Exhibit 99.3

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (In thousands, except share and per share amounts or unless otherwise noted)

The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this Form 10-K. Additional sections in this Form 10-K which should be helpful to the reading of our discussion and analysis include the following: (i) a description of our services provided, by segment found in Items 1 and 2 “Business and Properties”—”Services Provided” (ii) a description of our business strategy found in Items 1 and 2 “Business and Properties”—”Our Strategy”; and (iii) a description of risk factors affecting us and our business, found in Item 1A “Risk Factors.”

In as much as the discussion below and the other sections to which we have referred you pertain to management’s comments on financial resources, capital spending, our business strategy and the outlook for our business, such discussions contain forward-looking statements. These forward-looking statements reflect the expectations, beliefs, plans and objectives of management about future financial performance and assumptions underlying management’s judgment concerning the matters discussed, and accordingly, involve estimates, assumptions, judgments and uncertainties. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to any differences include, but are not limited to, those discussed below and elsewhere in this Form 10-K, particularly in Item 1A “Risk Factors” and in “Forward-Looking Statements.”

OVERVIEW

Willbros is a global provider of engineering and construction services to the oil, gas, refinery, petrochemical and power industries with a focus on infrastructure such as oil and gas pipeline systems, electric T&D systems and refining and processing plants. Our offerings include engineering, procurement and construction (either individually or as an integrated EPC service offering), turnarounds, maintenance and other specialty services.

2011 Year in Review

During 2011, revenue increased $489,968 to $1,615,040 from $1,125,072 in 2010. The increase in revenue was primarily a result of a full year of our Utility T&D segment operations versus only a half year in 2010. Our Oil & Gas segment, which expanded its regional presence and breadth of services to include oilfield services work and was also successful in converting engineering assignments into full EPC projects, also increased its top line by over 17 percent. The revenue increase was partially offset by a decline in certain activity, primarily related to turnaround project delays. Operating income decreased $163,881 to a loss of $184,722 in 2011 compared to a loss of $20,841 in 2010. The variance is largely explained by two unfavorable non-cash items in 2011 – a $118,575 increase in goodwill impairment charges and a $35,340 decrease in the benefit of reducing the InfrastruX acquisition’s contingent earnout liability. We believe we have made substantial progress in improving our results in the seasonally slower fourth and first quarters and our challenge is to bring lagging business units up to the level of performance of our best businesses. We will continue to take actions to improve upon these results. See the following Financial Summary included in this Item 7 for additional details on the 2011 financial performance.

As part of our 2011 debt reduction process, we completed a study to determine the strategic fit and potential future contributions of various business units. We identified certain businesses that were not producing results at a level comparable to our peer group companies’ businesses. We are taking actions to improve the performance of these lagging businesses through a combination of initiatives consisting of a realignment of management, reduction of indirect costs (including fleet management) and general and administrative costs, and a more robust sales and marketing program to expand the revenue base. In instances where our evaluation identifies disadvantaged businesses, we are prepared to make divestiture decisions, when our analysis dictates that is the correct business decision. Specific targets of this profitability initiative are our Utility T&D segment’s distribution businesses in the Northeast and South Central regions and certain businesses within our Oil & Gas segment which, as previously mentioned, has seen continued delay in maintenance and turnaround awards and a diminishing customer base as the refining industry rationalizes capacity.

Also, as part of this study, we identified several non-strategic businesses and have divested, or are in the process of divesting, these businesses to strengthen the balance sheet and to allow management to better focus on the remaining strategic businesses. In October 2011, we sold InterCon Construction Inc. (“InterCon”) (acquired in the InfrastruX transaction). In connection with this sale, we received total compensation of $18,749 in cash and $250 in the form of an escrow deposit from the buyer. We continue to work towards a sale of our Canada cross-country pipeline construction business and are evaluating divestiture of several other businesses.

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The integration of InfrastruX is advancing and we have introduced our management systems and processes. We are seeing positive results in Texas transmission construction and expect this trend to continue in 2012. Our Northeast transmission business has successfully executed multiple large capital projects in the Northeast and we expect to leverage this recent relevant experience as we focus more management resources on this component of the Utility T&D segment. The distribution portion of the Utility T&D segment is still constrained by the dearth of housing starts, but we expect slow improvement throughout 2012, with upside from expanding gas distribution service opportunities.

Some positive highlights for 2011 include:

To sum up, in 2011, we successfully advanced our strategy to bring more recurring services into our revenue base, successfully responded to a shift in our legacy upstream oil and gas markets, identified and elevated the pipeline integrity opportunity, regained traction in our engineering businesses within our Oil & Gas segment, booked new meaningful EPC contracts, established a new oil sands focused model in our Canada segment with a high graded management team, generated positive project margins in our electric transmission construction business and isolated non-performing and non-strategic businesses for additional management actions.

Looking Forward

Last year, our primary financial objective was to reduce our leverage position by paying down debt while concurrently maintaining adequate liquidity. A 2011 debt repayment target range of $50,000 to $100,000 was exceeded by $23,379 and an additional $30,000 payment was made in the first quarter of 2012. During the first half of 2012, we expect to make substantial additional reductions as we continue to sell non-strategic assets (including equipment, real property, and businesses.) Our financial leverage will continue to be reduced and our overall balance sheet strengthened. We will be vigilant of opportunities to refinance our debt and modify or replace our existing 2010 Credit Facility.

In 2012, our primary financial objective is to improve our operating results to a level comparable with our peer group companies. Many of our businesses are already performing at this level; however, many are not. The non-performing businesses will be the focus of the actions we take to improve our operating profitability. We intend to do this through changes in the management teams, lowering the cost of service (through better management of variable and indirect costs such as equipment fleets, indirect personnel and yard costs and general and administrative costs), new marketing initiatives and increased accountability.

We intend to remain focused on actions underway throughout 2011, namely, the integration of the InfrastruX acquisition; implementing new process and procedures along with management systems to bring improvements realized in portions of the Oil & Gas segment to full realization in all of our Utility T&D businesses; cultural acceptance of Safety as an undeniable value and sharp focus on the end markets we serve in North America: the Canadian oil sands; the development of liquids-rich hydrocarbon sources and the robust market for expansion of the electric transmission grid. We will continue to advance our themes of recurring services, financial flexibility and excellence in project execution and expect to achieve incremental improvement in all our businesses and markets in 2012.

Financial Summary

During 2011, revenue increased $489,968 to $1,615,040 from $1,125,072 in 2010. This increase is

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primarily due to a $362,352 revenue increase in our Utility T&D segment related to a full year of revenue in 2011 and only a half year reported in 2010. Our Oil & Gas segment increased $131,872 due to an increase in facilities work and expansion into various shale regions in South Texas, West Texas and North Dakota, partially offset by a $72,901 decrease due to reduced demand for maintenance and turnaround activity.

