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

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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 thereto 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 in Item 1A. Risk Factors.

Introduction

We are a leading provider of specialty contracting services, offering infrastructure solutions primarily to the electric power and oil and gas industries in the United States, Canada and Australia 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, pipeline transmission and distribution systems and facilities, and infrastructure services for the offshore and inland water energy markets.

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, 2015 were approximately $7.57 billion, of which 65% was attributable to the Electric Power Infrastructure Services segment and 35% to the Oil and Gas Infrastructure Services segment. As a result of the sale of our fiber optic licensing operations on August 4, 2015, we have presented our fiber optic licensing operations as discontinued operations and our ancillary telecommunications infrastructure services as part of our Electric Power Infrastructure Services segment.

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 vendor to our customers. We enter into various types of contracts, including competitive 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 do the work for a price per unit of work performed (unit price) or for 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 revenue 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, revenue is 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.

For internal management purposes, following the disposition of our fiber optic licensing operations, we are 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 described above 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 infrastructure service projects for customers in multiple industries, deliver multiple types of infrastructure services under a single customer contract or provide services across industries, for example, 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, including allocations of shared and indirect costs, such as facility costs, indirect operating expenses including depreciation, and general and administrative costs, be made to determine operating segment profitability. Corporate costs, such as payroll and benefits, employee travel expenses, facility costs, professional fees, acquisition costs and amortization related to certain intangible assets are not allocated.

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, this segment provides services such as the construction of electric power generation facilities, the design, installation, maintenance and repair of commercial and industrial wiring, installation of traffic networks and the installation of cable and control systems for light rail lines and limited ancillary telecommunication infrastructure services.

The Oil and Gas Infrastructure Services segment provides comprehensive network solutions to customers involved in the development and transportation 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 automatic 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, fabrication, pipeline construction, integrity services and marine asset repair. To a lesser extent, this segment designs, installs and maintains fueling systems as well as water and sewer infrastructure.

Recent Investments, Acquisitions and Divestitures

During 2015, we acquired 11 companies. The results of eight of the acquired companies are generally included in our Electric Power Infrastructure Services segment. These companies include a foundation services company located in the United States, an electrical contracting company located in the United States, an electrical engineering company located in Australia, a powerline construction company located in the United States, an engineering company located in Canada, an engineering, procurement and construction services company based in the United States, an underground construction contracting company 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 companies are generally included in our Oil and Gas Infrastructure Services segment. These companies include a company 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 company 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 approximately $110.4 million paid or payable in cash, subject to net working capital

adjustments, 461,037 shares of Quanta common stock valued on the settlement dates of the acquisitions at approximately $10.1 million, and $1.0 million in contingent consideration. As these transactions were effective during 2015, the results have been included in our consolidated financial statements beginning on the respective dates of acquisition. These acquisitions should enable us to further enhance our electric power and oil and gas infrastructure service offerings in the United States, Canada and Australia.

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 approximately $1 billion in cash, resulting in after-tax net proceeds of approximately $848 million. In the third quarter of 2015, we recognized a net of tax gain of approximately $171 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.

During 2014, we completed nine acquisitions, which enabled us to further enhance our electric power and oil and gas infrastructure service offerings in the United States and Canada and expand our capabilities in Australia to include electric power infrastructure service offerings. These acquisitions included four electric power infrastructure services companies located in Canada; two oil and gas infrastructure services businesses located in Canada; an electric power infrastructure services company located in Australia; a U.S.-based general engineering and construction company specializing in hydrant fueling, waterfront and utility construction for the U.S. Department of Defense the results of which are generally included in our Oil and Gas Infrastructure Services segment; and a geotechnical and geological engineering services company based in the United States the results of which are generally included in our Electric Power Infrastructure Services segment. The aggregate consideration for these acquisitions was approximately $279.5 million in cash, 686,382 shares of Quanta common stock and 3,825,971 exchangeable shares of Canadian subsidiaries of Quanta that are exchangeable on a one-for-one basis for Quanta common stock. The exchangeable shares provide holders with rights equivalent to Quanta common stockholders with respect to dividends and other economic rights. In addition, we issued one share of Series G preferred stock associated with 899,858 of the exchangeable shares, which generally votes on the same matters as Quanta common stock and is entitled to a number of votes equal to the number of such exchangeable shares outstanding at that time. Exchangeable shares not associated with preferred stock do not have voting rights. The aggregate value of the securities issued on the settlement dates of the acquisitions totaled approximately $134.5 million. As these transactions were effective during 2014, the results of each acquired company have been included in our consolidated financial statements beginning on the respective dates of acquisition.

