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

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our historical consolidated financial statements and related notes included elsewhere in Item 8. Financial Statements and Supplementary Data. The discussion below contains forward-looking statements that are based upon our current expectations and are subject to uncertainty and changes in circumstances. Actual results may differ materially from these expectations due to inaccurate assumptions and known or unknown risks and uncertainties, including those identified in Uncertainty of Forward-Looking Statements and Information below and Item 1A. Risk Factors.

Introduction

We are a leading provider of specialty contracting services, offering infrastructure solutions primarily to the electric power, oil and gas and communications industries in the United States, Canada, Australia, Latin America and select other international markets. The services we provide include the design, installation, upgrade, repair and maintenance of infrastructure within each of the industries we serve, such as electric power transmission and distribution networks, substation facilities, renewable energy facilities, and pipeline transmission and distribution systems and facilities.

We report our results under two reportable segments: (1) Electric Power Infrastructure Services and (2) Oil and Gas Infrastructure Services. This structure is generally focused on broad end-user markets for our services. Our consolidated revenues for the year ended December 31, 2017 were $9.47 billion, of which 59% was attributable to the Electric Power Infrastructure Services segment and 41% was attributable to the Oil and Gas Infrastructure Services segment.

The Electric Power Infrastructure Services segment provides comprehensive network solutions to customers in the electric power industry. Services performed by the Electric Power Infrastructure Services segment generally include the design, installation, upgrade, repair and maintenance of electric power transmission and distribution infrastructure and substation facilities along with other engineering and technical services. This segment also provides emergency restoration services, including the repair of infrastructure damaged by inclement weather, the energized installation, maintenance and upgrade of electric power infrastructure utilizing unique bare hand and hot stick methods and our proprietary robotic arm technologies, and the installation of “smart grid” technologies on electric power networks. In addition, this segment designs, installs and maintains renewable energy generation facilities, consisting of solar, wind and certain types of natural gas generation facilities, and related switchyards and transmission infrastructure. To a lesser extent, the segment also provides comprehensive communications infrastructure services to wireline, fiber and wireless carrier customers within the communications industry; services in connection with the construction of electric power generation facilities; the design, installation, maintenance and repair of commercial and industrial wiring; and the installation of traffic networks and cable and control systems for light rail lines.

The Oil and Gas Infrastructure Services segment provides comprehensive network solutions to customers involved in the development, transportation, storage and processing of natural gas, oil and other pipeline products. Services performed by the Oil and Gas Infrastructure Services segment generally include the design, installation, repair and maintenance of pipeline transmission and distribution systems, gathering systems, production systems, storage systems and compressor and pump stations, as well as related trenching, directional boring and mechanized welding services. In addition, this segment’s services include pipeline protection, integrity testing, rehabilitation and replacement, and fabrication of pipeline support systems and related structures and facilities. We also serve the offshore and inland water energy markets, primarily providing services to oil and gas exploration platforms, including mechanical installation (or “hook-ups”), electrical and instrumentation, pre-commissioning and commissioning, coatings, shallow water pipeline installation, fabrication and marine asset repair. To a lesser extent, this segment designs, installs and maintains fueling systems, as well as water and sewer infrastructure. Through a recent acquisition discussed below, we expanded our service offerings in this segment to include high-pressure and critical-path turnaround services to the downstream and midstream energy markets and enhanced our capabilities with respect to instrumentation and electrical services, piping, fabrication and storage tank services.

For internal management purposes, we are also organized into two internal divisions, namely, the Electric Power Infrastructure Services Division and the Oil and Gas Infrastructure Services Division. These internal divisions are closely aligned with the reportable segments and are based on the predominant type of work provided by the operating units within each division.

Reportable segment information, including revenues and operating income by type of work, is gathered from each operating unit for the purpose of evaluating segment performance in support of our market strategies. These classifications of our operating unit revenues by type of work for segment reporting purposes can at times require judgment on the part of management. Our operating units may perform joint projects for customers in multiple industries, deliver multiple types of services under a single customer contract or provide services across industries. For example, we perform joint trenching projects to install distribution lines for electric power and natural gas customers. Our integrated operations and common administrative support at each of our operating units requires that certain allocations be made to determine segment profitability, including allocations of shared and indirect costs, such as facility costs, indirect operating expenses including depreciation, and general and administrative costs.

Corporate costs, such as payroll and benefits, employee travel expenses, facility costs, professional fees, acquisition costs and amortization related to intangible assets are not allocated.

Our customers include many of the leading companies in the industries we serve. We have developed strong strategic alliances with numerous customers and strive to develop and maintain our status as a preferred service provider to our customers. We enter into various types of contracts, including unit price, hourly rate, cost-plus (or time and materials basis), and fixed price (or lump sum basis), the final terms and prices of which are frequently negotiated with the customer. Although the terms of our contracts vary considerably, most are made on either a unit price or fixed price basis in which we agree to a price per unit of work performed (unit price) or a fixed amount for the entire project (fixed price). We complete a substantial majority of our fixed price projects, other than certain large transmission projects, within one year, while we frequently provide maintenance and repair work under open-ended unit price or cost-plus master service agreements that are renewable periodically.

We recognize revenues on our unit price and cost-plus contracts as units are completed or services are performed. For our fixed price contracts, we record revenues as work on the contract progresses on a percentage-of-completion basis. Under this method, revenues are recognized based on the percentage of total costs incurred to date in proportion to total estimated costs to complete the contract. Fixed price contracts generally include retainage provisions under which a percentage of the contract price is withheld until the project is complete and has been accepted by our customer.

We also enter into strategic partnerships and investment arrangements with customers and infrastructure investors to provide fully integrated infrastructure services on certain projects, including planning and feasibility analysis, engineering, design, procurement, construction and operation and maintenance, as well as project financing and investment. These projects include public-private partnerships, private infrastructure projects and concessions, along with build, own, operate and transfer and build to suit arrangements. As part of this strategy, during the year ended December 31, 2017, we formed a partnership with select infrastructure investors that provides up to $1.0 billion of capital, including approximately $80.0 million from us, available to invest in certain of these infrastructure projects through August 2024.

Recent Investments, Acquisitions and Divestitures

Acquisitions

In January 2018, we acquired an electrical infrastructure services business specializing in substation construction and relay services and a postsecondary educational institution that provides pre-apprenticeship training and programs for experienced lineman, both of which are located in the United States. The aggregate consideration for these acquisitions was $47.9 million in cash, subject to certain adjustments, and 379,817 shares of Quanta common stock, which had a fair value of approximately $13.6 million at the acquisition dates. Additionally, the acquisition of the postsecondary educational institution includes the potential payment of up to approximately $15.0 million of contingent consideration, payable if the acquired business achieves certain financial and operational objectives over a five-year period. The results of the acquired businesses will generally be included in our Electric Power Infrastructure Services segment and consolidated financial statements beginning on the acquisition dates.

On July 20, 2017, we acquired Stronghold, Ltd. and Stronghold Specialty, Ltd. (collectively Stronghold), a specialized services business located in the United States that provides high-pressure and critical-path solutions to the downstream and midstream energy markets. The aggregate consideration included $351.0 million in cash, subject to certain adjustments, and 2,693,680 shares of Quanta common stock, which had a value of $81.3 million at the acquisition date. Additionally, the acquisition includes the potential payment of up to $100.0 million of contingent consideration, payable if the acquired business achieves certain financial targets over a three-year period. Based on the estimated fair value of this contingent consideration, we recorded a $51.1 million liability as of the acquisition date. The results of the acquired business have generally been included in our Oil and Gas Infrastructure Services segment and consolidated financial statements since the acquisition date.

During the year ended December 31, 2017, we also acquired a communications infrastructure services contractor and an electrical and communications contractor, both of which are located in the United States. The aggregate consideration for these acquisitions consisted of $11.9 million paid or payable in cash, subject to certain adjustments, and 288,666 shares of Quanta common stock, with a value of $8.3 million as of the respective acquisition dates. The results of the acquired businesses have generally been included in our Electric Power Infrastructure Services segment and consolidated financial statements since the acquisition dates.

During 2016, we completed five acquisitions. The results of four of the acquired businesses are generally included in our Electric Power Infrastructure Services segment. These businesses included an electrical infrastructure services business located in Australia, a utility contracting business located in Canada, a full service medium- and high-voltage powerline contracting business located in the United States and a communications services business located in Canada. We also acquired a pipeline services contractor located in the United States, the results of which are generally included in our Oil and Gas Infrastructure Services segment. The aggregate consideration for these acquisitions consisted of $75.9 million paid or payable in cash, subject to certain adjustments, 70,840 shares of Quanta common stock valued at $1.5 million as of the settlement date of the applicable

acquisition, and contingent consideration payments of up to $39.5 million, payable if financial targets are achieved by certain of the acquired businesses. Based on the estimated fair value of this contingent consideration, we recorded a total of $18.7 million in liabilities as of the applicable acquisition dates. The results of the acquired businesses have been included in our consolidated financial statements since the acquisition dates.

During 2015, we completed 11 acquisitions. The results of eight of the acquired businesses are generally included in our Electric Power Infrastructure Services segment. These businesses included a foundation services business located in the United States, an electrical contracting business located in the United States, an electrical engineering business located in Australia, a powerline construction business located in the United States, an engineering business located in Canada, an engineering, procurement and construction services business based in the United States, an underground construction contracting business located in Canada and a supplier and material procurement specialist for the power and utility industry in Canada. The results of the remaining three acquired businesses are generally included in our Oil and Gas Infrastructure Services segment. These businesses include a business that services above-ground storage tanks in the United States, an underground utility distribution contractor that provides services to gas and electric utilities in Canada, and a business that specializes in the engineering, procurement, construction, and commissioning of compression and surface facilities for the high pressure gas industry in Australia. The aggregate consideration for these acquisitions consisted of $110.6 million paid or payable in cash, subject to certain adjustments, 461,037 shares of Quanta common stock valued at $10.1 million as of the settlement dates of the applicable acquisitions, and contingent consideration payments with an estimated fair value of $1.0 million as of the applicable acquisition date. The results of the acquired businesses have been included in our consolidated financial statements since the acquisition dates.

Disposition

On April 29, 2015, we entered into a stock purchase agreement with Crown Castle International Corp. pursuant to which we agreed to sell our fiber optic licensing operations. The purchase agreement contained customary representations and warranties, covenants and indemnities. On August 4, 2015, we completed the sale for a purchase price of $1.00 billion in cash, resulting in after-tax net proceeds of $848.2 million. In the third quarter of 2015, we recognized a net of tax gain of $171.0 million. We have presented the results of operations, financial position, cash flows and disclosures of the fiber optic licensing operations as discontinued operations for all periods in our consolidated financial statements.

Seasonality; Fluctuations of Results; Economic Conditions

Our revenues and results of operations can be subject to seasonal and other variations. These variations are influenced by weather, customer spending patterns, bidding seasons, receipt of required regulatory approvals, permits and rights of way, project timing and schedules, and holidays. Typically, our revenues are lowest in the first quarter of the year because cold, snowy or wet conditions can cause delays on projects. In addition, many of our customers develop their annual capital budgets during the first quarter, and therefore do not begin infrastructure projects in a meaningful way until their capital budgets are finalized. Second quarter revenues are typically higher than those in the first quarter, as some projects begin, but continued cold and wet weather can often impact second quarter productivity. Third quarter revenues are typically the highest of the year, as a greater number of projects are underway, and weather is normally more accommodating. Generally, revenues during the fourth quarter of the year are lower than the third quarter but higher than the second quarter. Many projects are completed in the fourth quarter, and revenues are often impacted positively by customers seeking to spend their capital budgets before the end of the year. However, the holiday season and inclement weather can sometimes cause delays during the fourth quarter, reducing revenues and increasing costs. Productivity and operating activity in any quarter may be positively or negatively affected by atypical weather patterns in the areas we serve, such as severe weather, excessive rainfall or unusual winter weather. The timing of project awards and unanticipated changes in project schedules as a result of delays or accelerations can also create variations in the level of operating activity from quarter to quarter.

These seasonal impacts are typical for our U.S. operations, but as our foreign operations grow, this pattern may have a lesser impact on our quarterly revenues. For example, revenues in Canada are often higher in the first quarter because projects are often accelerated in order to complete work prior to the break up, or seasonal thaw, as productivity is adversely affected by wet ground conditions during the warmer spring and summer months. Also, although revenues from Australia and other international operations have not been significant relative to our overall revenues to date, their seasonal patterns may differ from those in North America and may impact our seasonality more in the future.

Additionally, our industry can be highly cyclical. Our volume of business may be adversely affected by declines or delays in new projects due to cyclicality, which may vary by geographic region. Project schedules, particularly in connection with larger, longer-term projects, can also create fluctuations in the amount of work performed in a given period. For example, in connection with larger and more complicated projects, the timing of obtaining permits and other approvals may be delayed, and we may need to maintain a portion of our workforce and equipment in an underutilized capacity to ensure we are strategically positioned to deliver on such projects when they move forward. Examples of other items that may cause our results or demand for our services

to fluctuate materially from quarter to quarter include: the financial condition of our customers and their access to capital; margins of projects performed during any particular period; economic, political and market conditions on a regional, national or global scale; our customers’ capital spending, including on larger pipeline and electrical infrastructure projects; oil, natural gas and natural gas liquids prices; the timing of and costs associated with acquisitions; changes in the fair value of acquisition-related contingent consideration liabilities; dispositions; equity in earnings (losses) of unconsolidated affiliates; impairments of goodwill, intangible assets, long-lived assets or investments; effective tax rates; and interest rates. Accordingly, our operating results in any particular period may not be indicative of the results that can be expected for any other period. Please read Outlook and Understanding Margins for additional discussion of trends and challenges that may affect our financial condition, results of operations and cash flows.

Understanding Margins

Our gross margin is gross profit expressed as a percentage of revenues, and our operating margin is operating income expressed as a percentage of revenues. Cost of services, which is subtracted from revenues to obtain gross profit, consists primarily of salaries, wages and benefits to employees, depreciation, fuel and other equipment expenses, equipment rentals, subcontracted services, insurance, facilities expenses, materials and parts and supplies. Selling, general and administrative expenses and amortization of intangible assets are then subtracted from gross profit to obtain operating income. Various factors, only some of which are within our control, can impact our margins on a quarterly or annual basis.

Seasonal and geographical. Seasonal weather patterns can have a significant impact on margins. Generally, business is slower in the winter months versus the warmer months of the year, resulting in lower productivity and consequently reducing our ability to cover fixed costs. This can be offset somewhat by increased demand for electrical service and repair work resulting from severe weather. Additionally, project schedules, including when projects begin and are completed, may impact margins. The mix of business conducted in the areas we serve will also affect margins, as some areas offer the opportunity for higher margins due to their geographic characteristics. For example, margins may be negatively impacted by operations in an urban setting as opposed to a less populated rural setting or over mountainous or other difficult terrain as opposed to open terrain. Site conditions, including unforeseen underground conditions, can also impact margins.

Weather. Adverse or favorable weather conditions can impact gross margins in a given period. For example, snowfall, rainfall or other severe weather may negatively impact our revenues and margins due to reduced productivity, as projects may be terminated, deferred or delayed until weather conditions improve or an affected area recovers from a severe weather event. Conversely, in periods when weather remains dry and temperatures are accommodating, more work can be done, sometimes at a lower cost. In some cases, severe weather, such as hurricanes and ice storms, can provide us with emergency restoration service work, which typically yields higher margins due in part to better equipment utilization rates and absorption of fixed costs.

Revenue mix. The mix of revenues derived from the industries we serve and the types of services we provide within an industry will impact margins, as certain industries and services provide higher margin opportunities. Additionally, changes in our customers’ spending patterns can cause an imbalance in supply and demand and, therefore, affect margins and mix of revenues.

Service and maintenance versus installation. Installation work is often performed on a fixed price basis, while maintenance work is often performed under pre-established or negotiated prices or cost-plus pricing arrangements. Margins for installation work may vary from project to project, and may be higher than maintenance work, as work obtained on a fixed price basis has higher risk than other types of pricing arrangements. We typically derive approximately 30% of our annual revenues from maintenance work, but a higher portion of installation work in any given period may affect our gross margins for that period.