We recognized a 2011 operating loss of $184,722 and a net loss from continuing operations of $205,475, or $4.33 per diluted share. The following three 2011 transactions (collectively referred to as “2011 Special Items”) had a material impact on our 2011 financial results:

Additionally, as previously discussed in Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2010 Annual Report, we had two large non-cash transactions (together referred to as “2010 Special Items”) that are detailed as follows:

Excluding the impact of these 2011 and 2010 Special Items, full-year and three months ended December 31 2011 and 2010 results are shown for comparative purposes in the below table:

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Full Year Results

The 2011 operating loss was $184,722. Excluding 2011 Special Items, the operating loss was $16,147 which represents a $9,966 loss increase from the $6,181 operating loss in 2010, excluding 2010 Special Items. The year-over-year operating loss increase is primarily related to our Oil & Gas segment which recorded an operating loss increase of $33,940 (excluding goodwill impairment of $32,822 in 2011 and $60,000 in 2010) from lower margins on fixed price work and the unfavorable impact of the settlement of the TransCanada project dispute. An $8,236 non-cash charge and $3,721 in related legal cost were attributable to the settlement. Our Utility T&D segment’s $19,119 of reduced losses (excluding goodwill impairment of $143,543 in 2011) partially offset the Oil & Gas segment’s increased operating loss. Our Utility T&D segment’s improvement was primarily driven by improved performance in our Texas electric transmission business and reduction in losses for our Northeast electric distribution business.

Interest expense, net increased $17,440 to $45,117 in 2011 compared to $27,677 in 2010. The increase is primarily a result of additional interest expense related to a full year of the Term Loan in 2011 versus only six months in 2010; and the early amortization of debt issuance costs and Original Issue Discount (“OID”), and early payment penalties related to payments against our Term Loan.

The 2011 net loss was $205,475. Excluding 2011 and 2010 Special Items, 2011 net loss increased $39,576 or $0.92 per share primarily attributed to additional operating losses and interest expense as noted above.

Fourth Quarter Results

Our fourth quarter operating loss was $45,988. Excluding 2011 Special Items, the operating loss was $10,956 which represents a $10,151 (49.8 percent) loss decrease from $21,107 operating loss in 2010, excluding 2010 Special Items. This decrease is primarily a result of a reduction in losses incurred on several projects within our Canada segment in 2011 compared to the same period in 2010. In addition, the decrease can also be attributed to the startup of our midstream pipeline business within our Oil & Gas segment. This business opened a new market in one of the major regional shale plays that contributed additional income during 2011 as compared to none during the same period in 2010.

Interest expense, net decreased $2,751 to $8,842 in 2011 compared to $11,593 in 2010. The decrease is primarily a result of decreased interest expense related to our Term Loan due to accelerated principal payments made during 2011.

The 2011 fourth quarter net loss was $53,707. Excluding 2011 and 2010 Special Items, the 2011 fourth quarter net loss decreased $5,873 or $0.12 per share primarily attributed to the changes in operating losses and interest expense as noted above.

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Other Financial Measures

Backlog

In our industry, backlog is considered an indicator of potential future performance as it represents a portion of the future revenue stream. Our strategy is focused on capturing quality backlog with margins commensurate with the risks associated with a given project, and for the past several years we have put processes and procedures in place to identify contractual and execution risks in new work opportunities and believe we have instilled in the organization the discipline to price, accept and book only work which meets stringent criteria for commercial success and profitability.

We believe the backlog figures are firm, subject only to the cancellation and modification provisions contained in various contracts. Additionally, due to the short duration of many jobs, revenue associated with jobs won and performed within a reporting period will not be reflected in quarterly backlog reports. We generate revenue from numerous sources, including contracts of long or short duration entered into during a year as well as from various contractual processes, including change orders, extra work and variations in the scope of work. These revenue sources are not added to backlog until realization is assured.

Backlog broadly consists of anticipated revenue from the uncompleted portions of existing contracts and contracts whose award is reasonably assured. Our backlog presentation reflects not only the 12 month lump-sum and MSA work; but also, the full-term value of work under contract, including MSA work as we believe that this information is helpful in providing additional long-term visibility. We determine the amount of backlog for work under ongoing MSA maintenance and construction contracts by using recurring historical trends inherent in the MSAs, factoring in seasonal demand and projecting customer needs based upon ongoing communications with the customer. We also include in backlog our share of work to be performed under contracts signed by joint ventures in which we have an ownership interest.

At December 31, 2011, 12 month backlog from continuing operations increased $55,492 (6.9 percent) to $865,124 from $809,632 at December 31, 2010. Our Oil & Gas segment, with a 12 month backlog of $383,653, contributed to the overall rise in backlog by increasing $106,554, or 38.5 percent from the 2010 12 month backlog level. This increase was offset by a decrease in our Utility T&D segment 12 month backlog of $58,512 or 13.3 percent.

Our Oil & Gas segment’s 12 month backlog increase in 2011 was a result of escalated work activity in our Engineering business and our U.S. Pipeline and Facilities business, which experienced year-over-year increases of $37,574 and $60,447, respectively. Our pipeline construction services contracting is characterized by competitive fixed price bids and short time periods from project bid to execution, except for large EPC contracts that can span more than one year. With the return to these historical contracting patterns, we have experienced lower backlog numbers with respect to our pipeline construction services partially as a result of eliminating the much longer lead times between the award of and the execution of projects.

In our Utility T&D segment, five customer relationships are expected to contribute $297,480 in revenue during 2012. As previously discussed, a significant portion of our Utility T&D backlog is associated with recurring services on MSA contracts that extend beyond 2012. Utility T&D’s backlog decreased $58,512 from 2010 primarily due to the completion of two larger projects in the Northeast which had $50,584 and $17,068 respectively in backlog at December 31, 2010.

Total backlog beyond the current 12 months was $2,172,217 at December 31, 2011. The $1,307,093 of backlog expected to be worked off beyond 12 months is almost entirely comprised of MSA work. MSA agreements account for $1,656,944 or 76.3 percent of the total backlog. The remaining $515,273 or 23.7 percent of the total backlog is attributable to current lump sum projects. Our Utility T&D segment currently accounts for $1,289,451 or 77.8 percent of the total reported MSA backlog and is derived from agreements extending until July of 2017.

Backlog for discontinued operations consisted primary of work associated with our discontinued Canada cross-country pipeline construction business and was $25,857 at December 31, 2011 and $137,733 at December 31, 2010.

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The following tables show our backlog from continuing operations by operating segment and geographic location as of December 31, 2011 and 2010:

Adjusted EBITDA from Continuing Operations

We define Adjusted EBITDA from continuing operations as income (loss) from continuing operations before interest expense, income tax expense (benefit) and depreciation and amortization, adjusted for items broadly consisting of selected items which management does not consider representative of our ongoing operations and certain non-cash items of the Company. These adjustments are included in various performance metrics under our credit facilities and other financing arrangements. These adjustments are itemized in the following table. You are encouraged to evaluate these adjustments and the reasons we consider them appropriate for supplemental analysis. In evaluating Adjusted EBITDA from continuing operations, you should be aware that in the future we may incur expenses that are the same as, or similar to, some of the adjustments in this presentation. Our presentation of Adjusted EBITDA from continuing operations should not be construed as an inference that our future results will be unaffected by unusual or non-recurring items.

Management uses Adjusted EBITDA from continuing operations as a supplemental performance measure for:

Adjusted EBITDA from continuing operations decreased $22,691 to $45,106 in 2011 compared to $67,797 in 2010. The decrease in Adjusted EBITDA is primarily a result of increased losses year-over-year from operations as well as $8,236 of charges incurred during the second quarter of 2011 related to the TransCanada settlement. In addition, we made payments on our Term Loan during 2011 which resulted in the recognition of $6,304 of loss on early extinguishment of debt, which further reduced Adjusted EBITDA from continuing operations year-over-year.

