earn-out period ~~which extends through~~expired in 2010 ~~based upon the results of operations of various service lines acquired. The purchase price allocation associated~~ with ~~this acquisition has not yet been finalized.~~no additional consideration required. We recorded goodwill of approximately $27,456 associated with this ~~acquisition.~~acquisition, however, this goodwill was deemed impaired in 2009 and expensed as of December 31, 2009. We believe this acquisition ~~creates~~created a platform for future growth for our pressure pumping and other completion and production service lines in the Marcellus Shale.

We accounted for these acquisitions using the purchase method of accounting, whereby the purchase price was allocated to the fair value of net assets acquired, including ~~intangibles~~definite-lived intangible assets and property, plant and equipment at depreciated replacement costs, with the excess recorded as goodwill. Results for each of these acquisitions were included in our accounts and results of operations since the date of acquisition, and goodwill associated with these acquisitions was allocated entirely to the completion and production services business

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

segment. The following table summarizes our ~~preliminary~~ purchase price allocations for these acquisitions as of December 31, ~~2008, several of which are yet to be finalized:~~2008:


	KR Fishing		Frac									KR Fishing		Frac
	& Rental		Source			TSWS		AWS		Totals		& Rental		Source			TSWS		AWS		Totals

Net assets acquired:
Property, plant and equipment	$	2,673	$	41,172		$	28,852	$	24,140	$	96,837	$	2,673	$	41,172		$	28,852	$	24,140	$	96,837
Non-cash working capital		50		(2,085	)		1,000		3,226		2,191		50		(2,085	)		1,000		3,226		2,191
Intangible assets		330		6,810			6,400		4,200		17,740		330		6,810			6,400		4,200		17,740
Deferred tax asset		—		1,031			—		—		1,031		—		1,031			—		—		1,031
Goodwill		6,411		15,431			21,911		27,456		71,209		6,411		15,431			21,911		27,456		71,209

Net assets acquired	$	9,464	$	62,359		$	58,163	$	59,022	$	189,008	$	9,464	$	62,359		$	58,163	$	59,022	$	189,008

Consideration:
Cash, net of cash and cash equivalents acquired	$	9,464	$	62,359		$	58,163	$	50,168	$	180,154	$	9,464	$	62,359		$	58,163	$	50,168	$	180,154
Debt assumed in acquisition		—		—			—		8,854		8,854
Stock issued for acquisition													—		—			—		8,854		8,854

Total consideration	$	9,464	$	62,359		$	58,163	$	59,022	$	189,008	$	9,464	$	62,359		$	58,163	$	59,022	$	189,008

Of the $71,209 of goodwill above, $55,718 is tax deductible.

The purchase price of each of the businesses that we acquire is negotiated as an arm’s length transaction with the seller. We generally evaluate acquisition targets based on an earnings multiple approach, whereby we consider precedent transactions which we have undertaken and those of others in our industry.

~~In accordance with SFAS No. 157, we~~We determined the fair value of assets and liabilities acquired through these business acquisitions as of the acquisition date by retaining third-party consultants to perform valuation techniques related to identifiable intangible assets and to evaluate property, plant and equipment acquired based upon, at minimum, the replacement cost of the assets. Working capital items were deemed to ~~be acquired at~~have a fair market value equal to book value. Of the total intangible assets acquired, $14,010 related to customer relationship intangibles determined by applying an income approach over the expected term, allowing for customer ~~attribution~~attrition at an assumed rate. We considered these factors when determining the goodwill impairment recorded at December 31, ~~2008 pursuant to SFAS No. 142.~~2008. Of the businesses acquired in 2008, an insignificant portion of the goodwill associated with the acquisitions of TSWS and AWS was deemed impaired at December 31, 2008. As of December 31, 2009, the remaining goodwill associated with AWS, and other intangibles totaling $2,488, were deemed impaired and expensed.

~~COMPLETE PRODUCTION SERVICES, INC.~~
(c) Pro Forma Results

~~Notes to Consolidated Financial Statements — (Continued)~~


*~~(b)~~*	*~~Acquisitions During the Year Ended December 31, 2007:~~*

~~During~~Our acquisitions during the year ended December 31, 2007, we acquired substantially all the assets or all of the equity interests in six oilfield service businesses, and the remaining 50% interest in our Canadian joint venture, for $49,691 in cash, resulting in goodwill of $19,391. Several of these acquisitions2010 were ~~subject to final working capital adjustments. These acquisitions in 2007 were as follows:~~

(v) On January 4, 2007, we acquired substantially all of the assets of a company located in LaSalle, Colorado, which provides frac tank rental and fresh water hauling services to customers in the Wattenburg Field of the DJ Basin, which supplements our fluid handling and rental business in the Rocky Mountain region.

(vi) On February 28, 2007, we acquired substantially all of the assets of a company located in Greeley, Colorado, which provides fluid handling and fresh frac water heating services to customers in the Wattenburg Field of the DJ Basin, which also supplements our fluid handling business in the Rocky Mountain region.

(vii) On April 1, 2007, we acquired substantially all of the assets of a company located in Borger, Texas, which provides fluid handling and disposal services to customers in the Texas panhandle. We believe this acquisition complements certain operations that we acquired in 2006 within the Texas panhandle area and broadens our ability to provide fluid handling and disposal services throughout the Mid-continent region.

(viii) On June 8, 2007, we acquired all the membership interests in a business located in Rangely, Colorado, which provides rig workover and roustabout services to customers in the Rangely Weber Sand Unit and northern Piceance Basin area. This acquisition expands our geographic reach in the northern Piceance Basin, expands our workover rig capabilities and provides a beneficial customer relationship.

(ix) On October 18, 2007, we acquired all of the outstanding common stock of a company located in Kilgore, Texas, which provides remedial cement and acid services used in pressure pumping operations to customers throughout the east Texas region. This acquisition supplements our pressure pumping business and expands our presence in east Texas.

~~(x) On November 30, 2007, we acquired substantially all of the assets of a company located in Greeley, Colorado, which is ane-line~~ ~~service provider to customers in the Wattenberg Field of the DJ Basin. This acquisition supplements our completion and production services business in the Rocky Mountain region.~~

(xi) On December 31, 2007, we acquired the remaining 50% interest in our joint venture in Canada for approximately $1,600. This transaction resulted in a decrease in goodwill of $595, as the amount paid was less than the minority interest liability related to this operation just prior to the acquisition. This company provides optimization services in the Canadian market.

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

We accounted for these acquisitions using the purchase method of accounting, whereby the purchase price was allocated to the fair value of net assets acquired, including intangibles and property, plant and equipment at depreciated replacement costs, with the excess recorded as goodwill. Results for each of these acquisitions were included in our accounts and results of operations since the date of acquisition, and goodwill associated with these acquisitions was allocated entirely to the completion and production services business segment. We do not ~~deem these acquisitions~~deemed to be significant to our ~~consolidated operations~~overall results for the ~~year ended December 31, 2007. The following table summarizes our purchase price allocations for these acquisitions as of December 31, 2007:~~

Net assets acquired:
Property, plant and equipment $ 25,081
Non-cash working capital 1,397
Minority interest liability 2,188
Intangible assets 2,144
Long-term deferred tax liabilities (510 )
Goodwill 19,391

Net assets acquired $ 49,691

Consideration:
Cash, net of cash and cash equivalents acquired $ 49,691

~~The purchase price of each~~year. Therefore, no pro forma disclosure of the businesses that we acquire is negotiated as an arm’s length transaction with the seller. We generally evaluate acquisition targets based on an earnings multiple approach, whereby we consider precedent transactions which we have undertaken and those of others in our industry. To determine the fair value of assets acquired, we generally retain third-party consultants to perform valuation techniques related to identifiable intangible assets and to evaluate property, plant and equipment acquired based upon, at minimum, the replacement cost of the assets. Working capital items are deemed to be acquired at fair market value.
  ~~(c)~~   ~~Acquisitions During the Year Ended December 31, 2006:~~
~~(i)~~   ~~Outpost Office Inc. (“Outpost”):~~
On January 3, 2006, we acquired all of the operating assets of Outpost Office Inc., an oilfield equipment rental company based in Grand Junction, Colorado, for $6,542 in cash, and recorded goodwill of $2,348, which has been allocated entirely to the completion and production services business segment. We believe this acquisition supplemented our completion and production services business in the Rocky Mountain Region.
~~(ii)~~   ~~The Rosel Company (“Rosel”):~~
On January 25, 2006, we acquired all the equity interests of The Rosel Company, a cased-hole and open-hole electric-line business based in Liberal, Kansas, for $11,953, in cash, net of cash acquired and debt assumed, and recorded goodwill of $7,997 resulting from this acquisition, which has been allocated entirely to the completion and production services business segment. We believe this acquisition expanded our presence in the Mid-continent region and enhanced our completion and production services business.
~~(iii)~~   ~~The Arkoma Group of Companies (“Arkoma”):~~
On June 30, 2006, we acquired certain operating assets of J&M Rental Tool, Inc. dba Arkoma Machine & Fishing Tools, Arkoma Machine Shop, Inc. and N&M Supply, LLC, collectively referred to as The Arkoma Group of Companies, a provider of rental tools, machining and fishing services in the Fayetteville Shale and Arkoma Basin, located in Ft. Smith, Arkansas. We paid $18,002 in cash to acquire Arkoma, subject to a final working capital adjustment, and recorded goodwill totaling $8,993, which has been allocated entirely to the completion and

77

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

production services business segment. We believe this acquisition provides a platform to further expand our presence in the Fayetteville Shale and Arkoma Basin and supplement our completion and production services business in that region.


~~(iv)~~	~~CHB Holdings Partnership, Ltd. (“CHB”):~~

On July 17, 2006, we acquired all the assets of CHB Holdings Partnership, Ltd., a fluid handling and disposal services business located in Henderson, Texas, for $12,738 in cash, and recorded goodwill of $8,087, which was allocated entirely to the completion and production services business segment. We believe this acquisition is complementary to our fluid handling business in the Bossier Trend region of east Texas.


~~(v)~~	~~Turner Group of Companies (“Turner”):~~

On July 28, 2006, we acquired all of the outstanding equity interests of the Turner Group of Companies (Turner Energy Services, LLC, Turner Energy SWD, LLC, T. & J. Energy, LLC, T. & J. SWD, LLC and Lloyd Jones Well Service, LLC) for $54,328 in cash, after a final working capital adjustment, and recorded goodwill totaling $16,046. The Turner Group of Companies (“Turner”) is based in the Texas panhandle in Canadian, Texas, and owns a fleet of well service rigs, and provides other wellsite services such as fishing, equipment rental, fluid handling and salt water disposal services. We included the accounts of Turner in our completion and production services business segment and believe that Turner supplements our completion and production business in the Mid-continent region.


~~(vi)~~	~~Quinn Well Control Ltd. (“Quinn”):~~

On July 31, 2006, we acquired certain assets of Quinn Well Control Ltd., a slick line business located in Grande Prairie, Alberta, Canada, for $8,876 in cash and recorded goodwill of $4,247. We included the accounts of Quinn in our completion and production services business segment. We believe this acquisition enhances our Canadian slick-line business and expands our geographic reach in northern Alberta and northeast British Columbia.


~~(vii)~~	~~Pinnacle Drilling Co., L.L.C. (“Pinnacle”):~~

On August 1, 2006, we acquired substantially all of the assets of Pinnacle Drilling Co., L.L.C., a drilling company located in Tolar, Texas, for $31,703 in cash and recorded goodwill totaling $1,049. In addition, we paid $1,073 in cash related to this equipment during the fourth quarter of 2006. In 2007, we received $579 from the seller related to certain pre-acquisition contingencies, resulting in a decrease in goodwill. Pinnacle operates three drilling rigs, two in the Barnett Shale region in north Texas and one in east Texas. We included the accounts of Pinnacle in our drilling services business segment. We believe this acquisition increased our presence in the Barnett Shale of north Texas and the Bossier Trend of east Texas and expands our capacity to drill deep and horizontal wells, which are sought by our customers in this region.


~~(viii)~~	~~Oilfield Airfoam and Rentals I, LP (“Airfoam”):~~

On August 15, 2006, we acquired substantially all of the assets of Oilfield Airfoam and Rentals I, LP, a fishing and rental services business located in Pocola, Oklahoma, with operations in eastern Oklahoma and western Arkansas, for $6,939 in cash and recorded goodwill totaling $3,115. We paid an additional $1,180 in cash for capital equipment in process at the time of the acquisition but not received until October 2006. We included Airfoam in our completion and production services business segment. We believe this acquisition complements our completion services business in the Fayetteville Shale.


~~(ix)~~	~~Scientific Microsystems Inc. (“SMI”):~~

On August 31, 2006, we acquired all the outstanding common stock of Scientific Microsystems, Inc., for $2,900 in cash at closing and an additional $200 final working capital adjustment, and recorded goodwill totaling

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

$1,774. SMI is located in Waller, Texas, and is a manufacturer of a conventional line of plunger lift systems and related controllers, and a provider of related engineering services. In 2007, we paid $800 pursuant to an earn-out agreement with the former owners of SMI, based upon certain defined operating targets for the period from the date of acquisition through September 30, 2007. We included SMI in our completion and production services business segment. We believe the artificial lift systems manufactured by SMI complements our proprietary Pacemaker Plunger^tm ~~product.~~


~~(x)~~	~~Drilling Fluid Services, LLC (“DFS”) and KCL Company, LLC (“KCL”):~~

On September 15, 2006, we acquired substantially all of the assets of Drilling Fluid Services, LLC and KCL Company, LLC, each of which is located in Greeley, Colorado, and provide chemicals used for completion services to customers in the Wattenberg Field of the Denver-Julesburg Basin in Colorado. We paid a total of $4,250 in cash, or $2,125 each, to acquire DFS and KCL, and recorded goodwill of $1,872 and $1,847, respectively. We have included the operations of DFS and KCL in our completion and production services business segment. We believe these companies complement our completion and production services business in the Rocky Mountain region.


~~(xi)~~	~~Anderson Water Well Service, Ltd. (“Anderson”):~~

On September 29, 2006, we acquired substantially all of the assets of Anderson Water Well Service, Ltd., located in Bridgeport, Texas, for $10,760 in cash and we recorded goodwill totaling $7,914. In addition, we issued 38,268 shares of our non-vested restricted stock to the former owners of Anderson, valued at the closing price of our common stock on September 29, 2006, or an aggregate of $755, which will be expensed ratably through September 29, 2008. Anderson drills wells to source water used for hydraulic fractures in the Barnett Shale. We have included the operations of Anderson in our completion and production services business segment. We believe the acquisition of Anderson strengthens our current water well-drilling business in the Barnett Shale area.


~~(xii)~~	~~Jim Lee Trucking, Inc. (“Jim Lee”):~~

On October 13, 2006, we acquired substantially all the assets of Jim Lee Trucking, Inc. (“Jim Lee”), a company located in Rock Springs, Wyoming, for $5,000 in cash and we recorded goodwill totaling $3,842. Jim Lee is engaged in the business of hauling barite and other additives for customers in the Greater Green River Basin. We included the accounts of Jim Lee in our completion and production services business segment from the date of acquisition. We believe this acquisition is complementary to our completion and production services business in the Rocky Mountain region.


~~(xiii)~~	~~Brothers Group of Companies (“Brothers”):~~

On October 13, 2006, we acquired substantially all the assets of Brothers Industries, Ltd., Brothers Well Service, Ltd., Brothers Trucking Service, Ltd., Brothers Supply Company, Ltd., and BWS Vacuum Service, Ltd., collectively the Brothers Industries Group of Companies (“Brothers”) for $6,936 in cash and we recorded goodwill totaling $2,859. Brothers is located in El Campo, Texas, and provides various completion and production services, and has supply store operations. We included the accounts of Brothers in our completion and production services business segment from the date of acquisition. We believe this acquisition supplements our completion and production services business in the Texas region and expands our availability of products throughout the geographic regions we serve.


~~(xiv)~~	~~Femco Group of Companies (“Femco”):~~

On October 19, 2006, we acquired substantially all the assets of Femco Services, Inc., R&S Propane, Inc. and Webb Dozer Service, Inc. (collectively, “Femco”), a group of companies located in Lindsay, Oklahoma for $35,991 in cash, and we recorded goodwill totaling $11,189. Femco provides fluid handling, frac tank rental, propane distribution and fluid disposal services throughout southern central Oklahoma. We included the accounts of Femco

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

in our completion and production services business segment from the date of acquisition. We believe this acquisition expands our presence in the Fayetteville Shale and enhances our completion and production services business in the Mid-continent region.


~~(xv)~~	~~Pumpco Services, Inc. (“Pumpco”):~~

On November 8, 2006, we acquired Pumpco Services, Inc., a provider of pressure pumping services in the Barnett Shale play of north Texas, which owns and operates a fleet of pressure pumping units. Consideration for the acquisition included $144,635 in cash, net of cash received, and the issuance of 1,010,566 shares of our common stock, which was valued at the closing price listed on the New York Stock Exchange on November 8, 2006. The number of shares issued was negotiated with the seller, a related party. A fairness opinion was obtained from a third-party as to the value assigned to the common stock of Pumpco, which was used by us to negotiate the purchase price. In addition, Pumpco had debt outstanding of approximately $30,250 at the time of the acquisition. We recorded goodwill totaling $148,551 associated with this acquisition. We included the accounts of Pumpco in our completion and production services business segment from the date of acquisition. This acquisition allowed us to enter the pressure pumping business in the active Barnett Shale region of north Texas. In 2007, we reclassified $2,017 of the goodwill associated with the Pumpco acquisition to identifiable intangible assets and began amortizing this cost over the estimated lives of the related intangible assets. In addition, we reduced the goodwill balance by an additional $3,136 related to deferred tax liabilities which were deemed no longer necessary based on our 2006 tax return filings in 2007.

~~Results for each~~impact of these acquisitions ~~have~~has been included in our accounts and results of operations since the date of acquisition. The following tables summarize the purchase price allocations as of December 31, 2006 by geographic area, as indicated.provided for 2010.

Texas — US:
CHB Pinnacle Anderson SMI Brothers Pumpco Totals

Net assets acquired:
Property, plant and equipment $ 4,319 $ 31,452 $ 2,842 $ 169 $ 4,201 $ 45,976 $ 88,959
Non-cash working capital — — — 564 (424 ) 5,441 5,581
Intangible assets 332 275 4 393 300 1,000 2,304
Deferred tax liabilities — — — — — (4,659 ) (4,659 )
Goodwill 8,087 1,049 7,914 1,774 2,859 148,551 170,234

Net assets acquired $ 12,738 $ 32,776 $ 10,760 $ 2,900 $ 6,936 $ 196,309 $ 262,419

Consideration:
Cash, net of cash and cash equivalents acquired $ 12,738 $ 32,776 $ 10,760 $ 2,900 $ 6,936 $ 144,635 $ 210,745
Debt assumed in acquisition — — — — — 30,250 30,250
Common stock issued for acquisition (1,010,566 shares) — — — — — 21,424 21,424

Total consideration $ 12,738 $ 32,776 $ 10,760 $ 2,900 $ 6,936 $ 196,309 $ 262,419

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~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

Mid-continent — US:
Arkoma Turner Airfoam Rosel Femco Totals

Net assets acquired:
Property, plant and equipment $ 6,099 $ 31,313 $ 4,829 $ 5,615 $ 20,226 $ 68,082
Non-cash working capital 2,496 6,914 — 379 4,426 14,215
Intangible assets 414 55 175 341 150 1,135
Deferred tax liabilities — — — (1,845 ) — (1,845 )
Goodwill 8,993 16,046 3,115 7,997 11,189 47,340

Net assets acquired $ 18,002 $ 54,328 $ 8,119 $ 12,487 $ 35,991 $ 128,927

Consideration:
Cash, net of cash and cash equivalents acquired $ 18,002 $ 54,328 $ 8,119 $ 11,953 $ 35,991 $ 128,393
Debt assumed in acquisition — — — 534 — 534

Total consideration $ 18,002 $ 54,328 $ 8,119 $ 12,487 $ 35,991 $ 128,927

Rocky Mountains — US Canada
Other:
Outpost KCL DFS Jim Lee Quinn Totals

Net assets acquired:
Property, plant and equipment $ 4,297 $ 225 $ 200 $ 1,008 $ 4,066 $ 9,796
Non-cash working capital (225 ) — — — 45 (180 )
Intangible assets 122 53 53 150 518 896
Goodwill 2,348 1,847 1,872 3,842 4,247 14,156

Net assets acquired $ 6,542 $ 2,125 $ 2,125 $ 5,000 $ 8,876 $ 24,668

Consideration:
Cash, net of cash and cash equivalents acquired $ 6,542 $ 2,125 $ 2,125 $ 5,000 $ 8,876 $ 24,668

Mid-
Rocky

Overall Summary:
Texas Continent Mountains Canada Totals

Net assets acquired:
Property, plant and equipment $ 88,959 $ 68,082 $ 5,730 $ 4,066 $ 166,837
Non-cash working capital 5,581 14,215 (225 ) 45 19,616
Intangible assets 2,304 1,135 378 518 4,335
Deferred tax liabilities (4,659 ) (1,845 ) — — (6,504 )
Goodwill 170,234 47,340 9,909 4,247 231,730

Net assets acquired $ 262,419 $ 128,927 $ 15,792 $ 8,876 $ 416,014

Consideration:
Cash, net of cash and cash equivalents acquired $ 210,745 $ 128,393 $ 15,792 $ 8,876 $ 363,806
Debt assumed in acquisition 30,250 534 — — 30,784
Common stock issued for acquisition (1,010,566 shares) 21,424 — — — 21,424

Total consideration $ 262,419 $ 128,927 $ 15,792 $ 8,876 $ 416,014

81

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~


*~~(d)~~*	*~~Pro Forma Results:~~*

We calculated the pro forma impact of the businesses we acquired on our operating results for the ~~years~~year ended December 31, ~~2008 and 2007.~~2008. The following pro forma results give effect to each of these acquisitions, assuming that each occurred on January 1, ~~2008 and 2007, as applicable.~~2008.

We derived the pro forma results of these acquisitions based upon historical financial information obtained from the sellers and certain management assumptions. In addition, we assumed debt service costs related to these acquisitions based upon the actual cash investments, calculated at a rate of 7% per annum, less an assumed tax benefit calculated at our statutory rate of 35%. Each of these acquisitions related to our continuing operations, and, thus, had no pro forma impact on discontinued operations presented on the accompanying ~~statements~~statement of ~~operations.~~operations for the year ended December 31, 2008.

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

The following pro forma results do not purport to be indicative of the results that would have been obtained had the transactions described above been completed on the indicated dates or that may be obtained in the future.

Pro Forma Results
For the Year Ended

December 31,
2008 2007

Revenue $ 1,905,518 $ 1,587,040
Income before taxes and minority interest $ 4,244 $ 245,693
Net income (loss) from continuing operations $ (74,090 ) $ 156,535
Net income (loss) $ (78,949 ) $ 167,978
Earnings (loss) per share:
Basic $ (1.07 ) $ 2.33

Diluted $ (1.07 ) $ 2.29

Pro Forma Results
For the Year Ended

December 31,

2008
(Unaudited)

Revenue $ 1,901,879
Loss before taxes $ (2,132 )
Net loss from continuing operations $ (78,203 )
Net loss $ (83,062 )
Loss per share:
Basic $ (1.13 )

Diluted $ (1.13 )

4. Accounts receivable:

2008 2007 2010 2009

Trade accounts receivable $ 292,777 $ 251,361 $ 253,662 $ 155,871
Related party receivables(a) 11,631 8,048 51,046 6,593
Unbilled revenue 39,749 41,334 42,747 19,409
Notes receivable 283 3,378
Other receivables 4,889 7,048
Notes and other receivables 2,353 1,975

349,329 311,169 349,808 183,848
Allowance for doubtful accounts 5,976 5,487 4,160 12,564

$ 343,353 $ 305,682 $ 345,648 $ 171,284

(a) See Note 19, ~~Related Party Transactions.~~“Related party transactions.”

The following table summarizes the change in our allowance for doubtful accounts for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006:~~2008:

Balance at
Additions
Write-offs
Balance at
Balance at
Additions
Write-offs
Balance at
Beginning
Charged
or
End of
Beginning
Charged
or
End of
Year Ended
of Period to Expense Adjustments Period of Period to Expense Adjustments Period

2010 $ 12,564 $ (159 ) $ (8,245 ) $ 4,160
2009 $ 5,976 $ 10,770 $ (4,182 ) $ 12,564
2008 $ 5,487 $ 4,344 $ (3,855 ) $ 5,976 $ 5,487 $ 4,344 $ (3,855 ) $ 5,976
2007 $ 2,181 $ 6,613 $ (3,307 ) $ 5,487
2006 $ 1,872 $ 2,102 $ (1,793 ) $ 2,181
5. Inventory:

2010 2009

Finished goods $ 18,644 $ 23,435
Manufacturing parts, materials and fuel 16,063 14,486
Work in process 1,282 431

35,989 38,352
Inventory reserves 2,453 888

$ 33,536 $ 37,464

8280

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


5.	~~Inventory:~~

2008 2007

Finished goods $ 20,915 $ 22,235
Manufacturing parts, materials and fuel 16,353 9,055
Work in process 5,333 257

42,601 31,547
Inventory reserves 710 1,670

$ 41,891 $ 29,877

6. Property, plant and equipment:

Accumulated
Net Book
Accumulated
Net Book

December 31, 2008
Cost Depreciation Value
December 31, 2010 Cost Depreciation Value

Land $ 10,078 $ — $ 10,078 $ 16,153 $ — $ 16,153
Building 20,155 2,097 18,058 32,083 4,456 27,627
Field equipment 1,314,104 359,385 954,719 1,434,986 642,302 792,684
Vehicles 152,297 49,826 102,471 128,381 58,110 70,271
Office furniture and computers 16,069 6,736 9,333 18,259 11,970 6,289
Leasehold improvements 23,679 3,193 20,486 26,644 7,538 19,106
Construction in progress 51,308 — 51,308 23,898 — 23,898

$ 1,587,690 $ 421,237 $ 1,166,453 $ 1,680,404 $ 724,376 $ 956,028

Accumulated
Net Book
Accumulated
Net Book

December 31, 2007
Cost Depreciation Value
December 31, 2009 Cost Depreciation Value

Land $ 9,259 $ — $ 9,259 $ 8,884 $ — $ 8,884
Building 17,667 1,545 16,122 30,200 3,168 27,032
Field equipment 1,049,761 237,481 812,280 1,293,292 497,632 795,660
Vehicles 91,853 20,550 71,303 126,256 55,035 71,221
Office furniture and computers 12,391 4,212 8,179 17,087 9,108 7,979
Leasehold improvements 16,368 1,588 14,780 25,006 4,771 20,235
Construction in progress 81,267 — 81,267 10,122 — 10,122

$ 1,278,566 $ 265,376 $ 1,013,190 $ 1,510,847 $ 569,714 $ 941,133

Construction in progress at December 31, ~~2008~~2010 and ~~2007~~2009 primarily included progress payments to vendors for equipment to be delivered in future periods and component parts to be used in final assembly of operating equipment, which in all cases were not yet placed into service at the time. For the years ended December 31, ~~2008~~2010, 2009 and ~~2007,~~2008, we recorded capitalized interest of ~~$4,458~~$1,250, $878 and ~~$3,922,~~$4,458, respectively, related to assets that we are constructing for internal use and amounts paid to vendors under progress payments for assets that are being constructed on our behalf.
Effective March 1, 2009, our Canadian subsidiary transferred certain property, plant and equipment used in our production testing business to Enseco, a competitor, in exchange for certain electric line(e-line) equipment. This exchange was determined to have commercial substance for us and therefore we recorded the new assets acquired at the fair market value of the assets surrendered which had a carrying value of $9,284. We incurred costs to sell totaling approximately $71. We determined the fair value of the assets with the assistance of a third-party appraiser, assuming an orderly liquidation methodology, to be $4,487, resulting in a loss on the exchange of $4,868. Of the total value assigned to the new assets, $4,209 was included in property, plant and equipment and $279 was included in inventory in the accompanying balance sheet as of December 31, 2009. The fair market value of the assets received was determined to be $5,497, using the same methodology applied to the assets surrendered. We believe that thesee-line assets will generate cash flows in excess of the cash flows that would have been received from the production testing assets due to relatively higher demand from our customers fore-line services.
Effective March 31, 2009, we entered into a sale-leaseback transaction with Agua Dulce, LLC, through which we sold a facility and approximately 50 acres of real property located near Rock Springs, Wyoming for $3,827. The sales price approximated the net book value of the facility, which is currently under construction, and the land, resulting in an insignificant gain on the transaction which has been included as a component of selling, general and administrative expense in the accompanying statement of operations for the year ended December 31, 2009. In

8381

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

addition, the buyer agreed to fund the completion of the construction of the facility. Effective April 1, 2009, we became party to the lease agreement which requires monthly operating lease payments for a term of 10 years, with an option to extend the lease term for an additional 10 years. The rental rate adjusts for construction draws to date divided ratably over the remaining lease term. The lease term began on April 1, 2009 and the first monthly rental was $35. We will also incur additional lease costs related to certain operating costs, taxes and insurance for the facility over the term of the lease.