Subcontract work. Work that is subcontracted to other service providers generally yields lower margins. An increase in subcontract work in a given period may contribute to a decrease in margins. We typically subcontract approximately 20% to 25% of our work to other service providers.

Materials versus labor. Typically, our customers are responsible for supplying their own materials on projects; however, for some of our contracts we may agree to procure all or part of the required materials. Margins may be lower on projects where we furnish a significant amount of materials, including projects where we provide engineering, procurement and construction (EPC) services, as our mark-up on materials is generally lower than our mark-up on labor costs. In a given period, an increase in the percentage of work with higher materials procurement requirements may decrease our overall margins.

Size, scope and complexity of projects. We may experience a decrease or fluctuations in margins when larger, more complex electric transmission and pipeline projects experience significant delays. Larger projects with higher voltage capacities, larger diameter throughput capacities, increased engineering, design or construction complexities, more difficult terrain requirements or longer distance requirements typically yield opportunities for higher margins as we assume a greater degree of performance risk and allow for a higher degree of utilization of our resources for longer construction timeframes. Conversely, smaller or less complex electric transmission and pipeline projects typically provide lower margin opportunities as there are a greater number of competitors capable of performing in this market, and competitors at times may more aggressively pursue available volumes of work to absorb

fixed costs. A greater mix of smaller scale or less complex electric transmission and pipeline work also could negatively impact margins due to the inefficiency of transitioning between a greater number of smaller projects versus continuous production on fewer larger projects. Our margins may be further impacted by delays in the timing of larger projects, extended bidding procedures for more complex EPC projects or temporary decreases in capital spending by our customers. Also, during these periods we may choose to maintain a portion of our workforce and equipment in an underutilized capacity to ensure we are strategically positioned to deliver on larger, more complicated electric transmission or pipeline projects when they move forward.

Depreciation. We include depreciation in cost of services, which is common practice in our industry. However, this can make comparability of our margins to those of other companies difficult and must be taken into consideration when comparing us to other companies.

Insurance. As discussed in Contractual Obligations - Insurance, we are insured for employer’s liability, workers’ compensation, auto liability and general liability claims. We also have employee health care benefit plans for most employees not subject to collective bargaining agreements. Margins could be impacted by fluctuations in insurance accruals as additional claims arise and as circumstances and conditions of existing claims change.

Project Variability and Performance. Margins for a single project may fluctuate quarter to quarter due to changes in the volume or type of work performed, the pricing structure under the project contract or job productivity. Productivity can be influenced by many factors, including where the work is performed (e.g., rural versus urban area or mountainous or rocky area versus open terrain), whether the work is on an open or encumbered right of way, inclement weather, environmental restrictions or regulatory delays, protests or other political activity on a project, or the performance of third parties on a project. These types of factors are not practicable to quantify through accounting data, but may individually or in the aggregate have a direct impact on the gross margin of a specific project.

Foreign currency risk. Our financial performance is reported on a U.S. dollar-denominated basis but is partially subject to fluctuations in foreign currency exchange rates. Fluctuations in exchange rates relative to the U.S. dollar, primarily the Canadian and Australian dollars, could cause material fluctuations in comparisons of our results of operations between periods.

Change in fair value of contingent consideration liabilities. We anticipate fluctuations in operating income margins as a result of changes in the fair value of contingent consideration liabilities. See Note 2 to the Notes to Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data for more information about the valuation methodologies and assumptions related to the determination of the fair value of our contingent consideration liabilities.

Selling, General and Administrative Expenses

Selling, general and administrative expenses consist primarily of compensation and related benefits to management, administrative salaries and benefits, marketing, office rent and utilities, communications, professional fees, bad debt expense, acquisition costs, gains and losses on the sale of property and equipment, letter of credit fees and maintenance, training and conversion costs related to information technology systems.

Results of Operations

As previously discussed, the results of acquired businesses have been included in the following results of operations beginning on their respective acquisition dates. Additionally, the results of operations for our fiber optic licensing operations, which were disposed of on August 4, 2015, have been reclassified from continuing operations to net income (loss) from discontinued operations for all periods presented. The following table sets forth selected statements of operations data and such data as a percentage of revenues for the years indicated (dollars in thousands):

Consolidated Results



	Year Ended December 31,
	2017					2016					2015
Revenues	$	9,466,478		100.0	%	$	7,651,319		100.0	%	$	7,572,436		100.0	%
Cost of services (including depreciation)	8,224,618			86.9		6,637,519			86.7		6,648,771			87.8
Gross profit	1,241,860			13.1		1,013,800			13.3		923,665			12.2
Selling, general and administrative expenses	777,920			8.2		653,338			8.5		592,863			7.8
Amortization of intangible assets	32,205			0.4		31,685			0.5		34,848			0.5
Asset impairment charges	58,057			0.6		7,964			0.1		58,451			0.8
Change in fair value of contingent consideration liabilities	(5,171		)	(0.1	)	—			—		—			—
Operating income	378,849			4.0		320,813			4.2		237,503			3.1
Interest expense	(20,946		)	(0.4	)	(14,887		)	(0.2	)	(8,024		)	(0.1	)
Interest income	832			—		2,423			—		1,493			—
Other income (expense), net	(4,978		)	0.1		(663		)	—		(2,297		)	—
Income from continuing operations before income taxes	353,757			3.7		307,686			4.0		228,675			3.0
Provision for income taxes	35,532			0.3		107,246			1.4		97,472			1.3
Net income from continuing operations	318,225			3.4		200,440			2.6		131,203			1.7
Net income (loss) from discontinued operations	—			—		(342		)	—		190,621			2.5
Net income	318,225			3.4		200,098			2.6		321,824			4.2
Less: Net income attributable to non-controlling interests	3,247			0.1		1,715			—		10,917			0.1
Net income attributable to common stock	$	314,978		3.3	%	$	198,383		2.6	%	$	310,907		4.1	%
Amounts attributable to common stock:
Net income from continuing operations	$	314,978		3.3	%	$	198,725		2.6	%	$	120,286		1.6	%
Net income (loss) from discontinued operations	—			—		(342		)	—		190,621			2.5
Net income attributable to common stock	$	314,978		3.3	%	$	198,383		2.6	%	$	310,907		4.1	%

2017 compared to 2016

Revenues. Revenues increased $1.82 billion, or 23.7%, to $9.47 billion for the year ended December 31, 2017. Contributing to the increase was a $1.07 billion increase in revenues from oil and gas infrastructure services and a $749.3 million increase in revenues from electric power infrastructure services. The increase in revenues from oil and gas infrastructure services was primarily the result of increased capital spending by our customers on midstream gas pipeline transmission projects. Also contributing to the increase in oil and gas infrastructure services revenues were approximately $190 million in revenues from the acquisition of Stronghold. The increase in revenues from electric power infrastructure services was primarily due to increased customer spending associated with electric transmission projects and $143.8 million in additional emergency restoration services revenues primarily from Hurricanes Harvey and Irma and winter storms in the United States and Canada. Also contributing to the increase in revenues from electric power infrastructure services was approximately $40 million in revenues from acquired companies. Additionally, foreign currency exchange rates favorably impacted our international operations by approximately $53 million during the year ended December 31, 2017. This favorable impact was primarily attributable to the relationship between the U.S. dollar and the Canadian and Australian dollars.

Gross profit. Gross profit increased $228.1 million, or 22.5%, to $1.24 billion for the year ended December 31, 2017. Gross profit as a percentage of revenues decreased slightly to 13.1% for the year ended December 31, 2017 from 13.3% for the year ended December 31, 2016. Gross profit and gross profit as a percentage of revenues for the year ended December 31, 2017 were positively impacted by greater contributions from emergency restoration services and midstream gas pipeline transmission projects, which typically yield higher margins. However, these increases were partially offset by the negative impact of work disruptions, deferrals, cancellations and employee support costs due to Hurricanes Harvey and Irma. Gross profit and gross profit as a percentage of revenues for the year ended December 31, 2016 were negatively impacted by $54.8 million of project losses related to a power plant project in Alaska, which was substantially completed in the fourth quarter of 2016.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $124.6 million, or 19.1%, to $777.9 million for the year ended December 31, 2017. This increase was primarily attributable to $62.8 million in higher compensation costs, largely associated with higher incentive compensation based on current year levels of profitability, annual compensation increases and increased personnel to support business growth; $38.3 million of incremental selling, general and administrative expenses associated with acquired businesses, including acquisition and integration costs; and $6.9 million in higher attorneys’ fees and related expenses, $4.2 million of which was associated with a matter involving our prior disposition of certain communications operations that was resolved in the first quarter of 2017. During the year ended December 31, 2016, selling, general and administrative expenses included $6.3 million in severance costs associated with the departure of our former president and chief executive officer and severance and restructuring costs primarily associated with certain operations within the Oil and Gas Infrastructure Services segment. Selling, general and administrative expenses as a percentage of revenues decreased to 8.2% for the year ended December 31, 2017 from 8.5% for the year ended December 31, 2016, primarily due to the increase in revenues described above.

Amortization of intangible assets. Amortization of intangible assets increased $0.5 million to $32.2 million for the year ended December 31, 2017. This increase was primarily due to increased amortization of intangible assets associated with recently acquired companies, partially offset by reduced amortization expense from previously acquired intangible assets as certain of these assets became fully amortized.

Asset impairment charges. Asset impairment charges were $58.1 million for the year ended December 31, 2017 compared to $8.0 million for the year ended December 31, 2016. During the fourth quarter of 2017, we recorded a $57.0 million goodwill impairment and a $1.1 million impairment related to a customer relationship intangible asset. The extended low commodity price environment has significantly impacted certain reporting units within our Oil and Gas Infrastructure Services Division. Specifically, a reporting unit that provides material handling services experienced lower operating margins and is expected to continue to face a highly competitive environment in its select markets and a reporting unit that provides marine and offshore services experienced prolonged periods of reduced revenues and operating margins and is expected to continue to experience lower levels of activity in the U.S. Gulf of Mexico and other offshore markets. During the fourth quarter of 2016, we recorded an asset impairment of $8.0 million related to certain international renewable energy services operations as a result of a pending disposition of these operations, which was completed in 2017.

Change in fair value of contingent consideration liabilities. A $5.2 million decrease in fair value of contingent consideration liabilities was recognized as of December 31, 2017, which resulted in a corresponding increase in operating income during 2017, as compared to no change in fair value in the year ended December 31, 2016. The decrease in fair value was primarily due to changes in the timing and amounts of forecasted operating results of certain acquired businesses. It is anticipated that changes in fair value will be recorded periodically until the contingent consideration liabilities are settled. See Contractual Obligations - Contingent Consideration Liabilities for more information.

Interest expense. Interest expense increased $6.1 million to $20.9 million for the year ended December 31, 2017 as compared to the year ended December 31, 2016 due to increased borrowing activity, primarily related to the acquisition of Stronghold, as well as a higher weighted average interest rate.

Provision for income taxes. The provision for income taxes was $35.5 million for the year ended December 31, 2017, with an effective tax rate of 10.0%. The provision for income taxes was $107.2 million for the year ended December 31, 2016, with an effective tax rate of 34.9%. The lower effective tax rate for the year ended December 31, 2017 was primarily due to a provisional benefit of $70.1 million related to the enactment of the Tax Act on December 22, 2017, which among other things, lowers the U.S. federal corporate tax rate from 35% to 21% effective January 1, 2018, requires payment of a one-time transition tax on earnings of certain foreign subsidiaries, limits and eliminates certain tax deductions and creates new taxes on certain foreign-sourced earnings. The 2017 provision for income taxes was also favorably impacted by $26.7 million associated with entity restructuring and recapitalization efforts, a $7.2 million decrease in reserves for uncertain tax positions resulting from the expiration of statute of limitation periods, a higher proportion of income before taxes from international jurisdictions, which are generally taxed at lower statutory rates, and a discrete income tax benefit of $5.1 million associated with the adoption of an accounting update addressing share-based payments, which is discussed further in Note 3 of the Notes to Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data - Adoption of New Accounting Pronouncements. Partially offsetting these benefits

was an $8.5 million decrease of the production activity related tax benefit due to the acceleration of certain deductions in 2017. Additionally, the effective tax rate for the year ended December 31, 2016 was impacted by $20.5 million in tax benefits due to decreases in reserves for uncertain tax positions resulting from the expiration of federal and state statute of limitations periods. As described above, the Tax Act significantly revised the U.S. corporate tax regime and is anticipated to significantly reduce our future effective tax rate, which we expect to be approximately 29% for 2018. For additional information on the status of our provisional analysis of the Tax Act, refer to Note 10 of the Notes to Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data.

Other comprehensive income. Other comprehensive income, net of taxes, was a gain of $68.3 million in the year ended December 31, 2017 compared to a gain of $23.0 million in the year ended December 31, 2016. These gains were due to a strengthening of foreign currencies associated with our international operations, primarily the Canadian and Australian dollars, against the U.S. dollar as of December 31, 2017 when compared to December 31, 2016 and as of December 31, 2016 when compared to December 31, 2015.

2016 compared to 2015

Revenues. Revenues increased $78.9 million, or 1.0%, to $7.65 billion for the year ended December 31, 2016. Contributing to the increase was a $165.7 million increase in revenues from oil and gas infrastructure services, partially offset by an $86.8 million decrease in revenues from electric power infrastructure services. The increase in revenues from oil and gas infrastructure services primarily resulted from increased capital spending by our customers associated with larger projects, certain of which moved into full construction during the second half of 2016, after experiencing regulatory and permitting delays in the first half of 2016, as well as from increased customer spending for natural gas distribution services. Consolidated revenues were also favorably impacted by approximately $125 million due to revenues generated by acquired companies, primarily in the Electric Power Infrastructure Services segment. The decrease in revenues from electric power infrastructure services resulted from reduced customer spending associated with larger electric transmission projects as customers continued to face heightened regulatory and environmental requirements from state and federal agencies and more stringent permitting processes with various regional system operators. This regulatory environment negatively impacted the timing of existing projects and delayed the development of other infrastructure projects, which resulted in decreased demand for our services. In addition, revenues contributed by our international operations were negatively impacted by approximately $41 million due to less favorable average foreign currency translation rates in 2016 as compared to 2015, primarily attributable to the strengthening of the U.S. dollar against the Canadian dollar throughout 2016.

Gross profit. Gross profit increased $90.1 million, or 9.8%, to $1.01 billion for the year ended December 31, 2016. Gross profit as a percentage of revenues increased to 13.3% for the year ended December 31, 2016 from 12.2% for the year ended December 31, 2015. These increases were primarily due to better utilization of certain larger transmission project resources, mainly in the second half of 2016, as compared to the utilization of similar resources during 2015. Also contributing to these increases was improved performance of ongoing larger pipeline and electric power projects, as we experienced increased productivity compared to the year ended December 31, 2015 which was negatively impacted by heavy snowfall and other unfavorable weather conditions in certain areas of Canada and the northern United States. Also contributing to these increases was the contribution of profits from higher overall revenues during 2016. Gross profit and gross profit as a percentage of revenues were adversely impacted during 2016 by project losses of $54.8 million related to a power plant construction project in Alaska, which are discussed further in the results of operations for the Electric Power Infrastructure Services segment, as compared to project losses of $66.1 million during 2015 related to the same project and an electric transmission project in Canada completed in the third quarter of 2015.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $60.5 million, or 10.2%, to $653.3 million for the year ended December 31, 2016. This increase was primarily attributable to $9.8 million in incremental costs associated with acquired companies, net of reduced acquisition costs; $8.9 million in higher salaries and benefits from annual compensation increases and increased personnel; $8.6 million in higher incentive compensation costs associated with levels of profitability; $7.1 million in higher costs associated with ongoing technology and business development initiatives. Also contributing to the increase were $6.3 million in severance costs associated with the departure of Quanta’s former president and chief executive officer and severance and restructuring costs primarily associated with certain operations within the Oil and Gas Infrastructure Services segment; $2.5 million in higher legal costs related to ongoing litigation, which included $6.9 million of litigation costs related to our disposition of certain telecommunication operations; and $2.3 million contributed to a university endowment. Selling, general and administrative expenses as a percentage of revenues increased to 8.5% for the year ended December 31, 2016 from 7.8% for the year ended December 31, 2015.