Adjusted EBITDA from continuing operations is not a financial measurement recognized under U.S. generally accepted accounting principles, or U.S. GAAP. When analyzing our operating performance,

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investors should use Adjusted EBITDA from continuing operations in addition to, and not as an alternative for, net income, operating income, or any other performance measure derived in accordance with U.S. GAAP, or as an alternative to cash flow from operating activities as a measure of our liquidity. Because all companies do not use identical calculations, our presentation of Adjusted EBITDA from continuing operations may be different from similarly titled measures of other companies.

A reconciliation of Adjusted EBITDA from continuing operations to U.S. GAAP financial information follows:

Discontinued Operations

For the year ended December 31, 2011, loss from discontinued operations, net of tax was $88,541 or $1.86 per share. The loss includes approximately $55,500 in charges recorded in connection with the settlement of the WAGP project litigation and $16,358 in legal fees incurred in relation to this litigation.

In addition, we incurred losses in 2011 from our Canada cross-country pipeline operations of approximately $12,813 and losses from our recently disposed InterCon subsidiary of approximately $4,855.

Additional financial disclosures and information on discontinued operations are provided in Note 20 – Discontinuance of Operations, Held for Sale Operations, Asset Disposals and Transition Services Agreement included in Item 8 and in Item 1A—Risk Factors of this Form 10-K.

RESULTS OF OPERATIONS

Fiscal Year Ended December 31, 2011 Compared to Fiscal Year Ended December 31, 2010

Contract Revenue

Contract revenue increased $489,968 to $1,615,040 from $1,125,072 in 2010. A year-to-year comparison of revenue is as follows:

Our Oil & Gas segment revenue increased $131,872 to $885,214 in 2011 compared to $753,342 in 2010, driven primarily by an increase in demand for our engineering services, as well as increased facilities work and expansion into various shale regions in South Texas, West Texas and North Dakota. The increase was partially offset by a reduction in demand for maintenance and turnaround activity.

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Our Oil & Gas Upstream Professional Services business reported revenue of $151,351 in 2011, an increase of $84,696 compared to 2010. We continue to experience strong demand for our engineering and EPC services. During 2011, we commenced work on two large EPC projects to design and build compressor stations in South Texas.

Our U.S. Pipelines and Facilities business reported revenue of $280,828, an increase of $26,823 compared to 2010. The increase in revenue was largely driven by both our large diameter pipeline business and expansions of our facilities business into South Texas.

Our Regional Delivery business reported revenue of $106,462 in 2011, an increase of $58,297 compared to 2010. The increase in revenue was primarily attributed to a full year of operating results in 2011, versus only six months of operations in 2010, coupled with additional revenue from our new established offices in Wyoming and North Dakota, which were established to serve the Niobrara and Bakken shale plays.

Revenue from our Downstream Construction and Maintenance business decreased $64,458 to $154,405 for 2011. We secured contracts throughout 2011, though at a lower level than in 2010, due in part to the turnaround schedules of our existing customers, who performed a significant amount of deferred maintenance in 2010. We were also unsuccessful in replacing several significant turnaround contracts for 2011. In the latter half of 2011 we opened an office on the Houston Ship Channel to capture growth opportunities on the Gulf Coast.

Revenue from our Premier business, which is primarily comprised of utility line locating and stray voltage and gas leak detection, increased $23,578 in comparison to 2010. The increase was primarily attributed to a full year of operating results in 2011, versus only six months of operations in 2010.

Revenue from our Downstream Professional Services business increased $2,695 to $70,654 for 2011 due primarily to improved demand for our engineering services as well as an EPC contract awarded in the third quarter of 2010 and completed in 2011.

Our Utility T&D segment revenue increased $362,352 to $576,415 in 2011 from $214,063 in 2010. The increase was largely driven by a full year of results for 2011. The Utility T&D segment was created from the acquisition of InfrastruX on July 1, 2010. During the last six months of 2011 compared to the last six months of 2010, revenue increased $82,696 mainly related to our Chapman business in Texas and our Hawkeye business in the Northeast.

In our Canada segment, revenue decreased $4,256 to $153,411 in 2011, driven primarily by lower levels of maintenance and capital projects performed pursuant to MSAs, partially offset by increased construction and fabrication of three major pump stations during the year.

Operating Income (Loss)

Operating income decreased $163,881 to a loss of $184,722 in 2011 compared to a loss of $20,841 in 2010. The change in fair value of the contingent earnout was characterized as a corporate change in estimate and is not allocated to the reporting segments. A year-to-year comparison of operating income is as follows:

Oil & Gas operating loss increased $6,762 to a loss of $43,614 in 2011 from a loss of $36,852 in 2010.

Our U.S. Pipelines and Facilities business reported an operating loss of $9,135 in 2011, a $30,049 decrease compared to 2010. This business was unfavorably impacted by the settlement of the facility construction project dispute with TransCanada, which resulted in a pre-tax, non-cash charge of $8,236, as well as, additional legal costs of $3,721, in the second quarter of 2011. Overall, the remainder of our pipeline business has seen a decrease in operating income driven by lower margins on fixed price contracts, primarily the result of increased competition and pricing pressure from our customers.

Our Downstream Construction and Maintenance business reported an operating loss of $12,101 in 2011, a $2,852 decrease compared to 2010. The decrease was primarily attributed to cost overruns on several fixed-price fabrication, maintenance and turnaround and tank construction contracts in 2011.

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We also recorded a goodwill impairment charge of $32,822 and $60,000 in 2011 and 2010, respectively, related to reductions in the outlook for expected future cash flows driven by a depressed fair market valuation for the segment and a reduction in demand for certain services.

Our Utility T&D segment operating income decreased $124,424 to a loss of $153,593 in 2011 compared to a loss of $29,169 in 2010. The year-over year decrease is attributed to a 2011 goodwill impairment charge of $143,543 offset by an increase in operating income of $12,144 in our Chapman business and an increase in operating income of $5,382 in our UtilX business. The increase in Chapman operating income was derived from work performed under the Oncor MSA which remained strong throughout the year and the increase in UtilX operating income was derived from continued positive margins in the cable and restoration business.

Our Canada segment reported operating income of $2,485 in 2011, compared to an operating loss of $160 in 2011. The $2,645 increase was primarily due to improved margins within our Tanks and Facilities and Equipment and Maintenances businesses coupled with reduced overhead cost across the segment. The increase was partially offset by a fourth quarter of 2011 goodwill impairment charge within the segment and narrower margins within our Fabrication business.

Non-Operating Items

Interest expense, net increased $17,440 to $45,117 in 2011 compared to $27,677 in 2010. The increase is primarily a result of additional cash interest expense of $9,959 related to a full year of the Term Loan and the amortization of debt issuance costs and OID of $5,202 and $4,052 related to payments against our Term Loan.

In 2011, we recorded a $6,304 loss attributed to the write-off of OID and financing costs inclusive of early termination fees in connection with payments of $123,379 against our Term Loan. The loss is recorded in the line item “Loss on early extinguishment of debt” for the year ended December 31, 2011.

Benefit for income taxes increased $1,245 to a benefit of $32,293 from a benefit of $31,048 in 2010. During 2011, we recognized a tax benefit of $32,293 on a loss from continuing operations before income taxes of $236,573 as compared to a tax benefit of $31,048 on a loss from continuing operations before income taxes of $46,869 in 2010. The increase in the benefit for income taxes is due to the decrease in operating income recognized during 2011.