Effective July 30, 2009, we entered into a sale-leaseback agreement with Enterprise Leasing Company of Houston to sell over 550 light-vehicles with a net book value of approximately $10,362 as of July 30, 2009. During the third quarter of 2009, we received proceeds from the sale which totaled $10,551. In August 2009, pursuant to this lease agreement, we began making monthly rental payments of approximately $306. The lease terms range from 24 to 36 months.


7.	Intangible assets:


			As of December 31, 2008						As of December 31, 2007								As of December 31, 2010						As of December 31, 2009
			Historical		Accumulated		Net Book		Historical		Accumulated		Net Book				Historical		Accumulated		Net Book		Historical		Accumulated		Net Book
Description	Term		Cost		Amortization		Value		Cost		Amortization		Value		Term		Cost		Amortization		Value		Cost		Amortization		Value
	(In months)														(In months)

Patents and trademarks		60 to 120	$	5,448	$	864	$	4,584	$	4,026	$	937	$	3,089		60 to 120	$	5,215	$	3,353	$	1,862	$	5,942	$	2,421	$	3,521
Contractual agreements		24 to 120		10,555		5,284		5,271		9,150		3,621		5,529		24 to 120		11,985		8,660		3,325		9,455		6,644		2,811
Customer lists and other		36 to 60		17,244		3,837		13,407		3,192		1,204		1,988		36 to 60		13,302		9,280		4,022		13,322		6,411		6,911

Totals			$	33,247	$	9,985	$	23,262	$	16,368	$	5,762	$	10,606			$	30,502	$	21,293	$	9,209	$	28,719	$	15,476	$	13,243

We recorded amortization expense associated with intangible assets of continuing operations totaling ~~$5,248, $2,918~~$6,591, $7,769 and ~~$1,662~~$5,248 for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006,~~2008, respectively. We expect to record amortization expense associated with these intangible assets for the next five years approximating: ~~2009 — $5,782; 2010 — $7,630;~~ 2011 — ~~$5,123;~~$4,645; 2012 — ~~$3,000; and~~$2,926; 2013 — ~~$1,619.~~$1,341; 2014 — $170 and 2015 — $127.


8.	Deferred financing costs:


			Accumulated		Net				Accumulated		Net
	Cost		Amortization		Book Value		Cost		Amortization		Book Value

December 31, 2008
December 31, 2010
Deferred financing costs	$	16,649	$	4,186	$	12,463	$	19,010	$	9,316	$	9,694

December 31, 2007
December 31, 2009
Deferred financing costs	$	16,649	$	2,455	$	14,194	$	19,010	$	6,266	$	12,744

We incurred deferred financing costs ~~during 2006~~associated with our amended credit facility as well as $13,414 related to the issuance of our senior notes in December ~~2006 totaling $13,414 and $718 associated with the amendment of our existing term loan and revolving credit facility.~~

~~We assumed the debt of Pumpco upon acquisition on November 11,~~ 2006. In ~~December 2006,~~October 2009, we ~~retired all outstanding borrowings under the Pumpco term loan~~amended our senior secured credit facility and incurred ~~a $170 charge~~additional financing costs of $2,911 in the fourth quarter of 2009. In October 2009, due to ~~expense~~ the ~~remaining~~decrease in borrowing capacity after giving effect to the amendment, we expensed $528 of unamortized ~~deferred financing costs.~~fees related to our prior revolving credit facilities.

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


9.	Taxes:

Tax expense (benefit) from continuing operations consisted of:


	2008			2007			2006		2010			2009			2008

Domestic:
Current income taxes	$	44,754		$	43,687		$	38,107	$	(105	)	$	(59,637	)	$	42,490
Deferred income taxes		24,738			38,786			27,138		48,468			(4,733	)		24,739

		69,492			82,473			65,245		48,363			(64,370	)		67,229
Foreign:
Current income taxes		9,256			7,148			3,585		3,844			4,116			8,988
Deferred income taxes (benefit)		(4,180	)		(2,770	)		1,686
Deferred income taxes										(627	)		(2,834	)		(3,912	)

		5,076			4,378			5,271		3,217			1,282			5,076

Tax expense — continuing operations	$	74,568		$	86,851		$	70,516
Tax expense (benefit) — continuing operations									$	51,580		$	(63,088	)	$	72,305

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

We operate in several tax jurisdictions. A reconciliation of the U.S. federal income tax rate of 35% for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006~~2008 to our effective income tax rate follows:


	2008			2007			2006			2010			2009			2008

Expected provision for taxes:	$	(2,110	)	$	82,728		$	68,412		$	47,508		$	(85,665	)	$	(4,341	)
Increase (decrease) resulting from foreign tax rate differential		280			2,626			(1,756	)		(528	)		(1,971	)		280
(Increase) decrease in foreign deferred taxes		746			(760	)		—
Change in foreign tax rates											—			68			746
Change in domestic tax rates											1,357			4,544			—
State taxes, net of federal benefit		5,021			6,501			4,995			978			(4,948	)		4,989
Non-deductible expenses		70,619			(2,296	)		(1,282	)		2,180			18,125			70,619
Other, net		12			(1,948	)		147			85			6,759			12

Tax expense — continuing operations	$	74,568		$	86,851		$	70,516
Tax expense (benefit) — continuing operations										$	51,580		$	(63,088	)	$	72,305

~~The net deferred income tax liability from continuing operations was comprised of~~Non-deductible expenses for the ~~tax effect of the following temporary differences:~~

2008 2007

Deferred income tax assets:
Net operating loss $ 1,746 $ 445
Goodwill and intangible assets 5,086 —
Accrued liabilities and other 8,089 3,500
Stock-based compensation costs 5,105 3,843

20,026 7,788
Less valuation allowance (270 ) (290 )

19,756 7,498

Deferred income tax liabilities:
Property, plant and equipment (153,148 ) (119,182 )
Goodwill — (10,417 )
Other (14,256 ) (4,720 )

(167,404 ) (134,319 )

Net deferred income tax liability $ (147,648 ) $ (126,821 )

~~The net deferred income tax liability consisted of:~~

2008 2007

Domestic $ (143,793 ) $ (119,055 )
Foreign (3,855 ) (7,766 )

$ (147,648 ) $ (126,821 )

~~Net operating loss carryforwards are included in the determination of our deferred tax asset at~~years ended December 31, ~~2008. We will need~~2009 and 2008 relate primarily to ~~generate future taxable income of approximately $5,465 in order to fully utilize our net operating loss carryforwards.~~
~~We had U.S. loss carryforwards of $2,535 at~~impaired goodwill with limited tax basis. There was no goodwill impairment for the year ended December 31, ~~2008 and no U.S. loss carryforwards at December 31, 2007. We have a $2,930 foreign non-capital loss carryforward at December 31, 2008, compared to $1,534 at December 31, 2007.~~2010.

8583

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

The net deferred income tax liability was comprised of the tax effect of the following temporary differences:

2010 2009

Deferred income tax assets:
Net operating loss $ 10,386 $ 6,909
Goodwill and intangible assets 9,240 14,487
Accrued liabilities and other 6,789 4,853
Stock-based compensation costs 4,125 6,744

30,540 32,993
Less valuation allowance (253 ) (265 )

30,287 32,728

Deferred income tax liabilities:
Property, plant and equipment (213,589 ) (168,450 )
Other (4,621 ) (4,360 )

(218,210 ) (172,810 )

Net deferred income tax liability $ (187,923 ) $ (140,082 )

The net deferred income tax liability consisted of:

2010 2009

Domestic $ (187,988 ) $ (139,061 )
Foreign 65 (1,021 )

$ (187,923 ) $ (140,082 )

Included in our deferred tax assets are state tax net operating loss carry forwards of $9,279. We expect to generate future state taxable income to fully utilize these loss carry forwards.
We had no U.S. federal loss carry forward at December 31, 2010 and $3,592 of U.S. loss carry forward at December 31, 2009. We have $1,107 of foreign non-capital loss carry forward at December 31, 2010, compared to $2,930 at December 31, 2009.
No deferred income taxes were provided on ~~$11,989~~$28,584 of undistributed earnings of foreign subsidiaries as of December 31, ~~2008,~~2010, as we intend to indefinitely reinvest these funds. 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. It is not practical, however, to estimate the amount of taxes that may be payable on the eventual distribution of these earnings after consideration of available foreign tax credits.

We adopted the FASB ~~Interpretation No. 48 entitled “Accounting~~interpretation on accounting for ~~Uncertainty~~uncertainty in ~~Income Taxes — an interpretation of FASB Statement No. 109,” referred to as “FIN 48,”~~income taxes as of January 1, 2007. ~~FIN 48~~This guidance clarifies the accounting for uncertain tax positions that may have been taken by an entity. Specifically, ~~FIN 48~~it prescribes a more-likely-than-not recognition threshold to measure a tax position taken or expected to be taken in a tax return through a two-step process: (1) determining whether it is more likely than not that a tax position will be sustained upon examination by taxing authorities, after all appeals, based upon the technical merits of the position; and (2) measuring to determine the amount of benefit/expense to recognize in the financial statements, assuming taxing authorities have all relevant information concerning the issue. The tax position is measured at the largest amount of benefit/expense that is greater than 50 percent likely of being realized upon ultimate settlement. This pronouncement also specifies how to present a liability for unrecognized tax benefits in a classified balance sheet, but does not change the classification requirements for deferred taxes. Under ~~FIN 48,~~this guidance, if a tax position previously failed the more-likely-than-not recognition threshold, it should be recognized in the first subsequent

84

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

financial reporting period in which the threshold is met. Similarly, a position that no longer meets this recognition threshold should no longer be recognized in the first financial reporting period in which the threshold is no longer met.

We performed an examination of our tax positions and calculated the cumulative amount of our estimated exposure by evaluating each issue to determine whether the impact exceeded the 50 percent threshold of being realized upon ultimate settlement with the taxing authorities. Based upon this examination, we determined that the aggregate exposure under FIN 48 did not have a material impact on our financial statements during the years ended December 31, 2008 and 2007. Therefore, we have not recorded an adjustment to our financial statements related to the adoption of FIN 48. We will continue to evaluate our tax positions in accordance with FIN 48, and recognize any future impact under FIN 48 as a charge to income in the applicable period in accordance with the standard. Our tax filings for tax years 2005 to 2007 remain open for examination by taxing authorities.

Our accounting policy related to income tax penalties and interest assessments is to accrue for these costs and record a charge to selling, general and administrative expense for tax penalties and a charge to interest expense for interest assessments during the period that we take an uncertain tax position through resolution with the taxing authorities or the expiration of the applicable statute of limitations. We did not record any significant amounts related to penalties and interest during the years ended December 31, 2008, 2007 and 2006.

~~In May 2007, the~~The FASB issued ~~FASB Staff PositionFIN 48-1,~~ ~~an amendment to FIN 48, which provides~~additional guidance on how an entity is to determine whether a tax position has effectively settled for purposes of recognizing previously unrecognized tax benefits. Specifically, this guidance states that an entity would recognize a benefit when a tax position is effectively settled using the following criteria: (1) the taxing authority has completed its examination including all appeals and administrative reviews; (2) the entity does not plan to appeal or litigate any aspect of the tax position; and (3) it is remote that the taxing authority would examine or reexamine any aspect of the tax position, assuming the taxing authority has full knowledge of all relevant information relative to making their assessment on the position.

We performed an examination of our tax positions and calculated the cumulative amount of our estimated exposure by evaluating each issue to determine whether the impact exceeded the 50 percent threshold of being realized upon ultimate settlement with the taxing authorities. Based upon this examination, we determined that the aggregate exposure did not have a material impact on our financial statements during the years ended December 31, 2010, 2009 and 2008. Therefore, we have not recorded an adjustment to our financial statements related to this interpretation. We will ~~apply this guidance going forward,~~continue to evaluate our tax positions, and recognize any future impact as ~~applicable.~~a charge to income in the applicable period in accordance with the standard. Our tax filings for tax years 2006 to 2009 remain open for examination by taxing authorities. We do not anticipate any significant changes in our uncertain tax positions during the next twelve months.


10.	Notes payable:

~~On January 5, 2006, we~~We entered into a note ~~agreement with our insurance broker~~arrangement to finance certain of our annual insurance premiums for the policy ~~year beginning~~term from December 1, ~~2005~~2007 to April 30, 2009. Effective May 1, 2009, we renewed our insurance policies and entered into a similar financing arrangement for the twelve-month policy term which extended through ~~November 30, 2006. As of December 31, 2005,~~April 2010. Concurrently, we ~~recorded~~renewed our workers’ compensation, general liability and auto insurance policies through our insurance broker for the same policy term. Our accounting policy has been to record a ~~note payable totaling $14,584 and an offsetting~~ prepaid asset associated with certain of these policies which ~~included a broker’s fee. We~~is amortized over the ~~prepaid asset~~term and which takes into account actual premium payments and deposits made to ~~expense over~~date, to record an accrued liability for premiums which are contractually committed for the policy term and ~~incurred finance charges totaling $268 as interest expense related~~ to ~~this arrangement during 2006. This policy was~~make monthly premium payments in accordance with our premium commitments and monthly note payments for amounts financed. Effective May 1, 2010, we renewed our annual insurance premiums for the policy term May 1, 2010 through April 30, 2011, but chose to prepay our premiums for certain insurance coverages which had been financed through a note arrangement in prior renewals, and to continue to make monthly premium payments through our broker for other insurance coverages, including workers’ compensation, general liability and auto insurance during this twelve-month policy term. As a result, we recorded a prepaid asset of $4,267 in May 2010 associated with these renewals.

8685

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

beginning December 1, 2006 through November 30, 2007, pursuant to which we recorded a note payable and an offsetting prepaid asset totaling $17,087 as of December 31, 2006, which included a broker’s fee. Of this liability, $10,190 was paid on January 5, 2007, and the remainder was paid during the policy term. We entered into a new note arrangement to finance our annual insurance premiums for the policy term beginning December 1, 2007 and extending through April 30, 2009. As of December 31, 2007, we recorded a note payable totaling $15,354 and an offsetting prepaid asset which included a broker’s fee. Of this prepaid asset, we recorded $3,257 as a long-term asset at December 31, 2007. At December 31, 2008, this note balance totaled $1,353 and was classified as a current liability.


11.	Long-term debt:

The following table summarizes long-term debt as of December 31, ~~2008~~2010 and ~~2007:~~2009:


	2008		2007		2010		2009

U.S. revolving credit facility(a)	$	186,000	$	160,000	$	—	$	—
Canadian revolving credit facility(a)		7,495		12,219		—		—
8% senior notes(b)		650,000		650,000		650,000		650,000
Subordinated seller notes(c)		3,450		3,450
Capital leases and other(d)		700		714
Capital leases and other						—		230

		847,645		826,383		650,000		650,230
Less: current maturities of long-term debt and capital leases		3,803		398		—		228

	$	843,842	$	825,985	$	650,000	$	650,002


(a)		We maintain a senior secured ~~credit~~ facility (the “Credit Agreement”) with Wells Fargo Bank, National Association, as U.S. Administrative Agent, HSBC Bank Canada, as Canadian Administrative Agent, and certain other financial institutions. On October 13, 2009, we entered into the Third Amendment (the Credit Agreement after giving effect to the Third Amendment, the “Amended Credit Agreement”) and modified the structure of our existing credit facility to an asset-based facility subject to borrowing base restrictions. In connection with the Third Amendment, Wells Fargo Capital Finance, LLC (formerly known as Wells Fargo Foothill, LLC) replaced Wells Fargo Bank, National Association, as U.S. Administrative Agent and also serves as U.S. Issuing Lender and U.S. Swingline Lender under the Amended Credit Agreement. The Amended Credit Agreement provides for a ~~$360,000~~ U.S. revolving credit facility of up to $225,000 that matures in December 2011 and a ~~$40,000~~ Canadian revolving credit facility of up to $15,000 (with Integrated Production Services Ltd., one of our wholly-owned subsidiaries, as the borrower ~~thereof)~~thereof (“Canadian Borrower”)) that matures in December 2011. The ~~U.S. revolving credit facility~~Amended Credit Agreement includes a provision for a “commitment increase” ~~clause,~~, as defined ~~in the Credit Agreement,~~therein, which permits us to effect up to two separate increases in the aggregate commitments under the ~~facility~~Amended Credit Agreement by designating ~~a participating lender~~one or more existing lenders or other banks or financial institutions, subject to the bank’s sole discretion as to participation, to provide additional aggregate financing up to $75,000, with each committed increase ~~its commitment, by mutual agreement, in increments of~~equal to at least ~~$50,000, with~~$25,000 in the ~~aggregate of such commitment increases not to exceed $100,000,~~U.S., or $5,000 in Canada, and in accordance with other provisions as stipulated in the ~~amendment.~~Amended Credit Agreement. Certain portions of the credit facilities are available to be borrowed in U.S. dollars, Canadian dollars ~~Pounds Sterling, Euros~~ and other currencies approved by the lenders.

		Our U.S. borrowing base is limited to: (1) 85% of U.S. eligible billed accounts receivable, less dilution, if any, plus (2) the lesser of 55% of the amount of U.S. eligible unbilled accounts receivable or $10.0 million, plus (3) the lesser of the “equipment reserve amount” and 80% times the most recently determined “net liquidation percentage”, as defined in the Amended Credit Agreement, times the value of our and the U.S. subsidiary guarantors’ equipment, provided that at no time shall the amount determined under this clause exceed 50% of the U.S. borrowing base, minus (4) the aggregate sum of reserves established by the U.S. Administrative Agent, if any. The “equipment reserve amount” means $50.0 million upon the effective date of the Third Amendment, less $0.6 million for each subsequent month, not to be reduced below zero in the aggregate.

		The Canadian borrowing based is limited to: (1) 80% of Canadian eligible billed accounts receivable, plus (2) if the Canadian Borrower has requested credit for equipment under the Canadian borrowing base, the lesser of (a) $15.0 million, and (b) 80% times the most recently determined “net liquidation percentage”, as defined in the Amended Credit Agreement, times the value (calculated on a basis consistent with our historical accounting practices) of our and the US subsidiary guarantors’ equipment, minus (3) the aggregate amount of reserves established by our Canadian Administrative Agent, if any.

		Subject to certain limitations set forth in the Amended Credit Agreement, we have the ability to elect how interest under the Amended Credit Agreement will be computed. Interest under the Amended Credit Agreement may be determined by reference to (1) the London Inter-bank Offered Rate, or LIBOR, plus an applicable margin between 0.75% and 1.75% per annum (with the applicable margin depending upon our ratio of total debt to EBITDA (as defined in the agreement)), or (2) the Base Rate (i.e., the higher of the Canadian bank’s prime rate or the CDOR rate plus 1.0%, in the case of Canadian loans or the greater of the prime rate and the federal funds rate plus 0.5%, in the case of U.S. loans), plus an applicable margin between 0.00% and 0.75% per annum. If an event of default exists under the Credit Agreement, advances will bear interest at the then-applicable rate plus 2%. Interest is payable quarterly for base rate loans and at the end of applicable interest periods for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest will be paid at the end of each three-month period.

		The Credit Agreement also contains various covenants that limit our and our subsidiaries’ ability to: (1) grant certain liens; (2) make certain loans and investments; (3) make capital expenditures; (4) make distributions; (5) make acquisitions; (6) enter into hedging transactions; (7) merge or consolidate; or (8) engage in certain asset dispositions. Additionally, the Credit Agreement limits our and our subsidiaries’ ability to incur additional

8786

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


		~~indebtedness if: (1) we are not in pro forma compliance with all terms under~~an applicable margin between 3.75% and 4.25% per annum (with the Credit Agreement, (2) certain covenants of the additional indebtedness are more onerous than the covenants set forth in the Credit Agreement, or (3) the additional indebtedness provides for amortization, mandatory prepayment or repurchases of senior unsecured or subordinated debt during the duration of the Credit Agreement with certain exceptions. The Credit Agreement also limits additional secured debt to 10% ofapplicable margin depending upon our ~~consolidated net worth (i.e.~~“excess availability amount”, the excess of our assets over the sum of our liabilities plus the minority interests). The Credit Agreement contains covenants which, among other things, require us and our subsidiaries, on a consolidated basis, to maintain specified ratios or conditions as follows (with such ratios tested at the end of each fiscal quarter): (1) total debt to EBITDA, as defined in the Amended Credit Agreement) or (2) the “Base Rate” (which means the higher of the Prime Rate, Federal Funds Rate plus 0.50%,3-month LIBOR plus 1.00% and 3.50%), plus the applicable margin, as described above. For the period from the effective date of the Third Amendment until the six month anniversary of the effective date of the Third Amendment, interest was computed with an applicable margin rate of 4.00%. If an event of default exists or continues under the Amended Credit Agreement, advances will bear interest as described above with an applicable margin rate of ~~not more than 3.0 to 1.0; and (2) EBITDA, as defined, to total interest expense~~4.25% plus 2.00%. Additionally, if an event of ~~not less than 3.0 to 1.0. We were in compliance with all debt covenants~~default exists under the ~~amended and restated~~Amended Credit Agreement, as defined therein, the lenders could accelerate the maturity of ~~December 31, 2008.~~the obligations outstanding thereunder and exercise other rights and remedies. Interest is payable monthly.

		Under the Amended Credit Agreement, we are permitted to prepay our ~~borrowings.~~borrowings and we have the right to terminate, in whole or in part, the unused portion of the U.S. commitments in $1.0 million increments upon written notice to the U.S. Administrative Agent. If all of the U.S. facility is terminated, the Canadian facility must also be terminated.

		All of the obligations under the U.S. portion of the Amended Credit Agreement are secured by first priority liens on substantially all of our assets and the assets of our U.S. subsidiaries as well as a pledge of approximately 66% of the stock of our first-tier foreign subsidiaries. Additionally, all of the obligations under the U.S. portion of the Amended Credit Agreement are guaranteed by substantially all of our U.S. subsidiaries. ~~All of the~~The obligations under the Canadian ~~portions~~portion of the Amended Credit Agreement are secured by first priority liens on substantially all of our assets and the assets of our ~~subsidiaries.~~subsidiaries (other than our Mexican subsidiary). Additionally, all of the obligations under the Canadian ~~portions~~portion of the Amended Credit Agreement are guaranteed by us as well as certain of our subsidiaries.

		~~If an event~~The Amended Credit Agreement also contains various covenants that limit our and our subsidiaries’ ability to: (1) grant certain liens; (2) incur additional indebtedness; (3) make certain loans and investments; (4) make capital expenditures; (5) make distributions; (6) make acquisitions; (7) enter into hedging transactions; (8) merge or consolidate; or (9) engage in certain asset dispositions. The Amended Credit Agreement contains one financial maintenance covenant which requires us and our subsidiaries, on a consolidated basis, to maintain a “fixed charge coverage ratio”, as defined in the Amended Credit Agreement, of ~~default exists~~not less than 1.10 to 1.00. This covenant is only tested if our “excess availability amount”, as defined under the Amended Credit Agreement, plus certain qualified cash and cash equivalents (collectively “Liquidity”) is less than $50.0 million for a period of 5 consecutive days and continues only until such time as ~~defined therein, the lenders may accelerate the maturity~~our Liquidity has been greater than or equal to $50.0 million for a period of ~~the obligations outstanding under the Credit Agreement and exercise other rights and remedies. While an event~~90 consecutive days or greater than or equal to $75.0 million for a period of ~~default is continuing, advances will bear interest at the then-applicable rate plus 2%.~~45 consecutive days.

		~~All borrowings outstanding under~~Our fixed charge coverage ratio covenant is calculated, for fiscal quarters ending after September 30, 2009, as the ~~term loan portion~~ratio of “EBITDA” calculated for the four fiscal quarter period ended after September 30, 2009 minus capital expenditures made with cash (to the extent not already incurred in a prior period) or incurred during such four quarter period, compared to “fixed charges”, calculated for the four quarters then ended. “EBITDA” is defined in the Amended Credit Agreement as consolidated net income for the period plus, to the extent deducted in determining our consolidated net income, interest expense, taxes, depreciation, amortization and other non-cash charges for such period, provided that EBITDA shall be subject to pro forma adjustments for acquisitions and non-ordinary course asset sales assuming that such transactions occurred on the first day of the ~~amended~~determination period, which adjustments shall be made in accordance with the guidelines for pro forma presentations set forth by the Securities and Exchange Commission. “Fixed charges”, as defined in the Amended Credit Agreement, ~~bore~~include interest expense, among other things, reduced by the amortization of transaction fees associated with the Third Amendment.