Amortization of intangible assets. Amortization of intangible assets decreased $3.2 million to $31.7 million for the year ended December 31, 2016. This decrease was primarily due to reduced amortization expense from previously acquired intangible assets as certain of these assets became fully amortized, partially offset by increased amortization of intangible assets associated with acquired companies.

Asset impairment charges. Asset impairment charges were $8.0 million for the year ended December 31, 2016 compared to $58.5 million for the year ended December 31, 2015. During the fourth quarter of 2015, we recorded an asset impairment of $6.6 million related to certain international renewable energy services operations. These assets were further impaired during the fourth quarter of 2016 as a result of a pending disposition of these operations, which was completed in 2017. Additionally, during the fourth quarter of 2015, we recorded a $39.8 million goodwill impairment and a $12.1 million impairment of other intangible assets related to certain operations within our Oil and Gas Infrastructure Services Division, which were primarily attributable to lower levels of expected activity in the U.S. Gulf of Mexico and, to a lesser extent, the extended low commodity price environment for certain directional drilling operations in Australia.

Interest expense. Interest expense increased $6.9 million to $14.9 million for the year ended December 31, 2016 primarily due to increased borrowing activity and a higher weighted average interest rate during the year ended December 31, 2016.

Provision for income taxes. The provision for income taxes was $107.2 million for the year ended December 31, 2016, with an effective tax rate of 34.9%. The provision for income taxes was $97.5 million for the year ended December 31, 2015, with an effective tax rate of 42.6%. The lower effective tax rate for the year ended December 31, 2016 was primarily due to $20.5 million in tax benefits due to decreases in reserves for uncertain tax positions resulting from the expiration of federal and state statute of limitations periods, partially offset by the impact of a lower proportion of income before taxes from international operations, which are generally taxed at lower statutory rates. The provision for income taxes for the year ended December 31, 2015 included $5.0 million related to an increase in the Alberta provincial statutory income tax rate, effective as of June 1, 2015 and requiring a remeasurement of certain cumulative deferred tax assets and liabilities, which was partially offset by the realization of $4.2 million in tax benefits associated with the realization of a previously unrecognized deferred tax asset related to our investment in a foreign operating subsidiary. The effective tax rate for 2015 did not reflect a significant decrease in reserves for uncertain tax positions because the statute of limitations periods remained open for various tax years under audit.

Other comprehensive income (loss). Other comprehensive income (loss), net of taxes was a gain of $23.0 million in the year ended December 31, 2016 compared to a loss of $171.4 million in the year ended December 31, 2015. The gain in 2016 was due to a strengthening of foreign currencies associated with our international operations, primarily the Canadian dollar, against the U.S. dollar as of December 31, 2016 when compared to the exchange rates for those same currencies as of December 31, 2015. The loss in 2015 was due to weaker foreign currencies associated with our international operations, primarily the Canadian dollar, against the U.S. dollar as of December 31, 2015 when compared to the exchange rates for those same currencies as of December 31, 2014.

Segment Results

The following table sets forth segment revenues and segment operating income (loss) for the years indicated (dollars in thousands):



	Year Ended December 31,
	2017					2016					2015
Revenues:
Electric Power Infrastructure Services	$	5,599,836		59.2	%	$	4,850,495		63.4	%	$	4,937,289		65.2	%
Oil and Gas Infrastructure Services	3,866,642			40.8		2,800,824			36.6		2,635,147			34.8
Consolidated revenues from external customers	$	9,466,478		100.0	%	$	7,651,319		100.0	%	$	7,572,436		100.0	%
Operating income (loss):
Electric Power Infrastructure Services	$	518,130		9.3	%	$	395,745		8.2	%	$	362,328		7.3	%
Oil and Gas Infrastructure Services	184,083			4.8		149,502			5.3		142,929			5.4
Corporate and non-allocated costs	(323,364		)	N/A		(224,434		)	N/A		(267,754		)	N/A
Consolidated operating income	$	378,849		4.0	%	$	320,813		4.2	%	$	237,503		3.1	%

2017 compared to 2016

Electric Power Infrastructure Services Segment Results

Revenues for this segment increased $749.3 million, or 15.4%, to $5.60 billion for the year ended December 31, 2017. This increase was primarily due to increased customer spending associated with electric transmission projects, an increase of $143.8 million in emergency restoration services revenues and approximately $40 million in revenues from acquired companies. The increased customer spending associated with electric transmission projects primarily resulted from interconnections with new generation facilities and from modernization of the North American electric power grid. The increase is emergency restoration

services revenues primarily resulted from Hurricanes Harvey and Irma and winter storms across the United States and Canada. Also contributing to the increase were more favorable foreign currency exchange rates during the year ended December 31, 2017, which favorably impacted revenues by approximately $27 million, primarily attributable to the relationship between the U.S. dollar and the Canadian and Australian dollars. Partially offsetting these increases were delays on certain projects, including as a result of work disruptions, deferrals and cancellations due to Hurricanes Harvey and Irma, and a decrease in renewable energy services revenues due primarily to a lower volume of renewable energy projects and a reduction in revenues associated with a power plant project in Alaska that was substantially completed in the fourth quarter of 2016.

Operating income increased $122.4 million, or 30.9%, to $518.1 million for the year ended December 31, 2017. Operating income as a percentage of segment revenues increased to 9.3% for the year ended December 31, 2017 from 8.2% for the year ended December 31, 2016. These increases primarily resulted from the recognition of $54.8 million of project losses on a power plant project in Alaska during the year ended December 31, 2016, as well as incremental emergency restoration services revenues in the year ended December 31, 2017, which typically yield higher margins due in part to higher equipment utilization and absorption of fixed costs. Partially offsetting these increases was a loss of $17.3 million during the year ended December 31, 2017 on an electric transmission project that experienced road access, subcontractor and labor production issues. The project was approximately 90% complete as of December 31, 2017. Additionally, operating income and operating income as a percentage of revenues were negatively impacted by delays on certain projects, including as a result of work disruptions, deferrals, cancellations and employee support costs due to Hurricanes Harvey and Irma and expenses incurred to support the growth of our communications services operations.

Oil and Gas Infrastructure Services Segment Results

Revenues for this segment increased $1.07 billion, or 38.1%, to $3.87 billion for the year ended December 31, 2017. This increase was primarily the result of increased capital spending by our customers on midstream gas pipeline transmission projects. The timing of construction for pipeline transmission projects is highly variable due to delays associated with obtaining permits, as well as worksite access limitations related to environmental regulations and seasonality of weather patterns. Also contributing to this increase were approximately $190 million in revenues from acquired companies and more favorable foreign currency exchange rates during the year ended December 31, 2017, which favorably impacted our international operations by approximately $26 million, primarily attributable to the relationship between the U.S. dollar and the Canadian dollar. During the year ended December 31, 2016, revenues were negatively impacted by project delays due to forest fires in Alberta, Canada during mid-2016.

Operating income increased $34.6 million, or 23.1%, to $184.1 million for the year ended December 31, 2017. Operating income as a percentage of segment revenues decreased to 4.8% for the year ended December 31, 2017 from 5.3% for the year ended December 31, 2016. Operating income and operating income as a percentage of segment revenues were positively impacted by a higher proportion of midstream gas transmission work which typically yields higher margins. In addition, overall higher revenues in the segment allowed for better coverage of fixed and overhead costs. These increases were offset by higher costs associated with adverse weather conditions, delays and other production issues during the third and fourth quarters of 2017 on certain Canadian pipeline transmission projects. Additionally, several projects associated with our recent acquisition of Stronghold were temporarily suspended or deferred as a result of Hurricane Harvey, which negatively impacted operating income and operating income as a percentage of segment revenues.

Corporate and Non-allocated Costs

Certain selling, general and administrative expenses and amortization of intangible assets are not allocated to segments. Corporate and non-allocated costs for the year ended December 31, 2017 increased $98.9 million to $323.4 million compared to the year ended December 31, 2016. This increase was primarily due to the $58.1 million of goodwill and intangible asset impairment charges recorded in the year ended December 31, 2017 mentioned above. In addition, higher compensation costs, largely associated with higher incentive compensation based on profitability for 2017, as well as higher acquisition and integration costs and higher costs associated with ongoing technology and business development initiatives contributed to the 2017 increase. Also contributing to the increase were $4.2 million of attorneys’ fees and related expenses associated with a matter involving our prior disposition of certain communications operations that was resolved in the three months ended March 31, 2017 and $2.4 million in charitable contributions in connection with the formation of a non-profit line training school. These increases were partially offset by the favorable impact of a $5.2 million decrease in fair value of contingent consideration liabilities during the year ended December 31, 2017 and $4.0 million in costs associated with the departure of our former president and chief executive officer recognized in the year ended December 31, 2016.

2016 compared to 2015

Electric Power Infrastructure Services Segment Results

Revenues for this segment decreased $86.8 million, or 1.8%, to $4.85 billion for the year ended December 31, 2016. This decrease was primarily a result of reduced customer spending associated with larger electric transmission projects as customers

continued to face heightened regulatory and environmental requirements from state and federal agencies and more stringent permitting processes with various regional system operators. This regulatory environment negatively impacted the timing of existing projects and delayed the development of other infrastructure projects, which resulted in decreased demand for our services. Revenues also declined as a result of less favorable foreign currency exchange rates during the year ended December 31, 2016, which negatively impacted our international operations by approximately $23 million and were primarily attributable to the strengthening of the U.S. dollar against the Canadian dollar. Partially offsetting these decreases were approximately $95 million in revenues from acquired companies and $29.9 million in higher emergency restoration services revenues.

Operating income increased $33.4 million, or 9.2%, to $395.7 million for the year ended December 31, 2016. Operating income as a percentage of segment revenues increased to 8.2% for the year ended December 31, 2016 from 7.3% for the year ended December 31, 2015. These increases were primarily due to better utilization of certain larger transmission project resources as compared to the utilization of similar resources in 2015. Also contributing to these increases was improved performance of ongoing projects, as we experienced more favorable weather and increased productivity compared to the year ended December 31, 2015, which was negatively impacted by heavy snowfall and other unfavorable weather conditions in certain areas of Canada and the northern United States. Operating income and operating income as a percentage of revenues during 2016 were adversely impacted by project losses of $54.8 million related to performance issues on a power plant construction project in Alaska which compares to the 2015 impact of project losses of $66.1 million primarily associated with the same project in Alaska and an electric transmission project in Canada that was completed in the third quarter of 2015.

The project losses related to the Alaska power plant construction project recognized during the year ended December 31, 2016 were primarily due to performance issues and a claimed force majeure event that disrupted the commissioning phase of the project during the second quarter of 2016. These issues resulted in higher than expected production costs due to quality deficiencies and their impact on production sequencing. We provided the customer and its insurance providers with a notice of force majeure in order to seek schedule relief and cost recovery from the disruptions. We are also in the process of developing potential claims for damages that may have resulted from third-party engineering and other contractor performance issues; however, no revenues or cost recovery was reflected in the estimate of total project losses at December 31, 2017 or 2016. This project had a contract value of $202 million and was completed in 2017. However, we remain within the warranty period and are subject to potential warranty claims, for which we have provided an estimated warranty reserve.

Oil and Gas Infrastructure Services Segment Results

Revenues for this segment increased $165.7 million, or 6.3%, to $2.80 billion for the year ended December 31, 2016. This increase was primarily the result of increased capital spending by our customers on larger projects, certain of which moved into full construction during the second half of 2016, after experiencing regulatory and permitting delays in the first half of 2016, as well as increased customer spending for natural gas distribution services. In addition, revenues were favorably impacted by the contribution of approximately $30 million in revenues from acquired companies. The revenues contributed from our international operations were negatively impacted by approximately $18 million as a result of less favorable foreign currency exchange rates in the year ended December 31, 2016 as compared to the year ended December 31, 2015, primarily attributable to the strengthening of the U.S. dollar against the Canadian dollar.

Operating income increased $6.6 million, or 4.6%, to $149.5 million for the year ended December 31, 2016. Operating income as a percentage of segment revenues decreased to 5.3% for the year ended December 31, 2016 from 5.4% for the year ended December 31, 2015. The increase in operating income was primarily due to the increase in revenues described above. The decrease in operating income as a percentage of segment revenues was primarily due to the negative impact on resource utilization due to permitting delays on certain pipeline projects that were scheduled to begin in the first half of 2016 but did not start until the second half of 2016. Operating income as a percentage of revenues was also negatively impacted by approximately $2 million in severance and restructuring costs recognized during 2016. Partially offsetting these items that negatively impacted operating income as a percentage of revenues was improved performance on certain larger pipeline projects that moved into full construction during 2016.

Corporate and Non-allocated Costs

Liquidity and Capital Resources

Cash Requirements

Our cash and cash equivalents totaled $138.3 million and $112.2 million as of December 31, 2017 and 2016. As of December 31, 2017 and 2016, cash and cash equivalents held in domestic bank accounts were $83.1 million and $19.5 million, and cash and cash equivalents held in foreign bank accounts were $55.2 million and $92.7 million. As of December 31, 2017 and 2016, cash and cash equivalents held by our joint ventures, which are either consolidated or proportionately consolidated, were $16.7 million and $11.5 million, of which $10.0 million and $10.0 million related to domestic joint ventures. Cash and cash equivalents held by the joint ventures are available to support joint venture operations, but we cannot utilize those assets to support our other operations. We generally have no right to a joint venture’s cash and cash equivalents other than participating in distributions and in the event of dissolution.

We were in compliance with the covenants under the credit agreement for our senior secured revolving credit facility at December 31, 2017. We anticipate that our cash and cash equivalents on hand, existing borrowing capacity under such credit facility, and our future cash flows from operations will provide sufficient funds to enable us to meet our future operating needs and our planned capital expenditures during 2018, as well as facilitate our ability to grow through acquisitions or otherwise in the foreseeable future.

We also evaluate opportunities for strategic acquisitions from time to time that may require cash, as well as opportunities to make investments in strategic partnerships with customers and infrastructure investors where we anticipate performing services such as project management, engineering, procurement or construction services. These investment opportunities exist in the markets and industries we serve and may require the use of cash to purchase debt or equity investments.

Management continues to monitor the financial markets and general national and global economic conditions for factors that may affect our liquidity and capital resources. We consider our cash and cash equivalents investment policies to be conservative in that we maintain a diverse portfolio of what we believe to be high-quality cash and cash equivalent investments with short-term maturities. Accordingly, we do not anticipate that any weakness in the capital markets will have a material impact on the principal amounts of our cash and cash equivalents or our ability to rely upon our senior secured revolving credit facility for funds. To date, we have not experienced a loss of or lack of access to our cash or cash equivalents or funds under our senior secured revolving credit facility; however, our access to invested cash and cash equivalents or availability under our senior secured revolving credit facility could be impacted in the future by adverse conditions in the financial markets.

We generally do not provide for taxes related to undistributed earnings of our foreign subsidiaries because such earnings either would not be taxable when remitted or they are considered to be indefinitely reinvested. We could also be subject to additional foreign withholding taxes if we were to repatriate cash that is indefinitely reinvested outside the United States, but we do not expect such amounts to be material.

Sources and Uses of Cash

As of December 31, 2017, we had cash and cash equivalents of $138.3 million and working capital of $1.38 billion. We also had $413.3 million of outstanding letters of credit and bank guarantees under our senior secured revolving credit facility, $228.6 million of which were denominated in U.S. dollars and $184.7 million of which were denominated in currencies other than the U.S. dollar, primarily in Australian or Canadian dollars. We also had $668.4 million of outstanding revolving loans under our senior secured revolving credit facility, $645.0 million of which were denominated in U.S. dollars and $23.4 million of which were denominated in Australian dollars. As of December 31, 2017, our $1.81 billion senior secured revolving credit facility had $728.3 million available for revolving loans or issuing new letters of credit or bank guarantees. As discussed in Debt Instruments - Credit Facility below, we entered into an amendment to our senior secured revolving credit facility that extended the maturity date to October 31, 2022 and adjusted the interest rates applicable to certain borrowings.