During 2013, we acquired six businesses, which included three electric power and three oil and gas infrastructure services companies. The electric power acquisitions expanded our geographic presence primarily in the northeastern, midwestern and western regions of the United States and in the central region of Canada, while the oil and gas infrastructure services companies increased our capacity to provide mechanical installations for the offshore oil and gas industry and pipeline logistics services throughout the United States and expanded our geographic presence to include pipeline construction services in Australia. The aggregate consideration paid for these acquisitions consisted of approximately $341.1 million in cash and 3,547,482 shares of our common stock valued, as of the respective dates of issuance, at approximately $88.9 million. The results for each company have been included in our consolidated financial statements beginning on the respective dates of acquisition.

On December 6, 2013, we sold all of our equity ownership interest in Howard Midstream Energy Partners, LLC (HEP) for proceeds of approximately $220.9 million in cash, which resulted in a pre-tax gain of approximately $112.7 million.

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 capital budgets for the coming year during the first quarter and 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 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, reducing revenues and increasing costs. Any quarter may be positively or negatively affected by atypical weather patterns in any of the areas we serve, such as severe weather, excessive rainfall or warmer winter weather, making it difficult to predict these variations and their effect on particular projects quarter to quarter. 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 continue to grow, we may see a lessening of this pattern impacting our quarterly revenues. For example, revenues in Canada are often higher in the first quarter as projects are accelerated so that work can be completed 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, including the United States, Canada and Australia. Project schedules, particularly in connection with larger, longer-term projects, can also create fluctuations in the services provided, which may adversely affect us in a given period. For example, in connection with larger, 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 to fluctuate materially from quarter to quarter include: the financial condition of our customers and their access to capital; variations in the margins of projects performed during any particular period; regional, national and global economic and market conditions; the timing of acquisitions, the timing and magnitude of acquisition and integration costs associated with acquisitions; dispositions; fluctuations in our equity in earnings (losses) of unconsolidated affiliates; impairments of goodwill, intangible assets, long-lived assets or investments; and interest rate fluctuations. Accordingly, our operating results in any particular period may not be indicative of the results that can be expected for any other period.

We and our customers continue to operate in an uncertain business environment, with heightened regulatory and environmental requirements, stringent permitting processes and only gradual recovery in the economy from recessionary levels. Furthermore, significant declines in oil and natural gas prices since mid-2014 have cast uncertainty on the demand for our oil and gas infrastructure services, which may be exacerbated if we experience a sustained period of lower oil and natural gas prices. However, we expect that, as the current oversupply of global oil corrects and global demand for oil increases over time, oil prices could recover from current levels over the long term. We believe that long-term production of natural gas and oil from North American unconventional shale formations and the Canadian oil sands will continue, which we expect to create demand for our infrastructure services over time.

We are closely monitoring our customers and the effect that changes in economic and market conditions have or may have on them. Certain of our customers have reduced or delayed spending in recent years, which we attribute primarily to regulatory and permitting hurdles and negative economic and market conditions, and we

anticipate that these issues may continue to affect demand for some of our services in the near term. As mentioned previously, there have been significant decreases in oil prices and natural gas prices since mid-2014. We have experienced a decrease in demand for some of our services, primarily infrastructure services in Australia, Canada and the Gulf of Mexico, as a result of low oil prices. Further declines in prices or a sustained period of low prices could result in further reduction of our customers’ capital spending on mainline pipe and/or other midstream infrastructure, such as gathering systems and other related infrastructure, resulting in less demand for our services. We believe that most of our customers, many of whom are regulated utilities, remain financially stable in general and will be able to continue with their business plans in the long term. You should 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 — some controllable, some not — can impact our margins on a quarterly or annual basis.

Seasonal and geographical. As discussed previously, seasonal 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 when they are completed, may impact margins. The mix of business conducted in the areas we serve will also affect margins, as some of the areas we serve offer the opportunity for higher margins than others due to the geographic characteristics associated with the physical location where the work is being performed. Such characteristics include whether the project is performed in an urban versus a rural setting or in a mountainous area or in 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 or rainfall in the areas in which we operate may negatively impact our revenues and margins due to reduced productivity, as projects may be delayed or temporarily placed on hold until weather conditions improve. Conversely, in periods when weather remains dry and temperatures are accommodating, more work can be done, sometimes with less cost, which would have a favorable impact on margins. In some cases, severe weather, such as hurricanes and ice storms, can provide us with higher margin emergency restoration service work, which generally has a positive impact on margins.