		We were not subject to the fixed charge coverage ratio covenant in the Amended Credit Agreement as of December 31, 2010 since the Excess Availability Amount plus Qualified Cash Amount (each as defined in the

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


		Amended Credit Agreement) exceeded $50,000. If we had been subject to the fixed charge coverage ratio covenant at ~~7.66% through 2006 until the term loan was retired~~December 31, 2010, we would have been in ~~December 2006.~~ compliance.

		There were no borrowings outstanding under ~~the term loan portion of the facility at December 31, 2008 and 2007. Borrowings under the~~our U.S. ~~revolving facility bore interest at 3.50% and the~~or Canadian revolving credit ~~facility bore interest at rates ranging from 3.75% to 4.00%, or a weighted average~~facilities as of ~~3.80% at~~ December 31, ~~2008. For the years ended December 31, 2008 and 2007, the weighted average interest rates on average borrowings under the amended Credit Facility were approximately 3.92% and 6.56%, respectively.~~2010. There were letters of credit outstanding under the U.S. revolving portion of the facility totaling ~~$37,699~~$26,370, which reduced the available borrowing capacity as of December 31, ~~2008.~~2010. We incurred fees related to our letters of ~~1.25%~~credit as of December 31, 2010 at 3.75% per annum. For the twelve months ended December 31, 2010, fees related to our letters of credit were calculated using a360-day provision, at 4.0% per annum. The availability of the ~~total amount outstanding under letter~~U.S. and Canadian revolving credit facilities is determined by our borrowing base less any borrowings and letters of credit ~~arrangements through December 31, 2008. Our available~~outstanding. The net excess availability under our borrowing ~~capacity under~~base calculations for the U.S. and Canadian revolving facilities at December 31, ~~2008~~2010 was ~~$136,301~~$187,380 and ~~$32,505,~~$8,405, respectively.

		The primary purpose of our letters of credit is to secure potential future claim liability which may be incurred by our insurance providers. During the quarter ended September 30, 2010, we negotiated a reduction in our letter of credit requirements of $5,569. In addition, we placed $17,000 in escrow as a compensating balance, effectively cash collateralizing a portion of our letters of credit, in order to better utilize excess cash and reduce interest expense. This compensating balance has been recorded as a long-term asset called “Restricted cash” on the accompanying consolidated balance sheet at December 31, 2010.

		We incur unused commitment fees under the Amended Credit Agreement ranging from 0.50% to 1.00% based on the average daily balance of amounts outstanding. The unused commitment fees were calculated at 1.00% as of December 31, 2010.

(b)		On December 6, 2006, we issued 8.0% senior notes with a face value of $650,000 through a private placement of debt. ~~The~~These notes mature in 10 years, on December 15, 2016, and require semi-annual interest payments, paid in arrears and calculated based on an annual rate of 8.0%, on June 15 and December 15, of each year, ~~commencing~~which commenced on June 15, 2007. There was no discount or premium associated with the issuance of these notes. The senior notes are guaranteed by all of our current domestic subsidiaries. The senior notes have covenants which, among other things: (1) limit the amount of additional indebtedness we can incur; (2) limit restricted payments such as a dividend; (3) limit our ability to incur liens or encumbrances; (4) limit our ability to purchase, transfer or dispose of significant assets; (5) limit our ability to purchase or redeem stock or subordinated debt; (6) limit our ability to enter into transactions with affiliates; (7) limit our ability to merge with or into other companies or transfer all or substantially all of our assets; and (8) limit our ability to enter into sale and leaseback transactions. We have the option to redeem all or part of these notes on or after December 15, 2011. ~~We can redeem 35% of these notes on or before December 15, 2009 using the proceeds of certain equity offerings.~~ Additionally, we may redeem some or all of the notes prior to December 15, 2011 at a price equal to 100% of the principal amount of the notes plus a make-whole premium. ~~We used the net proceeds from this note issuance to repay all outstanding borrowings under the term loan portion of our credit facility which totaled~~

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~


		approximately $415,800, to repay all of the outstanding indebtedness assumed in connection with the acquisition of Pumpco which totaled approximately $30,250 and to repay approximately $192,000 of the outstanding indebtedness under the U.S. revolving credit portion of the credit facility. We paid semi-annual interest payments of $26,000 on June 15 and December 15, 2008 related to these notes, and $27,300 and $26,000 on June 15, 2007 and December 31, 2007, respectively.

		Pursuant to a registration rights agreement with the holders of our 8.0% senior notes, on June 1, 2007, we filed a registration statement onForm S-4 with the ~~Securities and Exchange Commission~~SEC which enabled these holders to exchange their notes for publicly registered notes with substantially identical terms. These holders exchanged 100% of ~~these~~the notes for publicly traded notes on July 25, 2007. On August 28, 2007, we entered into a supplement to the indenture governing the 8.0% senior notes, whereby additional domestic subsidiaries became guarantors under the indenture.

~~(c)~~		~~On February 11, 2005,~~ Effective April 1, 2009, we ~~issued subordinated notes totaling $5,000~~entered into a second supplement to ~~certain sellers of Parchman common shares in connection with~~this indenture whereby additional domestic subsidiaries became guarantors under the acquisition of Parchman. These notes were unsecured, subordinated to all present and future senior debt and bore interest at 6.0% during the first three years of the note, 8.0% during year four and 10.0% thereafter. The notes matured in early May 2006. On May 3, 2006, we repaid all principal and accrued interest outstanding pursuant to these note agreements totaling $5,029.

		~~We issued subordinated seller notes totaling $3,450 in 2004 related to certain business acquisitions. These notes bear interest at 6% and mature in March 2009.~~

~~(d)~~		Included in other outstanding debt at December 31, 2008 was: (1) capital leases totaling $436 which are collateralized by specific assets and bear interest at various rates averaging approximately 8.0% for the years ended December 31, 2008 and 2007; (2) a $145 mortgage loan related to property in Wyoming, which requires annual principal payments of approximately $60, accrues interest at 6.0% and matures in 2012; and (3) loans totaling $119 related to equipment purchases with terms a term of 5 years extending through 2009.indenture.

At December 31, 2008, principal maturities under our long-term debt facilities (including capital leases) for the next five years were: 2009 — $3,803; 2010 — $266; 2011 — $193,576; 2012 — $0; and 2013 — $0. Our senior notes mature in 2016, at a face value of $650,000.


12.	Stockholders’ equity:


*~~(a)~~*	*~~Authorized Share Capital:~~*

(a) Authorized Share Capital:

On September 12, 2005, our authorized share capital was increased to 200,000,000 shares of common stock from 24,000,000 shares of common stock with par value of $0.01 per share and to 5,000,000 shares of preferred stock from 1,000 shares of preferred stock with a par value of $0.01 per share.

COMPLETE PRODUCTION SERVICES, INC.


*~~(b)~~*	*~~Initial Public Offering:~~*

Notes to Consolidated Financial Statements — (Continued)

(b) Initial Public Offering:

On April 26, 2006, we sold 13,000,000 shares of our common stock, $.01 par value per share, in our initial public offering. These shares were offered to the public at $24.00 per share, and we recorded proceeds of approximately $292,500 after underwriter fees of $19,500. In addition, we incurred transaction costs of $3,865 associated with the issuance that were netted against the proceeds of the offering. Our stock began trading on the New York Stock Exchange on April 21, 2006. We used approximately $127,500 of the proceeds from this offering to retire principal and interest outstanding under the U.S. revolving credit facility as of April 28, 2006. Of the remaining funds, approximately $165,000 was invested in tax-free or tax-advantaged municipal bond funds and similar financial instruments with a term of less than one year. We liquidated these short-term investments during 2006 to purchase capital assets, to acquire complementary businesses and for other general corporate purposes. We considered our short-term investments as held for sale in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” as they did not appreciate or depreciate with changes in market value but rather provided only investment income.

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~(c) Stock-based Compensation:

The following table summarizes the pro forma impact of our initial public offering on earnings per share for the year ended December 31, 2006, assuming the 13,000,000 shares had been issued on January 1, 2006. No pro forma adjustments have been made to net income as reported.

2006

Net income as reported $ 139,086
Basic earnings per share, as reported:
Continuing operations $ 1.90
Discontinued operations $ 0.21

$ 2.11

Basic earnings per share, pro forma:
Continuing operations $ 1.79
Discontinued operations $ 0.20

$ 1.99

Diluted earnings per share, as reported:
Continuing operations $ 1.84
Discontinued operations $ 0.20

$ 2.04

Diluted earnings per share, pro forma:
Continuing operations $ 1.73
Discontinued operations $ 0.20

$ 1.93

~~(c)~~   ~~Stock-based Compensation:~~

We maintain ~~each of the~~ option plans ~~previously maintained by our predecessor companies. Under the three option plans,~~under which we grant stock-based compensation ~~could be granted~~ to employees, officers and directors to purchase ~~up to 2,540,485~~our common ~~shares, 3,003,463 common shares and 986,216 common shares, respectively.~~stock. The exercise price of each option is based on the fair value of the ~~individual~~issuing company’s common stock at the date of grant. Options may be exercised over a five or ten-year period and generally a third of the options vest on each of the first three anniversaries from the grant date. Upon exercise of stock options, we issue our common stock.
For grants of stock-based compensation on or after January 1, 2006, we apply the prospective transition method prescribed by U.S. GAAP, whereby we recognize expense associated with new awards of stock-based compensation ratably, as determined using a Black-Scholes pricing model, over the expected term of the award.

In November 2006, we assumed the stock option plan of Pumpco, which included 145,000 outstanding employee stock options at an exercise price of $5.00 per share. The exercise price of these stock options was $5.00 per share, which was below market price at the date of grant pursuant to theagreed-upon conversion rate negotiated as part of the acquisition. These options ~~vest~~vested ratably over athe three-year term. Upon exercise of these Pumpco stock options, we issue shares of our common stock.

~~We adopted SFAS No. 123R on January~~(i)  Employee Stock Options Granted Between October 1, 2006. This pronouncement requires that we 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, by using an option pricing model to determine fair value.
~~(i)~~   ~~Employee Stock Options Granted Prior to September 30, 2005:~~
~~As required by SFAS No. 123R, we continue to account for stock-based compensation for grants made prior to September 30,~~ 2005 ~~the date of our initial filing with the Securities~~ and ~~Exchange Commission, using the intrinsic~~December 31, 2005:

90

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

value method prescribed by APB No. 25, whereby no compensation expense is recognized for stock-based compensation grants that have an exercise price equal to the fair value of the stock on the date of grant.


~~(ii)~~	~~Employee Stock Options Granted Between October 1, 2005 and December 31, 2005:~~

For grants of stock-based compensation between October 1, 2005 and December 31, 2005, ~~(prior to adoption of SFAS No. 123R),~~ we have utilized the modified prospective transition method to record expense associated with these stock-based compensation instruments. Under this transition method, beginning January 1, 2006, we began to recognize expense related to these option grants over the applicable vesting period, with expense calculated by applying a Black-Scholes pricing model with the following assumptions: risk-free rate of 4.23% to 4.47%; expected term of 4.5 years and no dividend rate. The weighted average fair value of these option grants was $2.05 per share.

For the ~~years~~year ended December 31, 2008, ~~2007 and 2006,~~ the compensation expense recognized related to these stock options was $270, ~~$307 and $307, respectively,~~ which reduced net income by ~~$174, $200 and $195, respectively.~~$174. There was no impact on basic and diluted earnings per share from continuing operations as reported for the ~~years~~year ended December 31, 2008 ~~2007 and 2006~~ attributable to the compensation expense recognized related to these stock options. These awards were 100% vested at December 31, 2008.


~~(iii)~~	~~Employee Stock Options Granted On or After January 1, 2006:~~

(ii) Employee Stock Options Granted On or After January 1, 2006:

For grants of stock-based compensation on or after January 1, 2006, we apply the prospective transition method ~~under SFAS No. 123R,~~prescribed by U.S. GAAP, whereby we recognize expense associated with new awards of stock-based compensation ratably, as determined using a Black-Scholes pricing model, over the expected term of the award.

During the years ended December 31, ~~2008~~2010 and ~~2007,~~2009, the Compensation Committee of our Board of Directors authorized ~~the grant of 368,596~~ and ~~885,700 employee stock options, respectively, 605,176 and 79,110 non-vested restricted shares issuable~~issued to our officers and employees ~~respectively. These~~480,300 and 875,300 employee stock options, respectively, and 774,800 and 1,191,400 non-vested restricted shares, ~~were issued pursuant to this authorization in the respective years.~~respectively. The stock options granted on January 29, 2010 had an exercise price of $12.53 per share. Stock option grants in ~~2008~~2009 had an exercise price which ranged from ~~$8.16~~$6.41 to ~~$34.19 per share. Stock option grants in 2007 had an exercise price which ranged from $17.67 to $27.11~~$6.78 per share. The exercise price represented the fair market value of the shares on the date of grant. These stock option grants vest ratably over a ~~three- to four-year~~three-year term. ~~Additionally, the~~In addition, our directors received stock option grants during 2010 and 2009 of ~~stock based compensation during 2008~~30,000 and ~~2007, which included~~ 40,000 ~~stock options granted in each of these years~~shares, respectively, which vest ratably over a three-year period. ~~In addition,~~Furthermore, the directors received ~~13,456~~

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

34,296 shares of non-vested restricted stock ~~that vest~~in 2010 which vests 100% on ~~May 22, 2009~~January 29, 2011 and ~~17,144~~received 109,608 shares of non-vested restricted stock ~~that~~in 2009 which vested 100% on ~~May 24, 2008.~~January 30, 2010. The fair value of ~~this stock-based compensation~~the stock option grants was determined by applying a Black-Scholes option pricing model based on the following assumptions:


	For the Year Ended December 31,		For the Year Ended December 31,
Assumptions:	2008	2007	2010	2009

Risk-free rate	0.68% to 3.24%	4.16% to 4.98%	1.38% to 2.34%	0.89% to 2.51%
Expected term (in years)	2.2 to 5.1	2.2 to 5.1	3.7 to 5.1	2.2 to 5.1
Volatility	17% to 27%	29% to 38%	50%	29% to 47%
Calculated fair value per option	$1.33 to $6.75	$4.21 to $9.33	$4.83 to $5.81	$1.14 to $3.01

The weighted average fair ~~values~~value of ~~2008, 2007 and 2006~~ stock option grants ~~were~~for the years ended December 31, 2010, 2009 and 2008 was $5.74, $1.82 and $4.62, ~~$6.14 and $9.46,~~ respectively.

~~We completed our initial public offering in April 2006. Prior~~For stock option grants made prior to the second quarter of 2008, we did not have sufficient historical market data in order to determine the volatility of our common stock. In accordance with ~~the provisions of SFAS No. 123R,~~U.S. GAAP, we analyzed the market data of peer companies and calculated an average volatility factor based upon changes in the closing price of these companies’ common stock for a three-year period. This volatility factor was then applied as a variable to determine the fair value of our stock ~~options granted prior to the second quarter of 2008.~~option grants. For stock options granted during or after the second quarter of 2008, we calculated an

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

average volatility factor for our common stock for the period from April 21, 2006 through the respective quarter ~~end.~~end, or for the three-year period then ended. These volatility calculations were used to compute the calculation of the fair market value of ~~these~~ stock option grants ~~during the last three quarters of~~made subsequent to June 30, 2008.

We projected a rate of stock option forfeitures based upon historical experience and management assumptions related to the expected term of the options. After adjusting for these forfeitures, we expect to recognize expense totaling ~~$15,407~~$19,538 related to our stock option grants made after January 1, 2006. For the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006,~~2008, we have recognized expense related to these stock option grants totaling ~~$5,166, $4,118~~$2,321, $3,943 and ~~$1,498,~~$5,166, respectively, which represents a reduction of net income before ~~taxes and minority interest.~~taxes. The impact on net income (loss) was a reduction of ~~$3,332, $2,677~~$1,439, $2,926 and ~~$956,~~$3,332, respectively. The unrecognized compensation costs related to the non-vested portion of these awards was ~~$4,486~~$2,418 as of December 31, ~~2008~~2010 and will be recognized over the applicable remaining vesting periods.

The non-vested restricted shares were granted at fair value on the date of grant. If the restricted non-vested shares are not forfeited, we will recognize compensation expense related to our ~~2008, 2007~~2010, 2009 and ~~2006~~2008 grants to officers and employees totaling ~~$14,025, $1,600~~$9,781, $7,634 and ~~$1,555,~~$14,025, respectively, over the three-year vesting ~~period, our~~period. We expect to recognize expense associated with grants to our directors in 2010, 2009 and 2008 ~~2007~~totaling $430, $703 and ~~2006 totaling~~ $402, ~~$450 and $400,~~ respectively, over a twelve-month vesting period.

~~The following tables provide a roll forward of stock options from December 31, 2005 to December 31, 2008 and a summary of stock options outstanding by exercise price range at December 31, 2008:~~

Options Outstanding
Weighted

Average

Exercise

Number Price

Balance at December 31, 2005 3,512,444 $ 5.42
Granted 1,008,900 $ 21.19
Exercised (506,406 ) $ 3.52
Cancelled (150,378 ) $ 8.41

Balance at December 31, 2006 3,864,560 $ 9.67
Granted 925,700 $ 20.19
Exercised (934,095 ) $ 4.40
Cancelled (125,404 ) $ 17.06

Balance at December 31, 2007 3,730,761 $ 13.36
Granted 408,596 $ 17.90
Exercised (1,238,819 ) $ 9.70
Cancelled (154,026 ) $ 20.11

Balance at December 31, 2008 2,746,512 $ 15.33

9290

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Options Outstanding Options Exercisable
Weighted
Weighted
Weighted
Weighted
Outstanding at
Average
Average
Exercisable at
Average
Average
December 31,
Remaining
Exercise
December 31,
Remaining
Exercise
Range of Exercise Price
2008 Life (Months) Price 2008 Life (months) Price

$2.00 53,565 7 $ 2.00 53,565 7 $ 2.00
$4.48 - $4.80 59,262 13 $ 4.78 59,262 13 $ 4.78
$5.00 127,865 46 $ 5.00 82,032 42 $ 5.00
$6.69 - $8.16 604,233 76 $ 6.71 448,222 74 $ 6.69
$11.66 288,755 81 $ 11.66 288,755 81 $ 11.66
$15.90 345,000 109 $ 15.90 — — —
$17.60 - $19.87 661,520 97 $ 19.83 142,605 97 $ 19.80
$22.55 - $24.07 504,312 88 $ 23.95 264,311 88 $ 23.96
$26.26 - $27.11 45,000 101 $ 26.35 15,000 101 $ 26.35
$29.88 40,000 113 $ 29.88 — — —
$34.19 17,000 114 $ 34.19 — — —

2,746,512 85 $ 15.33 1,353,752 74 $ 12.35

The following tables provide a roll forward of stock options from December 31, 2007 to December 31, 2010 and a summary of stock options outstanding by exercise price range at December 31, 2010:

Options Outstanding
Weighted

Average

Exercise

Number Price

Balance at December 31, 2007 3,730,761 $ 13.36
Granted 408,596 $ 17.90
Exercised (1,238,819 ) $ 9.70
Cancelled (154,026 ) $ 20.11

Balance at December 31, 2008 2,746,512 $ 15.33
Granted 915,300 $ 6.41
Exercised (123,858 ) $ 4.01
Cancelled (154,334 ) $ 20.17

Balance at December 31, 2009 3,383,620 $ 13.09
Granted 510,300 $ 12.53
Exercised (599,035 ) $ 13.49
Cancelled (153,305 ) $ 18.16

Balance at December 31, 2010 3,141,580 $ 12.68

Options Outstanding Options Exercisable
Weighted
Weighted
Weighted
Weighted

Outstanding at
Average
Average
Exercisable at
Average
Average

December 31,
Remaining
Exercise
December 31,
Remaining
Exercise

Range of Exercise Price 2010 Life (Months) Price 2010 Life (months) Price

$5.00 65,000 29 $ 5.00 65,000 29 $ 5.00
$6.69 - $8.16 1,386,031 77 $ 6.54 793,276 63 $ 6.63
$11.66 - $12.53 573,569 103 $ 12.43 63,269 57 $ 11.66
$15.90 275,400 85 $ 15.90 176,644 73 $ 15.90
$17.60 - $19.87 412,011 73 $ 19.82 412,011 73 $ 19.82
$22.55 - $24.07 333,069 64 $ 23.97 333,069 64 $ 23.97
$26.26 - $27.11 45,000 77 $ 26.35 45,000 77 $ 26.35
$29.88 40,000 89 $ 29.88 26,667 89 $ 29.88
$34.19 11,500 90 $ 34.19 7,667 90 $ 34.19

3,141,580 80 $ 12.68 1,922,603 66 $ 14.32

The total intrinsic value of stock options exercised during the years ended December 31, ~~2008~~2010 and ~~2007~~2009 was ~~$24,063~~$7,888 and ~~$16,636,~~$568, respectively. The total intrinsic value of allin-the-money vested outstanding stock options at December 31, ~~2008~~2010 was ~~$1,442.~~$29,330. Assuming all stock options outstanding at December 31, ~~2008~~2010 were vested, the total intrinsic value of allin-the-money outstanding stock options would have been ~~$1,805.~~$53,394.

(d) ~~Amended and Restated 2001 Stock Incentive Plan:~~
On March 28, 2006, our Board of Directors approved an amendment to the 2001 Stock Incentive Plan which increased the maximum number of shares issuable under the plan to 4,500,000 from 2,540,485, pursuant to which we could grant up to 1,959,515 additional shares of stock-based compensation, as of that date, to our directors, officers and employees. On April 12, 2006, stockholders owning more than a majority of the shares of our common stock adopted the amendment to the 2001 Stock Incentive Plan.
~~(e)~~ 2008 Incentive Award Plan:

In March 2008, upon the recommendation of the Compensation Committee and subject to approval by stockholders, our Board of Directors approved the Complete Production Services, Inc. 2008 Incentive Award Plan, which was intended to succeed the prior stock option plan, the Amended and Restated 2001 Stock Incentive Plan,

91

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

pursuant to which, 2,500,000 shares of common stock were authorized for future issuance to our directors, officers and employees in conjunction with stock-based compensation arrangements. On May 22, 2008, stockholders owning more than a majority of the shares of our common stock adopted the 2008 Stock Incentive Plan. We subsequently filed a registration statement onForm S-8 and made grants to our directors, officers and employees. In March 2009, upon the recommendation of the Compensation Committee and as approved by our stockholders owning more than a majority of the shares of our common stock on May 24, 2009, we amended the 2008 Incentive Award Plan to increase the number of shares authorized for future issuance to up to 6,400,000 shares. As amended, the aggregate number of shares of common stock available for issuance under the 2008 Incentive Award Plan will be reduced by (i) 1.3 shares for each share of common stock delivered in settlement of any full value award, and (ii) 1.0 shares for each share of common stock delivered in settlement of any option, stock appreciation right or any other award that is not a full value award. If all of the shares authorized by the amendment to the 2008 Incentive Award Plan were granted as full value awards, then there would be 4,900,000 shares granted as full value awards and no shares available for issuance as awards that were not full value awards. For purposes of the 2008 Incentive Award Plan, full value awards mean any award other than (i) an option, (ii) a stock appreciation right or (iii) any other award for which the holder pays the intrinsic value existing as of the date of grant (whether directly or by forgoing a right to receive a payment from us or any subsidiary of ours). We subsequently filed a registration statement onForm S-8 and made grants to our directors, officers and employees under the 2008 Incentive Award Plan, as amended. The 2008 Stock Incentive Plan provides that forfeitures under the Amended and Restated 2001 Stock Incentive Plan will become available for issuance under the 2008 ~~Stock~~ Incentive Award Plan.


*~~(f)~~(e)*	*Non-vested Restricted Stock:*

~~In accordance with SFAS No. 123R, we do not present deferred compensation as a contra-equity account, but rather~~We present the amortization of non-vested restricted stock as an increase in additional paid-in capital. At December 31, ~~2008~~2010 and ~~2007,~~2009, amounts not yet recognized related to non-vested stock totaled ~~$10,080~~$9,704 and ~~$2,977,~~$9,727, respectively, which represented the unamortized expense associated with awards of non-vested stock granted to employees, officers and directors under our compensation ~~plans, including $9,293 and $1,248 related to grants~~

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

~~made in 2008 and 2007, respectively.~~plans. Compensation expense associated with these grants of non-vested stock is determined as the fair value of the shares on the date of grant, and recognized ratably over the applicable vesting periods. We recognized compensation expense associated with non-vested restricted stock totaling ~~$6,934, $3,142~~$9,233, $8,222 and ~~$2,738~~$6,934 for the years ended December 31, 2010, 2009 and 2008, ~~2007 and 2006,~~ respectively.

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

The following table summarizes the change in non-vested restricted stock from December 31, ~~2005~~2007 to December 31, ~~2008:~~2010:


	Non-vested					Non-vested
	Restricted Stock					Restricted Stock
				Weighted					Weighted
				Average					Average
	Number			Grant Price		Number			Grant Price

Balance at December 31, 2005		786,170		$	5.74
Granted		145,643		$	22.79
Vested		(213,996	)	$	7.53
Forfeited		(27,744	)	$	8.39

Balance at December 31, 2006		690,073		$	8.67
Granted		96,254		$	21.30
Vested		(156,944	)	$	12.93
Forfeited		(3,512	)	$	23.50

Balance at December 31, 2007		625,871		$	9.46		625,871		$	9.46
Granted		618,632		$	23.32		618,632		$	23.32
Vested		(422,461	)	$	9.94		(422,461	)	$	9.94
Forfeited		(32,851	)	$	12.47		(32,851	)	$	12.47

Balance at December 31, 2008		789,191		$	19.95		789,191		$	19.95
Granted							1,301,008		$	6.41
Vested							(406,880	)	$	16.75
Forfeited							(47,754	)	$	9.85

Balance at December 31, 2009							1,635,565		$	10.27
Granted							809,096		$	12.62
Vested							(679,815	)	$	10.89
Forfeited							(91,992	)	$	10.89

Balance at December 31, 2010							1,672,854		$	11.12


*~~(g)~~*	*(f) Common Shares Issued for Acquisitions:*

On November 8, 2006, we issued 1,010,566 shares of our common stock as purchase consideration for Pumpco. See Note 19, Related Party Transactions. In connection with this issuance, we recorded common stock and additional paid-in capital totaling $21,424, an issuance price of $21.20 per share which was the closing price of our common stock on November 8, 2006. The number of shares issued was calculated based upon the determined market value of Pumpco’s common stock and the~~agreed-upon~~ ~~purchase price negotiated with the seller.~~

On October 4, 2008, we issued 588,292 unregistered shares of our $0.01 par value common stock as a portion of the purchase consideration for Appalachian Well Service, Inc. and its wholly owned subsidiary. See Note 3, ~~Business combinations.~~“Business combinations”. In connection with this issuance, we recorded common stock and additional paid-in capital totaling $8,854, based on an issuance price of $15.04 per share, based on an average of the closing and opening price of our common stock on the business day proceeding and following the acquisition date. The number of shares issued was calculated based upon theagreed-upon purchase price negotiated with the seller.