Operating Activities

Cash flow from operations is primarily influenced by demand for our services and operating margins but can also be influenced by working capital needs associated with the various types of services that we provide. In particular, working capital needs may increase when we commence large volumes of work under circumstances where project costs, primarily associated with labor, equipment and subcontractors, are required to be paid before the receivables resulting from the work performed are billed and collected. Accordingly, changes within working capital in accounts receivable, costs and estimated earnings in excess of billings

on uncompleted contracts, and billings in excess of costs and estimated earnings on uncompleted contracts are normally related and are typically affected on a collective basis by changes in revenue due to the timing and volume of work performed and variability in the timing of customer billings and payments. Additionally, working capital needs are generally higher during the summer and fall months due to increased demand for our services when favorable weather conditions exist in many of our operating regions. Conversely, working capital assets are typically converted to cash during the winter months. These seasonal trends can be offset by changes in the timing of projects due to delays or accelerations and other economic factors that may affect customer spending.

Operating activities of continuing operations provided net cash of $372.5 million during 2017 as compared to $390.2 million during 2016 and $628.6 million during 2015. Net cash provided by operating activities during 2017 and 2016, as compared to 2015, were favorably impacted by increases in earnings from continuing operations. However, for 2017, the higher earnings were offset by increased working capital requirements primarily related to variability in billing and payment terms across various projects and an increase in accounts receivable associated with emergency restoration services work performed late in 2017. Also contributing to the decrease in 2017 as compared to 2016 was the $25.5 million payment related to the settlement of the multiemployer pension plan withdrawal liabilities associated with the Central States Plan, partially offset by reduced cash tax payments due to the acceleration of tax deductions into 2017. The decrease in cash flow from operating activities of continuing operations for the year ended December 31, 2016 compared to the year ended December 31, 2015 was primarily due to additional working capital requirements associated with larger oil and gas infrastructure projects that moved into full construction during the second half of 2016 and invoicing challenges and billing delays on two related electric transmission projects located in remote regions of northeastern Canada, which resulted from extensive quality assurance documentation and administrative requirements. These invoicing and billing delays were substantially resolved during 2017. Operating activities of continuing operations for 2015 were positively impacted by the receipt of a $65 million cash payment associated with the settlement of a large project receivable, as well as a corresponding benefit due to the reduction in income tax payments that resulted from the prior year charge to selling, general and administrative expenses of $102.5 million associated with this settlement.

Days sales outstanding (DSO) as of December 31, 2017 was 76 days, as compared to 74 days as of December 31, 2016. This increase was primarily due to favorable billing terms for certain projects ongoing at December 31, 2016 as compared to projects ongoing at December 31, 2017, partially offset by the impact of invoicing challenges and billing delays on two related large electric transmission projects in remote regions of northeastern Canada as of December 31, 2016. DSO is calculated by using the sum of current accounts receivable, net of allowance (which includes retainage and unbilled balances), plus costs and estimated earnings in excess of billings on uncompleted contracts less billings in excess of costs and estimated earnings on uncompleted contracts, divided by average revenues per day during the quarter.

Investing Activities

During 2017, we used net cash in investing activities of continuing operations of $575.8 million as compared to $266.0 million and $307.1 million used in 2016 and 2015. Investing activities of continuing operations in 2017 included $361.2 million used for acquisitions, including $347.5 million associated with the Stronghold acquisition, and $244.7 million used for capital expenditures. These items were partially offset by $23.3 million of proceeds from the sale of property and equipment. Investing activities of continuing operations in 2016 included $212.6 million used for capital expenditures and $68.8 million used for acquisitions, partially offset by $22.0 million of proceeds from the sale of property and equipment. Investing activities of continuing operations in 2015 included $210.0 million used for capital expenditures and $112.9 million used for acquisitions, partially offset by $26.2 million of proceeds from the sale of property and equipment.

Additionally, our acquisition of Stronghold in 2017 includes the potential payment of up to approximately $100.0 million of contingent consideration, payable at the end of a three-year period if the acquired business achieves certain financial targets. Any contingent consideration that is earned will be paid at least 70% in cash, and we may elect to pay up to the full amount in cash. We recorded a $51.1 million liability as of the acquisition date based on the estimated fair value of the liability. The aggregate fair value of all of our contingent consideration liabilities totaled $65.7 million as of December 31, 2017. We also completed an acquisition in January 2018 that included contingent consideration of up to $15.0 million, payable if the acquired business achieves certain financial and operational objectives and which would be paid at least 70% in cash.

Our industry is capital intensive, and we expect the need for substantial capital expenditures to continue into the foreseeable future to meet the anticipated demand for our services. We also have various contractual obligations related to investments in unconsolidated affiliates and other capital commitments which are detailed in Contractual Obligations below. In addition, we expect to continue to pursue strategic acquisitions and investments, although we cannot predict the timing or magnitude of the potential cash outlays for these initiatives.

Financing Activities

During 2017, net cash provided by financing activities of continuing operations was $227.8 million as compared to net cash used in financing activities of continuing operations of $133.8 million and $1.23 billion in 2016 and 2015. Financing activities of continuing operations during 2017 included $307.9 million of net borrowings under our senior secured revolving credit facility, partially offset by $50.0 million of common stock repurchases under our stock repurchase program and $18.5 million of payments to satisfy tax withholding obligations associated with share-based compensation. Net borrowings during 2017 were primarily utilized to fund the cash portion of the consideration paid at closing for the Stronghold acquisition and additional working capital requirements associated with increases in emergency restoration services projects and the number and size of ongoing oil and gas infrastructure projects. Financing activities of continuing operations in 2016 included $116.2 million of net repayments under our senior secured revolving credit facility and $8.3 million of payments to satisfy tax withholding obligations associated with share-based compensation.

Financing activities of continuing operations in 2015 included $1.61 billion of common stock repurchases under our stock repurchase programs; $18.9 million of cash payments to non-controlling interests as distributions of joint venture profits, net of contributions received; and $9.8 million of payments to satisfy tax withholding obligations associated with share-based compensation, partially offset by $413.6 million of net borrowings under our senior secured revolving credit facility.

Additionally, on August 4, 2015, we completed the sale of our fiber optic licensing operations for a purchase price of $1.00 billion in cash, resulting in after-tax net proceeds of $848.2 million. We have presented the results of operations, financial position, cash flows and disclosures of the fiber optic licensing operations as discontinued operations for all periods in our consolidated financial statements. A cash tax payment of $134.3 million related to the gain was paid in the fourth quarter of 2015 and was included in net cash provided by (used in) investing activities from discontinued operations on our consolidated statement of cash flows for the year ended December 31, 2015.

Stock Repurchases

During the second quarter of 2017, our board of directors approved a stock repurchase program that authorizes us to purchase, from time to time through June 30, 2020, up to $300.0 million of our outstanding common stock (the 2017 Repurchase Program). Repurchases under the 2017 Repurchase Program can be made in open market and privately negotiated transactions. As of December 31, 2017, we had repurchased 1.4 million shares of our common stock at a cost of $50.0 million in the open market under the 2017 Repurchase Program.

During the third quarter of 2015, our board of directors approved a stock repurchase program that authorized us to purchase, from time to time through February 28, 2017, up to $1.25 billion of our outstanding common stock (the 2015 Repurchase Program). During 2015, we repurchased 19.2 million shares of our common stock at a cost of $449.9 million in the open market under the 2015 Repurchase Program. During the third quarter of 2015, we also entered into an accelerated share repurchase arrangement (the ASR) to repurchase $750.0 million of our common stock under the 2015 Repurchase Program. Pursuant to the terms of the ASR, based on the final volume-weighted average share price during the term of the ASR, minus a discount and subject to other adjustments, we paid $750.0 million to JPMorgan Chase Bank, National Association, London Branch (JPMorgan) and received 25.7 million shares of our common stock in the third quarter of 2015 and 9.4 million shares of our common stock in the second quarter of 2016. As a result, we repurchased a total of 54.3 million shares of our common stock at a cost of $1.20 billion under the 2015 Repurchase Program prior to its termination on February 28, 2017.

During the fourth quarter of 2013, our board of directors approved a stock repurchase program authorizing us to purchase from time to time through December 31, 2016, up to $500.0 million of our outstanding common stock (the 2013 Repurchase Program). During the year ended December 31, 2015, we repurchased 14.3 million shares of our common stock at a cost of $406.5 million in the open market and completed the 2013 Repurchase Program.

Debt Instruments

Senior Secured Revolving Credit Facility

On December 18, 2015, we entered into an amended and restated credit agreement with various lenders that provides for a $1.81 billion senior secured revolving credit facility. On October 31, 2017, we and the lenders entered into an amendment to the credit facility which, among other things, extended the maturity date from December 18, 2020 to October 31, 2022 and adjusted the interest rates applicable to certain borrowings. The entire amount available under the credit facility may be used by us for revolving loans and letters of credit in U.S. dollars and certain alternative currencies. Up to $600.0 million of the credit facility may be used by certain of our subsidiaries for revolving loans and letters of credit in certain alternative currencies. Up to $100.0 million of the credit facility may be used for swing line loans in U.S. dollars, up to $50.0 million of the credit facility may be used for swing line loans in Canadian dollars and up to $30.0 million of the credit facility may be used for swing line loans in Australian dollars. In addition, subject to the conditions specified in the credit agreement, we have the option to increase the revolving

commitments by up to $400.0 million from time to time upon receipt of additional commitments from new or existing lenders. Borrowings under the credit agreement are to be used to refinance existing indebtedness and for working capital, capital expenditures and other general corporate purposes.

As of December 31, 2017, we had $413.3 million of outstanding letters of credit and bank guarantees under our senior secured revolving credit facility, $228.6 million of which were denominated in U.S. dollars and $184.7 million of which were denominated in currencies other than the U.S. dollar, primarily in Australian or Canadian dollars. We also had $668.4 million of outstanding revolving loans under the credit facility, $645.0 million of which were denominated in U.S. dollars and $23.4 million of which were denominated in Australian dollars. The remaining $728.3 million was available for revolving loans or new letters of credit or bank guarantees.

Beginning on November 20, 2017, amounts borrowed in U.S. dollars bear interest, at our option, at a rate equal to either (i) the Eurocurrency Rate plus 1.125% to 2.000%, as determined based on our Consolidated Leverage Ratio, or (ii) the Base Rate plus 0.125% to 1.000%, as determined based on our Consolidated Leverage Ratio. Amounts borrowed as revolving loans under the credit agreement in any currency other than U.S. dollars bear interest at a rate equal to the Eurocurrency Rate plus 1.125% to 2.000%, as determined based on our Consolidated Leverage Ratio. Additionally, standby or commercial letters of credit issued under the credit agreement are subject to a letter of credit fee of 1.125% to 2.000%, based on our Consolidated Leverage Ratio, and Performance Letters of Credit issued under the credit agreement in support of certain contractual obligations are subject to a letter of credit fee of 0.675% to 1.150%, based on our Consolidated Leverage Ratio.

From December 18, 2015 through November 19, 2017, amounts borrowed in U.S. dollars bore interest, at our option, at a rate equal to either (i) the Eurocurrency Rate (as defined in the credit agreement) plus 1.125% to 2.125%, as determined based on our Consolidated Leverage Ratio (as described below), or (ii) the Base Rate (as described below) plus 0.125% to 1.125%, as determined based on our Consolidated Leverage Ratio. Amounts borrowed as revolving loans under the credit agreement in any currency other than U.S. dollars bore interest at a rate equal to the Eurocurrency Rate plus 1.125% to 2.125%, as determined based on our Consolidated Leverage Ratio. Standby or commercial letters of credit issued under the credit agreement were subject to a letter of credit fee of 1.125% to 2.125%, based on our Consolidated Leverage Ratio, and Performance Letters of Credit (as defined in the credit agreement) issued under the credit agreement in support of certain contractual obligations were subject to a letter of credit fee of 0.675% to 1.275%, based on our Consolidated Leverage Ratio.

We are also subject to a commitment fee of 0.20% to 0.40%, based on our Consolidated Leverage Ratio, on any unused availability under the credit agreement.

The Consolidated Leverage Ratio is the ratio of our Consolidated Funded Indebtedness to Consolidated EBITDA (as those terms are defined in the credit agreement). For purposes of calculating our Consolidated Leverage Ratio, Consolidated Funded Indebtedness is reduced by available cash and cash equivalents (as defined in the credit agreement) in excess of $25.0 million. The Base Rate equals the highest of (i) the Federal Funds Rate (as defined in the credit agreement) plus 0.5%, (ii) the prime rate publicly announced by Bank of America, N.A. and (iii) the Eurocurrency Rate plus 1.00%.

Subject to certain exceptions, the credit agreement is secured by substantially all of our assets and the assets of our wholly owned U.S. subsidiaries and by a pledge of all of the capital stock of our wholly owned U.S. subsidiaries and 65% of the capital stock of direct foreign subsidiaries of our wholly owned U.S. subsidiaries. Our wholly owned U.S. subsidiaries also guarantee the repayment of all amounts due under the credit agreement. Subject to certain conditions, all collateral will automatically be released from the liens at any time we maintain an Investment Grade Rating (defined in the credit agreement as two of the following three conditions being met: (i) a corporate credit rating that is BBB- or higher by Standard & Poor’s Rating Services, (ii) a corporate family rating that is Baa3 or higher by Moody’s Investors Services, Inc. or (iii) a corporate credit rating that is BBB- or higher by Fitch Ratings, Inc.).

The credit agreement contains certain covenants, including (1) a maximum Consolidated Leverage Ratio of 3.0 to 1.0 (provided that in connection with certain permitted acquisitions in excess of $200.0 million, such ratio is 3.5 to 1.0 for the fiscal quarter in which the acquisition is completed and the two subsequent fiscal quarters) and (2) a minimum Consolidated Interest Coverage Ratio (as defined in the credit agreement) of 3.0 to 1.0. As of December 31, 2017, we were in compliance with all of the covenants in the credit agreement.

The credit agreement also limits certain acquisitions, mergers and consolidations, indebtedness, asset sales and prepayments of indebtedness and, subject to certain exceptions, prohibits liens on our assets. The credit agreement allows cash payments for dividends and stock repurchases subject to compliance with the following requirements (after giving effect to the dividend or stock repurchase): (i) no default or event of default under the credit agreement; (ii) continued compliance with the financial covenants in the credit agreement; and (iii) at least $100.0 million of availability under the credit agreement and/or cash and cash equivalents on hand.

The credit agreement provides for customary events of default and contains cross-default provisions with our underwriting, continuing indemnity and security agreement with our sureties and all of our other debt instruments exceeding $100.0 million in borrowings or availability. If an Event of Default (as defined in the credit agreement) occurs and is continuing, on the terms and

subject to the conditions set forth in the credit agreement, the lenders may declare all amounts outstanding and accrued and unpaid interest immediately due and payable, require that we provide cash collateral for all outstanding letter of credit obligations, terminate the commitments under the credit agreement, and foreclose on the collateral.

Prior to the amendment and restatement of our credit agreement on December 18, 2015 and after April 1, 2014, amounts borrowed bore interest at the same rates as the period from December 18, 2015 through November 19, 2017 described above, and we were subject to the same commitment fees as above.

Other Facilities

We have also entered into bilateral credit agreements with various lenders that provide for up to $50.2 million in aggregate availability in both U.S. dollars and certain alternative currencies, primarily Australian dollars. We may utilize these facilities for, among other things, the issuance of letters of credit or bank guarantees and overdraft protection and had $2.8 million of letters of credit and bank guarantees outstanding under these facilities at December 31, 2017.

Off-Balance Sheet Transactions

As is common in our industry, we have entered into certain off-balance sheet arrangements in the ordinary course of business that result in risks not directly reflected in our balance sheets. Our significant off-balance sheet transactions include certain obligations relating to our investments and joint venture arrangements, liabilities associated with non-cancelable operating leases, letters of credit obligations, surety guarantees related to performance bonds, commitments to purchase equipment and certain multiemployer pension plan liabilities.

Investments in Affiliates and Other Entities

Certain joint venture structures involve risks not directly reflected in our balance sheets. For example, we have guaranteed all of the obligations of certain joint ventures under contracts with the customer. Additionally, other joint venture arrangements qualify as a general partnership, for which we are jointly and severally liable for all of the obligations of the joint venture. In our joint venture arrangements, typically each joint venture party indemnifies the other party for any liabilities incurred in excess of the liabilities such other party is obligated to bear under the respective joint venture agreement.

Leases

We enter into non-cancelable operating leases for many of our facility, vehicle and equipment needs. These leases allow us to conserve cash by paying a monthly lease rental fee for use of the facilities, vehicles and equipment rather than purchasing them. We may decide to cancel or terminate a lease before the end of its term, in which case we are typically liable to the lessor for the remaining lease payments under the term of the lease.