Loss from Discontinued Operations, Net of Taxes

Loss from discontinued operations, net of taxes increased $68,533 from a loss of $20,008 in 2010 to a loss of $88,541 for 2011. The increased loss year over year is primarily attributed to $55,500 in charges recorded in 2011 in connection with the settlement of the WAGP project litigation. Further, legal costs associated with this litigation increased $14,313 from $2,045 in 2010 to $16,358 in 2011.

Fiscal Year Ended December 31, 2010 Compared to Fiscal Year Ended December 31, 2009

Contract Revenue

Contract revenue decreased $60,737 to $1,125,072 in 2010 compared to $1,185,809 in 2009. A year-to-year comparison of revenue is as follows:

Oil & Gas revenue decreased $252,011 to $753,342 in 2010 compared to $1,005,353 in 2009. The decrease in revenue was the result of our customers’ reduction in capital and maintenance spending in 2010 as a continued reaction to the overall global economic recession. This was evidenced by an overall decrease in revenue of $321,230, associated with our U.S. Pipelines and Facilities business specific to large diameter pipeline projects available for bid and an overall decrease in revenue of $30,478 with respect to our Professional Services business in the upstream market. However, as a result of these conditions, the segment began to pursue midstream pipeline projects which opened a new market in 2010 in one of the major regional

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shale plays. Services within this new Regional Delivery business generated revenue of $48,165 during the year. In addition, our new Premier business, generated revenue of $24,107 during the year and revenue from our Downstream Construction and Maintenance business increased $19,916 year-over-year driven primarily through increased maintenance and turnaround activity.

Utility T&D contributed revenue of $214,063 as a result of revenues derived from a broad range of transmission and distribution construction and maintenance services from July 1, 2010 through December 31, 2010. Contract revenue is also largely driven through established MSA contracts related to overhead and underground transmission, distribution and telecommunication systems and through an alliance agreement with Oncor providing turnkey transmission and substation construction and maintenance solutions and overhead and underground utility construction services.

In our Canada segment, revenue decreased $22,789 to $157,667 in 2010, due primarily to reduced capital budgets of the oil-sand producers and pipeline companies that was, in turn, driven by uncertain crude pricing.

Operating Income (Loss)

Operating income decreased $58,827 to a loss of $20,841 in 2010 compared to income of $37,986 in 2009. The change in fair value of the contingent earnout was characterized as a corporate change in estimate and was not allocated to the reporting segments. A year-to-year comparison of operating income is as follows:

Oil & Gas operating income decreased $71,225 to an operating loss of $36,852 in 2010 compared to operating income of $34,373 in 2009. The decrease was caused primarily by the $60,000 goodwill impairment charge taken in the second half of 2010. In addition, we experienced a decrease in operating income within our U.S. Pipelines and Facilities business of $8,621 driven by the revenue declines previously discussed, however, our focus on execution of the available work allowed us to improve our contract margins and still deliver strong operating income at a significantly smaller volume. This continued profitability came as we saw the market shift back fully to lump-sum contracting terms, marking the end of the cost-reimbursable work that we completed in 2009 for large diameter cross-country pipeline construction.

Our Utility T&D segment generated an operating loss of $29,169 in 2010 which included non-recurring acquisition costs of $9,814, and non-recurring restructuring fees of $2,638 associated with the Seattle office closure. In addition, we experienced operating losses during the year attributed to lower volumes from a shift in the mix in transmission construction revenues associated with the Oncor work in Texas, project delays in the Northeast and a generally weaker market for electric and gas distribution work.

Our Canada segment reported an operating loss of $160 in 2010 compared to operating income of $3,613 in 2009. The decrease was driven largely by a year-over-year reduction in contract revenue as well as lower utilization levels and higher overhead costs.

Non-Operating Items

Interest expense, net increased $19,317 to $27,677 in 2010 compared to $8,360 in 2009. The increase is primarily a result of increased interest expense of $16,106 related to the new Term Loan, debt issuance cost amortization of $1,994 related to the 2010 Credit Agreement and a reduction in interest income of $1,211 due to lower levels of and rates of return on invested cash.

Provision for income taxes decreased $38,576 to a benefit of $31,048 in 2010 from a provision of $7,528 in 2009. The decrease in the provision for income taxes is due to the decrease in operating income recognized during 2010 and no tax expense incurred in connection with the release of the contingent earnout liability in the amount of $45,340 associated with the acquisition of InfrastruX.

Loss from Discontinued Operations, Net of Taxes

Loss from discontinued operations, net of taxes increased $18,224 to a loss of $20,008 in 2010

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compared to a loss of $1,784 in 2009. During 2010, we recognized a tax benefit of $31,048 on a loss from continuing operations before income taxes of $46,869 as compared to income tax expense of $7,528 on income from continuing operations before income taxes of $28,952 in 2009. The decrease in the provision for income taxes is due to the decrease in operating income recognized during 2010 and no tax expense incurred in connection with the release of the contingent earnout liability of $45,340 associated with the acquisition of InfrastruX.

LIQUIDITY AND CAPITAL RESOURCES

Our financing objective is to maintain financial flexibility to meet the material, equipment and personnel needs to support our project commitments, and pursue our expansion and diversification objectives, while reducing debt.

The 2010 Credit Agreement consists of a four year, $300,000 Term Loan maturing in July 2014 and a three year revolving credit facility (the “Revolving Credit Facility”) of $175,000. The proceeds from the Term Loan were used to pay part of the cash portion of the merger consideration payable in connection with our acquisition of InfrastruX. The Revolving Credit Facility is primarily used to provide letters of credit; however, it does allow for borrowings. Our ability to use the Revolving Credit Facility for borrowings, however, has been restricted because of the amendment discussed in the next paragraph. The Maximum Total Leverage ratio covenant under the 6.5% Notes Indenture may also restrict our ability to use the Revolving Credit Facility for revolving loans from time to time.

On March 4, 2011, the 2010 Credit Agreement was amended to allow us to make certain dispositions of equipment, real estate and business units. In most cases, proceeds from these dispositions will be required to be used to pay-down the existing Term Loan. Financial covenants and associated definitions, such as Consolidated EBITDA, were also amended to permit us to carry out our business plan and to clarify the treatment of certain items. Until our maximum total leverage ratio is 3.00 to 1.00 or less, we have agreed to limit our revolver borrowings to $25,000, with the exception of proceeds from revolving borrowings used to make payments on the 6.5% Senior Convertible Notes (the “6.5% Notes”) and to make $59,357 in payments to the 2.75% Convertible Senior Notes that were submitted to us for cash payment in the first quarter. The amendment does not change the limit on obtaining letters of credit. The amendment also modifies the definition of Excess Cash Flow to include proceeds from the TransCanada arbitration, which required us to use a portion of such proceeds to further pay-down the existing Term Loan. In late June 2011, we received $61,000 from TransCanada as a settlement and used $40,000 to pay-down the Term Loan. For prepayments made with Net Debt Proceeds or Equity Issuance Proceeds (as those terms are defined in the 2010 Credit Agreement), the amendment requires a prepayment premium of 4% of the principal amount of the Term Loans to be paid before December 31, 2011; and 1% of the principal amount of the Term Loans prepaid on and after December 31, 2011, but before December 31, 2012. Premiums for prepayments made with proceeds other than Net Debt Proceeds or Equity Issuance Proceeds remain the same as originally set forth under the 2010 Credit Agreement.