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 in each of the industries we serve can cause an imbalance in supply and demand and, therefore, affect margins and mix of revenues by industry served.

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, as our mark-up on materials is generally lower than on our labor costs. In a given period, an increase in the percentage of work with higher materials procurement requirements may decrease our overall margins.

Larger versus smaller transmission projects. We may experience a decrease or fluctuations in margins when, as was the case in 2015, larger electric transmission projects across the industry experience significant delays. This has, and may again in the future, lead to an increasingly competitive smaller transmission market, as competitors more aggressively pursue higher volumes of work to absorb fixed costs. A greater mix of smaller transmission work also could negatively impacts margins due to the inefficiency of transitions between smaller projects versus the continuous production on larger projects. We believe that the delay in larger transmission projects is temporary, as a number of large projects are awaiting permitting and other approvals. In the event that we believe delays are temporary, we may choose to maintain a portion of our workforce and equipment in an underutilized capacity to ensure we were strategically positioned to deliver on larger, more complicated electric transmission projects when they move forward, as was the case in 2015.

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

Insurance. As discussed in Liquidity and Capital Resources — Self-Insurance, we are insured for employer’s liability, general liability, auto liability and workers’ compensation 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.

Performance risk. Margins may fluctuate because of the volume of work and the impacts of pricing and job productivity, which can be affected both favorably and negatively by weather, geography, customer decisions and crew productivity. For example, when comparing a service contract between a current quarter and the comparable prior year’s quarter, factors affecting the gross margins associated with the revenues generated by the contract may include pricing under the contract, the volume of work performed under the contract, the mix of the type of work specifically being performed and the productivity of the crews performing the work. 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, the impacts of inclement weather or the effects of environmental restrictions or regulatory delays. These types of factors are not practicable to quantify through accounting data, but each of these items 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 and is subject to fluctuation 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.

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 the implementation of an information technology solution.

Results of Operations

As previously discussed, we have acquired certain businesses, the results of which 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 income 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,
	2015					2014					2013
Revenues	$	7,572,436		100.0	%	$	7,747,229		100.0	%	$	6,411,577		100.0	%
Cost of services (including depreciation)		6,648,771		87.8			6,578,435		84.9			5,424,644		84.6

Gross profit		923,665		12.2			1,168,794		15.1			986,933		15.4
Selling, general and administrative expenses		592,863		7.8			705,477		9.1			485,069		7.6
Amortization of intangible assets		34,848		0.5			34,257		0.5			25,865		0.4
Asset impairment charges		58,451		0.8			—		—			—		—

Operating income		237,503		3.1			429,060		5.5			475,999		7.4
Interest expense		(8,024	)	(0.1	)		(4,765	)	—			(2,668	)	(0.1	)
Interest income		1,493		—			3,736		—			3,378		0.1
Equity in earnings (losses) of unconsolidated affiliates, including gain on sale of investment		(466	)	—			(332	)	—			112,744		1.8
Other income (expense), net		(1,831	)	—			(1,100	)	—			(1,133	)	—

Income from continuing operations before income taxes		228,675		3.0			426,599		5.5			588,320		9.2
Provision for income taxes		97,472		1.3			139,007		1.8			196,875		3.1

Net income from continuing operations		131,203		1.7			287,592		3.7			391,445		6.1
Net income from discontinued operations, net of taxes		190,621		2.5			27,490		0.4			29,864		0.5

Net income		321,824		4.2			315,082		4.1			421,309		6.6
Less: Net income attributable to non-controlling interests		10,917		0.1			18,368		0.3			19,388		0.3

Net income attributable to common stock	$	310,907		4.1	%	$	296,714		3.8	%	$	401,921		6.3	%

Amounts attributable to common stock:
Net income from continuing operations	$	120,286		1.6	%	$	269,224		3.4	%	$	372,057		5.8	%
Net income from discontinued operations		190,621		2.5			27,490		0.4			29,864		0.5

Net income attributable to common stock	$	310,907		4.1	%	$	296,714		3.8	%	$	401,921		6.3	%

2015 compared to 2014

Revenues. Revenues decreased $174.8 million, or 2.3%, to $7.57 billion for the year ended December 31, 2015. This decrease was primarily attributable to a decrease in electric power infrastructure services revenues of $365.4 million, or 6.9%, partially offset by an increase in oil and gas infrastructure services revenues of $190.6 million, or 7.8%. Revenues from electric power infrastructure services were adversely impacted primarily by reduced customer spending and delays in project timing due to regulatory and permitting issues associated with large electric transmission projects during the year ended December 31, 2015. In addition, revenues contributed by our international operations were negatively impacted by approximately $227 million due to less favorable foreign currency exchange rates as the U.S. dollar strengthened against the Canadian and Australian dollars. Partially offsetting these decreases for the year ended December 31, 2015 was the favorable impact of approximately $375 million in revenues generated by acquired companies, primarily in the Oil and Gas Infrastructure Services segment.