We have guaranteed the residual value of the underlying assets under certain of our equipment operating leases at the date of termination of such leases. We have agreed to pay any difference between this residual value and the fair market value of each underlying asset as of the lease termination date. As of December 31, 2017, the maximum guaranteed residual value was $626.8 million. We believe that no significant payments will be made as a result of the difference between the fair market value of the leased equipment and the guaranteed residual value. However, there can be no assurance that future significant payments will not be required.

Letters of Credit

Certain of our vendors require letters of credit to ensure reimbursement for amounts they disburse on our behalf, such as to beneficiaries under our insurance programs. In addition, from time to time, certain customers require us to post letters of credit to ensure payment of subcontractors and vendors and guarantee performance under our contracts. Such letters of credit are generally issued by a bank or similar financial institution, typically pursuant to our credit agreement. Each letter of credit commits the issuer to pay specified amounts to the holder of the letter of credit if the holder claims that we have failed to perform specified actions. If this were to occur, we would be required to reimburse the issuer of the letter of credit. Depending on the circumstances of such a reimbursement, we may also be required to record a charge to earnings for the reimbursement. We do not believe that it is likely that any material claims will be made under a letter of credit in the foreseeable future.

As of December 31, 2017, we had $413.3 million in outstanding letters of credit and bank guarantees under our senior secured revolving credit facility securing our casualty insurance program and various contractual commitments. These are irrevocable stand-by letters of credit with maturities generally expiring at various times throughout 2018. Upon maturity, it is expected that the majority of the letters of credit related to the casualty insurance program will be renewed for subsequent one-year periods.

Performance Bonds and Parent Guarantees

Many customers, particularly in connection with new construction, require us to post performance and payment bonds issued by a financial institution known as a surety. These bonds provide a guarantee to the customer that we will perform under the terms of a contract and that we will pay subcontractors and vendors. If we fail to perform, the customer may demand that the surety make payments or provide services under the bond. We must reimburse the surety for any expenses or outlays it incurs. Under our underwriting, continuing indemnity and security agreement with our sureties and with the consent of the lenders that are party to our credit agreement, we have granted security interests in certain of our assets to collateralize our obligations to the sureties. Subject to certain conditions and consistent with terms of our credit agreement, these security interests will be automatically released if we maintain a credit rating that meets two of the following three conditions: (i) a corporate credit rating that is BBB- or higher by Standard & Poor’s Rating Services, (ii) a corporate family rating that is Baa3 or higher by Moody’s Investors Services, Inc. or (iii) a corporate credit rating that is BBB- or higher by Fitch Ratings, Inc. We may be required to post letters of credit or other collateral in favor of the sureties or our customers in the future, which would reduce the borrowing availability under our senior secured revolving credit facility. To date, we have not been required to make any reimbursements to our sureties for bond-related costs. We believe that it is unlikely that we will have to fund significant claims under our surety arrangements in the foreseeable future.

As of December 31, 2017, the total amount of outstanding performance bonds was estimated to be approximately $3.0 billion. Our estimated maximum exposure as it relates to the value of performance bonds outstanding is lowered on each bonded project as the cost to complete is reduced, and each of our commitments under the performance bonds generally extinguishes concurrently with the expiration of our related contractual obligation. The estimated cost to complete these bonded projects was approximately $869 million as of December 31, 2017.

Additionally, from time to time, we guarantee the obligations of our wholly owned subsidiaries, including obligations in connection with certain contracts with customers, lease obligations, joint venture arrangements and, in some states, contractors’ licenses. We are not aware of any material obligations for performance or payment asserted against us under any of these guarantees.

Equipment Purchase Commitments

See Contractual Obligations - Equipment Purchase Obligations below for a description of these obligations.

Multiemployer Pension Plans

See Contractual Obligations - Multiemployer Pension Plans below for a description of these obligations.

Contractual Obligations

The following table summarizes our future contractual obligations as of December 31, 2017, excluding amounts related to certain capital commitments related to investments in unconsolidated affiliates, unrecognized tax benefits, multiemployer pension plan obligations, interest associated with letters of credit and bank guarantees, commitment fees under our senior secured revolving credit facility, commitments associated with our insurance liabilities and acquisition-related contingent consideration liabilities (in thousands):



	Total		2018		2019		2020		2021		2022		Thereafter
Long-term debt - principal (1)	$	670,237	$	158	$	1,652	$	—	$	—	$	668,427	$	—
Long-term debt - cash interest (2)	49		43		6		—		—		—		—
Operating lease obligations	316,004		115,985		75,556		49,287		28,422		15,883		30,871
Capital lease and related interest obligations (3)	1,704		1,062		642		—		—		—		—
Equipment purchase commitments	14,633		14,633		—		—		—		—		—
Capital commitment related to investments in unconsolidated affiliates	39,988		14,793		25,195		—		—		—		—
Total	$	1,042,615	$	146,674	$	103,051	$	49,287	$	28,422	$	684,310	$	30,871


(1)	Amounts were recorded in our December 31, 2017 consolidated balance sheet and included $668.4 million of outstanding revolving loans under our senior secured revolving credit facility, which bear interest at variable market rates. Assuming the principal amount outstanding at December 31, 2017 remained outstanding and the interest rate in effect at December 31, 2017 remained the same, the annual cash interest expense with respect to our senior secured revolving credit facility would be approximately $19.9 million, payable for the remainder of the term of such credit facility, which matures in October 2022.

(1)

Amounts were recorded in our December 31, 2017 consolidated balance sheet and included $668.4 million of outstanding revolving loans under our senior secured revolving credit facility, which bear interest at variable market rates. Assuming the principal amount outstanding at December 31, 2017 remained outstanding and the interest rate in effect at December 31, 2017 remained the same, the annual cash interest expense with respect to our senior secured revolving credit facility would be approximately $19.9 million, payable for the remainder of the term of such credit facility, which matures in October 2022.


(2)	Amounts relate to cash interest expense on our fixed-rate long-term debt, which excludes our senior secured revolving credit facility.


(3)	Principal amounts of capital lease obligations were recorded in our December 31, 2017 consolidated balance sheet.

Equipment Purchase Commitments

We have committed capital for the expansion of our vehicle fleet in order to accommodate manufacturer lead times on certain types of vehicles. As of December 31, 2017, $14.6 million of production orders were issued with expected delivery dates in 2018. Although we have committed to the purchase of these vehicles at the time of their delivery, we intend that these orders will be assigned to third party leasing companies and made available to us under certain of our master equipment lease agreements, which will release us from our capital commitment.

Capital Commitments Related to Investments in Unconsolidated Affiliates

During the year ended December 31, 2017, we formed a partnership with select investors that provides up to $1.0 billion of capital, including approximately $80.0 million from us, available to invest in certain specified types of infrastructure projects through August 2024. Because we are not obligated to invest this amount and are unable to determine the timing of any such investments, we have excluded this capital commitment from the Contractual Obligations table.

Unrecognized Tax Benefits

During 2016, the Internal Revenue Service (IRS) completed its examination related to tax years 2010, 2011 and 2012; however, certain subsidiaries remain under examination by various U.S. state, Canadian and other foreign tax authorities for multiple periods, and the amount of unrecognized tax benefits could therefore increase or decrease as a result of the expiration of certain statute of limitations periods or settlements of these examinations. We believe it is reasonably possible that within the next 12 months unrecognized tax benefits may decrease by up to $13.7 million due to the expiration of certain statute of limitations periods or settlements of the examinations.

Multiemployer Pension Plans

The previously presented table of estimated contractual obligations does not reflect the obligations under the multiemployer pension plans in which our union employees participate. Some of our operating units are parties to various collective bargaining agreements that require us to provide to the employees subject to these agreements specified wages and benefits, as well as to make contributions to multiemployer pension plans. Our multiemployer pension plan contribution rates generally are specified in the collective bargaining agreements (usually on an annual basis), and contributions are made to the plans on a “pay-as-you-go” basis based on our union employee payrolls. The location and number of union employees that we employ at any given time and

the plans in which they may participate vary depending on the projects we have ongoing at any time and the need for union resources in connection with those projects. Therefore, we are unable to accurately predict our union employee payroll and the amount of the resulting multiemployer pension plan contribution obligations for future periods.

We may also be required to make additional contributions to our multiemployer pension plans if they become underfunded, and these additional contributions will be determined based on our union employee payrolls. The Pension Protection Act of 2006 added special funding and operational rules generally applicable to plan years beginning after 2007 for multiemployer plans that are classified as “endangered,” “seriously endangered,” or “critical” status. Plans in these classifications must adopt measures to improve their funded status through a funding improvement or rehabilitation plan, as applicable, which may require additional contributions from employers (which may take the form of a surcharge on benefit contributions) and/or modifications to retiree benefits. A number of multiemployer plans to which our operating units contribute or may contribute in the future are in “endangered,” “seriously endangered,” or “critical” status. The amount of additional funds, if any, that we may be obligated to contribute to these plans in the future cannot be reasonably estimated and are not included in the above table due to uncertainty of the future levels of work that require the specific use of the union employees covered by these plans, as well as the future contribution levels and possible surcharges on contributions applicable to these plans.

We may also have additional liabilities imposed by law as a result of our participation in multiemployer defined benefit pension plans. The Employee Retirement Income Security Act of 1974, as amended by the Multiemployer Pension Plan Amendments Act of 1980, imposes certain liabilities upon employers who are contributors to a multiemployer plan if the employer withdraws from the plan or the plan is terminated or experiences a mass withdrawal. These liabilities include an allocable share of the unfunded vested benefits in the plan for all plan participants, not merely the benefits payable to a contributing employer’s own retirees. Other than as noted below, we are not aware of any material amounts of withdrawal liability that have been or are expected to be incurred as a result of a withdrawal by any of our operating units from any multiemployer defined benefit pension plans.

2011 Central States Plan Withdrawal Liability. In the fourth quarter of 2011, certain of our subsidiaries withdrew from the Central States Plan. This withdrawal event was the result of an amendment to a collective bargaining agreement with the International Brotherhood of Teamsters (Teamsters) that eliminated certain employers’ obligations to contribute to the Central States Plan, which was then in critical status and significantly underfunded as to its vested benefit obligations. The amendment was negotiated by the Pipe Line Contractors Association (PLCA) on behalf of its members, which include certain of our subsidiaries. Because certain of our other subsidiaries continued participation in the Central States Plan into 2012, the subsidiaries’ withdrawals in 2011 effected only a partial withdrawal on our behalf in 2011. We believed that the partial withdrawal was advantageous because it limited exposure to increased liability resulting from a future withdrawal event, at which point the Central States Plan could have been further underfunded. We and other PLCA members now contribute to a different multiemployer pension plan on behalf of the affected Teamsters employees.

The Central States Plan subsequently asserted that the withdrawal of the PLCA members, and thus our partial withdrawal, was not effective in 2011. The PLCA and Quanta believed at that time that a legally effective withdrawal had occurred during the fourth quarter of 2011, and this issue was litigated in the federal district court for the Northern District of Illinois, Eastern Division. In September 2013, the district court ruled in favor of the Central States Plan, and that decision was appealed by the PLCA. In July 2014, the Central States Plan provided us with a Notice and Demand claiming partial withdrawal liability in the amount of $39.6 million and requiring Quanta to make payments on this assessment while the dispute was ongoing. In September 2015, the United States Court of Appeals for the Seventh Circuit ruled in favor of the PLCA and reversed the district court’s previous ruling. Based on the outcome of the appeal, in January 2016, the Central States Plan issued a revised Notice and Demand claiming partial withdrawal liability in the amount of $32.9 million.

Separately, in December 2013, the Central States Plan filed lawsuits against two of our subsidiaries in connection with their withdrawal in 2012. In the first lawsuit, the Central States Plan alleged that the subsidiary elected to participate in the Central States Plan pursuant to the collective bargaining agreement under which it participated. We argued that no such election was made and that any payments made to the Central States Plan were made in error. In July 2014, the parties reached an agreement to settle the lawsuit, and the court dismissed the case with prejudice. In the second lawsuit, the Central States Plan alleged that contributions made by our subsidiary to a new industry fund created after we withdrew from the Central States Plan should have been made to the Central States Plan. This arguably would have extended our withdrawal date for this subsidiary to at least the end of 2013. We disputed these allegations on the basis that we properly paid contributions to the new industry fund based on the terms of the collective bargaining agreement under which we participated and asserted that we terminated our obligation to contribute to the Central States Plan by the end of 2012. The parties both moved for summary judgment, and in March 2015, the court entered judgment in our favor. The Central States Plan filed a notice of appeal in April 2015, and in December 2015, the Central States Plan agreed to dismiss the appeal with prejudice.

In December 2017, Quanta and the Central States Plan entered into a settlement agreement and release, whereby the parties agreed on a final settlement amount of $48.9 million, which included a final withdrawal liability of $44.1 million and retention of interest paid on the assessed amount of $4.8 million. This settlement addressed (i) the partial withdrawal liability assessed in the January 2016 Notice and Demand; (ii) an unassessed withdrawal liability in connection with a partial withdrawal in 2012; and (iii) an unassessed withdrawal liability in connection with a complete withdrawal in 2013 or 2014. Prior to settlement of the matter, we made monthly payments on the assessed partial withdrawal liability according to the terms of the January 2016 Notice and Demand, and the portion of those payments that was attributable to the principal amount of the assessed liability was offset against our final withdrawal liability. Accordingly, a final payment of $25.5 million was made in December 2017 in full satisfaction of this matter.

2013 Central States Plan Withdrawal Liability. On October 9, 2013, we acquired a business that experienced a complete withdrawal from the Central States Plan prior to the acquisition date. Prior to the acquisition, the Central States Plan issued a Notice and Demand to the acquired business claiming a withdrawal liability in the total amount of $6.9 million and requiring payments to be made on this assessment while the dispute is ongoing. In connection with the acquisition, we recorded an initial liability of $4.8 million related to this withdrawal liability, and a portion of the purchase price for the acquired business was deposited into an escrow account to fund any withdrawal obligation in excess of the initial liability recorded. In January 2016, the Central States Plan issued a revised Notice and Demand claiming a withdrawal liability in the amount of $4.8 million. Although we continue to dispute the total liability owed to the Central States Plan, we continue to make monthly payments according to the terms of this revised Notice and Demand while the parties determine the final withdrawal liability. As of December 31, 2017, payments totaling $4.2 million had been made toward the withdrawal liability assessment. The final amount of withdrawal liability payable in connection with this matter remains the subject of a pending arbitration proceeding and will ultimately depend on various factors, including the outcome of the arbitration. However, the acquired business’s withdrawal from the Central States Plan is not expected to have a material impact on our financial condition, results of operations or cash flows.

Letters of Credit and Bank Guarantee Fees and Commitment Fees

We have excluded from the Contractual Obligations table interest associated with letters of credit and bank guarantees and commitment fees under our senior secured revolving credit facility because the outstanding letters of credit and bank guarantees, availability and applicable interest rates and fees are variable. For additional information regarding our letters of credit and bank guarantees and the interest rates and fees associated with these items and our borrowings under our senior secured revolving credit facility, see Liquidity and Capital Resources - Debt Instruments - Credit Facility above.

Insurance

We are insured for employer’s liability, workers’ compensation, auto liability and general liability claims. Under these programs, the deductible for employer’s liability is $1.0 million per occurrence, the deductible for workers’ compensation is $5.0 million per occurrence, and the deductibles for auto liability and general liability are $10.0 million per occurrence. We manage and maintain a portion of our casualty risk through our wholly-owned captive insurance company, which insures all claims up to the amount of the applicable deductible of our third-party insurance programs. In connection with our casualty insurance programs, we are required to issue letters of credit to secure our obligations. We also have employee health care benefit plans for most employees not subject to collective bargaining agreements, of which the primary plan is subject to a deductible of $0.4 million per claimant per year.