Covenants

The 2010 Credit Agreement was amended, effective March 29, 2012, to eliminate the minimum Net Tangible Worth covenant as of December 31, 2011.

The table below sets forth the primary covenants in the 2010 Credit Agreement and the status with respect to these covenants as of December 31, 2011.

The Maximum Total Leverage Ratio requirement declined to 4.75 to 1 as of December 31, 2011 from

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5.00 to 1 at September 30, 2011. The value of the trailing 12-month EBITDA as defined in the 2010 Credit Agreement (or “Covenant EBITDA”), was negatively impacted by the first quarter of 2011 with Covenant EBITDA of ($7,656). We expect to achieve Covenant EBITDA improvement during 2012 as a result of each 2012 quarter that replaces a corresponding 2011 quarter representing a net gain in Covenant EBITDA. In addition, we continue to improve the primary covenant ratios through payments against our Term Loan. The December 31, 2011 primary covenant calculations benefitted from a fourth quarter $28,700 accelerated payment against our Term Loan. Based on our current operating projections, we believe that we will remain in compliance with the above primary covenants through 2012. Depending on our financial performance, we may be required to request amendments, or waivers for the primary covenants, dispose of assets, or obtain refinancing in future periods. There can be no assurance that we will be able to obtain amendments or waivers, complete asset sales, or negotiate agreeable refinancing terms should it become needed.

The 2010 Credit Agreement also includes customary affirmative and negative covenants, including:

A default under the 2010 Credit Agreement may be triggered by events such as a failure to comply with financial covenants or other covenants under the 2010 Credit Agreement; a failure to make payments when due under the 2010 Credit Agreement; a failure to make payments when due in respect of, or a failure to perform obligations relating to other debt obligations in excess of $15,000; a change of control of the Company; and certain insolvency proceedings. A default under the 2010 Credit Agreement would permit Crédit Agricole and the lenders to terminate their commitment to make cash advances or issue letters of credit, require the immediate repayment of any outstanding cash advances with interest and require the cash collateralization of outstanding letter of credit obligations. As of December 31, 2011, we were in compliance with all covenants under the 2010 Credit Agreement.

In addition, any “material adverse change” could restrict our ability to borrow under the 2010 Credit Agreement and could also be deemed an event of default under the 2010 Credit Agreement. A “material adverse change” is defined as a change in our business, results of operations, properties or condition that could reasonably be expected to have a material adverse effect, as defined in the 2010 Credit Agreement.

On September 16, 2011, following receipt of the requisite consents of the holders of our 6.5% Notes, the 6.5% Notes Indenture was amended, in part, to increase the Maximum Total Leverage Ratio from 4.00 to 1.00 to 6.00 to 1.00 during the fiscal quarter ending December 31, 2011, 5.50 to 1.00 during the fiscal quarter ending March 31, 2012, 3.75 to 1.00 during the fiscal quarter ending June 30, 2012 and 3.50 to 1.00 during the fiscal quarters ending September 30, 2012 and December 31, 2012. The 6.5% Notes Indenture includes a debt incurrence test and the calculation of the Maximum Total Leverage Ratio mirrors the calculation in the 2010 Credit Agreement. The Indenture was also amended to conform the definition of Consolidated EBITDA in the Indenture to the definition of Consolidated EBITDA in the 2010 Credit Agreement. We believe that these amendments enhance our financial flexibility by enabling us to borrow up to $25,000 of available funds under the Revolving Credit Facility. Based on our current operating projections, we believe that we will remain in compliance with the Maximum Total Leverage Ratio under the 6.5% Notes Indenture through 2012. Depending on our financial performance, we may be required to request amendments, or waivers for the debt incurrence covenant under the 6.5% Notes Indenture, dispose of assets, or obtain refinancing in future periods. There can be no assurance that we will be able to obtain amendments or waivers, complete asset sales, or negotiate agreeable refinancing terms should it become needed.

On March 29, 2012, we entered into a Settlement Agreement with WAPCo to settle the WAGP project litigation. The Settlement Agreement provides that we will make payments to WAPCo over a period of six years totaling $55,500. The Settlement Agreement also provides that the payments due in the years 2015, 2016 and 2017 may be accelerated and become payable in whole or in part within 21 days after filing our third quarter results in 2014 in the event we achieve a leverage ratio of debt to EBITDA of 2.25 to 1.00 or less or certain other acceleration metrics. In the event the acceleration metrics applied during 2014 do not result in payment of the entire outstanding sum, the acceleration metrics are applied again in each subsequent year and may result in the acceleration of all or some of the remaining payments in each of those years.

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Cash Balances

As of December 31, 2011, we had cash and cash equivalents of $58,686. Our cash and cash equivalent balances held in the United States and foreign countries were $29,206 and $29,480, respectively. In April 2011, we discontinued our strategy of reinvesting non-U.S. earnings in foreign operations. During 2011, we repatriated $37,500 of cash from our principal foreign holding company to repay Term Loan debt. As of December 31, 2011, we had $59,357 in outstanding borrowings and $27,967 in outstanding letters of credit under our Revolving Credit Facility. The Revolving Credit Facility has total capacity of $175,000 with a $150,000 sublimit for cash advances. As of December 31, 2011, we are able to only draw up to an additional $25,000 under the Revolving Credit Facility. If we achieve a Maximum Total Leverage Ratio covenant of 3.00 to 1.00 or less, we may borrow up to an additional $87,676 under the Revolving Credit Facility.

Our working capital position for continuing operations decreased $82,592 to $172,452 at December 31, 2011 from $255,044 at December 31, 2010. This was primarily attributed to $123,379 in payments against our Term Loan as well as changes in project related working capital requirements during the year. Exceeding our goal to reduce the Term Loan balance has resulted in lower cash balances. To partially compensate for lower cash balances, we have placed additional emphasis in achieving a cash neutral position by balancing our receivable collections with our vendor payments. Occasionally, vendor payments have been delayed when clients delayed payments or we were delayed in reaching project payment milestones. To further improve our liquidity, we are currently minimizing our capital expenditures and taking steps to improve our cash flows from operations.

Cash Flows

Statements of cash flows for entities with international operations that use the local currency as the functional currency exclude the effects of the changes in foreign currency exchange rates that occur during any given period, as these are non-cash charges. As a result, changes reflected in certain accounts on the Consolidated Statements of Cash Flows may not reflect the changes in corresponding accounts on the Consolidated Balance Sheets. Cash flows provided by (used in) continuing operations by type of activity were as follows for the twelve months ended December 31, 2011, 2010 and 2009:

Operating Activities

Cash flow from operations is primarily influenced by demand for our services, operating margins and the type of services we provide, but can also be influenced by working capital needs such as the timing of collection of receivables and the settlement of payables and other obligations. Working capital needs are generally higher during the summer and fall months when the majority of our capital intensive projects are executed. Conversely, working capital assets are typically converted to cash during the winter months. Operating activities from continuing operations provided net cash of $47,850 during 2011 as compared to $40,355 during 2010 and cash provided of $58,970 during 2009. The slight increase in operating cash flows in 2011 as compared to 2010 is due primarily to:

This was partially offset by

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Investing Activities

During 2011, investing activities provided us net cash of $50,637 as compared to $404,460 and $32,161 of cash used in investing activities in 2010 and 2009, respectively. The $455,097 increase in cash flow provided by investing activities in 2011 is primarily the result of the following:

During 2010 and 2009, we used $16,121 and $11,082, respectively, for capital expenditures, offset by $16,343 and $9,435 of proceeds from the sales of under-utilized facilities and equipment. The increase in capital expenditures in 2010 compared to 2009 is related primarily to the acquisition of InfrastruX in July 2010.