(g) Treasury shares:

In accordance with the provisions of the 2008 Incentive Award Plan, holders of unvested restricted stock were given the option to either remit to us the required withholding taxes associated with the vesting of restricted stock, or to authorize us to repurchase shares equivalent to the cost of the withholding tax and to remit the withholding taxes

9493

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

on behalf of the holder. Pursuant to this provision, we repurchased the following shares during the year ended December 31, 2010:

Shares
Average Price
Extended

Period Purchased Paid per Share Amount

January 1 — 31, 2010 109,360 $ 12.53 $ 1,370
March 1 — 31, 2010 902 14.06 13
April 1 — 30, 2010 426 11.84 5
May 1 — 31, 2010 1,260 14.48 18
June 1 — 30, 2010 355 14.83 4
July 1 — 31, 2010 591 14.38 8
December 1 — 31, 2010 436 29.00 13

113,330 $ 1,431

These shares were included as treasury stock at cost in the accompanying balance sheet as of December 31, 2010. We expect to purchase additional shares in the future pursuant to this plan provision.

13. Earnings per share:

We compute basic earnings per share by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per common and potential common share includes the weighted average of additional shares associated with the incremental effect of dilutive employee stock options and non-vested restricted stock, ~~contingent shares, stock warrants and convertible debentures,~~ as determined using the treasury stock method prescribed by ~~SFAS No. 128, “Earnings Per Share.”~~the FASB guidance on earnings per share. The following table reconciles basic and diluted weighted average shares used in the computation of earnings per share for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006:~~2008:

Year Ended December 31, Year Ended December 31,
2008 2007 2006 2010 2009 2008
(In thousands) (In thousands)

Weighted average basic common shares outstanding 73,600 71,991 65,843 76,048 75,095 73,600
Effect of dilutive securities:
Employee stock options — 1,078 1,613 759 — —
Non-vested restricted stock — 283 313 877 — —
Contingent shares(a) — — 306

Weighted average diluted common and potential common shares outstanding 73,600 73,352 68,075 77,684 75,095 73,600

~~(a)~~ Contingent shares represent potential common stock issuable to the former owners of Parchman and MGM pursuant to the respective purchase agreements based upon 2005 operating results. On March 31, 2006, we calculated and issued the actual shares earned totaling 1,214 shares.
For each of the ~~year~~years ended December 31, 2009 and 2008, we incurred a net loss and thus all potential common shares were deemed to be anti-dilutive. We excluded the impact of anti-dilutive potential common shares from the calculation of diluted weighted average shares for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006.~~2008. If these potential common shares were included, the impact would have been a decrease in weighted average shares outstanding of ~~1,245,148~~194,211 shares, ~~231,233~~2,474,169 shares and ~~41,555~~1,245,148 shares, respectively, for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006.~~2008.

14. Discontinued operations:

In May 2008, our Board of Directors authorized and committed to a plan to sell certain business assets located primarily in north Texas which included our product supply stores, certain drilling logistics assets and other completion and production services assets. Although this sale ~~does~~did not represent a material disposition of assets relative to our total assets, ~~as presented in the accompanying balance sheets,~~ the disposal group ~~does~~did represent a significant portion of the assets and operations which were attributable to our product sales business segment for the periods presented, and therefore, was accounted for

94

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

as a disposal group that is held for ~~sale in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.”~~sale. We revised our financial statements, ~~pursuant to SFAS No. 144, and reclassified the assets and liabilities of the disposal group as held for sale as of the date of each balance sheet presented~~in accordance with U.S. GAAP and removed the results of operations of the disposal group from net income from continuing operations, and presented these separately as income from discontinued operations, net of tax, for ~~each of~~ the accompanying ~~statements~~statement of ~~operations.~~operations for the year ended December 31, 2008. We ceased depreciating the assets of this disposal group in May 2008 and adjusted the net assets to the lower of carrying value or fair value less selling costs, which resulted in a pre-tax charge of approximately $200. In addition, we allocated $11,109 of goodwill associated with the original formation of Complete Production Services, Inc. to this ~~business. Our company was formed from the combination of three entities under common control in September 2005, which resulted in~~business, and impaired this goodwill ~~of $93,792. Of~~

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

~~this amount, $11,109 was deemed to be attributable to this disposal group and was impaired~~ as of the date of the transaction. Thus, this amount has been included in the calculation of the loss on the sale of this disposal group.

On May 19, 2008, we completed the sale of the disposal group for $50,150 in cash and we received assets with a fair market value of $7,987. In addition, we retained the receivables and payables associated with the operating results of these entities as of the date of the sale. The carrying value of the related net assets was approximately $51,353 on May 19, 2008, excluding allocated goodwill of $11,109. We recorded a loss of $6,935 associated with the sale of this disposal group, which represents the excess of the carrying value of the assets less selling costs over the sales price and a charge of approximately $2,610 related to income tax on the transaction. The income tax on the disposal was primarily attributable to the $11,109 of allocated goodwill which was non-deductible for tax purposes and resulted in a taxable gain on the disposal. We sold this disposal group to Select Energy Services, L.L.C., an oilfield service company located in Gainesville, Texas which iswas owned by a former officer of one of our subsidiaries. Pursuant to the agreement, we ~~will~~ sublet office space to Select Energy Services, L.L.C., and ~~provide~~provided certain administrative functions for a period of one year at anagreed-upon rate for services per hour. Proceeds from the sale of this disposal group were used to repay outstanding borrowings under our U.S. revolving credit facility and for other general corporate purposes.

The following table summarizes operating results for this disposal group for the periods indicated:

Period

January 1, 2008

through
Year Ended
Year Ended
May 19,
December 31,
December 31,
2008 2007 2006

Revenue $ 59,553 $ 159,794 $ 127,813
Income before taxes $ 3,330 $ 18,333 $ 19,619
Net income (loss) before loss on disposal in 2008 $ 2,076 $ 11,443 $ 12,247
Net income (loss) $ (4,859 ) $ 11,443 $ 12,247

96

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

~~The captions related to discontinued operations in the accompanying balance sheet at December 31, 2007 included the following account balances:~~

December 31,
2007

Current assets held for sale:

Accounts receivable $ 23,003
Inventory 27,191
Other 113

$ 50,307

Long-term assets held for sale:

Property, plant and equipment, net $ 21,505
Goodwill 11,358
Intangible assets 187

$ 33,050

Current liabilities of held for sale operations:

Accounts payable $ 8,260
Accrued expenses 1,168
Other 277

$ 9,705

Long-term liabilities of held for sale operations:

Long-term deferred tax liabilities and other $ 2,085

$ 2,085

In August 2006, our Board of Directors authorized and committed to a plan to sell certain manufacturing and production enhancement operations of a subsidiary located in Alberta, Canada, which includes certain assets located in south Texas. Although this sale did not represent a material disposition of assets relative to our total assets, the disposal group did represent a significant portion of the assets and operations which were attributable to our product sales business segment for the periods presented, and therefore, was accounted for as a disposal group that is held for sale in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” We revised our financial statements, pursuant to SFAS No. 144, and reclassified the assets and liabilities of the disposal group as held for sale as of the date of each balance sheet presented and removed the results of operations of the disposal group from net income from continuing operations, and presented these separately as income from discontinued operations, net of tax, for the accompanying statements of operations for the year ended December 31, 2006. We ceased depreciating the assets of this disposal group in September 2006 and adjusted the net assets to the lower of carrying value or fair value less selling costs, which resulted in a pre-tax charge of approximately $100.
On October 31, 2006, we completed the sale of the disposal group for $19,310 in cash and a $2,000 Canadian dollar denominated note (an equivalent of 1,715 U.S. dollars at December 31, 2006) which matures on October 31, 2009 and accrues interest at a specified Canadian bank prime rate plus 1.50% per annum. The carrying value of the related net assets was $21,705 on October 31, 2006. We recorded a loss of $603 associated with the sale of this disposal group, which represents the excess of the sales price over the carrying value of the assets less selling costs, the benefit of a transaction gain related to a release of cumulative translation adjustment associated with this business, and a charge of approximately $1,000 related to capital tax in Canada. We sold this disposal group to Paintearth Energy Services, Inc., an oilfield service company located in Calgary, Alberta, Canada, that employs two

97

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

of our former employees as key managers. The sales agreement allowed Paintearth Energy Services, Inc. to use our subsidiary’s trade name for a period of 120 days from November 1, 2006 through February 28, 2007. Proceeds from the sale of this disposal group were used to repay outstanding borrowings under the Canadian revolving portion of our credit facility. In January 2009, we amended the note issued in conjunction with the sale of this disposal group. See Note 24, Subsequent events.

~~Operating results for this disposal group for the period January 1, 2006 through October 31, 2006, excluding the loss on the sale of the disposal group, were as follows:~~

Period
January 1, 2006
through
October 31,
2006

Revenue $ 37,292
Income before taxes and minority interest $ 3,393
Net income before loss on disposal in 2006 $ 2,406
Net income $ 1,803

Period

January 1, 2008

through

May 19,

2008

Revenue $ 59,553
Income before taxes $ 3,330
Net income before loss on disposal in 2008 $ 2,076
Net income loss $ (4,859 )

15. Segment information:

~~SFAS No. 131, “Disclosure About Segments of an Enterprise and Related Information,” establishes standards for the reporting of~~We report segment information ~~about operating segments, products and services, geographic areas, and major customers. The method of determining what information to report is~~ based on ~~the way~~how our management organizes the operating segments ~~for making~~to make operational decisions and ~~assessing~~to assess financial performance. We evaluate performance and allocate resources based on net income (loss) from continuing operations before net interest expense, taxes, depreciation and amortization, ~~minority~~non-controlling interest and impairment loss (“Adjusted EBITDA”). The calculation of Adjusted EBITDA should not be viewed as a substitute for calculations under U.S. GAAP, in particular net income. Adjusted EBITDA is included in this Annual Report onForm 10-K 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 structuresand/or tax rates by using Adjusted EBITDA. In addition, we use Adjusted EBITDA in evaluating acquisition targets. Management also believes that Adjusted EBITDA is a useful tool for measuring our ability to meet our future debt service, capital expenditures and working capital requirements, and Adjusted EBITDA is commonly used by us and our investors to measure our ability to service indebtedness. Adjusted EBITDA is not a substitute for the U.S. GAAP measures of earnings or cash flow and is not necessarily a measure of our ability to fund our cash needs. It should be noted that companies calculate EBITDA (including Adjusted EBITDA) differently and,

95

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

therefore, EBITDA has material limitations as a performance measure because it excludes interest expense, taxes, depreciation and amortization. Adjusted EBITDA calculated by us may not be comparable to the EBITDA (or Adjusted EBITDA) calculation of another ~~company.~~company and also differs from the calculation of EBITDA under our credit facilities (see Note 11 for a description of the calculation of EBITDA under our existing credit facility, as amended). See the table below for a reconciliation of Adjusted EBITDA to operating income (loss) by segment.

We have three reportable operating segments: completion and production services (“C&PS”), drilling services and product sales. The accounting policies of our reporting segments are the same as those used to prepare our consolidated financial statements as of December 31, ~~2008, 2007~~2010, 2009 and ~~2006.~~2008. Inter-segment transactions are accounted for on a cost recovery basis.

Drilling
Product

C&PS Services Sales Corporate Total

Year Ended December 31, 2010

Revenue from external customers $ 1,354,797 $ 172,821 $ 33,775 $ — $ 1,561,393
Inter-segment revenues $ 248 $ 236 $ 5,998 $ (6,482 ) $ —
Adjusted EBITDA, as defined $ 369,826 $ 38,973 $ 5,197 $ (39,088 ) $ 374,908
Depreciation and amortization $ 159,110 $ 18,480 $ 2,211 $ 2,022 $ 181,823

Operating income (loss) $ 210,716 $ 20,493 $ 2,986 $ (41,110 ) $ 193,085
Capital expenditures $ 156,787 $ 10,950 $ 320 $ 1,862 $ 169,919
As of December 31, 2010

Segment assets $ 1,488,755 $ 170,944 $ 35,015 $ 105,862 $ 1,800,576
Year Ended December 31, 2009

Revenue from external customers $ 897,584 $ 114,729 $ 44,081 $ — $ 1,056,394
Inter-segment revenues $ 105 $ 746 $ 8,237 $ (9,088 ) $ —
Adjusted EBITDA, as defined $ 165,787 $ 9,641 $ 7,966 $ (34,313 ) $ 149,081
Depreciation and amortization $ 174,929 $ 21,067 $ 2,460 $ 2,276 $ 200,732
Write-off of deferred financing fees $ — $ — $ — $ (528 ) $ (528 )
Fixed asset and other intangible impairment loss $ 2,488 $ 36,158 $ — $ — $ 38,646
Goodwill impairment loss $ 97,643 $ — $ — $ — $ 97,643

Operating income (loss) $ (109,273 ) $ (47,584 ) $ 5,506 $ (36,061 ) $ (187,412 )
Capital expenditures $ 30,930 $ 6,680 $ 228 $ 649 $ 38,487
As of December 31, 2009

Segment assets $ 1,292,199 $ 172,605 $ 37,270 $ 86,780 $ 1,588,854
Year Ended December 31, 2008

Revenue from external customers $ 1,541,709 $ 234,104 $ 59,102 $ — $ 1,834,915
Inter-segment revenues $ 576 $ 860 $ 30,358 $ (31,794 ) $ —
Adjusted EBITDA, as defined $ 467,100 $ 58,743 $ 12,677 $ (38,293 ) $ 500,227
Depreciation and amortization $ 156,298 $ 19,961 $ 2,537 $ 2,401 $ 181,197
Goodwill impairment loss $ 243,203 $ 27,410 $ 1,393 $ — $ 272,006

Operating income (loss) $ 67,599 $ 11,372 $ 8,747 $ (40,694 ) $ 47,024
Capital expenditures $ 211,648 $ 34,253 $ 6,244 $ 1,631 $ 253,776
As of December 31, 2008

Segment assets $ 1,631,875 $ 251,015 $ 52,048 $ 52,415 $ 1,987,353

9896

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Drilling
Product

C&PS Services Sales Corporate Total

Year Ended December 31, 2008

Revenue from external customers $ 1,545,348 $ 234,104 $ 59,102 $ — $ 1,838,554
Inter-segment revenues $ 576 $ 860 $ 30,358 $ (31,794 ) $ —
EBITDA, as defined $ 473,376 $ 58,743 $ 12,677 $ (38,293 ) $ 506,503
Depreciation and amortization $ 156,198 $ 19,961 $ 2,537 $ 2,401 $ 181,097
Impairment charge $ 243,203 $ 27,410 $ 1,393 $ — $ 272,006

Operating income (loss) $ 73,975 $ 11,372 $ 8,747 $ (40,694 ) $ 53,400
Capital expenditures $ 211,687 $ 34,253 $ 6,244 $ 1,631 $ 253,815
As of December 31, 2008

Segment assets $ 1,639,399 $ 251,015 $ 52,048 $ 52,415 $ 1,994,877
Year Ended December 31, 2007

Revenue from external customers $ 1,242,314 $ 212,272 $ 40,857 $ — $ 1,495,443
Inter-segment revenues $ 1,148 $ 2,223 $ 38,715 $ (42,086 ) $ —
EBITDA, as defined $ 398,628 $ 61,418 $ 9,943 $ (28,136 ) $ 441,853
Depreciation and amortization $ 112,836 $ 14,572 $ 2,064 $ 1,881 $ 131,353
Impairment charge $ 13,094 $ — $ — $ — $ 13,094

Operating income (loss) $ 272,698 $ 46,846 $ 7,879 $ (30,017 ) $ 297,406
Capital expenditures $ 305,940 $ 60,259 $ 4,323 $ 2,032 $ 372,554
As of December 31, 2007

Segment assets $ 1,651,653 $ 287,563 $ 89,492 $ 26,051 $ 2,054,759
Year Ended December 31, 2006

Revenue from external customers $ 860,508 $ 194,517 $ 29,586 $ — $ 1,084,611
Inter-segment revenues $ 136 $ 1,684 $ 39,920 $ (41,740 ) $ —
EBITDA, as defined $ 252,621 $ 70,428 $ 8,536 $ (20,922 ) $ 310,663
Depreciation and amortization $ 64,393 $ 9,069 $ 834 $ 1,606 $ 75,902
Write-off of deferred financing fees $ — $ — $ — $ (170 ) $ (170 )

Operating income (loss) $ 188,228 $ 61,359 $ 7,702 $ (22,358 ) $ 234,931
Capital expenditures $ 234,380 $ 57,853 $ 9,349 $ 2,340 $ 303,922
As of December 31, 2006

Segment assets $ 1,369,906 $ 245,806 $ 96,537 $ 28,075 $ 1,740,324
Inter-segment sales in ~~2008, 2007~~2010, 2009 and ~~2006~~2008 were largely due to service work performed and drilling rigs assembled by a subsidiary in the product sales business segment that ~~sold such~~provided these services and rigs to a subsidiary in the drilling services business segment as well as other subsidiaries primarily in the completion and production services business segment.
99

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

The following table reconciles segment information for our business segments as originally reported for the years ended December 31, 2007 and 2006, to the information revised for discontinued operations:

Original
Discontinued
Revised

Presentation Operations Presentation

Year Ended December 31, 2007

Completion and production services:

Revenue from external customers $ 1,262,100 $ 19,786 $ 1,242,314

EBITDA, as defined $ 404,893 $ 6,265 $ 398,628
Depreciation and amortization 114,139 1,303 112,836
Impairment charge 13,094 — 13,094

Operating income $ 277,660 $ 4,962 $ 272,698

Drilling services:

Revenue from external customers $ 240,377 $ 28,105 $ 212,272

EBITDA, as defined $ 69,628 $ 8,210 $ 61,418
Depreciation and amortization 17,023 2,451 14,572

Operating income $ 52,605 $ 5,759 $ 46,846

Product Sales:

Revenue from external customers $ 152,760 $ 111,903 $ 40,857

EBITDA, as defined $ 18,443 $ 8,500 $ 9,943
Depreciation and amortization 2,918 854 2,064

Operating income $ 15,525 $ 7,646 $ 7,879

Year Ended December 31, 2006

Completion and production services:

Revenue from external customers $ 873,493 $ 12,985 $ 860,508

EBITDA, as defined $ 257,630 $ 5,009 $ 252,621
Depreciation and amortization 65,317 924 64,393

Operating income $ 192,313 $ 4,085 $ 188,228

Drilling services:

Revenue from external customers $ 215,255 $ 20,738 $ 194,517

EBITDA, as defined $ 78,543 $ 8,115 $ 70,428
Depreciation and amortization 10,599 1,530 9,069

Operating income $ 67,944 $ 6,585 $ 61,359

Product Sales:

Revenue from external customers $ 123,676 $ 94,090 $ 29,586

EBITDA, as defined $ 18,708 $ 10,172 $ 8,536
Depreciation and amortization 1,943 1,109 834

Operating income $ 16,765 $ 9,063 $ 7,702

~~100~~

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

We do not allocate net interest expense or tax expense ~~or minority interest~~ to the operating segments. The write-off of deferred financing fees of ~~$170~~$528 for the year ended December 31, ~~2006 was recorded as a decrease in~~2009 reduced Adjusted EBITDA, as defined, for the Corporate and Other segment. The following table reconciles operating income (loss) as reported above to net income from continuing operations for each of the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006.~~2008.


	2008			2007			2006			2010			2009			2008

Segment operating income	$	53,400		$	297,406		$	234,931
Segment operating income (loss)										$	193,085		$	(187,412	)	$	47,024
Interest expense		59,729			61,328			40,645			57,669			56,895			59,729
Interest income		(301	)		(325	)		(1,387	)		(322	)		(79	)		(301	)
Income taxes		74,568			86,851			70,516			51,580			(63,088	)		72,305
Write-off of deferred financing fees		—			—			170			—			528			—
Minority interest		—			(569	)		(49	)

Net income (loss) from continuing operations	$	(80,596	)	$	150,121		$	125,036		$	84,158		$	(181,668	)	$	(84,709	)

The following table summarizes the changes in the carrying amount of goodwill for continuing operations by segment for the three-year period ended December 31, ~~2008:~~2010:


				Drilling			Product									Drilling			Product
	C&PS			Services			Sales			Total			C&PS			Services			Sales			Total

Balance at December 31, 2005	$	247,792		$	33,827		$	12,032		$	293,651
Acquisitions		230,681			1,049			—			231,730
Stock issued in accordance with earn-out provisions of purchase agreements		27,359			—			—			27,359
Foreign currency translation		(69	)		—			—			(69	)

Balance at December 31, 2006	$	505,763		$	34,876		$	12,032		$	552,671
Acquisitions		19,391			—			—			19,391
Impairment charge(a)		(13,360	)		—			—			(13,360	)
Amount paid pursuant to earn-out agreement		800			—			—			800
Contingency adjustment and other(b)		(6,068	)		(579	)		—			(6,647	)
Foreign currency translation		7,178			—			455			7,633

Balance at December 31, 2007	$	513,704		$	34,297		$	12,487		$	560,488		$	512,363		$	32,973		$	3,794		$	549,130
Impairment associated with discontinued operations(c)		(1,341	)		(1,324	)		(8,693	)		(11,358	)

Balance at December 31, 2007, adjusted for discontinued operations	$	512,363		$	32,973		$	3,794		$	549,130
Acquisitions		71,209			—			—			71,209			71,209			—			—			71,209
Impairment charge(a)		(243,481	)		(27,410	)		(1,393	)		(272,284	)		(243,481	)		(27,410	)		(1,393	)		(272,284	)
Contingency adjustment and other		(128	)		—			—			(128	)		(128	)		—			—			(128	)
Foreign currency translation		(6,335	)		—			—			(6,335	)		(6,335	)		—			—			(6,335	)

Balance at December 31, 2008	$	333,628		$	5,563		$	2,401		$	341,592		$	333,628		$	5,563		$	2,401		$	341,592
Impairment charge(a)														(97,643	)		—			—			(97,643	)
Contingency adjustment and other														(126	)		—			—			(126	)

Balance at December 31, 2009													$	235,859		$	5,563		$	2,401		$	243,823
Acquisitions														6,710			—			—			6,710

Balance at December 31, 2010													$	242,569		$	5,563		$	2,401		$	250,533


(a)		~~In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets,” we are required to test our~~We evaluate goodwill for impairment annually, or more often if indicators of impairment exist. ~~We performed this test for 2007 and determined that goodwill associated with our Canadian reportable unit was deemed to be impaired as of the test date, resulting in an impairment charge of $13,360.~~ For the year ending December 31, 2008, we determined that goodwill associated with our Canadian reportable unit was ~~further~~ impaired as of the annual test date. ~~However, during the fourth quarter of 2008, we believe that~~Furthermore, due to the decline in the U.S. debt and equity markets, as well as the credit

~~101~~

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~~Notes to Consolidated Financial Statements — (Continued)~~


		market, ~~constituted a triggering event, as defined in SFAS No. 142. As such,~~ we ~~performed~~re-performed the prescribed impairment testing at December 31, 2008 and noted impairment which impacted several of our reportable units. Therefore, we recorded an impairment charge of $272,006 for the year ended December 31, 2008. For the year ending December 31, 2009, we determined that goodwill associated with several of our reportable units was also impaired so we recorded an impairment charge of $97,643. See Note 2, ~~Significant Accounting Policies~~“Significant accounting policies — Fair ~~Value Measurements.~~

~~(b)~~		The contingency adjustment includes a reclassification of $3,485 from goodwill to identifiable intangible assets, primarily non-compete agreements and customer relationships, which were identified upon acquisition but for which the fair value was recently determined based upon estimates calculated by a third-party appraiser. Of this amount, $2,017 related to the acquisition of Pumpco Services, Inc. in November 2006. In addition, we recorded an adjustment to reduce goodwill related to the acquisition of Pumpco Services, Inc. totaling $3,136 associated with certain federal income tax liabilities recorded at the acquisition date that were deemed to be unnecessary based upon the 2006 federal tax return prepared in 2007. Partially offsetting these reductions to goodwill were additional charges associated with final working capital adjustments for several 2006 and 2007 acquisitions.

~~(c)~~		~~See Note 10 — Discontinued operations.~~measurements.”

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Geographic information ~~(d)~~(b):


	United						Other					United						Other
	States			Canada			International		Total			States			Canada			International		Total

Year Ended December 31, 2010
Revenue by sale origin to external customers												$	1,398,091		$	81,190		$	82,112	$	1,561,393
Income from continuing operations before taxes												$	123,595		$	1,255		$	10,888	$	135,738
December 31, 2010
Long-lived assets												$	1,190,545		$	34,256		$	23,865	$	1,248,666
Year Ended December 31, 2009
Revenue by sale origin to external customers												$	910,297		$	55,514		$	90,583	$	1,056,394
Income (loss) from continuing operations before taxes												$	(254,884	)	$	(11,069	)	$	21,197	$	(244,756	)
December 31, 2009
Long-lived assets												$	1,151,320		$	40,577		$	27,031	$	1,218,928
Year Ended December 31, 2008
Revenue by sale origin to external customers	$	1,650,815		$	86,250		$	101,489	$	1,838,554		$	1,647,176		$	86,250		$	101,489	$	1,834,915
Income (loss) before taxes and minority interest	$	(3,426	)	$	(26,412	)	$	23,810	$	(6,028	)
Income (loss) from continuing operations before taxes												$	(9,802	)	$	(26,412	)	$	23,810	$	(12,404	)
December 31, 2008
Long-lived assets	$	1,477,103		$	47,170		$	23,470	$	1,547,743		$	1,477,336		$	47,170		$	23,470	$	1,547,976
Year Ended December 31, 2007
Revenue by sale origin to external customers	$	1,336,490		$	80,933		$	78,020	$	1,495,443
Income (loss) before taxes and minority interest	$	241,799		$	(13,484	)	$	8,088	$	236,403
December 31, 2007
Long-lived assets	$	1,518,318		$	94,434		$	13,683	$	1,626,435
Year Ended December 31, 2006
Revenue by sale origin to external customers	$	939,895		$	88,533		$	56,183	$	1,084,611
Income (loss) before taxes and minority interest	$	178,815		$	5,977		$	10,711	$	195,503
December 31, 2006
Long-lived assets	$	1,226,342		$	117,809		$	5,533	$	1,349,684


~~(d)~~(b)		The segment operating results provided above represent amounts for continuing operations as presented on the accompanying statements of operations. Long-lived assets presented above represent amounts associated with all operations as of the periods then ended as indicated. Revenues from external customers are assigned to geographic ~~regions~~region based upon the domicile of the subsidiary providing the services or products to the customers.