Losses under all of these insurance programs are accrued based upon our estimate of the ultimate liability for claims reported and an estimate of claims incurred but not reported, with assistance from third-party actuaries. These insurance liabilities are difficult to assess and estimate due to unknown factors, including the severity of an injury, the extent of damage, 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, and management believes such accruals are adequate. As of December 31, 2017 and 2016, the gross amount accrued for insurance claims totaled $254.7 million and $218.2 million, with $200.0 million and $162.0 million considered to be long-term and included in “Insurance and other non-current liabilities.” Related insurance recoveries/receivables as of December 31, 2017 and 2016 were $50.4 million and $8.7 million, of which $0.4 million and $0.4 million were included in “Prepaid expenses and other current assets” and $50.0 million and $8.3 million were included in “Other assets, net.”

We renew our insurance policies on an annual basis, and therefore deductibles and levels of insurance coverage may change in future periods. In addition, insurers may cancel our coverage or determine to exclude certain items from coverage, or we may elect not to obtain certain types or incremental levels of insurance if we believe that the cost to obtain such coverage exceeds any additional benefits. In any such event, our overall risk exposure would increase, which could negatively affect our results of operations, financial condition and cash flows. The Contractual Obligations table excludes commitments associated with our insurance liabilities, as we are unable to determine the timing of payments related to these obligations.

Contingent Consideration Liabilities

We have excluded from the Contractual Obligations table acquisition-related contingent consideration liabilities, which represent the estimated fair value of future amounts payable to the former owners of acquired businesses, because the amounts have not been earned and we are unable to determine the portion of the liabilities that will be settled in cash and the exact timing of any such payments as of December 31, 2017. Payment of such consideration is contingent on the future financial performance of the acquired businesses, and the fair value of such consideration is estimated by management based on entity-specific assumptions that are evaluated on an ongoing basis. As of December 31, 2017 and 2016, the fair value of these contingent consideration liabilities totaled $65.7 million and $19.5 million, all of which was included in “Insurance and other non-current liabilities” on our consolidated balance sheets. Because acquisition-related contingent consideration liabilities are contingent upon future events, we include these liabilities in the Contractual Obligations table when the contingencies are resolved. We expect a significant portion of these liabilities to be settled by late 2020 or early 2021.

The fair values of the contingent consideration liabilities as of December 31, 2017 was determined using a Monte Carlo simulation valuation methodology based on probability-weighted financial performance projections and other inputs including a discount rate and an expected volatility factor for each acquisition. The discount rates ranged from 0.9% to 2.3% depending on the settlement methods available and are generally based on a risk-free rate and/or our cost of debt. The expected volatility factors ranged from 23.0% to 32.7% based on historical asset volatility of selected guideline public companies. The fair value determinations incorporate significant inputs not observable in the market. Accordingly, the level of inputs used for these fair value measurements is the lowest level (Level 3), as further described in Note 2 to our consolidated financial statements. Significant changes in any of these assumptions could result in a significantly higher or lower potential liability.

The majority of our contingent consideration liabilities are subject to a maximum payment amount, and the aggregate maximum amount of these liabilities was $139.5 million as of December 31, 2017. One contingent consideration liability is not subject to a maximum payout amount, and the fair value of that liability was $1.0 million as of December 31, 2017.

Our aggregate contingent consideration liabilities can change due to additional business acquisitions, payments to settle outstanding liabilities, changes in the fair value of amounts owed to former owners of the acquired businesses, and foreign currency translation gains or losses. During the years ended December 31, 2017, 2016 and 2015, acquisitions increased our contingent consideration liabilities by $51.1 million, $18.7 million and $1.0 million. We made no payments related to contingent consideration liabilities during the years ended December 31, 2017 and 2015 and a nominal payment during the year ended December 31, 2016. During the year ended December 31, 2017, we recognized a decrease in the fair value of contingent consideration liabilities of $5.2 million. No changes in fair value of contingent consideration liabilities were recognized in 2016 and 2015. Changes in fair value of contingent consideration liabilities are included in “Change in fair value of contingent consideration liabilities” on our consolidated statements of operations.

Concentrations of Credit Risk

We are subject to concentrations of credit risk related primarily to our cash and cash equivalents and our net receivable position with customers, which includes amounts related to billed and unbilled accounts receivable and costs and estimated earnings in excess of billings on uncompleted contracts net of advanced billings with the same customer. Substantially all of our cash and cash equivalents are managed by what we believe to be high credit quality financial institutions. In accordance with our investment policies, these institutions are authorized to invest cash and cash equivalents in a diversified portfolio of what we believe to be high quality investments, which primarily include interest-bearing demand deposits, money market investments, money market mutual funds and investment grade commercial paper with original maturities of three months or less. Although we do not currently believe the principal amount of these cash and cash equivalents is subject to any material risk of loss, changes in economic conditions could impact the interest income we receive from these investments. In addition, we grant credit under normal payment terms, generally without collateral, to our customers, which include electric power and oil and gas companies, governmental entities, general contractors, and builders, owners and managers of commercial and industrial properties located primarily in the United States, Canada, Australia and Latin America. Consequently, we are subject to potential credit risk related to changes in business and economic factors in these locations, which may be heightened as a result of uncertain economic and financial market conditions that have existed in recent years. However, we generally have certain statutory lien rights with respect to services provided. Historically, some of our customers have experienced significant financial difficulties, and others may experience financial difficulties in the future. These difficulties expose us to increased risk related to collectability of billed and unbilled receivables and costs and estimated earnings in excess of billings on uncompleted contracts for services we have performed.

At December 31, 2016, one customer within our Electric Power Infrastructure Services segment accounted for 16% of our consolidated net receivable position. Portions of this net receivable balance were related to invoicing challenges and billing delays on two electric transmission projects located in remote regions of northeastern Canada which resulted from changed site conditions requiring extensive quality assurance documentation and administrative requirements. During the second quarter of 2017, we and the customer reached a settlement and entered into a renegotiated contract, which eliminated the previous scheduling and billing

issues and settled outstanding change orders. No other customers represented 10% or more of our consolidated net receivable position as of December 31, 2017 and 2016, and no customers represented 10% or more of our consolidated revenues for the years ended December 31, 2017, 2016 and 2015.

Legal Proceedings

We are from time to time party to various lawsuits, claims and other legal proceedings that arise in the ordinary course of business. These actions typically seek, among other things, compensation for alleged personal injury, breach of contract and/or property damages, employment-related damages, punitive damages, civil penalties or other losses, or injunctive or declaratory relief. With respect to all such lawsuits, claims and proceedings, we record a reserve when it is probable that a loss has been incurred and the amount of loss can be reasonably estimated. In addition, we disclose matters for which management believes a material loss is at least reasonably possible. See Legal Proceedings and Collective Bargaining Agreements in Note 15 of the Notes to Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data for additional information regarding litigation, claims and other legal proceedings.

Related Party Transactions

In the normal course of business, we enter into transactions from time to time with related parties. Our significant related party transactions typically take the form of facility leases with prior owners of certain acquired companies.

Inflation

Due to relatively low levels of inflation experienced during the years ended December 31, 2017, 2016 and 2015, inflation did not have a significant effect on our results of operations, financial condition or cash flows.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based on our consolidated financial statements, which have been prepared in accordance with US GAAP. The preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent assets and liabilities known to exist as of the date the consolidated financial statements are published and the reported amounts of revenues and expenses recognized during the periods presented. We review all significant estimates affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their publication. Judgments and estimates are based on our beliefs and assumptions derived from information available at the time such judgments and estimates are made. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. There can be no assurance that actual results will not differ from those estimates. Management has reviewed its development and selection of critical accounting estimates with the audit committee of our board of directors. We believe the following accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements:

Revenue Recognition

We provide services pursuant to master service agreements, repair and maintenance contracts and fixed price and non-fixed price installation contracts. Pricing under these contracts may be competitive unit price, cost-plus/hourly (or time and materials basis) or fixed price (or lump sum basis), and the final terms and prices of these contracts are frequently negotiated with the customer. Under unit-based contracts, the utilization of an output-based measurement is appropriate for revenue recognition, and we recognize revenue as units are completed based on pricing established with the customer for each delivered unit, which best reflects the pattern in which the obligation to the customer is fulfilled. Under our cost-plus/hourly and time and materials type contracts, we recognize revenue on an input basis, as labor hours are incurred and services are performed.

Revenues from fixed price contracts are recognized using the percentage-of-completion method, measured by the percentage of costs incurred to date to total estimated costs for each contract. Such contracts provide that the customer accept completion of progress to date and compensate us for services rendered, which may be measured in terms of units installed, hours expended, costs incurred to date compared to total estimated contract costs or some other measure of progress. Contract costs include all direct materials, labor and subcontract costs and those indirect costs related to contract performance, such as indirect labor, supplies, tools, repairs and depreciation costs. Much of the material associated with our work is owner-furnished and is therefore not included in contract revenues and costs. The cost estimation process is based on professional knowledge and experience of our engineers, project managers and financial professionals. Changes in job performance, job conditions and final contract settlements are factors that influence management’s assessment of contract value and estimated costs, and as a result, the profit recognized.

As discussed in Note 3 of the Notes to Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data, effective for the quarter ending March 31, 2018, we will adopt new revenue recognition guidance using the modified

retrospective transition method. The new guidance will be applied to contracts with customers that were not substantially complete as of January 1, 2018. Our financial results for reporting periods after January 1, 2018 will be presented under the new guidance, while our financial results for prior periods will continue to be reported in accordance with the prior guidance and our historical accounting policy. We have substantially completed our evaluation of the impact of the new guidance on our contracts with customers, including identification of differences that will result from the new requirements. Based on this evaluation, we estimate that the net cumulative adjustment to retained earnings from adoption as of January 1, 2018 will be less than $10.0 million. With respect to ongoing revenues generated from master service agreements, repair and maintenance contracts and fixed price and non-fixed price installation contracts, we do not anticipate any significant changes to the pattern of revenue recognition and do not believe that the guidance surrounding identification of contracts and performance obligations or measurement of variable consideration will have a material impact on the revenue recognition for these arrangements. We expect our disclosures related to revenue recognition will expand to address new quantitative and qualitative requirements regarding the nature, amount and timing of revenue from contracts with customers and additional information related to contract assets and liabilities.

Actual revenues and project costs can vary, sometimes substantially, from previous estimates due to changes in a variety of factors, including unforeseen or changed circumstances not included in our cost estimates or covered by our contracts for which we cannot obtain adequate compensation or reimbursement. Some of these include concealed or unknown environmental conditions; changes in the cost of equipment, commodities, materials or labor; unanticipated costs or claims due to delays caused by customers or third parties; customer failure to provide required materials or equipment; errors in engineering, specifications or designs; project modifications or contract termination; weather conditions; and quality issues requiring rework or replacement. These factors, along with other risks inherent in performing fixed price contracts, may cause actual revenues and gross profits for a project to differ from previous estimates and could result in reduced profitability or losses on projects. Changes in these factors may result in revisions to costs and income, and their effects are recognized in the period in which the revisions are determined. These factors are routinely evaluated on a project-by-project basis throughout the project term, and the impact of any such revisions in management’s estimates of contract value, contract cost and contract profit are recorded as necessary in the period in which the revisions are determined. Provisions for losses on uncompleted contracts are made in the period in which such losses are determined to be probable and the amount can be reasonably estimated.

Our operating results for the year ended December 31, 2017 were impacted by less than 5% as a result of aggregate changes in contract estimates related to projects that were in progress at December 31, 2016. Our operating results for the year ended December 31, 2016 were impacted by less than 5% as a result of aggregate changes in contract estimates related to projects that were in progress at December 31, 2015. However, operating results for the year ended December 31, 2016 included losses of $54.8 million on a power plant construction project in Alaska due to performance issues that increased the estimated costs of the project. This project was substantially completed during the fourth quarter of 2016. The losses on this project were partially offset by the aggregate positive impact of numerous individually immaterial changes in profitability generally due to better than expected performance for projects that were ongoing at December 31, 2015. Our operating results for the year ended December 31, 2015 were impacted by numerous individually immaterial changes in contract estimates related to projects that were in progress at December 31, 2014; however, the aggregate impact was less than 5% despite losses of $44.9 million recorded during 2015 on the same Alaska power plant construction project.

The current asset “Costs and estimated earnings in excess of billings on uncompleted contracts” represents revenues recognized in excess of amounts billed for contracts accounted for under the percentage-of-completion method. The current liability “Billings in excess of costs and estimated earnings on uncompleted contracts” represents billings in excess of revenues recognized for contracts accounted for under the percentage-of-completion method.

We may incur costs subject to change orders, whether approved or unapproved by the customer, and/or claims related to certain contracts. We determine the probability that such costs will be recovered based upon evidence such as past practices with the customer, specific discussions or preliminary negotiations with the customer or verbal approvals. We treat items as costs of contract performance in the period incurred if it is not probable that the costs will be recovered or will recognize additional revenue if it is probable that the contract price will be adjusted and can be reliably estimated.

As of December 31, 2017 and 2016, we recognized revenues of $144.0 million and $137.8 million related to change orders and/or claims that were in the process of being negotiated and approved in the normal course of business. These aggregate contract price adjustments represent management’s best estimate of additional contract revenues which have been earned and which management believes are probable of collection. The amounts ultimately realized by us upon final acceptance by our customers could be higher or lower than such estimated amounts; however, such amounts cannot currently be estimated.

Insurance

As discussed in Contractual Obligations - Insurance, we are insured for employer’s liability, workers’ compensation, auto liability, general liability, and group health claims.

Losses under all of these insurance programs are accrued based upon our estimate of the ultimate liability for claims reported and an estimate of claims incurred but not reported, with assistance from third-party actuaries. These insurance liabilities are difficult to assess and estimate due to unknown factors, including the severity of an injury, the extent of damage, 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, and management believes such accruals are adequate. As of December 31, 2017 and 2016, the gross amount accrued for insurance claims totaled $254.7 million and $218.2 million, with $200.0 million and $162.0 million considered to be long term and included in “Insurance and other non-current liabilities.” Related insurance recoveries/receivables as of December 31, 2017 and 2016 were $50.4 million and $8.7 million, of which $0.4 million and $0.4 million were included in “Prepaid expenses and other current assets” and $50.0 million and $8.3 million were included in “Other assets, net.”

Valuation of Goodwill

We have recorded goodwill in connection with our historical acquisitions of companies. Upon acquisition, these companies were either combined into one of our existing operating units or managed on a stand-alone basis as an individual operating unit. Goodwill recorded in connection with these acquisitions is subject to an annual assessment for impairment, which we perform at the operating unit level for each operating unit that carries a balance of goodwill. Each of our operating units is organized into one of two internal divisions: the Electric Power Infrastructure Services Division and the Oil and Gas Infrastructure Services Division. As most of the companies acquired by us provide multiple types of services for multiple types of customers, these divisional designations are based on the predominant type of work performed by each operating unit at the point in time the divisional designation is made. Goodwill is required to be measured for impairment at the reporting unit level, which represents the operating segment level or one level below the operating segment level for which discrete financial information is available. We have determined that our individual operating units represent our reporting units for the purpose of assessing goodwill impairments.

In January 2017, the Financial Accounting Standards Board issued an update intended to simplify the subsequent measurement of goodwill by eliminating the second step in the two-step goodwill impairment test. The update requires an entity to perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount and to recognize an impairment charge for the amount by which the carrying amount exceeds the fair value. The income tax effect associated with an impairment of tax deductible goodwill is also considered in the measurement of the goodwill impairment. We elected to adopt the provisions of the update in connection with our annual impairment test performed in the fourth quarter of 2017.

We have the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative fair value-based impairment test described below. If we believe that, as a result of our qualitative assessment, it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the quantitative impairment test is required. We can choose to perform the qualitative assessment on none, some, or all of our reporting units. We can also bypass the qualitative assessment for any reporting unit in any period and proceed directly to the quantitative impairment test, and then resume the qualitative assessment in any subsequent period. Qualitative indicators including deterioration in macroeconomic conditions, declining financial performance, or a sustained decrease in share price, among other things, may trigger the need for annual or interim impairment testing of goodwill associated with one or all of our reporting units.

Our annual goodwill impairment assessment is performed in the fourth quarter of our fiscal year, or more frequently if events or circumstances arise which indicate that goodwill may be impaired. For instance, a decrease in our market capitalization below book value, a significant change in business climate or loss of a significant customer, as well as the qualitative indicators referenced above, may trigger the need for interim impairment testing of goodwill for a reporting unit. The quantitative impairment test involves comparing the fair value of each of our reporting units with its carrying amount, including goodwill. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recorded as a reduction to goodwill with a corresponding charge to “Asset impairment charges.” Any goodwill impairment is limited to the total amount of goodwill allocated to that reporting unit.