Financing Activities

In 2011, financing activities used net cash of $147,291 as compared to cash provided of $298,002 and $28,085 cash used by financing activities in 2010 and 2009, respectively. The $445,293 increase in cash used in financing activities in 2011 resulted primarily from:

Net cash used by financing activities in 2010 compared to 2009 resulted primarily from the cash proceeds received related to the Term Loan of $282,000 in connection with our acquisition of InfrastruX in July 2010.

Discontinued Operations

Net cash from discontinued operations used $28,403 in 2011 as compared to cash provided of $6,118 in 2010. This resulted primarily from the losses generated during 2011 by our Canadian cross-country pipeline and InterCon businesses ($11,936 and $4,260 respectively). Also contributing to the 2011 cash used were $16,358 in legal fees related to our ongoing WAPCo parent company guarantee dispute. However, this was somewhat offset by the $55,500 settlement fee we entered into with WAPCo which provides for cash payments over the next six years. In 2009, our net cash from discontinued operations used cash of $13,937, which was primarily the result of decreased income from operations in our Canadian cross-country pipeline construction business due to lower volume of project activity.

Interest Rate Risk

We are subject to hedging arrangements to fix or otherwise limit the interest cost of the Term Loan. We are subject to interest rate risk on our debt and investment of cash and cash equivalents arising in the normal course of business, as we do not engage in speculative trading strategies.

In September 2010, we entered into two 18-month forward-starting interest rate swap agreements for a total notional amount of $150,000 in order to hedge changes in the variable rate interest expense of most of the remaining principle balance under our $300,000 Term Loan maturing on June 30, 2014. Under each swap agreement, we receive interest at a floating rate of three-month London Interbank Offered Rate (“LIBOR”), conditional on three-month LIBOR exceeding 2 percent (to mirror variable rate interest provisions of the underlying hedged debt), and pay interest at a fixed rate of 2.685 percent, effective March 28, 2012 through June 30, 2014. Each swap agreement is designated and qualifies as a cash flow hedging instrument, with the effective portion of the swaps’ change in fair value recorded in Other Comprehensive Income (“OCI”). The interest rate swaps are deemed to be highly effective hedges, and resulted in no gain or loss recorded for hedge ineffectiveness in the Condensed Consolidated Statement of Operations. Amounts in OCI are reported in interest expense when the hedged interest payments on the underlying debt are recognized. The fair value of each swap agreement was determined using a model with Level 2 inputs including quoted market prices for contracts with similar terms and maturity dates.

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Interest Rate Caps

In September 2010, we entered into two interest rate cap agreements for notional amounts of $75,000 each in order to limit our exposure to an increase of the interest rate above 3 percent, effective September 28, 2010 through March 28, 2012. Total premiums of $98 were paid for the interest rate cap agreements. Through June 1, 2011, the cap agreements were designated and qualified as cash flow hedging instruments, with the effective portion of the caps’ change in fair value recorded in OCI. Amounts in OCI and the premiums paid for the caps were reported in interest expense as the hedged interest payments on the underlying debt were recognized during the period when the caps were designated as cash flow hedges. Through June 1, 2011, the interest rate caps were deemed to be highly effective, resulting in an immaterial amount of hedge ineffectiveness recorded in the Condensed Consolidated Statement of Operations. On June 1, 2011, the caps were de-designated due to the interest rate being fixed on the underlying debt through the remaining term of the caps; changes in the value of the caps subsequent to that date will be reported in earnings. The amount reported in earnings from the undesignated interest rate caps for the year ended December 31, 2011 is immaterial. The fair value of the interest rate cap agreements was determined using a model with Level 2 inputs including quoted market prices for contracts with similar terms and maturity dates. An immaterial amount of OCI relating to the interest rate swap and caps is expected to be recognized in earnings in the coming 12 months.

Capital Requirements

During 2011, $49,253 of cash was used by our continuing operations activities. Capital expenditures by segment amounted to $5,339 spent by Oil & Gas, $52 for Canada, $3,484 for Utility T&D, and $1,989 by Corporate, for a total of $10,864. Approved capital spending of $2,011 has been carried forward to 2012.

We believe that our financial results combined with our current liquidity and financial management will ensure sufficient cash to meet our capital requirements for continuing operations. As such, we are focused on the following significant capital requirements:

We believe that we will be able to support our working capital needs during 2012 through our cash on hand and operating cash flows.

Contractual Obligations

As of December 31, 2011, we had $175,871 of outstanding debt related to our Term Loan, $59,357 of outstanding debt related to our revolver and $32,050 of outstanding debt related to the 6.5% Notes. In addition, we have various capital leases of construction equipment and property resulting in aggregate capital lease obligations of $7,382 at December 31, 2011.

During the twelve months ended December 31, 2011, we made payments of $123,379 against the Term Loan. These payments resulted in the recognition of a $6,304 loss on early extinguishment of debt for the twelve months ended December 31, 2011. These losses represent the write-off of unamortized OID and financing costs inclusive of early payment fees. Such loss is recorded in the line item “Loss on early extinguishment of debt” for the year ended December 31, 2011.

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As of December 31, 2011, there were $59,357 in outstanding borrowings under the Revolving Credit Facility and there were $27,967 in outstanding letters of credit. All outstanding letters of credit relate to continuing operations.

The 6.5% Notes remain outstanding as of December 31, 2011 and continue to be subject to the terms and conditions of the Indenture governing the 6.5% Notes. An aggregate principal amount of $32,050 remains outstanding (net of $0 discount) and has been classified as current and included within “Notes payable and current portion of other long-term debt” on the Consolidated Balance Sheet at December 31, 2011.

At December 31, 2011, we had uncertain tax positions totaling $4,030 which ultimately could result in a tax payment. As the amount of the ultimate tax payment is contingent on the tax authorities’ assessments, it is not practical to present annual payment information.

We have unsecured credit facilities with banks in certain countries outside the United States. Borrowings in the form of short-term notes and overdrafts are made at competitive local interest rates. Generally, each line is available only for borrowings related to operations in a specific country. Credit available under these facilities is approximately $6,381 at December 31, 2011. There were no outstanding borrowings made under these facilities at December 31, 2011 or 2010.

Off-Balance Sheet Arrangements and Commercial Commitments

From time to time, we enter into commercial commitments, usually in the form of commercial and standby letters of credit, surety bonds and financial guarantees. Contracts with our customers may require us to provide letters of credit or surety bonds with regard to our performance of contracted services. In such cases, the commitments can be called upon in the event of our failure to perform contracted services. Likewise, contracts may allow us to issue letters of credit or surety bonds in lieu of contract retention provisions, in which the client withholds a percentage of the contract value until project completion or expiration of a warranty period.