~~We did not have revenues from any single customer which amounts to 10% or more of our total annual revenue for the years ended December 31, 2008, 2007 or 2006.~~

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~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~


16.	Legal matters and contingencies:

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

premiums should not have a material adverse effect on our financial position, results of operations or liquidity. We incurred no additional premium related to this cost-sharing provision of our general liability policy ~~in 2008, but paid approximately $1,400 of additional premium~~ for the ~~year~~years ended December 31, ~~2007.~~2010, 2009 or 2008.


17.	Financial instruments:


*~~(a)~~*	*~~Interest rate risk:~~*

(a) Interest rate risk:

We ~~manage our~~currently have little exposure to interest rate ~~risks through a combination of fixed and floating rate borrowings.~~risks. At December 31, ~~2008, 23%~~2010, 100% of our ~~long-term~~outstanding debt ~~was floating rate borrowings. Of the remaining debt, 99% relates~~related to the senior notes issued in December 2006 with a fixed interest rate of 8%. We are exposed to variable interest rate impact related to our outstanding letters of credit under our amended credit facility, See Note 11, “Long-term debt.”


*(b)*	*Foreign currency rate risk:*

We are exposed to foreign currency fluctuations in relation to our foreign operations. Approximately 5% of our revenues from continuing operations were derived from operations conducted in Canadian dollars for the years ended December 31, ~~2008~~2010 and ~~2007.~~2009. For our Canadian operations, we recorded net income from continuing operations before taxes of $1,255 for the year ended December 31, 2010 and a net loss from continuing operations before taxes ~~and minority interest~~ of ~~$26,412 and $13,484~~$11,069 for the ~~years~~year ended December 31, ~~2008 and 2007, respectively.~~2009. Total assets denominated in Canadian dollars at December 31, ~~2008~~2010 and ~~2007~~2009 were ~~$66,355~~$71,842 and ~~$120,378,~~$59,343, respectively.


*(c)*	*Credit risk:*

A significant portion of our trade accounts receivable are from companies in the oil and gas industry, and as such, we are exposed to normal industry credit risks. We evaluate the credit-worthiness of our major new and existing customers’ financial condition and generally do not require collateral.

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~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes~~For the year ended December 31, 2010, we had two customers who provided 12.2% and 10.7% of our total annual revenue. For the year ended December 31, 2009, the same two customers represented 9.9% and 9.7% of our revenue. We did not have revenues from any single customer which amounted to ~~Consolidated Financial Statements — (Continued)~~10% or more of our total annual revenue for the year ended December 31, 2008.


18.	Commitments and contingences:

We have non-cancelable operating lease commitments for equipment and office space. These commitments for the next five years ~~were~~and thereafter are as follows at December 31, ~~2008:~~2010:


2009	$	20,849
2010		15,667
2011		11,099	$	27,287
2012		8,354		21,624
2013		6,378		17,538
2014				10,487
2015				4,954
Thereafter		8,166		11,055

	$	70,513	$	92,945

We expensed operating lease payments totaling ~~$22,750, $22,446~~$31,595, $25,477 and ~~$19,108~~$22,750 for the years ended December 31, 2010, 2009 and 2008, ~~2007 and 2006,~~ respectively.

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


19.	Related party transactions:

We believe all transactions with related parties have terms and conditions no less favorable to us than transactions with unaffiliated parties.

We have entered into lease agreements for properties owned by certain of our employees and former officers. The leases expire at different times through December 2016. Total lease expense pursuant to these leases was ~~$2,828, $2,991~~$2,993, $2,749 and ~~$2,306~~$2,828 for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006,~~2008, respectively.

In connection with ~~CES’~~the Complete Energy Services, Inc. (“CES”) acquisition of Hamm Co. in 2004, CES entered into ~~that~~a certain Strategic Customer Relationship Agreement with Continental Resources, Inc. (“CRI”). By virtue of the Combination, through a subsidiary, we are now party to such agreement. The agreement provides CRI the option to engage a limited amount of our assets into a long-term contract at market rates. Mr. Hamm is a majority owner of CRI and serves as a member of our board of directors.

We provided services to companies that were majority-owned by certain of our directors during 2010 which totaled $131,524, of which $131,337 was sold to CRI and $187 was sold to other companies. In 2009, these sales totaled $40,623, of which $40,343 was sold to CRI, and $280 was sold to other companies and in 2008, ~~which~~these sales totaled $61,194, of which $60,634 was sold to CRI, and $560 was sold to other companies. In 2007, these sales totaled $52,027, of which $51,340 was sold to CRI, and $687 was sold to other companies and, in 2006, these sales totaled $37,405, of which $37,008 was sold to CRI, and $397 was sold to other companies. We also purchased services from companies that are majority-owned by certain of our directors which totaled ~~$2,866~~$556 in 2010, of which $490 was purchased from CRI and $66 was purchased from other companies. These purchases for 2009 totaled $1,423, of which $1,191 was purchased from CRI and $232 was purchased from other companies and in 2008, these purchases totaled $2,866, of which $2,750 was purchased from CRI and $116 was purchased from other companies. These purchases for 2007 totaled $1,260, of which $1,211 was purchased from CRI and $49 was purchased from other companies and, in 2006, these purchases totaled $755, of which $614 was purchased from CRI and $141 was purchased from other companies. At December 31, ~~2008~~2010 and ~~2007,~~2009, our trade receivables included amounts from CRI of ~~$10,542~~$50,048 and ~~$7,611,~~$5,957, respectively, ~~and our~~with no balance in trade payables ~~included amounts due to CRI~~for either of ~~$181 and $47, respectively.~~these periods.

We provided services to companies majority-owned by certain of our officers, or current or former officers of our subsidiaries, for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006.~~2008. In 2010, these sales totaled $4,065, of which $2,537 was sold to HEP Oil (“HEP”), $21 was sold to Peak Oilfield and $1,507 was sold to other companies. For 2009, these sales totaled $3,552, of which $2,433 was sold to HEP, $9 was sold to Peak Oilfield and $1,110 was sold to other companies. For 2008, these sales totaled $11,256, of which $3,348 was sold to HEP, ~~Oil (“HEP”),~~ $1,660 was sold to Cimarron, $3,513 was sold to Peak Oilfield and $2,735 was sold to other companies. For 2007, these sales totaled $4,914, of which $2,974 was sold to HEP, $39 was sold to Cimarron, $1,527 was sold to Peak Oilfield and $374 was sold to other companies. In 2006, these sales totaled $8,346, of which $8,324 was sold to HEP and $22 was sold to other companies. HEP, Cimarron and Peak Oilfield are owned by a former officer of one of our subsidiaries who resigned his position in late 2006 but continued to provide consulting services through early 2007. We also purchased services from companies majority-owned by certain officers, or current or former officers of one of our subsidiaries. For ~~2008,~~2010, these purchases totaled ~~$60,546,~~$180,119, of which ~~$25,344~~$56,994 was purchased from ~~Ortowski Construction primarily related to the manufacture of pressure~~

~~104~~

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

~~pumping units, $7,910~~Resource Transport, $40,245 was purchased from Texas Specialty Sands, LLC primarily for the purchase of sand used for pressure pumping activities, $31,552 was purchased from Ortowski Construction primarily related to the manufacture of pressure pumping units, $30,217 was purchased from ORTEQ Energy Services, a heavy equipment construction company which also manufactures pressure pumping equipment, $7,772 was purchased from ProFuel, $7,935 was purchased from Wood Flowline Products, LLC $43 was purchased from Select Energy Services LLC and affiliates and $5,361 was purchased from other companies. For 2009, these purchases totaled $40,373, of which $13,920 was purchased from Ortowski Construction, $12,005 was purchased from Texas Specialty Sands, LLC, $3,302 was purchased from Resource Transport, $2,642 was purchased from ProFuel, $3,535 was purchased from Wood Flowline Products, LLC, $24 was purchased from Select Energy Services LLC and affiliates and $4,945 was purchased from other companies. For 2008, these purchases totaled $61,708, of which $25,344 was purchased from Ortowski Construction, $7,910 was purchased from Texas Specialty Sands, LLC, $4,809 was purchased from Resource Transport, $5,601 was purchased from ProFuel, $16,595 was purchased from Select Energy Services LLC and affiliates and ~~$287~~$1,449 was purchased from other companies. Ortowski Construction, ORTEQ Energy Services, Texas Specialty Sands, LLC, Resource Transport, ~~and~~ Pro Fuel and Wood Flowline Products, LLC are owned by parties, one of whom is a former employee, who are related to a current ~~employee who is an~~ officer of ~~one of our subsidiaries.~~a subsidiary, or the officer himself. Select Energy Services LLC is owned by a former officer of one of our subsidiaries who purchased a disposal group from us during May 2008. Of the total purchases

100

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

from Select Energy Services, LLC, $11,098 was purchased from the businesses sold as part of this disposal group for the period May 19, 2008 through December 31, 2008. For 2007, these purchases from related companies totaled $70,550, of which $64,503 was purchased from Ortowski Construction, $70 was purchased from HEP and $5,977 was purchased from other companies. In 2006, we purchased $5,598, of which $216 was purchased from HEP and $5,382 was purchased from other companies. At December 31, ~~2008~~2010 and ~~2007,~~2009, our trade receivables included amounts from HEP of ~~$384~~$310 and ~~$405,~~$270, respectively. ~~Our trade payables~~

One of our Mexican subsidiaries, Servicios Petrotec de S.A. de C.V., has purchased services from entities in which certain of our current and ~~accrued expenses at~~former employees have ownership interests. We purchased fluid transportation, industrial cleaning, pumping equipment and safety equipment, totaling $1,575, $1,262 and $1,485 for the years ended December 31, 2010, 2009 and 2008, ~~and 2007 included amounts payable to Ortowski construction of $175 and $6,105,~~ respectively. Amounts payable at December 31, 2008 to Texas Specialty Sand, LLC, Resource Transport, and ProFuel totaled $581, $199 and $187, respectively. There were no amounts payable to HEP or Cimarron at December 31, 2008 and 2007.

We provided services totaling ~~$1,697, $2,068~~$1,430, $1,012 and ~~$5,367~~$1,697 for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006,~~2008, respectively, to Laramie Energy LLC and Laramie Energy II (collectively “Laramie”), companies for which one of our directors serves as an officer. At December 31, ~~2008~~2010 and ~~2007,~~2009, our trade receivables included amounts due from Laramie totaling ~~$383~~$858 and ~~$27,~~$326, respectively.

For the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006,~~2008, we provided services totaling ~~$9,468, $11,016~~$8,555, $3,613 and ~~$3,659,~~$9,468, respectively, and purchased services totaling ~~$14,108, $13,757~~$3,456, $8,784 and ~~$28,114,~~$14,108, respectively, from companies, or their affiliates, that formerly employed our current officers or for customers on whose board of directors or management team certain of our current directors serve.

We ~~entered into~~paid $3,450 in May 2009 pursuant to subordinated note agreements with certain employees, including ~~current~~former officers of subsidiaries, ~~whereby we are obligated to pay an aggregate principal amount of $8,450 pursuant~~related to promissory notes issued in conjunction with 2005 and 2004 business acquisitions. ~~Of this amount, $5,000 was repaid in May 2006. The remaining notes mature in 2009. See Note 11, Long-term Debt.~~

On December 1, 2001, Bison Oilfield Tools, Ltd. (“Bison”), and PEG, a subsidiary of IPS, entered into a lease agreement pursuant to which PEG leases real property from Bison. A former director of IPS controls Bison as the president of its two general partners. IPS paid Bison $4 per month through December 2006.

Premier Integrated Technologies Ltd. (“PIT”), an affiliate of IPS, purchased ~~$1,493, $2,290~~$3,823, $2,427 and ~~$2,083~~$1,493 of machining services from a company controlled by employees of PIT during the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006,~~2008, respectively.

On September 29, 2005, we entered into an Asset Purchase Agreement with Spindletop and Mr. Schmitz, a former officer of one of our subsidiaries. Pursuant to the agreement, we purchased the assets of Spindletop in exchange for approximately $200 cash and 90,364 shares of our common stock. Mr. Schmitz was a member of our key operational management who resigned as an officer of one of our subsidiaries in late 2006. Mr. Schmitz remained in our employ as of December 31, 2006. On January 1, 2007, Mr. Schmitz purchased the assets of one of our subsidiaries for $412, resulting in a gain on the sale of $156. On May 19, 2008, we sold certain business assets located primarily in north Texas which included our product supply stores, certain drilling logistics assets and other completion and production services assets to Select Energy Services, L.L.C., an oilfield service company located in Gainesville, Texas which is partially owned by Mr. ~~Schmitz.~~Schmitz who resigned as an officer of one of our subsidiaries in late 2006. The proceeds from the sale totaled $50,150 in cash and we received assets with a fair market value of $7,987. We recorded a loss of $6,935 associated with the sale of this disposal group, and we will provide certain administrative functions for a period of one year at anagreed-upon rate. For the period May 20, 2008 through December 31, 2008, we sold services totaling $1,509 and purchased products and services totaling $11,098 from these former subsidiaries. See Note 14, ~~Discontinued~~“Discontinued operations.” At December 31, 2010, our trade receivables and payables included amounts related to these disposed businesses which totaled $7 and $177, respectively and at December 31, 2009, our trade receivables and payables included amounts related to these disposed businesses which totaled $21 and $295, respectively.


20.	Retirement plans:

Effective January 1, 2009, we adopted and established (and subsequently amended and restated for compliance and other issues) the Complete Production Services, Inc. Deferred Compensation Plan, whereby eligible participants, including members of senior management, non-employee directors and certain highly-compensated individuals, could defer up to 90% of their compensation and up to 90% of the employees’ annual incentive bonus, or 100% of director compensation for services rendered, into various investment options pre-tax. For amounts deferred, we will match the contributiondollar-for-dollar up to four percent of compensation minus $3.3, and we may make other discretionary contributions pursuant to resolutions of this plan’s administrative committee. Participants immediately vest in amounts deferred as well as any matching or discretionary contributions we make. Participants bear the risk of loss associated with investment gains or losses. We intend that this plan will meet all the requirements necessary to be a nonqualified, unfunded, unsecured plan of deferred compensation within the meaning of Sections 201(2), 301(a)(3) and 401(a)(1) of the Employee Retirement Income Security Act of 1974, as amended. We have recorded an asset and corresponding liability totaling $882 related to the rabbi trust associated

~~105~~101

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

with our deferred compensation plan. For the years ended December 31, ~~2008, our trade receivables~~2010 and ~~payables included amounts~~2009, we expensed an insignificant amount related to ~~these disposed businesses which totaled $323 and $529, respectively.~~matching contributions associated with this deferred compensation plan.

On November 8, 2006, we acquired Pumpco, a provider of pressure pumping services in the Barnett Shale play of north Texas, in exchange for consideration of $144,635 in cash, net of cash acquired, the issuance of 1,010,566 shares of our common stock and the assumption of $30,250 of debt held by Pumpco at the time of the acquisition. Pumpco was purchased from the stockholders of Pumpco. Prior to the acquisition,~~SCF-VI,~~ ~~L.P.(“SCF-VI”)~~ ~~was the majority stockholder of Pumpco.SCF-VI~~ ~~is an affiliate ofSCF-IV,~~ ~~L.P.(“SCF-IV”),~~ which held approximately 35% of our outstanding common stock at the time of the acquisition. Andy Waite and David Baldwin were our Directors at the time of the acquisition and serve as officers of the ultimate general partner of~~SCF-VI.~~ ~~Our Board of Directors established a Special Committee of directors, each independent ofSCF-IV~~ or any of its affiliates, to review and approve the terms of the transaction. UBS Investment Bank acted as exclusive financial advisor to the Special Committee. In addition, John Schmitz, one of our key members of management during 2006, was a stockholder of Pumpco prior to the acquisition. The nature and amount of the consideration paid was determined by negotiations between the stockholders of Pumpco and our management and the Special Committee of our Board of Directors.


~~20.~~	~~Retirement plans:~~

We maintain defined contribution retirement plans for substantially all of our U.S. and Canadian employees who have completed six months of service. Employees may voluntarily contribute up to a maximum percentage of their salaries to these plans subject to certain statutory maximum dollar values. The ~~maximums range from 20% to 60%, depending on the plan. We make matching contributions at 25% — 50% of the first 6% or 7% of the employee’s contributions, depending on the plan. The~~ employer contributions vest immediately with respect to the Canadian RRSP plan and U.S. 401(k) plan. In response to market conditions, effective May 1, 2009, we amended our 401(k) plan and deferred compensation plan to suspend matching contributions to such plans through December 31, 2010. We re-instated our matching contribution in 2011, see Note 24, “Subsequent events.”

We expensed ~~$6,101, $5,216~~$436, $2,231 and ~~$3,194~~$6,101 related to our various defined contribution plans for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006,~~2008, respectively.

We provide a seniority premium benefit to substantially all of our Mexican employees, through a subsidiary, in accordance with Mexican law. The benefit consists of a one-time payment equivalent to12-days wages for each year of service (calculated at the employee’s current wage rate but not exceeding twice the minimum wage), payable upon voluntary termination after fifteen years of service, involuntary termination or death. In addition, we provide statutory mandated severance benefits to substantially all Mexican employees, which includes a one-time payment of three months wages, plus20-days wages for each year of service, payable upon involuntary termination without cause and charged to income as incurred. We accrued ~~$1,591~~$1,249 and ~~$814~~$1,604 at December 31, ~~2008~~2010 and ~~2007,~~2009, respectively, related to our liability under this benefit arrangement in Mexico.

~~106~~

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~


21.	Unaudited selected quarterly data:

The following table presents selected quarterly financial data for the years ended December 31, ~~2008~~2010 and ~~2007~~2009 (unaudited, in thousands, except per share amounts):


	2008 — Quarter Ended									2010 — Quarter Ended
	March 31,		June 30,		September 30,		December 31,			March 31,			June 30,		September 30,		December 31,

Revenues	$	417,178	$	441,085	$	493,233	$	487,058		$	309,704		$	360,245	$	418,609	$	472,835
Operating income (loss)	$	80,477	$	75,140	$	96,041	$	(198,258	)
Net income (loss) from continuing operations	$	41,773	$	39,843	$	52,343	$	(214,555	)
Operating income										$	10,589		$	39,869	$	68,181	$	74,446
Net income (loss)	$	43,924	$	32,986	$	52,190	$	(214,555	)	$	(2,762	)	$	15,671	$	33,030	$	38,219
Earnings per share — continuing operations(a):
Earnings (loss) per share(a):
Basic	$	0.58	$	0.54	$	0.71	$	(2.87	)	$	(0.04	)	$	0.21	$	0.43	$	0.50
Diluted	$	0.57	$	0.54	$	0.70	$	(2.87	)	$	(0.04	)	$	0.20	$	0.42	$	0.49
Earnings per share(a):
Basic	$	0.61	$	0.45	$	0.71	$	(2.87	)
Diluted	$	0.60	$	0.44	$	0.70	$	(2.87	)


	2007 — Quarter Ended								2009 — Quarter Ended
	March 31,		June 30,		September 30,		December 31,		March 31,			June 30,			September 30,			December 31,

Revenues	$	366,222	$	366,814	$	373,405	$	389,002	$	336,681		$	238,398		$	229,913		$	251,402
Operating income	$	87,172	$	77,961	$	72,174	$	60,099
Net income from continuing operations	$	44,217	$	40,105	$	38,791	$	27,008
Net income	$	47,351	$	43,783	$	41,608	$	28,822
Earnings per share — continuing operations(a):
Operating income (loss)									$	14,006		$	(22,902	)	$	(64,132	)	$	(114,384	)
Net loss									$	(336	)	$	(25,832	)	$	(52,025	)	$	(103,475	)
Loss per share(a):
Basic	$	0.62	$	0.56	$	0.54	$	0.37	$	0.00		$	(0.34	)	$	(0.69	)	$	(1.38	)
Diluted	$	0.61	$	0.55	$	0.53	$	0.37	$	0.00		$	(0.34	)	$	(0.69	)	$	(1.38	)
Earnings per share(a):
Basic	$	0.66	$	0.61	$	0.58	$	0.40
Diluted	$	0.65	$	0.60	$	0.57	$	0.39


(a)		Quarterly earnings per share amounts were calculated based upon the weighted average number of shares outstanding for the applicable quarter. Therefore the sum of the quarterly earnings per share results may not agree to earnings per share for the year in the accompanying Statements of Operations, as the annual results were calculated based upon the weighted average number of shares outstanding for the year.

~~107~~102

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)


22.	Guarantor and non-guarantor condensed consolidating financial statements:

The following tables present the financial data required by SECRegulation S-XRule 3-10(f) related to condensed consolidating financial statements, and includes the following: (1) condensed consolidating balance sheets for the years ended December 31, ~~2008~~2010 and ~~2007;~~2009; (2) condensed consolidating statements of operations for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006;~~2008; and (3) condensed consolidating statements of cash flows for the years ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006.~~2008.

Condensed Consolidating Balance Sheet
December 31, ~~2008~~2010


				Guarantor			Non-guarantor			Eliminations/								Guarantor		Non-guarantor			Eliminations/
	Parent			Subsidiaries			Subsidiaries			Reclassifications			Consolidated		Parent			Subsidiaries		Subsidiaries			Reclassifications			Consolidated

Current assets
Cash and cash equivalents	$	25,399		$	936		$	5,078		$	(12,323	)	$	19,090	$	111,834		$	569	$	31,046		$	(16,768	)	$	126,681
Trade accounts receivable, net		201			312,591			30,561			—			343,353
Accounts receivable, net																696			313,936		31,016			—			345,648
Inventory, net		—			28,051			13,840			—			41,891		—			21,935		11,601			—			33,536
Prepaid expenses		1,060			19,375			1,037			—			21,472		6,388			10,980		1,332			—			18,700
Tax receivable		21,021			307			—			—			21,328
Income tax receivable																10,164			13,298		—			—			23,462
Current deferred tax assets																2,499			—		—			—			2,499
Other current assets																882			502		—			—			1,384

Total current assets		47,681			361,260			50,516			(12,323	)		447,134		132,463			361,220		74,995			(16,768	)		551,910
Property, plant and equipment, net		4,956			1,097,241			64,256			—			1,166,453		4,730			898,013		53,285			—			956,028
Investment in consolidated subsidiaries		937,773			88,669			—			(1,026,442	)		—		930,631			115,449		—			(1,046,080	)		—
Inter-company receivable		784,125			(502	)		—			(783,623	)		—		554,482			—		445			(554,927	)		—
Goodwill		55,354			283,657			2,581			—			341,592		15,531			232,144		2,858			—			250,533
Other long-term assets, net		14,009			22,163			3,526			—			39,698		29,966			10,161		1,978			—			42,105

Total assets	$	1,843,898		$	1,852,488		$	120,879		$	(1,822,388	)	$	1,994,877	$	1,667,803		$	1,616,987	$	133,561		$	(1,617,775	)	$	1,800,576

Current liabilities
Current maturities of long-term debt	$	—		$	3,792		$	11		$	—		$	3,803
Accounts payable		2,201			59,052			8,553			(12,323	)		57,483	$	376		$	82,952	$	8,539		$	(16,768	)	$	75,099
Accrued liabilities		13,422			17,916			6,247			—			37,585		18,269			21,355		4,667			—			44,291
Accrued payroll and payroll burdens		5,362			22,960			2,971			—			31,293		4,353			19,325		2,890			—			26,568
Accrued interest		2,704			—			50			—			2,754		2,439			1		6			—			2,446
Notes payable		1,353			—			—			—			1,353
Taxes payable		(1,900	)		—			1,900			—			—
Current deferred tax liabilities		—			1,289			—			—			1,289
Income taxes payable																(1,043	)		—		1,043			—			—

Total current liabilities		23,142			105,009			19,732			(12,323	)		135,560		24,394			123,633		17,145			(16,768	)		148,404
Long-term debt		836,000			299			7,543			—			843,842		650,000			—		—			—			650,000
Inter-company payable		—			784,125			(502	)		(783,623	)		—		—			553,907		1,020			(554,927	)		—
Deferred income taxes		115,641			25,281			5,437			—			146,359		186,693			3,794		(65	)		—			190,422
Minority interest		—			—			—			—			—
Other long-term liabilities																882			5,022		12			—			5,916

Total liabilities		974,783			914,714			32,210			(795,946	)		1,125,761		861,969			686,356		18,112			(571,695	)		994,742
Stockholders’ equity
Total stockholders’ equity		869,115			937,774			88,669			(1,026,442	)		869,116		805,834			930,631		115,449			(1,046,080	)		805,834

Total liabilities and stockholders’ equity	$	1,843,898		$	1,852,488		$	120,879		$	(1,822,388	)	$	1,994,877	$	1,667,803		$	1,616,987	$	133,561		$	(1,617,775	)	$	1,800,576

~~108~~103

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Condensed Consolidating Balance Sheet
December 31, ~~2007~~2009


			Guarantor		Non-guarantor		Eliminations/							Guarantor		Non-guarantor		Eliminations/
	Parent		Subsidiaries		Subsidiaries		Reclassifications			Consolidated		Parent		Subsidiaries		Subsidiaries		Reclassifications			Consolidated

Current assets
Cash and cash equivalents	$	8,217	$	5,549	$	6,605	$	(6,747	)	$	13,624	$	64,871	$	519	$	17,001	$	(5,031	)	$	77,360
Trade accounts receivable, net		62		276,706		28,914		—			305,682
Accounts receivable, net													610		143,135		27,539		—			171,284
Inventory, net		—		16,022		13,855		—			29,877		—		23,001		14,463		—			37,464
Prepaid expenses		2,021		20,826		896		—			23,743		3,897		13,052		994		—			17,943
Income tax receivable													35,404		20,201		2,001		—			57,606
Current deferred tax assets													8,158		—		—		—			8,158
Other current assets		5,092		—		—		—			5,092		—		111		—		—			111
Current assets held for sale		—		50,307		—		—			50,307

Total current assets		15,392		369,410		50,270		(6,747	)		428,325		112,940		200,019		61,998		(5,031	)		369,926
Property, plant and equipment, net		4,623		953,169		55,398		—			1,013,190		4,222		876,304		60,607		—			941,133
Investment in consolidated subsidiaries		850,238		114,529		—		(964,767	)		—		755,435		104,974		—		(860,409	)		—
Inter-company receivable		894,356		371		—		(894,727	)		—		607,325		—		—		(607,325	)		—
Goodwill		82,683		418,035		48,412		—			549,130		15,531		225,434		2,858		—			243,823
Other long-term assets, net		14,804		12,321		3,939		—			31,064		16,026		13,803		4,143		—			33,972
Long-term assets held for sale		—		33,050		—		—			33,050

Total assets	$	1,862,096	$	1,900,885	$	158,019	$	(1,866,241	)	$	2,054,759	$	1,511,479	$	1,420,534	$	129,606	$	(1,472,765	)	$	1,588,854