We determine the fair value of our reporting units using a weighted combination of the discounted cash flow, market multiple and market capitalization valuation approaches, with heavier weighting on the discounted cash flow method because management believes this method results in the most accurate calculation of fair value. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions, including revenue growth rates, operating margins, discount rates, weighted average costs of capital and future market conditions. We believe the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated.

Under the discounted cash flow method, we determine fair value based on the estimated future cash flows of each reporting unit, discounted to present value using risk-adjusted industry discount rates, which reflect the overall level of inherent risk of a reporting unit and the rate of return an outside investor would expect to earn. Cash flow projections are derived from budgeted

amounts and operating forecasts (typically a one-year model) plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur, along with a terminal value derived from the reporting unit’s earnings before interest, taxes, depreciation and amortization (EBITDA). The EBITDA multiples for each reporting unit are based on trailing twelve-month comparable industry data.

Under the market multiple and market capitalization approaches, we determine the estimated fair value of each of our reporting units by applying transaction multiples to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using either a one, two or three year average. For the market capitalization approach, we add a reasonable control premium, which is estimated as the premium that would be received in a sale of the reporting unit in an orderly transaction between market participants.

The projected cash flows and estimated levels of EBITDA by reporting unit were used to determine fair value under the three approaches discussed herein. The following table presents the significant estimates used by management in determining the fair values of our reporting units at December 31, 2017, 2016 and 2015:



	2017	2016	2015
Years of cash flows before terminal value	5 years	5 years	5 years
Discount rates	12.0% to 14.0%	12.5% to 14.5%	12.0% to 16.0%
EBITDA multiples	5.5 to 7.0	5.5 to 7.0	5.0 to 6.5
Weighting of three approaches:
Discounted cash flows	70%	70%	70%
Market multiple	15%	15%	15%
Market capitalization	15%	15%	15%

For recently acquired reporting units, a quantitative impairment test may indicate a fair value that is substantially similar to the reporting unit’s carrying amount. Such similarities in value are generally an indication that management’s estimates of future cash flows associated with the recently acquired reporting unit remain relatively consistent with the assumptions that were used to derive its initial fair value.

During the fourth quarter of 2017, a quantitative fair-value based goodwill impairment analysis was performed for each of our reporting units, and no reporting units were evaluated solely on a qualitative basis. The analysis indicated that the fair value of each of our reporting units, with the exception of two reporting units in our Oil and Gas Infrastructure Services Division, was in excess of its carrying amount. We recorded a $57.0 million non-cash charge in the fourth quarter of 2017 for the impairment of goodwill associated with the two reporting units. Specifically, a reporting unit that provides material handling services experienced lower operating margins and is expected to continue to face a highly competitive environment in its select markets and a reporting unit that provides marine and offshore services experienced prolonged periods of reduced revenues and operating margins and is expected to continue to experience lower levels of activity in the U.S. Gulf of Mexico and other offshore markets.

As discussed generally above, when evaluating the 2017 quantitative impairment test results, management considered many factors in determining whether an impairment of goodwill for any reporting unit was reasonably likely to occur in future periods, including future market conditions and the economic environment. Additionally, management considered the sensitivity of its fair value estimates to changes in certain valuation assumptions. After taking into account a 10% decrease in the fair value of each of our reporting units, one additional reporting unit within our Oil and Gas Infrastructure Services Division would have a fair value below its carrying amount. The fair value determined in 2017 for this reporting unit was consistent with the fair value determined in 2016. Circumstances such as market declines, unfavorable economic conditions, loss of a major customer or other factors could increase the risk of impairment of goodwill for this reporting unit in future periods.

If an operating unit experiences prolonged periods of declining revenues, operating margins or both, it may be at risk of failing the quantitative goodwill impairment test. In addition to the reporting units referenced above, certain operating units have experienced declines over the short-term due to challenging macroeconomic conditions in certain geographic areas and low oil and natural gas prices, which have negatively impacted customer spending and resulted in project cancellations and delays. Additionally, customer capital spending has been constrained as a result of an increasingly complex regulatory and permitting environment. Certain operating units within our Oil and Gas Infrastructure Services Division that primarily operate within the midstream and smaller-scale transmission market, including the reporting unit referenced above, have continued to be negatively impacted by these factors. Goodwill and intangible assets associated with these operating units were $50.1 million and $14.7 million at December 31, 2017. We monitor these conditions and others to determine if it is necessary to perform the quantitative fair-value based impairment test for one or more operating units prior to the annual impairment assessment. Although we are not

aware of circumstances that would lead to additional goodwill impairments at this time, circumstances such as a continued market decline, the loss of a major customer or other factors could impact the valuation of goodwill in the future.

The goodwill analysis performed for each reporting unit was based on estimates and comparisons obtained from the electric power and oil and gas industries. We assigned a higher weighting to the discounted cash flow approach in all periods to reflect increased expectations of market value being determined from a “held and used” model. As stated previously, cash flows are derived from budgeted amounts and operating forecasts that have been evaluated by management. In connection with the 2017 assessment, reporting unit annual compounded revenue growth rates during the cash flow projection period varied from negative 14% to positive 17%.

Estimating future cash flows requires significant judgment, and our projections may vary from cash flows eventually realized. Changes in our judgments and projections could result in a significantly different estimate of the fair values of reporting units and intangible assets and could result in an impairment. Variances in the assessment of market conditions, projected cash flows, cost of capital, growth rates and acquisition multiples applied could have an impact on the assessment of impairments and the amount of any goodwill impairment charges recorded. For example, lower growth rates, lower acquisition multiples or higher costs of capital assumptions would all individually lead to lower fair value assessments and potentially increased frequency or size of goodwill impairments. Goodwill impairments are included within “Asset impairment charges” on our consolidated statements of operations.

Based on the goodwill impairment analysis, we compared the sum of fair values of our reporting units to our market capitalization at December 31, 2017 and determined that the excess of the aggregate fair value of all reporting units to our market capitalization reflected a reasonable control premium. Our market capitalization at December 31, 2017 was approximately $6.02 billion, and our total stockholders’ equity was approximately $3.79 billion. If the price of our common stock were to decline to a level that causes our market capitalization to be lower than the value of our stockholders’ equity, this would be another factor that could increase the risk of further impairment of goodwill in future periods. Increases in the carrying amount of individual reporting units that may be indicated by our impairment tests are not recorded, therefore we may record goodwill impairments in the future, even when the aggregate fair value of our reporting units as a whole may increase.

Our goodwill is included in multiple reporting units. Due to the cyclical nature of our business, and the other factors described under Risk Factors in Item 1A, the profitability of our individual reporting units may suffer from downturns in customer demand and other factors. These factors may have a disproportionate impact on the individual reporting units as compared to Quanta as a whole and might adversely affect the fair value of individual reporting units. If material adverse conditions occur that impact our reporting units, our future estimates of fair value may not support the carrying amount of one or more of our reporting units, and the related goodwill would need to be written down to an amount considered recoverable.

During the fourth quarter of 2015, management concluded that goodwill was impaired at two reporting units in our Oil and Gas Infrastructure Services Division and recorded a $39.8 million non-cash charge for the impairment of goodwill, which primarily resulted from lower levels of expected activity in the U.S. Gulf of Mexico and, to a lesser extent, the extended low commodity price environment for certain directional drilling operations in Australia.

Valuation of Other Intangible Assets

Our intangible assets include customer relationships, backlog, trade names, non-compete agreements, patented rights and developed technology, all of which are subject to amortization. The value of customer relationships is estimated as of the date a business is acquired based on the value-in-use concept utilizing the income approach, specifically the excess earnings method. This analysis discounts to present value the projected cash flows attributable to the customer relationships, with consideration given to customer contract renewals and estimated customer attrition rates. The following table presents the significant estimates used by management in determining the fair values of customer relationships associated with acquisitions in the years ended December 31, 2017, 2016 and 2015:



	2017	2016	2015
Discount rates	17% to 25%	20% to 23%	18% to 22%
Customer attrition rates	15% to 78%	10% to 70%	14% to 70%

We value backlog for acquired businesses as of the acquisition date based upon the contractual nature of the backlog within each service line, discounted to present value. 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 for use of the trade name.

We amortize intangible assets based upon the estimated consumption of their economic benefits, or on a straight-line basis if the pattern of economic benefit cannot otherwise be reliably estimated. Intangible assets subject to amortization are reviewed for impairment and 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. Intangible asset impairments are included within “Asset impairment charges” on our consolidated statements of operations.

During the fourth quarter of 2017, we recorded an impairment charge of $1.1 million related to a customer relationship intangible asset, which primarily resulted from a strategic decision to restructure a business within a reporting unit in our Oil and Gas Infrastructure Services Division.

During the fourth quarter of 2015, we recorded an impairment charge of $12.1 million related to customer relationship, trade name and non-compete agreement intangible assets, which primarily resulted from lower levels of expected activity in the U.S. Gulf of Mexico and, to a lesser extent, the extended low commodity price environment for certain directional drilling operations in Australia. The two reporting units impacted also had related goodwill impairments, as discussed above, and are in our Oil and Gas Infrastructure Services Division.

Valuation of Long-Lived Assets

We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount may not be realizable. If an evaluation is required, the estimated future undiscounted cash flows associated with the asset group are compared to the asset group’s carrying amount to determine if an impairment of such asset group is necessary. This requires us to make long-term forecasts of the future revenues and costs related to the asset group 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. When an impairment exists, the difference between the fair value of such asset group and its carrying amount is expensed and reflected in operating income (loss) in our consolidated statements of operations. In addition, we estimate the useful lives of our long-lived assets and periodically review these estimates to determine whether they are appropriate.

We recorded asset impairments primarily related to certain international renewable energy services operations of $8.0 million in 2016 and $6.6 million in 2015. The 2016 impairment was primarily due to a pending disposition of certain international renewable energy services operations, which was completed in 2017, and the 2015 impairment was based on the estimated future undiscounted cash flows for the asset group as compared to their carrying amount.

Current and Long-Term Accounts and Notes Receivable and Allowance for Doubtful Accounts

We provide an allowance for doubtful accounts when collection of an account or note receivable is considered doubtful, and receivables are written off against the allowance when deemed uncollectible. Inherent in the assessment of the allowance for doubtful accounts are certain judgments and estimates regarding, among other factors, our customer’s access to capital, our customer’s willingness or ability to pay, general economic and market conditions, the ongoing relationship with the customer and uncertainties related to the resolution of disputed matters. We consider accounts receivable delinquent after 30 days but do not generally include delinquent accounts in our analysis of the allowance for doubtful accounts unless the accounts receivable have been outstanding for at least 90 days. We also include accounts receivable balances that relate to customers in bankruptcy or with other known difficulties in our analysis of the allowance for doubtful accounts. Material changes in our customers’ business or cash flows, which may be impacted by negative economic and market conditions, could affect our ability to collect amounts due. As of December 31, 2017 and 2016, we had allowances for doubtful accounts on current receivables of $4.5 million and $2.8 million. Long-term accounts receivable are included within “Other assets, net” on our consolidated balance sheets.

Should customers experience financial difficulties or file for bankruptcy, or should anticipated recoveries relating to receivables in existing bankruptcies or other workout situations fail to materialize, we could experience reduced cash flows and losses in excess of current allowances provided.

The balances billed but not paid by customers pursuant to retainage provisions in certain contracts are generally due upon completion of the contracts and acceptance by the customer. Based on our experience with similar contracts in recent years, the majority of the retainage balances at each balance sheet date are expected to be collected within the next twelve months. Current retainage balances as of December 31, 2017 and 2016 were $300.5 million and $231.0 million and were included in “Accounts receivable.” Retainage balances with settlement dates beyond the next twelve months were included in “Other assets, net,” and as of December 31, 2017 and 2016 were $41.9 million and $5.2 million.

Within accounts receivable, we recognize unbilled receivables in circumstances such as when revenues have been earned and recorded but the amount cannot be billed under the terms of the contract until a later date; costs have been incurred but are yet to be billed under cost-reimbursement type contracts; or amounts arise from routine lags in billing (for example, work completed one month but not billed until the next month). These balances do not include revenues accrued for work performed under fixed-price contracts as these amounts are recorded as “Costs and estimated earnings in excess of billings on uncompleted contracts.”

At December 31, 2017 and 2016, the balances of unbilled receivables included in “Accounts receivable” were $303.9 million and $206.8 million.

Contingent Consideration Liabilities

We have recorded liabilities related to contingent consideration associated with certain acquisitions, the payment of which is contingent upon the future financial performance of the acquired businesses and, if earned, would be payable to the former owners of the acquired businesses. The liabilities recorded represent the estimated fair values of future amounts payable to the former owners, and the fair values are estimated by management based on entity-specific assumptions that are evaluated on an ongoing basis. As of December 31, 2017 and 2016, the aggregate fair value of these outstanding and unearned contingent consideration liabilities totaled $65.7 million and $19.5 million, which was included in “Insurance and other non-current liabilities” on our consolidated balance sheets.

The fair values of each contingent consideration liability as of December 31, 2017 was determined using a Monte Carlo simulation valuation methodology based on probability-weighted financial performance projections and other inputs, including a discount rate and an expected volatility factor for each acquisition. The discount rates ranged from 0.9% to 2.3% depending on the settlement methods available and are generally based on a risk-free rate and/or our cost of debt. The expected volatility factors ranged from 23.0% to 32.7% based on historical asset volatility of selected guideline public companies. The fair value determinations incorporate significant inputs not observable in the market. Accordingly, the level of inputs used for these fair value measurements is the lowest level (Level 3). Significant changes in any of these assumptions could result in a significantly higher or lower potential liability. We expect a significant portion of these liabilities to be settled by late 2020 or early 2021.

Our aggregate contingent consideration liabilities can change due to additional business acquisitions, payments to settle outstanding liabilities, changes in the fair value of amounts owed and foreign currency translation gains or losses. During the year ended December 31, 2017, we recognized a decrease in the fair value of contingent consideration liabilities of $5.2 million. No changes in fair value of contingent consideration liabilities were recognized in 2016 and 2015. Changes in fair value of contingent consideration liabilities are included in “Change in fair value of contingent consideration liabilities” on our consolidated statements of operations.

Income Taxes

We follow the liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for future tax consequences of temporary differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that are expected to be in effect when the underlying assets or liabilities are recovered or settled.

We regularly evaluate valuation allowances established for deferred tax assets for which future realization is uncertain, including in connection with changes in tax laws affecting these assets. The estimation of required valuation allowances includes estimates of future taxable income. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. We consider projected future taxable income and tax planning strategies in making this assessment. If actual future taxable income differs from our estimates, we may not realize deferred tax assets to the extent estimated.

We record reserves for income taxes related to certain tax positions in those instances where we consider it more likely than not that additional taxes may be due in excess of amounts reflected on income tax returns filed. When recording reserves for expected tax consequences of uncertain positions, we assume that taxing authorities have full knowledge of the position and all relevant facts. We continually review exposure to additional tax obligations, and as further information is known or events occur, changes in tax reserves may be recorded. To the extent interest and penalties may be assessed by taxing authorities on any underpayment of income tax, such amounts have been accrued and included in the provision for income taxes.

As of December 31, 2017, the total amount of unrecognized tax benefits relating to uncertain tax positions was $36.2 million, an increase from December 31, 2016 of $1.0 million. This increase resulted primarily from a $7.0 million increase in reserves for uncertain tax positions to be taken for 2017 and a $2.2 million increase for uncertain tax positions related to prior years, partially offset by an $8.3 million decrease in reserves for uncertain tax positions resulting from the expiration of statute of limitations periods. Although the IRS completed its examination related to tax years 2010, 2011 and 2012 during the year ended December 31, 2016, certain subsidiaries remain under examination by various U.S. state, Canadian and other foreign tax authorities for multiple periods. We believe it is reasonably possible that within the next 12 months unrecognized tax benefits may decrease by up to $13.7 million as a result of settlement of these examinations or as a result of the expiration of certain statute of limitations periods.