The letters of credit represent the maximum amount of payments we could be required to make if these letters of credit are drawn upon. Additionally, we issue surety bonds customarily required by commercial terms on construction projects. U.S. surety bonds represent the bond penalty amount of future payments we could be required to make if we fail to perform our obligations under such contracts. The surety bonds do not have a stated expiration date; rather, each is released when the contract is accepted by the owner. Our maximum exposure as it relates to the value of the bonds outstanding is lowered on each bonded project as the cost to complete is reduced. As of December 31, 2011, no liability has been recognized for letters of credit or surety bonds.

A summary of our off-balance sheet commercial commitments for both continuing and Discontinued Operations as of December 31, 2011 is as follows:

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Revenue

A number of factors relating to our business affect the recognition of contract revenue. We typically structure contracts as unit-price, time and materials, fixed-price or cost plus fixed fee. We believe that our operating results should be evaluated over a time horizon during which major contracts in progress are completed and change orders, extra work, variations in the scope of work, cost recoveries and other claims are negotiated and realized. Revenue from unit-price and time and materials contracts is recognized as earned.

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Revenue for fixed-price and cost plus fixed fee contracts is recognized using the percentage-of-completion method. Under this method, estimated contract income and resulting revenue is generally accrued based on costs incurred to date as a percentage of total estimated costs, taking into consideration physical completion. Total estimated costs, and thus contract income, are impacted by changes in productivity, scheduling, unit cost of labor, subcontracts, materials and equipment. Additionally, external factors such as weather, client needs, client delays in providing permits and approvals, labor availability, governmental regulation and politics may affect the progress of a project’s completion and thus the timing of revenue recognition. Certain fixed-price and cost plus fixed fee contracts include, or are amended to include, incentive bonus amounts, contingent on accomplishing a stated milestone. Revenue attributable to incentive bonus amounts is recognized when the risk and uncertainty surrounding the achievement of the milestone have been removed. We do not recognize income on a fixed-price contract until the contract is approximately five to ten percent complete, depending upon the nature of the contract. If a current estimate of total contract cost indicates a loss on a contract, the projected loss is recognized in full when determined.

We consider unapproved change orders to be contract variations on which we have customer approval for scope change, but not for price associated with that scope change. Costs associated with unapproved change orders are included in the estimated cost to complete the contracts and are expensed as incurred. We recognize revenue equal to cost incurred on unapproved changed orders when realization of price approval is probable and the amount is estimable. Revenue recognized on unapproved change orders is included in contract costs and recognized income not yet billed on the balance sheet. Revenue recognized on unapproved change orders is subject to adjustment in subsequent periods to reflect the changes in estimates or final agreements with customers.

We consider claims to be amounts that we seek or will seek to collect from customers or others for customer-caused changes in contract specifications or design, or other customer-related causes of unanticipated additional contract costs on which there is no agreement with customers on both scope and price changes. Revenue from claims is recognized when agreement is reached with customers as to the value of the claims, which in some instances may not occur until after completion of work under the contract. Costs associated with claims are included in the estimated costs to complete the contracts and are expensed when incurred.

Valuation of Goodwill

We record as goodwill the amount by which the total purchase price we pay in our acquisition transactions exceeds our estimated fair value of the identifiable net assets we acquire. Our goodwill impairment assessment includes a two-step fair value-based test and is performed annually, or more frequently if events or circumstances exist which indicate that goodwill may be impaired. We have determined that our segments represent our reporting units for the purpose of assessing goodwill impairments.

In the fourth quarter of 2011, we changed the date of our annual goodwill impairment test for the Utility T&D segment from July 1 to December 1. This change is preferable as it not only aligns the timing of the Utility T&D annual goodwill impairment test with the Oil & Gas and Canada annual goodwill impairment test, it also more closely aligns with our internal forecasting and budgeting process. As such, this change will allow us to better utilize our updated business plans that result from the forecasting and budget process in the valuation approaches used to estimate the fair value of the Utility T&D segment.

The first step of the two-step fair value-based test involves comparing the fair value of each of our reporting units with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, the second step is performed. The second step compares the carrying amount of the reporting unit’s goodwill to the implied fair value of the goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss would be recorded as a reduction to goodwill with a corresponding charge to operating expense.

We perform the required annual impairment test for goodwill by determining the fair values of our reporting units using a weighted combination of the following generally accepted valuation approaches:

These approaches include numerous assumptions with respect to future circumstances, such as industry and/or local market conditions that might directly impact operations in the future, and are, therefore, uncertain. These approaches are utilized to develop a range of fair values and a weighted average of these approaches are utilized to determine the best fair value estimate within that range.

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Income Approach—Discounted Cash Flows. This valuation approach derives a present value of the reporting unit’s projected future annual cash flows over the next 8 years and the present residual value of the segment. We used a variety of underlying assumptions to estimate these future cash flows, including assumptions relating to future economic market conditions, sales volumes, costs and expenses and capital expenditures. These assumptions are dependent on regional market conditions, including competitive position, degree of vertical integration, supply and demand for materials and other industry conditions. The discount rate used in our analysis for 2011, specifically the weighted average cost of capital, varied between approximately 17.0 percent and 18.0 percent. The revenue compounded annual growth rates used in our analysis for 2011 varied from 2.5 percent to 41.0 percent. Our EBITDA margins derived from these underlying assumptions for our 2011 analysis varied between approximately 4.1 percent and 12.0 percent. The terminal growth rate used for our 2011 analysis was 2.5 percent.

Market Approach—Multiples of EBITDA. This valuation approach utilizes publicly traded construction companies’ enterprise values, as compared to their recent EBITDA information. For our 2011 analysis, we used an average EBITDA multiple of 3.0 to 4.5 times in determining this market approach metric. This multiple is used as a valuation metric to our most recent financial performance. We used EBITDA as an indicator of demand because it is a widely used key indicator of the cash generating capacity of similar companies.

Market Approach—Comparisons of Recent Transactions. This valuation approach uses publicly available information regarding recent third-party sales transactions in our industry to derive a valuation metric of the target’s respective enterprise values over their EBITDA amounts. For our 2011 analysis, we did not weigh this market approach because current economic conditions did not yield significant recent transactions to derive an appropriate valuation metric.

We selected these valuation approaches because we believe the combination of these approaches, along with our best judgment regarding underlying assumptions and estimates, provides us with the best estimate of fair value. We believe these valuation approaches are proven and appropriate for our industry and widely accepted by investors. The estimated fair value would change if our weighting assumptions under these valuation approaches were materially modified. For our 2011 analysis, we weighted the Income Approach—Discounted Cash Flows at 70 percent and the Market Approach—Multiples of Sales and EBITDA at 30 percent. This weighting was utilized to reflect fair value in current market conditions.

Our valuation model utilizes assumptions, which represent our best estimate of future events, but would be sensitive to positive or negative changes in each of the underlying assumptions as well as an alternative weighting of valuation methods, which would result in a potentially higher or lower goodwill impairment charge. We can provide no assurance that future goodwill impairments will not occur.

Detailed below is a table of key underlying assumptions for all reporting units utilized in the fair value estimate calculation for the years ended December 31, 2011, 2010 and 2009.

Impairment of Goodwill

During the third quarter of 2011, we recorded an impairment charge of $143,543 related to our Utility T&D segment. Our original March 2010 growth projections in the electric transmission and distribution business have not materialized. The continued slow economic recovery, exacerbated by the recent recurrence of instability in the world financial markets, and the hard-hit U.S. housing sector, have resulted in a reassessment of future growth rates and led to a reduction in the outlook for expected future cash flows in this segment.