Current liabilities
Current maturities of long-term debt	$	—	$	328	$	70	$	—		$	398	$	—	$	228	$	—	$	—		$	228
Accounts payable		1,364		53,159		8,631		(6,747	)		56,407		445		30,028		6,303		(5,031	)		31,745
Accrued liabilities		5,792		39,355		7,425		—			52,572		14,064		18,257		8,781		—			41,102
Accrued payroll and payroll burdens		1,278		21,555		1,217		—			24,050		388		10,847		2,324		—			13,559
Accrued interest		4,462		—		91		—			4,553		3,198		—		8		—			3,206
Notes payable		15,319		35		—		—			15,354		1,068		1		—		—			1,069
Taxes payable		—		—		6,506		—			6,506
Current liabilities of held for sale operations		—		9,705		—		—			9,705
Income taxes payable													—		—		813		—			813

Total current liabilities		28,215		124,137		23,940		(6,747	)		169,545		19,163		59,361		18,229		(5,031	)		91,722
Long-term debt		810,000		3,690		12,295		—			825,985		650,000		—		2		—			650,002
Inter-company payable		—		894,356		371		(894,727	)		—		—		601,947		5,378		(607,325	)		—
Deferred income taxes		93,557		26,379		6,885		—			126,821		143,427		3,793		1,020		—			148,240
Minority interest		—		2,085		—		—			2,085

Total liabilities		931,772		1,050,647		43,491		(901,474	)		1,124,436		812,590		665,101		24,629		(612,356	)		889,964
Stockholders’ equity
Total stockholders’ equity		930,324		850,238		114,528		(964,767	)		930,323		698,889		755,433		104,977		(860,409	)		698,890

Total liabilities and stockholders’ equity	$	1,862,096	$	1,900,885	$	158,019	$	(1,866,241	)	$	2,054,759	$	1,511,479	$	1,420,534	$	129,606	$	(1,472,765	)	$	1,588,854

~~109~~104

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Condensed Consolidated Statement of Operations
Year Ended December 31, 2010

Guarantor
Non-guarantor
Eliminations/

Parent Subsidiaries Subsidiaries Reclassifications Consolidated

Revenue:
Service $ — $ 1,401,665 $ 132,774 $ (6,821 ) $ 1,527,618
Product — 3,247 30,528 — 33,775

— 1,404,912 163,302 (6,821 ) 1,561,393
Service expenses — 889,862 102,052 (6,821 ) 985,093
Product expenses — 3,452 22,495 — 25,947
Selling, general and administrative expenses 39,090 122,189 14,166 — 175,445
Depreciation and amortization 1,354 168,104 12,365 — 181,823

Income (loss) before interest and taxes (40,444 ) 221,305 12,224 — 193,085
Interest expense 58,132 5,653 105 (6,221 ) 57,669
Interest income (6,511 ) (8 ) (24 ) 6,221 (322 )
Equity in earnings of consolidated affiliates (140,929 ) (8,926 ) — 149,855 —

Income (loss) before taxes 48,864 224,586 12,143 (149,855 ) 135,738
Taxes (35,294 ) 83,657 3,217 — 51,580

Net income (loss) $ 84,158 $ 140,929 $ 8,926 $ (149,855 ) $ 84,158

105

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Condensed Consolidated Statement of Operations
Year Ended December 31, 2009

Guarantor
Non-guarantor
Eliminations/

Parent Subsidiaries Subsidiaries Reclassifications Consolidated

Revenue:
Service $ — $ 902,157 $ 115,768 $ (5,612 ) $ 1,012,313
Product — 13,752 30,329 — 44,081

— 915,909 146,097 (5,612 ) 1,056,394
Service expenses — 613,823 83,953 (5,612 ) 692,164
Product expenses — 13,273 19,928 — 33,201
Selling, general and administrative expenses 33,785 129,240 18,395 — 181,420
Depreciation and amortization 1,602 185,601 13,529 — 200,732
Fixed asset and other intangibles impairment loss — 38,646 — — 38,646
Goodwill impairment loss — 97,643 — — 97,643

Income (loss) before interest and taxes (35,387 ) (162,317 ) 10,292 — (187,412 )
Interest expense 56,955 6,713 177 (6,950 ) 56,895
Interest income (7,010 ) (6 ) (13 ) 6,950 (79 )
Write-off of deferred financing costs 528 — — — 528
Equity in earnings of consolidated affiliates 133,340 (8,846 ) — (124,494 ) —

Income (loss) before taxes (219,200 ) (160,178 ) 10,128 124,494 (244,756 )
Taxes (37,532 ) (26,838 ) 1,282 — (63,088 )

Net income (loss) $ (181,668 ) $ (133,340 ) $ 8,846 $ 124,494 $ (181,668 )

106

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Condensed Consolidated Statement of Operations
Year Ended December 31, 2008


				Guarantor			Non-guarantor			Eliminations/									Guarantor			Non-guarantor			Eliminations/
	Parent			Subsidiaries			Subsidiaries			Reclassifications			Consolidated			Parent			Subsidiaries			Subsidiaries			Reclassifications			Consolidated

Revenue:
Service	$	—		$	1,641,394		$	142,625		$	(4,567	)	$	1,779,452		$	—		$	1,637,755		$	142,625		$	(4,567	)	$	1,775,813
Product		—			13,988			45,114			—			59,102			—			13,988			45,114			—			59,102

		—			1,655,382			187,739			(4,567	)		1,838,554			—			1,651,743			187,739			(4,567	)		1,834,915
Service expenses		—			994,495			101,957			(4,567	)		1,091,885			—			997,184			101,957			(4,567	)		1,094,574
Product expenses		—			11,507			30,407			—			41,914			—			11,507			30,407			—			41,914
Selling, general and administrative expenses		38,293			142,667			17,292			—			198,252			38,293			142,615			17,292			—			198,200
Depreciation and amortization		1,516			164,965			14,616			—			181,097			1,516			165,065			14,616			—			181,197
Impairment charge		27,670			218,500			25,836			—			272,006			27,670			218,500			25,836			—			272,006

Income (loss) from continuing operations before interest and taxes		(67,479	)		123,248			(2,369	)		—			53,400			(67,479	)		116,872			(2,369	)		—			47,024
Interest expense		62,247			10,939			634			(14,091	)		59,729			62,247			10,939			634			(14,091	)		59,729
Interest income		(14,245	)		(13	)		(134	)		14,091			(301	)		(14,245	)		(13	)		(134	)		14,091			(301	)
Equity in earnings of consolidated affiliates		10,431			8,111			—			(18,542	)		—			10,431			8,111			—			(18,542	)		—

Income (loss) from continuing operations before taxes and minority interest		(125,912	)		104,211			(2,869	)		18,542			(6,028	)
Income (loss) from continuing operations before taxes																	(125,912	)		97,835			(2,869	)		18,542			(12,404	)
Taxes		(40,457	)		109,783			5,242			—			74,568			(40,457	)		107,520			5,242			—			72,305

Income (loss) from continuing operations		(85,455	)		(5,572	)		(8,111	)		18,542			(80,596	)		(85,455	)		(9,685	)		(8,111	)		18,542			(84,709	)
Discontinued operations (net of tax)		—			(4,859	)		—			—			(4,859	)		—			(4,859	)		—			—			(4,859	)

Net income (loss)	$	(85,455	)	$	(10,431	)	$	(8,111	)	$	18,542		$	(85,455	)	$	(85,455	)	$	(14,544	)	$	(8,111	)	$	18,542		$	(89,568	)

~~110~~107

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Condensed Consolidated Statement of ~~Operations~~Cash Flows
Year Ended December 31, ~~2007~~2010

Guarantor
Non-guarantor
Eliminations/

Parent Subsidiaries Subsidiaries Reclassifications Consolidated

Revenue:
Service $ — $ 1,338,528 $ 120,368 $ (4,310 ) $ 1,454,586
Product — 2,272 38,585 — 40,857

— 1,340,800 158,953 (4,310 ) 1,495,443
Service expenses — 759,334 91,918 (4,310 ) 846,942
Product expenses — 2,233 25,388 — 27,621
Selling, general and administrative expenses 28,136 137,475 13,416 — 179,027
Depreciation and amortization 1,102 119,909 10,342 — 131,353
Impairment loss — — 13,094 — 13,094

Income (loss) from continuing operations before interest, taxes, impairment charge and minority interest (29,238 ) 321,849 4,795 — 297,406
Interest expense 63,554 21,348 1,101 (24,675 ) 61,328
Interest income (24,715 ) — (285 ) 24,675 (325 )
Equity in earnings of consolidated affiliates (195,659 ) (474 ) — 196,133 —

Income (loss) from continuing operations before taxes and minority interest 127,582 300,975 3,979 (196,133 ) 236,403
Taxes (33,982 ) 116,759 4,074 — 86,851

Income (loss) from continuing operations before minority interest 161,564 184,216 (95 ) (196,133 ) 149,552
Minority interest — — (569 ) — (569 )

Income (loss) from continuing operations 161,564 184,216 474 (196,133 ) 150,121
Discontinued operations (net of tax) — 11,443 — — 11,443

Net income (loss) $ 161,564 $ 195,659 $ 474 $ (196,133 ) $ 161,564

Guarantor
Non-guarantor
Eliminations/

Parent Subsidiaries Subsidiaries Reclassifications Consolidated

Cash provided by:
Net income (loss) $ 84,158 $ 140,929 $ 8,926 $ (149,855 ) $ 84,158
Items not affecting cash:
Equity in loss of consolidated affiliates (140,929 ) (8,926 ) — 149,855 —
Depreciation and amortization 1,354 168,104 12,365 — 181,823
Other 15,066 50,422 (632 ) — 64,856
Changes in operating assets and liabilities, net of effect of acquisitions 30,112 (134,999 ) 1,500 (11,292 ) (114,679 )

Net cash provided by (used in) operating activities (10,239 ) 215,530 22,159 (11,292 ) 216,158
Investing activities:
Additions to property, plant and equipment (1,862 ) (138,808 ) (4,353 ) — (145,023 )
Inter-company receipts 52,843 — — (52,843 ) —
Business acquisitions, net of cash acquired — (33,721 ) — — (33,721 )
Proceeds from sale of fixed assets — 5,317 165 — 5,482
Other (826 ) — — — (826 )

Net cash provided by (used for) investing activities 50,155 (167,212 ) (4,188 ) (52,843 ) (174,088 )
Financing activities:
Repayments of long-term debt — (228 ) (2 ) — (230 )
Repayments of notes payable (1,069 ) — — — (1,069 )
Inter-company borrowings (repayments) — (48,040 ) (4,358 ) 52,398 —
Proceeds from issuances of common stock 8,082 — — — 8,082
Treasury stock purchased (1,431 ) — — — (1,431 )
Other 1,465 — — — 1,465

Net cash provided by (used in) financing activities 7,047 (48,268 ) (4,360 ) 52,398 6,817
Effect of exchange rate changes on cash — — 434 — 434

Change in cash and cash equivalents 46,963 50 14,045 (11,737 ) 49,321
Cash and cash equivalents, beginning of period 64,871 519 17,001 (5,031 ) 77,360

Cash and cash equivalents, end of period $ 111,834 $ 569 $ 31,046 $ (16,768 ) $ 126,681

~~111~~108

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Condensed Consolidated Statement of ~~Operations~~Cash Flows
Year Ended December 31, ~~2006~~2009

Guarantor
Non-guarantor
Eliminations/

Parent Subsidiaries Subsidiaries Reclassifications Consolidated

Revenue:
Service $ — $ 941,800 $ 117,137 $ (3,912 ) $ 1,055,025
Product — 792 28,794 — 29,586

— 942,592 145,931 (3,912 ) 1,084,611
Service expenses — 529,024 87,688 (3,912 ) 612,800
Product expenses — 122 16,424 — 16,546
Selling, general and administrative expenses 20,752 110,863 12,817 — 144,432
Depreciation and amortization 1,192 64,769 9,941 — 75,902

Income from continuing operations before interest, taxes and minority interest (21,944 ) 237,814 19,061 — 234,931
Interest expense 40,238 17,972 1,920 (19,485 ) 40,645
Interest income (20,733 ) — (139 ) 19,485 (1,387 )
Write-off of deferred financing costs — 170 — — 170
Equity in earnings of consolidated affiliates (162,045 ) (13,786 ) — 175,831 —

Income (loss) from continuing operations before taxes and minority interest 120,596 233,458 17,280 (175,831 ) 195,503
Taxes (18,490 ) 83,660 5,346 — 70,516

Income (loss) from continuing operations before minority interest 139,086 149,798 11,934 (175,831 ) 124,987
Minority interest — — (49 ) — (49 )

Net income (loss) from continuing operations 139,086 149,798 11,983 (175,831 ) 125,036
Discontinued operations (net of tax) — 12,247 1,803 — 14,050

Net income (loss) $ 139,086 $ 162,045 $ 13,786 $ (175,831 ) $ 139,086

Guarantor
Non-guarantor
Eliminations/

Parent Subsidiaries Subsidiaries Reclassifications Consolidated

Cash provided by:
Net income (loss) $ (181,668 ) $ (133,340 ) $ 8,846 $ 124,494 $ (181,668 )
Items not affecting cash:
Equity in loss of consolidated affiliates 133,340 (8,846 ) — (124,494 ) —
Depreciation and amortization 1,602 185,601 13,529 — 200,732
Fixed asset and other intangibles impairment loss — 38,646 — — 38,646
Goodwill impairment loss — 97,643 — — 97,643
Other 14,603 14,658 3,697 — 32,958
Changes in operating assets and liabilities 96,585 1,758 (8,742 ) 7,292 96,893

Net cash provided by operating activities 64,462 196,120 17,330 7,292 285,204
Investing activities:
Additions to property, plant and equipment (649 ) (32,431 ) (4,351 ) — (37,431 )
Inter-company receipts 172,228 (502 ) — (171,726 ) —
Proceeds from sale of fixed assets — 19,996 804 — 20,800
Other — (1,497 ) — — (1,497 )

Net cash provided by (used for) investing activities 171,579 (14,434 ) (3,547 ) (171,726 ) (18,128 )
Financing activities:
Issuances of long-term debt 1,635 — 1,559 — 3,194
Repayments of long-term debt (187,628 ) (3,907 ) (9,074 ) — (200,609 )
Repayments of notes payable (8,244 ) — — — (8,244 )
Inter-company borrowings (repayments) — (177,606 ) 5,880 171,726 —
Proceeds from issuances of common stock 496 — — — 496
Treasury stock purchased (132 ) — — — (132 )
Deferred financing fees (2,911 ) — — — (2,911 )
Other 215 — — — 215

Net cash provided by (used in) financing activities (196,569 ) (181,513 ) (1,635 ) 171,726 (207,991 )
Effect of exchange rate changes on cash — — (225 ) — (225 )

Change in cash and cash equivalents 39,472 173 11,923 7,292 58,860
Cash and cash equivalents, beginning of period 25,399 346 5,078 (12,323 ) 18,500

Cash and cash equivalents, end of period $ 64,871 $ 519 $ 17,001 $ (5,031 ) $ 77,360

~~112~~109

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2008


				Guarantor			Non-guarantor			Eliminations/									Guarantor			Non-guarantor			Eliminations/
	Parent			Subsidiaries			Subsidiaries			Reclassifications			Consolidated			Parent			Subsidiaries			Subsidiaries			Reclassifications			Consolidated

Cash provided by:
Net income (loss)	$	(85,455	)	$	(10,431	)	$	(8,111	)	$	18,542		$	(85,455	)	$	(89,568	)	$	(14,544	)	$	(8,111	)	$	22,655		$	(89,568	)
Items not affecting cash:
Equity in loss of consolidated affiliates		10,431			8,111			—			(18,542	)		—			14,544			8,111			—			(22,655	)		—
Depreciation and amortization		1,516			166,959			14,616			—			183,091			1,516			167,059			14,616			—			183,191
Impairment charge		27,670			218,500			25,836			—			272,006			27,670			218,500			25,836			—			272,006
Other		5,182			39,114			680			—			44,976			5,182			35,204			680			—			41,066
Changes in operating assets and liabilities, net of effect of acquisitions		(61,520	)		11,069			(8,143	)		(5,576	)		(64,170	)		(61,520	)		18,953			(8,143	)		(5,576	)		(56,286	)

Net cash provided by operating activities		(102,176	)		433,322			24,878			(5,576	)		350,448
Net cash provided by (used in) operating activities																	(102,176	)		433,283			24,878			(5,576	)		350,409
Investing activities:
Business acquisitions, net of cash acquired		—			(180,154	)		—			—			(180,154	)		—			(180,154	)		—			—			(180,154	)
Additions to property, plant and equipment		(1,632	)		(229,346	)		(22,837	)		—			(253,815	)		(1,632	)		(229,307	)		(22,837	)		—			(253,776	)
Inter-company receipts		87,395			—			—			(87,395	)		—			87,395			—			—			(87,395	)		—
Proceeds from sale of disposal group		—			50,150			—			—			50,150			—			50,150			—			—			50,150
Other		—			9,369			313			—			9,682			—			9,369			313			—			9,682

Net cash provided by (used for) investing activities		85,763			(349,981	)		(22,524	)		(87,395	)		(374,137	)		85,763			(349,942	)		(22,524	)		(87,395	)		(374,098	)
Financing activities:
Issuances of long-term debt		341,043			—			9,072			—			350,115			341,043			—			9,072			—			350,115
Repayments of long-term debt		(314,605	)		(814	)		(13,863	)		—			(329,282	)		(314,605	)		(814	)		(13,863	)		—			(329,282	)
Repayments of notes payable		(14,001	)		—			—			—			(14,001	)		(14,001	)		—			—			—			(14,001	)
Inter-company borrowings (repayments)		—			(87,140	)		(255	)		87,395			—			—			(87,140	)		(255	)		87,395			—
Proceeds from issuances of common stock		12,014			—			—			—			12,014			12,014			—			—			—			12,014
Other		9,144			—			—			—			9,144			9,144			—			—			—			9,144

Net cash provided by (used in) financing Activities		33,595			(87,954	)		(5,046	)		87,395			27,990
Net cash provided by (used in) financing activities																	33,595			(87,954	)		(5,046	)		87,395			27,990
Effect of exchange rate changes on cash		—			—			1,165			—			1,165			—			—			1,165			—			1,165

Change in cash and cash equivalents		17,182			(4,613	)		(1,527	)		(5,576	)		5,466			17,182			(4,613	)		(1,527	)		(5,576	)		5,466
Cash and cash equivalents, beginning of period		8,217			5,549			6,605			(6,747	)		13,624			8,217			4,959			6,605			(6,747	)		13,034

Cash and cash equivalents, end of period	$	25,399		$	936		$	5,078		$	(12,323	)	$	19,090		$	25,399		$	346		$	5,078		$	(12,323	)	$	18,500

~~113~~

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

~~Condensed Consolidated Statement of Cash Flows~~
~~Year Ended December 31, 2007~~

Guarantor
Non-guarantor
Eliminations/

Parent Subsidiaries Subsidiaries Reclassifications Consolidated

Cash provided by:
Net income $ 161,564 $ 195,659 $ 474 $ (196,133 ) $ 161,564
Items not affecting cash:
Equity in earnings of consolidated affiliates (195,659 ) (474 ) — 196,133 —
Depreciation and amortization 1,102 124,517 10,342 — 135,961
Impairment charge — — 13,094 — 13,094
Other 1,604 49,725 (2,225 ) — 49,104
Changes in operating assets and liabilities, net of effect of acquisitions 78,277 (102,458 ) 6,220 (3,259 ) (21,220 )

Net cash provided by operating activities 46,888 266,969 27,905 (3,259 ) 338,503
Investing activities:
Business acquisitions, net of cash acquired — (50,406 ) — — (50,406 )
Additions to property, plant and equipment (2,029 ) (349,568 ) (16,062 ) — (367,659 )
Inter-company advances (116,113 ) — — 116,113 —
Other — 8,325 945 — 9,270

Net cash provided by (used for) investing activities (118,142 ) (391,649 ) (15,117 ) 116,113 (408,795 )
Financing activities:
Issuances of long-term debt 333,684 — 10,106 — 343,790
Repayments of long-term debt (252,352 ) (1,230 ) (15,187 ) — (268,769 )
Repayments of notes payable (18,846 ) — — — (18,846 )
Inter-company borrowings (repayments) — 121,926 (5,813 ) (116,113 ) —
Proceeds from issuances of common stock 4,179 — — — 4,179
Other 6,289 — — — 6,289

Net cash provided by (used in) financing Activities 72,954 120,696 (10,894 ) (116,113 ) 66,643
Effect of exchange rate changes on cash — — (2,601 ) — (2,601 )

Change in cash and cash equivalents 1,700 (3,984 ) (707 ) (3,259 ) (6,250 )
Cash and cash equivalents, beginning of period 6,517 9,533 �� 7,312 (3,488 ) 19,874

Cash and cash equivalents, end of period $ 8,217 $ 5,549 $ 6,605 $ (6,747 ) $ 13,624

~~114~~

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~

~~Condensed Consolidated Statement of Cash Flows~~
~~Year Ended December 31, 2006~~

Guarantor
Non-guarantor
Eliminations/

Parent Subsidiaries Subsidiaries Reclassifications Consolidated

Cash provided by:
Net income $ 139,086 $ 162,045 $ 13,786 $ (175,831 ) $ 139,086
Items not affecting cash:
Equity in earnings of consolidated affiliates (162,045 ) (13,786 ) — 175,831 —
Depreciation and amortization 1,192 68,332 10,289 — 79,813
Other 8,946 29,502 (641 ) — 37,807
Changes in operating assets and liabilities, net of effect of acquisitions 37,966 (105,435 ) 1,994 (3,488 ) (68,963 )

Net cash provided by operating activities 25,145 140,658 25,428 (3,488 ) 187,743
Investing activities:
Business acquisitions, net of cash acquired — (360,730 ) (8,876 ) — (369,606 )
Additions to property, plant and equipment (810 ) (289,680 ) (13,432 ) — (303,922 )
Inter-company advances (504,609 ) — — 504,609 —
Purchase of short-term securities (165,000 ) — — — (165,000 )
Proceeds from sale of short-term securities 165,000 — — — 165,000
Proceeds from sale of disposal group — — 19,310 — 19,310
Other (808 ) 4,168 (5 ) — 3,355

Net cash used for investing activities (506,227 ) (646,242 ) (3,003 ) 504,609 (650,863 )
Financing activities:
Issuances of long-term debt 598,133 — 10,570 — 608,703
Repayments of long-term debt (1,028,631 ) — (25,158 ) — (1,053,789 )
Repayments of notes payable (13,589 ) — — — (13,589 )
Inter-company borrowings (repayments) — 509,074 (4,465 ) (504,609 ) —
Borrowings under senior notes 650,000 — — — 650,000
Proceeds from issuances of common stock 291,674 — — — 291,674
Other (11,623 ) — — — (11,623 )

Net cash provided by (used in) financing activities 485,964 509,074 (19,053 ) (504,609 ) 471,376
Effect of exchange rate changes on cash — — 213 — 213

Change in cash and cash equivalents 4,882 3,490 3,585 (3,488 ) 8,469
Cash and cash equivalents, beginning of period 1,635 6,043 3,727 — 11,405

Cash and cash equivalents, end of period $ 6,517 $ 9,533 $ 7,312 $ (3,488 ) $ 19,874

~~115~~

~~COMPLETE PRODUCTION SERVICES, INC.~~

~~Notes to Consolidated Financial Statements — (Continued)~~


23.	Recent accounting pronouncements and authoritative literature:

~~In June 2008, the FASB issued a FASB Staff Position (“FSP”)No. EITF 03-6-1,~~ “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” which states that unvested share-based awards which have non-forfeitable rights to participate in dividend distributions should be considered participating securities in order to calculate earnings per share in accordance with the “Two-Class Method” described in SFAS No. 128, “Earnings per Share.” This guidance becomes effective for fiscal years beginning after December 15, 2008, with retrospective application to prior periods. Early adoption is not permitted. We are currently evaluating the impact that this guidance may have on our financial position, results of operations and cash flows.acquiring

~~116~~110

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

~~In September 2008,~~entity must recognize that excess in earnings as a gain attributable to the acquirer. The FASB ~~issued an FSPNo. FAS 144-d,~~ ~~“Amending~~amended this guidance in April 2009 as it relates to accounting for assets and liabilities assumed in a business combination which arise from contingencies. This amendment requires that contingent assets acquired and liabilities assumed in a business combination to be recognized at fair value on the ~~Criteria~~acquisition date if fair value can be reasonably estimated during the measurement period. If fair value cannot be reasonably estimated during the measurement period, the contingent asset or liability would be recognized as a contingency, in accordance with existing U.S. GAAP, with reasonable estimation of the amount of loss, if any. This amendment also eliminated the specific subsequent accounting guidance for ~~Reporting a Discontinued Operation,” which clarifies~~contingent assets and liabilities, without significantly revising the ~~definition of a discontinued operation as either: (1) a component~~original guidance. However, contingent consideration arrangements of an ~~entity which has been disposed of or classified as held for sale which meets~~acquiree assumed by the ~~criteria of an operating segment as defined under SFAS No. 131, or (2) as~~acquirer in a business ~~as such term is defined in SFAS No. 141R which becomes~~combination would still be initially and subsequently measured at fair value. We originally adopted the revised guidance for business combinations when it became effective on January 1, 2009, and the amendment thereto, subsequently in 2009. In December 2010, the FASB updated this guidance to require each public entity that presents comparative financial statements to disclose the revenue and earnings of the combined entity as if the business combination that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. In addition, this amendment expands the supplemental pro forma disclosures related to such a business combination to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. This most recent amendment should be accounted for prospectively for business combinations for which ~~meets~~ the ~~criteria~~acquisition date is on or after January 1, 2011, for calendar-year reporting entities. Early adoption is permitted. Although we did not early adopt this standard, we do not expect this guidance to have a material impact on our financial position, results of operations or cash flows. We will comply with this update for business combinations that have a material impact on our financial results.

In May 2009, the FASB issued a standard regarding subsequent events that provides guidance as to when an entity should recognize events or transactions occurring after a balance sheet date in its financial statements and the necessary disclosures related to these events. Specifically, the entity should recognize subsequent events that provide evidence about conditions that existed at the balance sheet date, including significant estimates used to prepare financial statements. Originally, this standard required entities to disclose the date through which subsequent events had been evaluated and whether that date was the date the financial statements were issued or the date the financial statements were available to be ~~classified~~issued. We adopted this accounting standard effective June 30, 2009 and applied its provisions prospectively. In February 2010, the FASB modified this standard to eliminate the requirement for publicly-traded entities to disclose the date through which subsequent events have been evaluated.