U.S. federal and state and foreign income tax laws and regulations are voluminous and are often ambiguous. As such, we are required to make many subjective assumptions and judgments regarding our tax positions that could materially affect amounts recognized in our future consolidated balance sheets, consolidated statements of operations and consolidated statements of

comprehensive income. For example, as previously described, the Tax Act significantly revised the U.S. corporate tax regime and resulted in a remeasurement of our deferred tax assets and liabilities and is anticipated to significantly reduce our future effective tax rate. For additional information on the status of our provisional analysis of the Tax Act, refer to Note 10 of the Notes to Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data.

Outlook

We believe there are growth opportunities across the industries we serve and continue to have a positive long-term outlook. Overall, favorable end-market drivers have spurred demand for infrastructure services in both our Electric Power Infrastructure Services and Oil and Gas Infrastructure Services segments, and we believe both segments are generally entering a renewed multi-year up-cycle. We are focused on long-term profitable growth and continuing to distinguish ourselves through safe execution and best-in-class field leadership. Though not without risks and challenges, including those discussed below and referenced in Item 1A. Risk Factors and Uncertainty of Forward-Looking Statements and Information, we believe we are well-positioned to capitalize on opportunities and trends in the industries we serve with our full-service operations, broad geographic reach, financial position and technical expertise.

Electric Power Infrastructure Services Segment

We expect demand for electricity in North America to grow over the long term and believe that certain segments of the North American electric power grid are not adequate to efficiently serve the power needs of the future. These factors have affected and will continue to affect reliability, requiring utilities to upgrade, modernize and expand their existing transmission and distribution systems. Furthermore, current federal legislation also requires the power industry to meet federal reliability standards for its transmission and distribution systems. In response to these dynamics, over the past several years, many utilities across North America have begun to implement plans to upgrade their transmission and distribution systems in order to improve reliability and reduce congestion.

As demand for power increases, we expect the need for new power generation facilities to also increase. The development of such facilities, expected to be powered by certain types of traditional energy sources and renewable energy sources such as solar and wind, would necessitate new or expanded transmission infrastructure to transport power to demand centers. Furthermore, we anticipate that the access to low cost natural gas resources from unconventional shale formations in the United States and Canada will continue to increase the amount of electricity generated by natural gas powered plants. To the extent this dynamic continues, transmission and substation infrastructure will be needed to interconnect new natural gas-fired generation facilities. We also anticipate that modification and reengineering of existing transmission and substation infrastructure will be required as existing coal and nuclear generation facilities are retired or shut down.

With respect to distribution systems, a number of utilities are implementing system upgrades or hardening programs in response to severe weather events that have occurred over the past several years, which is increasing distribution investment in some regions of the United States. We also anticipate that utilities will continue to integrate smart grid technologies into their distribution systems over time to improve grid management and create efficiencies. Further, to the extent adoption of electrical vehicle technology increases, we believe upgrades to distribution and other electrical infrastructure will be required to accommodate increased load demand.

We believe that several existing, pending or proposed legislative or regulatory actions may also positively impact long-term demand for the services we provide, particularly in connection with electric power infrastructure and renewable energy spending. For example, legislative or regulatory action that alleviates some of the siting and right-of-way challenges that impact transmission projects would potentially accelerate future construction, and federal reliability standards for transmission and distribution systems could create incentives for system investment and maintenance. We also consider renewable energy, including solar and wind generation facilities, to be an ongoing opportunity for our engineering, project management and installation services; however, the economic feasibility of these projects may depend on the availability of tax incentive programs and there is no assurance that existing incentive programs will be extended or that new incentive programs will be implemented.

Despite these positive trends, the regulatory and environmental permitting processes remain a hurdle for some proposed transmission and renewable energy projects, and these factors continue to create uncertainty as to timing of projects and customer spending. In the near term, margins for our electric power infrastructure services operations have been impacted by regulatory and permitting delays and unfavorable economic and market conditions, particularly for larger transmission projects. We anticipate many of these issues to be resolved over the long term, as a number of these projects are currently underway, and we expect this segment’s backlog to remain strong during 2018.

Our customers are also seeking additional specialized labor resources to address an aging utility workforce and labor availability issues, increasing pressure to reduce costs and improve reliability, and increasing duration and complexity of customer capital programs. We believe these trends will continue, possibly to the point where customer demand for labor resources will outpace the supply of industry resources. Our ability to take advantage of this opportunity is limited by our ability to employ, train and retain the necessary skilled personnel. We are taking proactive steps to develop our workforce, including through the establishment and expansion of our training facility, our recent acquisition of a postsecondary educational institution that provides pre-apprenticeship training and programs for experienced linemen, and other strategic relationships.

With respect to our communications service offerings, consumer and commercial demand in North America and Latin America for communication and data-intensive, high-bandwidth wireline and wireless services and applications is driving significant investment in infrastructure and the deployment of new technologies. In particular, we believe there is increasing demand to upgrade or build fiber optic networks that are closer or connected to the end user, and in North America there are plans for new wireless networks and improvements to existing wireless networks. As a result of these near- and longer-term industry trends, we believe there will be meaningful demand for our services.

Oil and Gas Infrastructure Services Segment

We continue to see growth opportunities in our Oil and Gas Infrastructure Services segment, primarily with respect to installation and maintenance of larger pipeline systems and related facilities and services related to pipeline integrity, natural gas distribution, horizontal directional drilling and downstream industrial services. A number of larger pipeline projects from the North American shale formations and Canadian oil sands to power plants, refineries and other demand centers are in various stages of development. While there is risk the projects will not move forward or could be delayed, we believe many of our customers remain committed to them given the cost and time required to move from conception to construction. We expect to continue to execute on a significant number of larger pipeline projects during 2018.

Due to its abundant supply and current low price, we believe the demand for North American natural gas will continue to increase in the future and that natural gas will be the fuel of choice for both primary power generation and backup power generation for renewable-driven power plants. In certain areas of North America, the existing pipeline system infrastructure is insufficient to support this expected future development. Furthermore, the abundance of low price natural gas in the United States, Canada and Australia has also resulted in efforts to develop liquefied natural gas (LNG) export facilities to serve higher-price international markets, which could provide pipeline and related facilities development opportunities for us. Although fluctuating commodity prices, regulatory issues and changing economic conditions may impact the number of projects that ultimately move forward, we believe our comprehensive service offerings and broad geographic presence enable us to competitively pursue opportunities that become available.

We also believe there are growth opportunities for some of our other pipeline services over the long term, including pipeline integrity, rehabilitation and replacement services. Regulatory measures have and could continue to increase the frequency or stringency of pipeline integrity testing requirements, which we expect to result in increased capital expenditures by our customers. We have also experienced an increase in demand for our natural gas distribution services as a result of improved economic conditions, lower natural gas prices and a significant need to upgrade and replace aging infrastructure.

Despite these positive trends, a challenging regulatory and permitting environment has caused the delay of some larger pipeline projects during the past several years. These dynamics resulted in a below average number of larger pipeline construction opportunities for us and the industry during that period, and negatively impacted our segment margins, in part as a result of our inability to adequately cover certain fixed costs. Margins for larger pipeline projects are also subject to significant performance risk, which can arise from adverse weather conditions, challenging geography, customer decisions and crew productivity. Specific opportunities for larger pipeline projects are also sometimes difficult to predict because of the seasonality of bidding and construction cycles.

Additionally, the oil and gas industry is highly cyclical and subject to volatility as a result of fluctuations in natural gas, natural gas liquids and oil prices. Certain of our end markets remain challenged as the broader energy market has not fully recovered from the significant decline in prices that began in mid-2014. Exploration and production companies and midstream companies significantly reduced capital spending in response to the decline, and demand in areas where the price of oil is influential, such as Australia, the Canadian Oil Sands, certain oil-driven U.S. shale formations and the Gulf of Mexico, has been adversely impacted by low oil prices. If oil and natural gas prices decline further or remain at lower levels over the long term, our outlook may change and demand for our services could be materially impacted.

We have also recently expanded our industrial services offerings, including high-pressure and critical-path turnaround services to the downstream and midstream energy markets, and enhanced our capabilities with respect to instrumentation and electrical services, piping, fabrication and storage tank services. While these services have been negatively impacted in the short term by historic adverse weather events in the U.S. Gulf Coast region, we believe, looking at trends and estimates for process

facility utilization rates and overall refining capacity, North America will be the largest downstream maintenance market in the world over the next several years. Furthermore, we believe processing facilities located along the U.S. Gulf Coast region should have certain strategic advantages due to their access and proximity to affordable hydrocarbon resources.

Overall, we remain optimistic about this segment’s operations. From a near- and medium-term perspective, we continue to believe that larger pipeline opportunities can provide significant profitability, although these projects are often subject to more cyclicality and execution risk than our other service offerings. We have also taken steps to diversify our operations in this segment through other services, such as pipeline integrity, pipeline logistics, and downstream industrial services.

Strategic Acquisitions and Investments

We continue to evaluate potential strategic acquisitions and investments to broaden our customer base, expand our geographic area of operations, grow our portfolio of services and increase opportunities across our operations. We believe that attractive growth opportunities exist primarily due to the highly fragmented and evolving nature of the industries in which we operate and adjacent industries, along with the inability of many companies to expand and modernize due to capital or liquidity constraints. We will pursue opportunities designed to enhance our core business and leadership position in the industries we serve and provide innovative solutions to our customers. We also believe our unique operating model and entrepreneurial mindset will continue to be attractive to acquisition candidates.

Uncertainty of Forward-Looking Statements and Information

This Annual Report on Form 10-K includes “forward-looking statements” reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended to qualify for the “safe harbor” from liability established by the Private Securities Litigation Reform Act of 1995. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate,” “project,” “forecast,” “may,” “will,” “should,” “could,” “expect,” “believe,” “plan,” “intend” and other words of similar meaning. In particular, these include, but are not limited to, statements relating to the following:


•	Projected revenues, net income, earnings per share, margins, weighted average shares outstanding, capital expenditures, tax rates and other projections of operating or financial results;


•	Expectations regarding our business or financial outlook, growth, trends or opportunities in particular markets;


•	The expected value of contracts or intended contracts with customers;


•	Future capital allocation initiatives;


•	The scope, services, term and results of any projects awarded or expected to be awarded for services to be provided by us;


•	The development of larger electric transmission and oil and natural gas pipeline projects and the level of oil, natural gas and natural gas liquids prices and their impact on our business or demand for our services;


•	The impact of existing or potential legislation or regulation, including the Tax Act;


•	Potential opportunities that may be indicated by bidding activity or similar discussions with customers;


•	The future demand for and availability of labor resources in the industries we serve;


•	The potential benefits from investments or acquisitions, including Stronghold;


•	The expected outcome of pending or threatened litigation;


•	Beliefs and assumptions about the collectability of receivables;


•	The business plans or financial condition of our customers;


•	Our plans and strategies;


•	Possible recovery on pending or contemplated change orders or other claims against customers or third parties; and


•	The current economic and regulatory conditions and trends in the industries we serve.

These forward-looking statements are not guarantees of future performance, involve or rely on a number of risks, uncertainties, and assumptions that are difficult to predict or beyond our control, and reflect management’s beliefs and assumptions based on information available at the time the statements are made. We caution you that actual outcomes and results may differ materially from what is expressed, implied or forecasted by our forward-looking statements and that any or all of our forward-looking statements may turn out to be inaccurate or incorrect. Those statements can be affected by inaccurate assumptions and by known or unknown risks and uncertainties, including the following:


•	Market conditions;


•	The effects of industry, economic, financial or political conditions outside our control, including weakness in the capital markets;


•	Quarterly variations in our operating results;


•	Trends and growth opportunities in relevant markets;


•	Delays, reductions in scope or cancellations of anticipated, pending or existing projects, including as a result of weather, regulatory or permitting issues, environmental processes, project performance issues, claimed force majeure events, protests, legal challenges or other political activity or our customers’ capital constraints;


•	The successful negotiation, execution, performance and completion of anticipated, pending and existing contracts, including the ability to obtain awards of projects on which we bid or are otherwise discussing with customers;


•	Our dependence on suppliers, subcontractors, equipment manufacturers and other third-party contractors;


•	Our ability to attract and the potential shortage of skilled employees and our ability to retain key personnel and qualified employees;


•	Our dependence on fixed price contracts and the potential to incur losses with respect to these contracts;


•	Estimates relating to our use of percentage-of-completion accounting;


•	Adverse weather conditions or events;


•	Our ability to generate internal growth;


•	Competition in our business, including our ability to effectively compete for new projects and market share;


•	The effect of natural gas, natural gas liquids and oil prices on our operations and growth opportunities and on our customers’ capital programs and demand for our services;


•	The future development of natural resources;


•	The failure of existing or potential legislative actions and initiatives to result in demand for our services;


•	Liabilities associated with multiemployer pension plans, including underfunding of liabilities and termination or withdrawal liabilities;


•	Unexpected costs or liabilities that may arise from pending or threatened litigation, indemnity obligations or other claims asserted against us, including liabilities and costs for which we are not covered by third-party insurance;


•	The outcome of pending or threatened litigation;


•	Risks relating to the potential unavailability or cancellation of third-party insurance, the exclusion of coverage for certain losses, and potential increases in premiums for coverage deemed beneficial to us;


•	Cancellation provisions within our contracts and the risk that contracts expire and are not renewed or are replaced on less favorable terms;


•	Loss of customers with whom we have long-standing or significant relationships;


•	The potential that participation in joint ventures or similar structures exposes us to liability and/or harm to our reputation for acts or omissions by our partners;


•	Our inability or failure to comply with the terms of our contracts, which may result in additional costs, unexcused delays, warranty claims, failure to meet performance guarantees, damages or contract terminations;


•	The inability or refusal of our customers to pay for services, including failure to collect our outstanding receivables;


•	The failure to recover on payment claims against project owners or third-party contractors or to obtain adequate compensation for customer-requested change orders;


•	The failure of our customers to comply with regulatory requirements applicable to their projects, which may result in project delays and cancellations;


•	Budgetary or other constraints that may reduce or eliminate tax incentives or government funding for projects, which may result in project delays or cancellations;


•	Estimates and assumptions in determining our financial results and backlog;


•	Our ability to realize our backlog;


•	Risks associated with operating in international markets, including instability of foreign governments, currency fluctuations, tax and investment strategies, as well as compliance with foreign legal systems and cultural practices, the U.S. Foreign Corrupt Practices Act and other applicable anti-bribery and anti-corruption laws;


•	Our ability to successfully identify, complete, integrate and realize synergies from acquisitions, including Stronghold;


•	The potential adverse impact resulting from uncertainty surrounding acquisitions, including the ability to retain key personnel from an acquired business and the potential increase in risks already existing in our operations;


•	The adverse impact of impairments of goodwill, other intangible assets, receivables, long-lived assets or investments;


•	Our growth outpacing our decentralized management and infrastructure;


•	Requirements relating to governmental regulation and changes thereto;


•	Inability to enforce our intellectual property rights or the obsolescence of such rights;


•	Risks related to the implementation of new information technology solutions;


•	The impact of our unionized workforce on our operations, including labor stoppages or interruptions due to strikes or lockouts;


•	Potential liabilities and other adverse effects arising from occupational health and safety matters;


•	The cost of borrowing, availability of cash and credit, fluctuations in the price and volume of our common stock, debt covenant compliance, interest rate fluctuations and other factors affecting our financing and investing activities;


•	Fluctuations of prices of certain materials used in our business;


•	The ability to access sufficient funding to finance desired growth and operations;


•	Our ability to obtain performance bonds;


•	Potential exposure to environmental liabilities;


•	Our ability to meet the regulatory requirements applicable to us and our subsidiaries, including the Sarbanes-Oxley Act of 2002;


•	Rapid technological and other structural changes that could reduce the demand for our services;


•	New or changed tax laws, treaties or regulations;


•	Increased healthcare costs arising from healthcare reform legislation or other legislative action;


•	Regulatory changes that result in increased labor costs;


•	Significant fluctuations in foreign currency exchange rates; and


•	The other risks and uncertainties described elsewhere herein and in Item 1A. Risk Factors in this report on Form 10-K and as may be detailed from time to time in our other public filings with the SEC.

All of our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements or that are otherwise included in this report. In addition, we do not undertake and expressly disclaim any obligation to update or revise any forward-looking statements to reflect events or circumstances after the date of this report or otherwise.

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