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The initial purchase price allocation to acquired assets and liabilities for the InfrastruX acquisition included a $55,340 liability for the estimated fair value of the 2010, 2011 and combined two-year earnout provisions in the Merger Agreement. At the time of the purchase price allocation, recognition of this $55,340 liability resulted in goodwill increasing by a corresponding amount. No payments occurred and accordingly, the liability was reduced to zero as of December 31, 2011. Reductions to the liability resulted in a corresponding increase in operating income and net income of $10,000 during the year ended December 31, 2011 and a corresponding increase in operating income and net income of $45,340 during the year ended December 31, 2010.

Our weighted average cost of capital used for the original purchase price valuation has increased 1.6 percentage points from 14.4 percent at the time of the InfrastruX acquisition to 16.0 percent on July 1, 2011. The primary driver of the percentage increase was related to a higher risk premium. Our fair value analysis was heavily weighted on discounted cash flows. The resulting discounted cash flows would have been $65,000 higher if the discount rate was reduced to 14.4 percent.

During the fourth quarter of 2011, in connection with our annual goodwill impairment test, we recorded an impairment charge of $35,032, which represents a full write-off of goodwill attributed to our Oil & Gas and Canada segments. The impairment charge was a result of a depressed fair market valuation for these segments which drove an overall decline in market capitalization. The Utility T&D segment was less impacted in part due to its impairment charge recorded in the third quarter of 2011.

As a result of the above impairment charges, our consolidated goodwill was reduced to $8,067 at December 31, 2011 and relates entirely to the Utility T&D segment. In connection with our annual goodwill impairment test, the fair value of our Utility T&D segment was $2,114 higher than its carrying value.

In 2010, we began to experience reduced demand for services within our Oil & Gas segment. This downturn resulted from a low level of both capital and maintenance spending in the refining industry, which has fostered a highly competitive environment, resulting in significantly decreased margins. During the third quarter of 2010, in connection with the completion of our preliminary forecasts for 2011, it became evident that a goodwill impairment associated with the Oil & Gas segment was probable. Due to time restrictions with the filing of our third quarter Form 10-Q, we were unable to fully complete our two step analysis. According to the accounting standards for goodwill, if the second step of the goodwill impairment test is not complete before the financial statements are issued or are available to be issued and a goodwill impairment loss is probable and can be reasonably estimated, the best estimate of that loss shall be recognized. Using a weighted combination of both the Income Approach—Discounted Cash Flows and the Market Approach—Multiple of EBITDA to determine the fair value of the segment versus its carrying value, an estimated range of likely impairment was determined and an impairment charge of $12,000 was recorded during the third quarter of 2010.

Valuation of Other Intangible Assets

Our intangible assets with finite lives include customer relationships, trade names, non-compete agreements and developed technology. The value of customer relationships is estimated using the income approach, specifically the excess earnings method. The excess earnings analysis consists of discounting to present value the projected cash flows attributable to the customer relationships, with consideration given to customer contract renewals, the importance or lack thereof of existing customer relationships to our business plan, income taxes and required rates of return. The value of trade names is estimated using the relief-from-royalty method of the income approach. This approach is based on the assumption that in lieu of ownership, a company would be willing to pay a royalty in order to exploit the related benefits of this intangible asset.

We amortize intangible assets based upon the estimated consumption of the economic benefits of each intangible asset or on a straight-line basis if the pattern of economic benefits consumption cannot otherwise be reliably estimated. Intangible assets subject to amortization are reviewed for impairment and are tested for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For instance, a significant change in business climate or a loss of a significant customer, among other things, may trigger the need for interim impairment testing of intangible assets. An impairment loss is recognized if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value.

Valuation of Long-Lived Assets

Long-lived assets are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If an evaluation is required, the estimated future undiscounted cash flows associated with the asset are compared to the asset’s carrying amount to

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determine if an impairment of such asset is necessary. This requires us to make long-term forecasts of the future revenues and costs related to the assets subject to review. Forecasts require assumptions about demand for our products and future market conditions. Estimating future cash flows requires significant judgment, and our projections may vary from the cash flows eventually realized. Future events and unanticipated changes to assumptions could require a provision for impairment in a future period. The effect of any impairment would be to expense the difference between the fair value of such asset and its carrying value. Such expense would be reflected in earnings.

Leases

We have entered into operating lease agreements, some of which contain provisions for future rent increases, rent free periods, or periods in which rent payments are reduced (abated). Consistent with the FASB’s standard on leases, the total amount of rental payments due over the lease term is being charged to rent expense on the straight-line method over the term of the lease. The difference between rent expense recorded and the amount paid is credited or charged to deferred rent obligation, which is included in “Accounts payable and accrued liabilities” in the Consolidated Balance Sheets.

Interest Rate Contracts

We have designated certain interest rate contracts as cash flow hedges. No components of the hedging instruments are excluded from the assessment of hedge effectiveness. All changes in fair value of outstanding derivatives in cash flow hedges, except any ineffective portion, are recorded in other comprehensive income until earnings are impacted by the hedged transaction. Classification of the gain or loss in the Consolidated Statements of Operations upon release from comprehensive income is the same as that of the underlying exposure.

When we discontinue hedge accounting because it is no longer probable that an anticipated transaction will occur in the originally expected period, or within an additional two-month period thereafter, changes to fair value accumulated in other comprehensive income are recognized immediately in earnings.

Insurance

We are insured for workers’ compensation, employer’s liability, auto liability and general liability claims, subject to a deductible of $500 per occurrence. Additionally, our largest non-union employee-related health care benefit plan is subject to a deductible of $250 per claimant per year.

Losses are accrued based upon our estimates of the ultimate liability for claims incurred (including an estimate of claims incurred but not reported), with assistance from third-party actuaries. For these claims, to the extent we have insurance coverage above the deductible amounts, we have recorded a receivable reflected in “Other assets” in the Consolidated Balance Sheets. These insurance liabilities are difficult to assess and estimate due to unknown factors, including the severity of an injury, the determination of our liability in proportion to other parties and the number of incidents not reported. The accruals are based upon known facts and historical trends.

Income Taxes

The FASB standard for income taxes takes into account the differences between financial statement treatment and tax treatment of certain transactions. Deferred tax assets and liabilities are recognized for the expected future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date. We evaluate the realizability of our deferred tax assets in determination of our valuation allowance and adjust the amount of such allowance, if necessary. The factors used to assess the likelihood of realization are our forecast of future taxable income and available tax planning strategies that could be implemented to realize the net deferred tax assets. Failure to achieve forecasted taxable income in the applicable taxing jurisdictions could affect the ultimate realization of deferred tax assets and could result in an increase in our effective tax rate on future earnings. The provision or benefit for income taxes and the annual effective tax rate are impacted by income taxes in certain countries being computed based on a deemed profit rather than on taxable income and tax holidays on certain international projects.

RECENT ACCOUNTING PRONOUNCEMENTS

For a discussion of recent accounting pronouncements, see Note 1 to our consolidated financial statements included in this Annual Report.

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EFFECTS OF INFLATION AND CHANGING PRICES

Our operations are affected by increases in prices, whether caused by inflation, government mandates or other economic factors, in the countries in which we operate. We attempt to recover anticipated increases in the cost of labor, equipment, fuel and materials through price escalation provisions in certain major contracts or by considering the estimated effect of such increases when bidding or pricing new work.

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