In January 2010, the FASB issued “Fair Value Measurements and Disclosure (Topic 820)” which clarified the disclosure requirements of existing U.S. GAAP related to fair value measurements. This standard requires additional disclosures about recurring and non-recurring fair value measurements as ~~held~~follows: (1) for ~~sale~~transfers in and out of Level 1 and Level 2 fair value measurements, as those terms are currently defined in existing authoritative literature, a reporting entity is required to disclose the amount of the movement between levels and an explanation for the movement; (2) for activity at Level 3, primarily fair value measurements based on ~~acquisition. This proposed~~unobservable inputs, a reporting entity is required to present separately information about purchases, sales, issuances and settlements, as opposed to presenting such transactions on a net basis; (3) in the event of a disaggregation, a reporting entity is required to provide fair value measurement disclosure for each class of assets and liabilities; and (4) a reporting entity is required to provide disclosures about the valuation techniques and inputs used to measure fair value for both recurring and non-recurring fair value measurements for items that fall in either Level 2 or Level 3. These disclosure requirements are effective for interim and annual reporting periods beginning after December 15, 2009, except for disclosures about purchases, sales, issuances and settlements in the roll forward of activity in Level 3 fair value measurements for which disclosure becomes effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years.

111

COMPLETE PRODUCTION SERVICES, INC.

Notes to Consolidated Financial Statements — (Continued)

relative to the changes in the law. We do not believe that the provisions which have taken effect will have a significant impact on the operation of our existing health insurance plan. However, future provisions under the law which become effective in subsequent periods may impact our health insurance plan and our overall financial position. We are evaluating these provisions as they become effective and continue to seek guidance ~~further modifies certain~~from the FASB and SEC related to the implications of this new legislation on accounting and disclosure requirements. We ~~are currently evaluating the effect~~expect that this ~~proposed guidance may~~legislation will have an impact on our financial position, results of operations and cash ~~flows.~~flows, but we cannot determine the extent of the impact at this time.

In ~~January 2009,~~December 2010, the FASB issued ~~FSP No.FAS 107-b~~additional guidance related to accounting for intangible assets and ~~APB28-a,~~goodwill. The amendments in this update modify Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist. The qualitative factors are consistent with the existing guidance and examples, which require that goodwill of a reporting unit be tested for impairment between annual test dates if an event occurs or circumstances change that would ~~amend SFAS No. 107, “Disclosures About Fair Value of Financial Instruments” and APB Opinion No. 28, “Interim Financial Reporting,” to require disclosure of~~more likely than not reduce the fair value of financial instruments in interim financial statements as well as annual financial statements. In addition, entities would be required to disclose the method and significant assumptions used to estimate the fair value of financial instruments. If ratified, this proposed guidance would becomea reporting unit below its carrying amount. This update is effective for public entities with fiscal years beginning after December 15, 2010 and interim ~~and annual~~ periods ~~ending after March 15, 2009.~~within those years. Early adoption is not permitted. We are currently evaluating the effect this proposed guidance may have on our financial position, results of operations and cash flows.


24.	Subsequent events:

On January ~~30, 2009,~~31, 2011, the Compensation Committee of our Board of Directors approved the annual grant of stock options and non-vested restricted stock to certain employees, officers and directors. Pursuant to this authorization, we issued ~~1,287,008~~428,860 shares of non-vested restricted stock at a grant price of ~~$6.41.~~$27.94. We expect to recognize compensation expense associated with this grant of non-vested restricted stock totaling ~~$8,250~~$11,982 ratably over the three-year vesting period. In addition, we granted ~~905,300~~213,200 stock options to purchase shares of our common stock at an exercise price of ~~$6.41.~~$27.94. These stock options vest ratably over a three-year period. We will recognize compensation expense associated with these stock option grants over the vesting period in accordance with SFAS No. 123R. Further, we plan to seek shareholder approval in May 2009 to increase the shares available for grant through our stock compensation plans, pursuant to which, we expect to issue additional stock-based compensationperiod.

Pursuant to our ~~directors, officers~~2008 Incentive Award Plan, holders of unvested restricted stock have the option to authorize us to repurchase shares equivalent to the cost of the withholding tax associated with the vesting of restricted stock and ~~employees.~~to remit the withholding taxes on behalf of the holder. Pursuant to this provision, we purchased 64,348 shares of our common stock on January 29, 2011 for $27.29 per share, 91,417 shares on January 30, 2011 for $27.29 per share and 43,869 shares on January 31, 2011 for $27.94 per share. These shares were included in treasury stock at cost.

Effective January 1, ~~2009,~~2011, we ~~adopted and established~~reinstated the ~~Complete Production Services, Inc. Deferred Compensation Plan, whereby eligible participants, including members~~matching contributions for our defined contribution retirement plans to provide for 100% matching of ~~senior management, directors and certain highly-compensated individuals, could defer~~contributions, up to ~~90% of their compensation and up to 90%~~4% of the ~~employees’~~employee’s salary, depending on the plan. For a description of our retirement plans, see Note 20, “Retirement plans.”

During the review of our property, plant and equipment at December 31, 2010 in conjunction with our annual ~~incentive bonus, or, 100%~~impairment testing of ~~director compensation~~long-term assets, we noted approximately $5,814 of salvage value assigned to various coiled tubing and wireline assets at one of our operating divisions. Although we evaluated these assets and the assets of the overall reporting unit for ~~services rendered, into various investment options pre-tax. For amounts deferred,~~recoverability and noted no significant impairment based on an undiscounted cash flow projection, we ~~will match~~believe that the ~~contribution dollar-for-dollar up~~salvage value assigned to ~~four percent of compensation minus $10,~~these assets is no longer appropriate. These assets were acquired several years ago, and we ~~may make other discretionary contributions pursuant~~believe the estimate for salvage value used at that time was appropriate. However, increasingly, our business is focusing on larger-diameter coiled tubing units and more technologically-advanced equipment. As such, we have changed our estimate of salvage value to ~~resolutions~~zero and expect to depreciate these assets over their remaining useful lives, an average of ~~this plan’s administrative committee. Participants immediately vest~~1.3 years at December 31, 2010. This change in ~~amounts deferred as well as any matching or discretionary contributions we make. Participants bear~~estimate will be applied prospectively and is expected to increase our depreciation expense over the risk of loss associated with investment gains or losses. We intend that this plan will meet all the requirements necessary to be a nonqualified, unfunded, unsecured plan of deferred compensation within the meaning of Sections 201(2), 301(a)(3) and 401(a)(1) of the Employee Retirement Income Security Act of 1974, as amended.

In conjunction with the sale of a disposal group in 2006, we received a $2,000 Canadian dollar-denominated note from Paintearth Energy Services, Inc. on October 31, 2006 which was to mature on October 31, 2009 and accrued interest at 6% per annum. On January 31, 2009, we and the borrower amended this note to extend the maturity date to October 31, 2011. Interest is to be calculatednext five years as follows: ~~(1) for the calendar year 2009, the announced prime rate of a specified Canadian bank plus one~~2011 — $4,867; 2012 — $789; 2013 — $134 and one-half percent per annum; (2) for the calendar year 2010, the greater of five percent per annum or the prime rate of a specified Canadian bank plus two percent per annum; and (3) for the calendar year 2011 and thereafter, if applicable, the greater of five percent per annum or the prime rate of a specified Canadian bank plus three percent per annum. This note receivable has been classified as a long-term asset in the accompanying Balance Sheet as of December 31, 2008.2014 — $24.

~~117~~112


Item 9.	*Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.*

None.


Item 9A.	*Controls and Procedures.*

Evaluation of Disclosure Controls and Procedures

As required byRule 13a-15(b) under the Securities Exchange Act of 1934, as amended ~~we have~~(the “Exchange Act”), management has evaluated, ~~under the supervision and~~ with the participation of our ~~management, including our principal executive officer~~Chief Executive Officer and ~~principal financial officer,~~Chief Financial Officer, the effectiveness ~~of the design and operation~~ of our disclosure controls and procedures (as defined inRules 13a-15(e) and15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report onForm 10-K.~~Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure~~

Disclosure controls and procedures ~~were effective as of December 31, 2008,~~refer to controls and other procedures designed to ensure that information ~~is accumulated and communicated~~required to ~~our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and~~be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the ~~SEC.~~Securities and Exchange Commission. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding our required disclosure. In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management was required to apply its judgment in evaluating and implementing possible controls and procedures.

Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2010, the end of the period covered by this Annual Report onForm 10-K, our disclosure controls and procedures were effective at a reasonable assurance level to ensure that information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported as and when required.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a — 15(f) and 15d — 15(f) under the Exchange Act). Our internal control over financial reporting is a process designed by management, under the supervision of the Chief Executive Officer and Chief Financial Officer, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America, and includes those policies and procedures that:

(i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets;

(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States, and that our receipts and expenditures are being made only in accordance with authorizations of management and our directors; and

(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our consolidated financial statements.

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improver override. Because of its inherent limitations, there is a risk that internal control over financial reporting may not prevent or detect, on a timely basis, material misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the

113

degree of compliance with the policies and procedures may deteriorate. Accordingly, even effective internal control over financial reporting can only provide reasonable assurance of achieving their control objectives.

Our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control — Integrated Framework.

Based on our evaluation under the framework inInternal Control — Integrated Framework, our management concluded that, our internal control over financial reporting was effective as of December 31, 2010.

Grant Thornton LLP, the independent registered accounting firm who audited the consolidated financial statements included in this Annual Report, has issued a report on our internal control over financial reporting dated February 18, 2011, also included in this Annual Report and expressed an unqualified opinion on the effectiveness of our internal control over financial reporting as of December 31, 2010.

Changes in Internal Control over Financial Reporting

~~During the three months ended~~As of December 31, ~~2008,~~2010, there were no changes in our system of internal control over financial reporting (as defined in Rules 13a — 15(f) and 15d — 15(f) under the Exchange Act) that occurred during the last fiscal quarter then ended that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

~~Management’s Report on Internal Control~~In 2010, our management approved a plan to implement new accounting software which will replace our existing accounting systems at several of our operating divisions in a phased approach. Two divisions converted during the fourth quarter of 2010 and two divisions will convert during 2011. In addition, we implemented a new chart of accounts which is being adopted as these divisions convert to the new software. Although we believe the new software, once implemented, will enhance our internal controls over ~~Financial Reporting~~

~~Our management is responsible for establishing~~financial reporting and ~~maintaining adequate~~we believe that we have taken the necessary steps to maintain appropriate internal control over financial reporting ~~(as defined in Rules 13a — 15(f)~~during this period of system change, we will continuously monitor controls through and ~~15d — 15(f) under~~around the Securities and Exchange Act of 1934). Our internal control over financial reporting is a process designed by management, under the supervision of the Chief Executive Officer and Chief Financial Officer,system to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America, and includes those policies and procedures that:

~~(i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets;~~

(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect o our consolidated financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls ~~may become inadequate because~~are effective during and after each step of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate. Accordingly, even effective internal control over financial reporting can only provide reasonable assurance of achieving their control objectives.

Our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. In making this ~~assessment, management used the criteria set forth by the committee of Sponsoring Organizations of the Treadway Commission (COSO) in~~~~Internal Control — Integrated Framework~~.

~~Based on our evaluation under the framework in~~~~Internal Control — Integrated Framework~~~~, our management concluded that, as of December 31, 2008, our internal control over financial reporting was effective.~~

~~118~~

Grant Thornton LLP, the independent registered accounting firm who audited the consolidated financial statements included in this Annual Report, has issued a report on our internal control over financial reporting dated February 27, 2009, also included in this Annual Report.implementation process.

/s/ Joseph C. Winkler

Joseph C. Winkler

Chairman and Chief Executive Officer

February ~~27, 2009~~18, 2011

/s/ Jose A. Bayardo

Jose A. Bayardo

Sr. Vice President and Chief Financial Officer

February ~~27, 2009~~18, 2011


Item 9B.	*Other Information.*

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

~~Item 10 will~~The information to be ~~incorporated~~included in the sections entitled, “Election of Directors” and “Executive Officers,” respectively, in the Definitive Proxy Statement of the Annual Meeting of Stockholders to be filed by ~~reference pursuant to Regulation 14A under the Securities Exchange Act of 1934. The Registrant expects to file a definitive proxy statement~~us with the

114

Securities and Exchange Commission ~~within~~no later than 120 days after December 31, 2010 (the “2010 Proxy Statement”) is incorporated herein by reference.

The information to be included in the ~~close~~section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” in the 2011 Proxy Statement is incorporated herein by reference.

The information to be included in the section entitled “Corporate Governance” in the 2011 Proxy Statement is incorporated herein by reference.

We have filed, as exhibits to this Annual Report onForm 10-K, the certifications of our Principal Executive Officer and Principal Financial Officer required pursuant to Section 302 of the ~~year ended December 31, 2008.~~Sarbanes-Oxley Act of 2002.


Item 11.	*Executive Compensation.*

~~Item 11 will~~The information to be included in the sections entitled “Executive Compensation” and “Directors’ Compensation” in the 2011 Proxy Statement is incorporated herein by reference pursuant to Regulation 14A under the Securities Exchange Act of 1934. The Registrant expects to file a definitive proxy statement with the Securities and Exchange Commission within 120 days after the close of the year ended December 31, 2008.reference.


Item 12.	*Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.*

~~Item 12 will~~The information to be included in the section entitled “Security Ownership of Certain Beneficial Owners and Management” in the 2011 Proxy Statement is incorporated herein by reference pursuant to Regulation 14A under the Securities Exchange Act of 1934. The Registrant expects to file a definitive proxy statement with the Securities and Exchange Commission within 120 days after the close of the year ended December 31, 2008.reference.


Item 13.	*Certain Relationships and Related Transactions, and Director Independence.*

~~Item 13 will~~The information to be included in the sections entitled “Certain Relationships and Related Transactions” and “Board Independence” in the 2011 Proxy Statement is incorporated herein by reference pursuant to Regulation 14A under the Securities Exchange Act of 1934. The Registrant expects to file a definitive proxy statement with the Securities and Exchange Commission within 120 days after the close of the year ended December 31, 2008.reference.


Item 14.	*Principal Accounting Fees and Services.*

~~Item 14 will~~The information to be included in the section entitled “Independent Registered Public Accountants” in the 2011 Proxy Statement is incorporated herein by reference pursuant to Regulation 14A under the Securities Exchange Act of 1934. The Registrant expects to file a definitive proxy statement with the Securities and Exchange Commission within 120 days after the close of the year ended December 31, 2008.reference.

~~119~~

PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a) List the following documents filed as a part of the report:

Description
Page No.

Report of Independent Registered Public Accounting Firm
6162
Consolidated Balance Sheets as of December 31, ~~2008~~2010 and ~~2007~~
2009 6364
Consolidated Statements of Operations for the Years Ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006~~
2008 6465
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006~~
2008 6566
Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006~~
2008 6667
Consolidated Statements of Cash Flows for the Years Ended December 31, ~~2008, 2007~~2010, 2009 and ~~2006~~
67
~~Notes to Consolidated Financial Statements~~
2008 68
Notes to Consolidated Financial Statements 69

(b) Exhibits Please see our Exhibit Index, on Page 117.
~~The following exhibits are incorporated by reference into the filing indicated or are filed herewith.~~

Incorporated by
Exhibit
Reference to the
No.

Exhibit Title

Following

2 .1 — Stock Purchase Agreement dated November 8, 2006 among Complete Production Services, Inc., Integrated Production Services, LLC and Pumpco Services Inc. and Each Seller Listed on Schedule I Thereto Form 8-K, filed November 14, 2006

3 .1 — Amended and Restated Certificate of Incorporation Form S-1/A, filed January 18, 2006,(file no. 333-128750)

3 .2 — Amended and Restated Bylaws Form 8-K, filed February 27, 2008

4 .1 — Specimen Stock Certificate representing common stock Form S-1/A, filed April 4, 2006,(file no. 333-128750)

4 .2 — Indenture dated December 6, 2006, between Complete Production Services, Inc. and the Guarantors Named Therein, with Wells Fargo Bank, National Association, as Trustee, for 8% Senior Notes due 2016 Form 8-K, filed December 8, 2006

4 .3 — Registration Rights Agreement dated November 8, 2006 pursuant to Stock Purchase Agreement dated November 8, 2006 among Complete Production Services, Inc., Integrated Production Services, LLC and Pumpco Services Inc. and Each Seller Listed on Schedule I Thereto Form 8-K, filed November 14, 2006

4 .4 — First Supplemental Indenture, dated August 28, 2007, among Complete Production Services, Inc., the subsidiary guarantors party thereto, and Wells Fargo Bank, National Association, as trustee Form 10-Q, filed November 2, 2007,(file no. 001-32858)

10 .1 — Form of Indemnification Agreement Form S-1/A, filed November 15, 2005, (file no. 333-128750)

10 .2* — Employment Agreement dated as of June 20, 2005 with Joseph C. Winkler Form S-1, filed September 30, 2005,(file no. 333-128750)

10 .3 — Amended and Restated Stockholders’ Agreement by and among Complete Production Services Inc. and the stockholders listed therein Form S-1/A, filed March 20, 2006,(file no. 333-128750)

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 Form S-1, filed September 30, 2005,(file no. 333-128750)

~~120~~

Incorporated by
Exhibit
Reference to the
No.

Exhibit Title

Following

10 .5 — Second Amended and Restated Credit Agreement, dated as of December 6, 2006 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 U.S. 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 Lead Arranger and Amegy Bank N.A. and Comerica Bank, as Co-Documentation Agents Form 10-K, filed March 9, 2007,(file no. 001-32858)

10 .6* — Integrated Production Services, Inc. 2001 Stock Incentive Plan Form S-1/A, filed November 15, 2005, (file no. 333-128750)

10 .7* — Complete Energy Services, Inc. 2003 Stock Incentive Plan Form S-1/A, filed November 15, 2005, (file no. 333-128750)

10 .8* — First Amendment to Complete Energy Services, Inc. 2003 Stock Incentive Plan Form S-1/A, filed November 15, 2005, (file no. 333-128750)

10 .9* — Second Amendment to Complete Energy Services, Inc. 2003 Stock Incentive Plan Form S-1/A, filed November 15, 2005, (file no. 333-128750)

10 .10* — Amended and Restated Integrated Production Services, Inc. 2003 Parchman Restricted Stock Plan Form S-1/A, filed November 15, 2005, (file no. 333-128750)

10 .11* — Amended and Restated 2001 Stock Incentive Plan Form S-1/A, filed April 4, 2006, (file no. 333-128750)

10 .12* — Amendment No. 1 to the Complete Production Services, Inc. Amended and Restated 2001 Stock Incentive Plan Form 10-K, filed March 9, 2007, (file no. 001-32858)

10 .13* — I.E. Miller Services, Inc. 2004 Stock Incentive Plan Form S-1/A, filed November 15, 2005, (file no. 333-128750)

10 .14 — Strategic Customer Relationship Agreement Form S-1/A, filed November 15, 2005, (file no. 333-128750)

10 .15* — Form of Restricted Stock Grant Agreement (Employee) Form S-1/A, filed November 15, 2005, (file no. 333-128750)

10 .16* — Form of Restricted Stock Grant Agreement (Non-employee Director) Form S-1/A, filed November 15, 2005, (file no. 333-128750)

10 .17* — Form of Non-Qualified Option Grant Agreement (Executive Officer) Form S-1/A, filed April 4, 2006, (file no. 333-128750)

10 .18* — Form of Non-Qualified Option Grant Agreement (Non-Employee Director) Form S-1/A, filed April 4, 2006, (file no. 333-128750)

10 .19* — Compensation Package Term Sheet — J. Michael Mayer Form S-1/A, filed March 20, 2006, (file no. 333-128750)

10 .20* — Compensation Package Term Sheet — James F. Maroney, III Form S-1/A, filed March 20, 2006, (file no. 333-128750)

10 .21* — Compensation Package Term Sheet — Kenneth L. Nibling Form S-1/A, filed March 20, 2006, (file no. 333-128750)

10 .22* — Incentive Plan Guidelines for Senior Management Form 8-K, filed February 22, 2007

10 .23* — Form of Non-qualified Stock Option Grant Agreement Form 8-K, filed February 2, 2007

10 .24* — Form of Restricted Stock Agreement — Executive Officer (Post-September 2006) Form 8-K, filed February 2, 2007

10 .25* — Restricted Stock Agreement Terms and Conditions (Revised 2006) — Employee Form 10-K, filed March 9, 2007, (file no. 001-32858)

10 .26* — Signature Page for Restricted Stock Agreement — Employee Form 10-K, filed March 9, 2007, (file no. 001-32858)

10 .27* — Non-Employee Director Restricted Stock Agreement Form 10-K, filed March 9, 2007, (file no. 001-32858)

10 .28* — Stock Option Terms and Conditions (Revised 2006) — Employee Form 10-K, filed March 9, 2007, (file no. 001-32858)

10 .29* — Signature Page for Executive Officers Form 10-K, filed March 9, 2007, (file no. 001-32858)

10 .30* — Director Option Agreement Form 10-K, filed March 9, 2007, (file no. 001-32858)

10 .31* — Form of Executive Agreement Form 10-Q, filed May 4, 2007, (file no. 001-32858)
~~121~~

Incorporated by
Exhibit
Reference to the
No.

Exhibit Title

Following

10 .32* — Amendment to Employment Agreement, dated March 21, 2007 between Complete Production Services, Inc. and Mr. Joseph C. Winkler Form 10-Q, filed May 4, 2007, (file no. 001-32858)

10 .33* — Pumpco Services, Inc. 2005 Stock Incentive Plan Registration Statement on Form S-8, filed March 28, 2007, (file no. 333-141628)

10 .34 — First Amendment to Second Amended and Restated Credit Agreement, dated as of December 6, 2006 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 U.S. 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 Lead Arranger and Amegy Bank N.A. and Comerica Bank, as Co-Documentation Agents, effective June 29, 2007. Form 10-Q, filed August 3, 2007, (file no. 001-32858)

10 .35 — Second Amendment to Credit Agreement and Omnibus Amendment to Security Documents, dated October 9, 2007 but effective October 19, 2007, among Complete Production Services, Inc., Integrated Production Services, Ltd., Wells Fargo Bank, National Association, as administrative agent, swing line lender and issuing lender and HSBC Bank Canada, as administrative agent, swing line lender and issuing lender. Form 10-Q, filed November 2, 2007, (file no. 001-32858)

10 .36* — Complete Production Services, Inc. 2008 Incentive Award Plan Registration Statement on Form S-8, filed May 22, 2008, (file no. 333-141628)

10 .37* — Form of Non-Qualified Stock Option Agreement Form 10-Q, filed August 1, 2008, (file no. 001-32858)

10 .38* — Agreement for Non-Employee Directors Form 10-Q, filed August 1, 2008, (file no. 001-32858)

10 .39* — Form of Signature Page for Stock Option Agreement Terms and Conditions Form 10-Q, filed August 1, 2008, (file no. 001-32858)

10 .40* — Restricted Stock Agreement Terms and Conditions Form 10-Q, filed August 1, 2008, (file no. 001-32858)

10 .41* — Form of Stock Agreement Form 10-Q, filed August 1, 2008, (file no. 001-32858)

10 .42* — Signature Page to the Restricted Stock Award Agreement Terms and Conditions Form 10-Q, filed August 1, 2008, (file no. 001-32858)

10 .43* — Restricted Stock Agreement for Non-Employee Directors Form 10-Q, filed August 1, 2008, (file no. 001-32858)

10 .44* — Retirement Agreement between Complete Production Services, Inc. and J. Michael Mayer, effective October 7, 2008. Form 8-K, filed October 9, 2008, (file no. 001-32858)

10 .45* — Complete Production Services, Inc. Deferred Compensation Plan, effective January 1, 2009 Filed herewith

10 .46* — Amended and Restated Employment Agreement, effective December 31, 2008 between Complete Production Services, Inc. and Mr. Joseph C. Winkler Filed herewith

10 .47* — Form of Amended and Restated Complete Production Services Executive Agreement Filed herewith

21 .1 — Subsidiaries of Complete Production Services, Inc. Filed herewith

23 .1 — Consent of Grant Thornton LLP Filed herewith

24 .1 — Power of Attorney (included on signature page) Filed herewith

31 .1 — Certification of Chief Executive Officer Pursuant to Rule 13a — 14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 Filed herewith
~~122~~

Incorporated by
Exhibit
Reference to the
No.

Exhibit Title

Following

31 .2 — Certification of Chief Financial Officer Pursuant to Rule 13a — 14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 Filed herewith

32 .1 — Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 Filed herewith

32 .2 — Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 Filed herewith
* ~~Management employment agreements, compensatory arrangements or option plans~~
~~123~~115

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized

COMPLETE PRODUCTION SERVICES, INC.

By:
/s/  JOSEPH C. WINKLER
Name:     Joseph C. Winkler
Title: Chief Executive Officer

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Joseph C. Winkler and Jose A. Bayardo, and each of them severally, his true and lawful attorney or attorneys-in-fact and agents, with full power to act with or without the others and with full power of substitution and ~~resubstitution,~~re-substitution, to execute in his name, place and stead, in any and all capacities, any or all amendments to this Annual Report onForm 10-K, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents and each of them, full power and authority to do and perform in the name of on behalf of the undersigned, in any and all capacities, each and every act and thing necessary or desirable to be done in and about the premises, to all intents and purposes and as fully as they might or could do in person, hereby ratifying, approving and confirming all that said attorneys-in-fact and agents or their substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature

Position

Date

/s/  JOSEPH C. WINKLER

Joseph C. Winkler Chief Executive Officer and Chairman of the Board (Principal Executive Officer) February ~~27, 2009~~18, 2011

/s/  JOSE A. BAYARDO

Jose A. Bayardo Sr. Vice President and Chief Financial Officer (Principal Financial Officer) February ~~27, 2009~~18, 2011

/s/  ~~ROBERT L. WEISGARBER~~DEWAYNE WILLIAMS

~~Robert L. Weisgarber~~Dewayne Williams Vice President-Accounting and Controller (Principal Accounting Officer) February ~~27, 2009~~
~~/s/  ANDREW L. WAITE~~

~~Andrew L. Waite~~ ~~Director~~ ~~February 27, 2009~~18, 2011

/s/  ROBERT BOSWELL

Robert Boswell Director February ~~27, 2009~~18, 2011

/s/  HAROLD G. HAMM

Harold G. Hamm Director February ~~27, 2009~~18, 2011

/s/  MIKE MCSHANE

Mike ~~Mcshane~~McShane Director February ~~27, 2009~~18, 2011

/s/  W. MATT RALLS

W. Matt Ralls Director February ~~27, 2009~~18, 2011

/s/  MARCUS WATTS

Marcus Watts Director February ~~27, 2009~~
~~/s/  R. GRAHAM WHALING~~

~~R. GRAHAM WHALING~~ ~~Director~~ ~~February 27, 2009~~18, 2011

/s/  JAMES D. WOODS

James D. Woods Director February ~~27, 2009~~18, 2011

~~124~~116

The following exhibits are incorporated by reference into the filing indicated or are filed herewith.

EXHIBIT INDEX


					Incorporated by					Incorporated by
Exhibit	Exhibit				Reference to the	Exhibit				Reference to the
No.	No.			Exhibit Title	Following	No.			Exhibit Title	Following


	2	.1	—	Stock Purchase Agreement dated November 8, 2006 among Complete Production Services, Inc., Integrated Production Services, LLC and Pumpco Services Inc. and Each Seller Listed on Schedule I Thereto	Form 8-K, filed November 14, 2006	3	.1	—	Amended and Restated Certificate of Incorporation	Form S-1/A, filed January 18, 2006, (file no. 333-128750)

	3	.1	—	Amended and Restated Certificate of Incorporation	Form S-1/A, filed January 18, 2006, (file no. 333-128750)	3	.2	—	Amended and Restated Bylaws	Form 8-K, filed February 27, 2008

	3	.2	—	Amended and Restated Bylaws	Form 8-K, filed February 27, 2008	4	.1	—	Specimen Stock Certificate representing common stock	Form S-1/A, filed April 4, 2006, (file no. 333-128750)

	4	.1	—	Specimen Stock Certificate representing common stock	Form S-1/A, filed April 4, 2006, (file no. 333-128750)	4	.2	—	Indenture dated December 6, 2006, between Complete Production Services, Inc. and the Guarantors Named Therein, with Wells Fargo Bank, National Association, as Trustee, for 8% Senior Notes due 2016	Form 8-K, filed December 8, 2006

	4	.2	—	Indenture dated December 6, 2006, between Complete Production Services, Inc. and the Guarantors Named Therein, with Wells Fargo Bank, National Association, as Trustee, for 8% Senior Notes due 2016	Form 8-K, filed December 8, 2006	4	.3	—	Registration Rights Agreement dated November 8, 2006 pursuant to Stock Purchase Agreement dated November 8, 2006 among Complete Production Services, Inc., Integrated Production Services, LLC and Pumpco Services Inc. and Each Seller Listed on Schedule I Thereto	Form 8-K, filed November 14, 2006

	4	.3	—	Registration Rights Agreement dated November 8, 2006 pursuant to Stock Purchase Agreement dated November 8, 2006 among Complete Production Services, Inc., Integrated Production Services, LLC and Pumpco Services Inc. and Each Seller Listed on Schedule I Thereto	Form 8-K, filed November 14, 2006	4	.4	—	First Supplemental Indenture, dated August 28, 2007, among Complete Production Services, Inc., the subsidiary guarantors party thereto, and Wells Fargo Bank, National Association, as trustee	Form 10-Q, filed November 2, 2007, (file no. 001-32858)

	4	.4	—	First Supplemental Indenture, dated August 28, 2007, among Complete Production Services, Inc., the subsidiary guarantors party thereto, and Wells Fargo Bank, National Association, as trustee	Form 10-Q, filed November 2, 2007, (file no. 001-32858)	10	.1	—	Form of Indemnification Agreement	Form S-1/A, filed November 15, 2005, (file no. 333-128750)

	10	.1	—	Form of Indemnification Agreement	Form S-1/A, filed November 15, 2005, (file no. 333-128750)	10	.2*	—	Employment Agreement dated as of June 20, 2005 with Joseph C. Winkler	Form S-1, filed September 30, 2005, (file no. 333-128750)

	10	.2*	—	Employment Agreement dated as of June 20, 2005 with Joseph C. Winkler	Form S-1, filed September 30, 2005, (file no. 333-128750)	10	.3	—	Amended and Restated Stockholders’ Agreement by and among Complete Production Services Inc. and the stockholders listed therein	Form S-1/A, filed March 20, 2006, (file no. 333-128750)

	10	.3	—	Amended and Restated Stockholders’ Agreement by and among Complete Production Services Inc. and the stockholders listed therein	Form S-1/A, filed March 20, 2006, (file no. 333-128750)	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	Form S-1, filed September 30, 2005, (file no. 333-128750)

	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	Form S-1, filed September 30, 2005, (file no. 333-128750)	10	.5	—	Second Amended and Restated Credit Agreement, dated as of December 6, 2006 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 U.S. 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 Lead Arranger and Amegy Bank N.A. and Comerica Bank, as Co-Documentation Agents	Form 10-K, filed March 9, 2007, (file no. 001-32858)

	10	.5	—	Second Amended and Restated Credit Agreement, dated as of December 6, 2006 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 U.S. 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 Lead Arranger and Amegy Bank N.A. and Comerica Bank, as Co-Documentation Agents	Form 10-K, filed March 9, 2007, (file no. 001-32858)	10	.6*	—	Integrated Production Services, Inc. 2001 Stock Incentive Plan	Form S-1/A, filed November 15, 2005, (file no. 333-128750)

	10	.6*	—	Integrated Production Services, Inc. 2001 Stock Incentive Plan	Form S-1/A, filed November 15, 2005, (file no. 333-128750)	10	.7*	—	Complete Energy Services, Inc. 2003 Stock Incentive Plan	Form S-1/A, filed November 15, 2005, (file no. 333-128750)

	10	.7*	—	Complete Energy Services, Inc. 2003 Stock Incentive Plan	Form S-1/A, filed November 15, 2005, (file no. 333-128750)	10	.8*	—	First Amendment to Complete Energy Services, Inc. 2003 Stock Incentive Plan	Form S-1/A, filed November 15, 2005, (file no. 333-128750)

	10	.8*	—	First Amendment to Complete Energy Services, Inc. 2003 Stock Incentive Plan	Form S-1/A, filed November 15, 2005, (file no. 333-128750)	10	.9*	—	Second Amendment to Complete Energy Services, Inc. 2003 Stock Incentive Plan	Form S-1/A, filed November 15, 2005, (file no. 333-128750)

	10	.9*	—	Second Amendment to Complete Energy Services, Inc. 2003 Stock Incentive Plan	Form S-1/A, filed November 15, 2005, (file no. 333-128750)	10	.10*	—	Amended and Restated Integrated Production Services, Inc. 2003 Parchman Restricted Stock Plan	Form S-1/A, filed November 15, 2005, (file no. 333-128750)

	10	.10*	—	Amended and Restated Integrated Production Services, Inc. 2003 Parchman Restated Stock Plan	Form S-1/A, filed November 15, 2005, (file no. 333-128750)	10	.11*	—	Amended and Restated 2001 Stock Incentive Plan	Form S-1/A, filed April 4, 2006, (file no. 333-128750)

	10	.11*	—	Amended and Restated 2001 Stock Incentive Plan	Form S-1/A, filed April 4, 2006, (file no. 333-128750)	10	.12*	—	Amendment No. 1 to the Complete Production Services, Inc. Amended and Restated 2001 Stock Incentive Plan	Form 10-K, filed March 9, 2007 (file no. 001-32858)

						10	.13*	—	I.E. Miller Services, Inc. 2004 Stock Incentive Plan	Form S-1/A, filed November 15, 2005, (file no. 333-128750)

117


					Incorporated by					Incorporated by
Exhibit	Exhibit				Reference to the	Exhibit				Reference to the
No.	No.			Exhibit Title	Following	No.			Exhibit Title	Following


	10	.12*	—	Amendment No. 1 to the Complete Production Services, Inc. Amended and Restated 2001 Stock Incentive Plan	Form 10-K, filed March 9, 2007 (file no. 001-32858)	10	.14	—	Strategic Customer Relationship Agreement	Form S-1/A, filed November 15, 2005, (file no. 333-128750)

	10	.13*	—	I.E. Miller Services, Inc. 2004 Stock Incentive Plan	Form S-1/A, filed November 15, 2005, (file no. 333-128750)	10	.15*	—	Form of Restricted Stock Grant Agreement (Employee)	Form S-1/A, filed November 15, 2005, (file no. 333-128750)

	10	.14	—	Strategic Customer Relationship Agreement	Form S-1/A, filed November 15, 2005, (file no. 333-128750)	10	.16*	—	Form of Restricted Stock Grant Agreement (Non-employee Director)	Form S-1/A, filed November 15, 2005, (file no. 333-128750)

	10	.15*	—	Form of Restricted Stock Grant Agreement (Employee)	Form S-1/A, filed November 15, 2005, (file no. 333-128750)	10	.17*	—	Form of Non-Qualified Option Grant Agreement (Executive Officer)	Form S-1/A, filed April 4, 2006, (file no. 333-128750)

	10	.16*	—	Form of Restricted Stock Grant Agreement (Non-employee Director)	Form S-1/A, filed November 15, 2005, (file no. 333-128750)	10	.18*	—	Form of Non-Qualified Option Grant Agreement (Non-Employee Director)	Form S-1/A, filed April 4, 2006, (file no. 333-128750)

	10	.17*	—	Form of Non-Qualified Option Grant Agreement (Executive Officer)	Form S-1/A, filed April 4, 2006, (file no. 333-128750)	10	.19*	—	Compensation Package Term Sheet — James F. Maroney, III	Form S-1/A, filed March 20, 2006, (file no. 333-128750)

	10	.18	—	Form of Non-Qualified Option Grant Agreement (Non-Employee Director)	Form S-1/A, filed April 4, 2006, (file no. 333-128750)	10	.20*	—	Compensation Package Term Sheet — Kenneth L. Nibling	Form S-1/A, filed March 20, 2006, (file no. 333-128750)

	10	.19*	—	Compensation Package Term Sheet — J. Michael Mayer	Form S-1/A, filed March 20, 2006, (file no. 333-128750)	10	.21*	—	Incentive Plan Guidelines for Senior Management	Form 8-K, filed February 22, 2007

	10	.20*	—	Compensation Package Term Sheet — James F. Maroney, III	Form S-1/A, filed March 20, 2006, (file no. 333-128750)	10	.22*	—	Form of Non-qualified Stock Option Grant Agreement	Form 8-K, filed February 2, 2007

	10	.21*	—	Compensation Package Term Sheet — Kenneth L. Nibling	Form S-1/A, filed March 20, 2006, (file no. 333-128750)	10	.23*	—	Form of Restricted Stock Agreement — Executive Officer (Post-September 2006)	Form 8-K, filed February 2, 2007

	10	.22*	—	Incentive Plan Guidelines for Senior Management	Form 8-K, filed February 22, 2007	10	.24*	—	Restricted Stock Agreement Terms and Conditions (Revised 2006) — Employee	Form 10-K, filed March 9, 2007, (file no. 001-32858)

	10	.23*	—	Form of Non-qualified Stock Option Grant Agreement	Form 8-K, filed February 2, 2007	10	.25*	—	Signature Page for Restricted Stock Agreement — Employee	Form 10-K, filed March 9, 2007, (file no. 001-32858)

	10	.24*	—	Form of Restricted Stock Agreement — Executive Officer (Post-September 2006)	Form 8-K, filed February 2, 2007	10	.26*	—	Non-Employee Director Restricted Stock Agreement	Form 10-K, filed March 9, 2007, (file no. 001-32858)

	10	.25*	—	Restricted Stock Agreement Terms and Conditions (Revised 2006) — Employee	Form 10-K, filed March 9, 2007, (file no. 001-32858)	10	.27*	—	Stock Option Terms and Conditions (Revised 2006) — Employee	Form 10-K, filed March 9, 2007, (file no. 001-32858)

	10	.26*	—	Signature Page for Restricted Stock Agreement — Employee	Form 10-K, filed March 9, 2007, (file no. 001-32858)	10	.28*	—	Signature Page for Executive Officers	Form 10-K, filed March 9, 2007, (file no. 001-32858)

	10	.27*	—	Non-Employee Director Restricted Stock Agreement	Form 10-K, filed March 9, 2007, (file no. 001-32858)	10	.29*	—	Director Option Agreement	Form 10-K, filed March 9, 2007, (file no. 001-32858)

	10	.28*	—	Stock Option Terms and Conditions (Revised 2006) — Employee	Form 10-K, filed March 9, 2007, (file no. 001-32858)	10	.30*	—	Form of Executive Agreement	Form 10-Q, filed May 4, 2007, (file no. 001-32858)

						10	.31*	—	Amendment to Employment Agreement, dated March 21, 2007 between Complete Production Services, Inc. and Mr. Joseph C. Winkler	Form 10-Q, filed May 4, 2007, (file no. 001-32858)

	10	.29*	—	Signature Page for Executive Officers	Form 10-K, filed March 9, 2007, (file no. 001-32858)	10	.32*	—	Pumpco Services, Inc. 2005 Stock Incentive Plan	Registration Statement on Form S-8, filed March 28, 2007, (file no. 333-141628)

	10	.30*	—	Director Option Agreement	Form 10-K, filed March 9, 2007, (file no. 001-32858)	10	.33	—	First Amendment to Second Amended and Restated Credit Agreement, dated as of December 6, 2006 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 U.S. 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 Lead Arranger and Amegy Bank N.A. and Comerica Bank, as Co-Documentation Agents, effective June 29, 2007.	Form 10-Q, filed August 3, 2007, (file no. 001-32858)

	10	.31*	—	Amendment to Employment Agreement, dated March 21, 2007 between Complete Production Services, Inc. and Mr. Joseph C. Winkler	Form 10-Q, filed May 4, 2007, (file no. 001-32858)	10	.34	—	Second Amendment to Credit Agreement and Omnibus Amendment to Security Documents, dated October 9, 2007 but effective October 19, 2007, among Complete Production Services, Inc., Integrated Production Services, Ltd., Wells Fargo Bank, National Association, as administrative agent, swing line lender and issuing lender and HSBC Bank Canada, as administrative agent, swing line lender and issuing lender.	Form 10-Q, filed November 2, 2007, (file no. 001-32858)

	10	.32*	—	Form of Executive Agreement	Form 10-Q, filed May 4, 2007, (file no. 001-32858)	10	.35*	—	Complete Production Services, Inc. 2008 Incentive Award Plan	Appendix A of Definitive Proxy Statement on Schedule 14, filed April 7, 2008

	10	.33*	—	Pumpco Services, Inc. 2005 Stock Incentive Plan	Registration Statement on Form S-8, filed March 28, 2007, (file no. 333-141628)	10	.36*	—	Form of Non-Qualified Stock Option Agreement	Form 10-Q, filed August 1, 2008, (file no. 001-32858)

	10	.34	—	First Amendment to Second Amended and Restated Credit Agreement, dated as of December 6, 2006 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 U.S. 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 Lead Arranger and Amegy Bank N.A. and Comerica Bank, as Co-Documentation Agents, effective June 29, 2007.	Form 10-Q, filed August 3, 2007, (file no. 001-32858)

118


					Incorporated by					Incorporated by
Exhibit	Exhibit				Reference to the	Exhibit				Reference to the
No.	No.			Exhibit Title	Following	No.			Exhibit Title	Following


	10	.35	—	Second Amendment to Credit Agreement and Omnibus Amendment to Security Documents, dated October 9, 2007 but effective October 19, 2007, among Complete Production Services, Inc., Integrated Production Services, Ltd., Wells Fargo Bank, National Association, as administrative agent, swing line lender and issuing lender and HSBC Bank Canada, as administrative agent, swing line lender and issuing lender.	Form 10-Q, filed November 2, 2007, (file no. 001-32858)	10	.37*	—	Agreement for Non-Employee Directors	Form 10-Q, filed August 1, 2008, (file no. 001-32858)

	10	.36*	—	Complete Production Services, Inc. 2008 Incentive Award Plan	Registration Statement on Form S-8, filed May 22, 2008, (file no. 333-141628)	10	.38*	—	Form of Signature Page for Stock Option Agreement Terms and Conditions	Form 10-Q, filed August 1, 2008, (file no. 001-32858)

	10	.37*	—	Form of Non-Qualified Stock Option Agreement	Form 10-Q, filed August 1, 2008, (file no. 001-32858)	10	.39*	—	Restricted Stock Agreement Terms and Conditions	Form 10-Q, filed August 1, 2008, (file no. 001-32858)

	10	.38*	—	Agreement for Non-Employee Directors	Form 10-Q, filed August 1, 2008, (file no. 001-32858)	10	.40*	—	Form of Stock Agreement	Form 10-Q, filed August 1, 2008, (file no. 001-32858)

	10	.39*	—	Form of Signature Page for Stock Option Agreement Terms and Conditions	Form 10-Q, filed August 1, 2008, (file no. 001-32858)	10	.41*	—	Signature Page to the Restricted Stock Award Agreement Terms and Conditions	Form 10-Q, filed August 1, 2008, (file no. 001-32858)

	10	.40*	—	Restricted Stock Agreement Terms and Conditions	Form 10-Q, filed August 1, 2008, (file no. 001-32858)	10	.42*	—	Restricted Stock Agreement for Non-Employee Directors	Form 10-Q, filed August 1, 2008, (file no. 001-32858)

	10	.41*	—	Form of Stock Agreement	Form 10-Q, filed August 1, 2008, (file no. 001-32858)	10	.43*	—	Retirement Agreement between Complete Production Services, Inc. and J. Michael Mayer, effective October 7, 2008.	Form 8-K, filed October 9, 2008, (file no. 001-32858)

	10	.42*	—	Signature Page to the Restricted Stock Award Agreement Terms and Conditions	Form 10-Q, filed August 1, 2008, (file no. 001-32858)	10	.44*	—	Complete Production Services, Inc. Deferred Compensation Plan, effective January 1, 2009	Form 10-K, filed February 27, 2009, (file no. 001-32858)

	10	.43*	—	Restricted Stock Agreement for Non-Employee Directors	Form 10-Q, filed August 1, 2008, (file no. 001-32858)	10	.45*	—	Amended and Restated Employment Agreement, effective December 31, 2008 between Complete Production Services, Inc. and Mr. Joseph C. Winkler	Form 10-K, filed February 27, 2009, (file no. 001-32858)

	10	.44*	—	Retirement Agreement between Complete Production Services, Inc. and J. Michael Mayer, effective October 7, 2008.	Form 8-K, filed October 9, 2008, (file no. 001-32858)	10	.46*	—	Form of Amended and Restated Complete Production Services Executive Agreement	Form 10-K, filed February 27, 2009, (file no. 001-32858)

	10	.45*	—	Complete Production Services, Inc. Deferred Compensation Plan, effective January 1, 2009	Filed herewith	10	.47	—	Second Supplemental Indenture among the Guarantor Subsidiaries of Complete Production Services, Inc., and Wells Fargo Bank, National Association, as trustee under the Indenture, dated April 1, 2009	Form 10-Q, filed April 30, 2009 (file no.001-32858)

	10	.46*	—	Amended and Restated Employment Agreement, effective December 31, 2008 between Complete Production Services, Inc. and Mr. Joseph C. Winkler	Filed herewith	10	.48	—	Third Amendment to Credit Agreement, Omnibus Amendment to Credit Documents and Assignment, dated as of October 13, 2009, among Complete Production Services, Inc., Integrated Production Services Ltd., certain subsidiary guarantors party thereto, the lenders party thereto, Wells Fargo Bank, National Association, Wells Fargo Foothill, LLC and HSBC Bank Canada	Form 8-K, filed October 16, 2009

	10	.47*	—	Form of Amended and Restated Complete Production Services Executive Agreement	Filed herewith	10	.49*	—	Retirement Agreement between the Company and Robert L. Weisgarber dated May 15, 2009	Form 8-K, filed May 18, 2009

	21	.1	—	Subsidiaries of Complete Production Services, Inc.	Filed herewith	10	.50*	—	Amendment No. 1 to the Complete Production Services, Inc. 2008 Incentive Award Plan	Proxy Statement on Schedule 14A, filed May 11, 2009

	23	.1	—	Consent of Grant Thornton LLP	Filed herewith	10	.51*	—	Complete Production Services, Inc. Amended and Restated Deferred Compensation Plan	Form 10-Q, filed April 30, 2010 (file no. 001-32858)

	24	.1	—	Power of Attorney (included on signature page)	Filed herewith	21	.1	—	Subsidiaries of Complete Production Services, Inc.	Filed herewith

	31	.1	—	Certification of Chief Executive Officer Pursuant to Rule 13a — 14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith	23	.1	—	Consent of Grant Thornton LLP	Filed herewith

	31	.2	—	Certification of Chief Financial Officer Pursuant to Rule 13a — 14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith	24	.1	—	Power of Attorney (included on signature page)	Filed herewith

	32	.1	—	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith	31	.1	—	Certification of Chief Executive Officer Pursuant to Rule 13a — 14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

	32	.2	—	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith	31	.2	—	Certification of Chief Financial Officer Pursuant to Rule 13a — 14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

						32	.1	—	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith

						32	.2	—	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith

119


(MARK ONE)

þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		FOR THE FISCAL YEAR ENDED DECEMBER 31, ~~2008~~2010
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


Delaware (State or Other Jurisdiction of Incorporation or Organization)		72-1503959 (I.R.S. Employer Identification No.)

11700 Katy Freeway, Suite 300 Houston, Texas (Address of principal executive offices)		77079 (Zip Code)


		Name of each exchange on
Title of each class		which registered

Common stock, $0.01 par value		New York Stock Exchange


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o


				Page

PART I
	Item 1.		Business		3
	Item 1A.		Risk Factors		1918
	Item 1B.		Unresolved Staff Comments		30
	Item 2.		Properties		30
	Item 3.		Legal Proceedings		30
	Item 4.	~~Submission of Matters to a Vote of Security Holders~~		31(Removed and Reserved)		30

PART II
	Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		3231
	Item 6.		Selected Financial Data		34
	Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operation		36
	Item 7A.		Quantitative and Qualitative Disclosures About Market Risk		6061
	Item 8.		Financial Statements and Supplementary Data		6061
	Item 9.		Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		~~118~~113
	Item 9A.		Controls and Procedures		~~118~~113
	Item 9B.		Other Information		~~119~~114

PART III
	Item 10.		Directors, Executive Officers and Corporate Governance		~~119~~114
	Item 11.		Executive Compensation		~~119~~115
	Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		~~119~~115
	Item 13.		Certain Relationships and Related Transactions, and Director Independence		~~119~~115
	Item 14.		Principal ~~Accountant~~Accounting Fees and Services		~~119~~115

PART IV
	Item 15.		Exhibits and Financial Statement Schedules		~~120~~115
Signatures					~~124~~116
~~EX-10.45~~
~~EX-10.46~~
~~EX-10.47~~
EX-21.1
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT


	•	clear business direction;

	•	thorough planning process;

	•	clearly defined targets and accountabilities;

	•	close performance monitoring;

	•	safety objectives;

	•	performance incentives for management and employees; and

	•	effective communication.


	•	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 ~~good~~well-maintained equipment, ~~well trained~~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.


	•	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~~access to the ~~surface.~~formation. 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. 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 where the


		information is processed by a surface computer system and displayed on a 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~~used 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 a well might 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.


Item 1.	*Business*


	•	~~Electric-Line Services:~~


Item 1A.	*Risk Factors.*


	•	Gas Lift Services and Products. We provide gas lift candidate selection, installation and maintenance services. Gas lift systems facilitate the removal of fluids that restrict the production of natural gas wells. Evacuating fluids that accumulate in wells increases production and, in many cases, slows decline rates. Gas is injected down the tubing-casing annular and enters the tubing string through a valve to aerate liquids above an entrance point to reduce hydrostatic pressure. Valves are set at varying depths and pressures throughout the tubing string to aerate the fluid column. This practice reduces bottom hole pressure, resulting in an increase in production.

	•	Acoustic Pressure Surveys. We provide acoustic pressure surveys, 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.


	•	Wellclean-ups or flowbacksare 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. Ourclean-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;~~gas.


	•	Exploration well testingmeasures how a reservoir performs under various flow conditions. These measurements allow reservoir and production engineers and geologists to understand ~~a well’s~~well or ~~reservoir’s~~reservoir production ~~capability.~~capabilities. Exploration testing jobs can last from a few days to several ~~months; and~~months.

	•	In-line production testingmeasures ~~a well’s~~well 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~~as well as other equipment ~~including~~such as stabilizers, power swivels and bottom-hole assemblies.

	•	Fishing Services. We provide ~~highly skilled~~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, as well as 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~~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 and casings and tubing strings. The units are also used to assemble and disassemble blowout preventors (“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. We have multi-service pressure testing units that we operate in Colorado, North Dakota, Utah, Wyoming and Mexico.


	•	Fluid Transportation. We operate 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. We operate a fleet of 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. We own salt water disposal wells in Oklahoma, Texas, Colorado and Arkansas 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 of oil and gas. ~~In addition, we 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 Rig Moving.~~ Through our owned and operated fleet of specialized trucks, we provide drilling rig mobilization services primarily in Louisiana, Texas, North Dakota and Arkansas. 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 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 Colorado and Wyoming.


	•	personal injury or loss of life;

	•	damage or destruction of property, equipment and the environment; and

	•	suspension of operations.


	•	~~competition within our industry;~~general economic and market conditions;

	•	~~general economic and market conditions;~~our access to current or future financing arrangements;


	•	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 ~~access to current or future financing arrangements;~~industry;

	•	our ability to replace or add workers at economic rates;

	•	environmental and other governmental ~~regulations;~~regulations including climate change related legislation; and

	•	the effects of severe weather on our services, centers or equipment.


	•	the supply of and demand for oil and gas, including current natural gas storage capacity and usage;

	•	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~~access to and cost of capital for oil and gas ~~producers to raise equity capital and debt financing;~~producers; and

	•	merger and divestiture activity among oil and gas producers.


	•	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;

	•	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; and

	•	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.


	•	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.


Item 5.	*Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.*


	CPX Stock Price
Period	High		Low

Quarter ended March 31, 2007	$	21.20	$	17.28
Quarter ended June 30, 2007	$	27.75	$	19.45
Quarter ended September 30, 2007	$	26.17	$	20.00
Quarter ended December 31, 2007	$	22.66	$	17.30
Quarter ended March 31, 2008	$	22.98	$	14.13
Quarter ended June 30, 2008	$	37.50	$	22.23
Quarter ended September 30, 2008	$	37.84	$	18.61
Quarter ended December 31, 2008	$	20.08	$	4.04


	CPX Stock Price
Period	High		Low

Quarter ended March 31, 2009	$	10.10	$	2.32
Quarter ended June 30, 2009	$	8.31	$	3.27
Quarter ended September 30, 2009	$	11.72	$	6.78
Quarter ended December 31, 2009	$	13.48	$	9.11
Quarter ended March 31, 2010	$	16.06	$	10.83
Quarter ended June 30, 2010	$	15.97	$	11.33
Quarter ended September 30, 2010	$	21.69	$	13.68
Quarter ended December 31, 2010	$	32.72	$	20.52


*		We do not have a publicly announced stock repurchase program. We had 1,672,854 shares of non-vested restricted stock outstanding at December 31, 2010. The holders of these shares have the option to either remit taxes due related to the vesting of these shares or to authorize us to purchase the shares at the current market value in a sufficient amount to settle the related tax withholding. The amount purchased will depend on the market value at the time and whether or not the holders choose to surrender shares in settlement of the related tax withholding.

		income (loss).
~~(6)~~
(5)		Acquisitions, net of cash acquired, 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.