Gross profit. Gross profit decreased $245.1 million, or 21.0%, to $923.7 million for the year ended December 31, 2015. Gross profit as a percentage of revenues decreased to 12.2% for the year ended December 31, 2015 from 15.1% for the year ended December 31, 2014. These decreases were primarily due to the decrease in revenues from large electric transmission and mainline transmission projects, which typically yield higher margins, and an increase in revenues from services that typically yield lower margins. Gross profit was also negatively impacted by approximately $73 million in aggregate losses recorded during the year ended December 31, 2015 on three projects due to increased costs associated with performance and site related factors that adversely impacted production. The projects included a power plant project in Alaska expected to be complete in mid-2016, an electric transmission project in Canada substantially completed in the third quarter of 2015, and a directional drilling project in Canada that was completed during the fourth quarter of 2015.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased $112.6 million, or 16.0%, to $592.9 million for the year ended December 31, 2015. The decrease was primarily attributable to an aggregate $102.5 million charge to provision for long-term contract receivable recorded in the third and fourth quarters of 2014 associated with an electric power infrastructure services project completed in 2012 and an aggregate $38.8 million expense recorded in the year ended December 31, 2014 associated with an adverse arbitration decision regarding a contract dispute on a 2010 directional drilling project. Partially offsetting these decreases was $16.5 million in incremental general and administrative costs associated with acquired companies and $11.0 million in higher costs associated with ongoing technology, business development initiatives and facilities expenses. Selling, general and administrative expenses as a percentage of revenues decreased to 7.8% for the year ended December 31, 2015 from 9.1% for the year ended December 31, 2014, due primarily to the impact of the charge to provision for long-term contract receivable and arbitration expense described above.

Amortization of intangible assets. Amortization of intangible assets increased $0.6 million to $34.8 million for the year ended December 31, 2015. This increase was primarily due to increased amortization of intangibles associated with 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 $58.5 million for the year ended December 31, 2015 compared to none for the year ended December 31, 2014. During the fourth quarter of 2015, we recorded a $39.8 million goodwill impairment and a $12.1 million impairment related to customer relationships, trade names and non-compete agreement intangible assets. The extended low commodity price environment has significantly impacted certain reporting units within our Oil and Gas Infrastructure Services Division. Specifically, lower forecasted oil and gas services revenues for our Gulf of Mexico operations and certain operations in Australia resulted in impairments of goodwill and intangible assets. Additionally, we recorded a property and equipment impairment of $6.6 million related to certain international renewable energy services operations.

Interest expense. Interest expense increased $3.3 million to $8.0 million for the year ended December 31, 2015 as compared to the year ended December 31, 2014 due to increased borrowing activity.

Interest income. Interest income decreased $2.2 million to $1.5 million for the year ended December 31, 2015. The decrease was primarily due to lower average cash balances during the year ended December 31, 2015 as compared to the year ended December 31, 2014.

Equity in earnings (losses) of unconsolidated affiliates. Equity in earnings (losses) of unconsolidated affiliates were losses of $0.5 million and $0.3 million for the years ended December 31, 2015 and 2014.

Provision for income taxes. 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 provision for income taxes was $139.0 million for the year ended December 31, 2014, with an effective tax rate of 32.6%. The effective tax rate was higher in 2015 due to a lower proportion of income before taxes from international jurisdictions, which are generally taxed at lower statutory rates. Additionally, certain of the asset impairments recorded were not deductible for tax purposes. A change in the Alberta provincial statutory income tax, effective as of June 1, 2015, which required a remeasurement of certain cumulative deferred tax assets and liabilities, resulted in additional taxes of $5.0 million. These negative impacts were 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 in 2015 did not reflect a significant decrease in reserves for uncertain tax positions because the statute of limitations remains open for various tax years currently under audit. The effective tax rate for 2014 was impacted by an $8.1 million decrease in reserves for uncertain tax positions resulting from the expiration of various federal and state statute of limitations periods.

Other comprehensive income (loss). Other comprehensive income (loss), net of taxes was a loss of $171.4 million in the year ended December 31, 2015 compared to a loss of $86.1 million in the year ended December 31, 2014. These losses were primarily due to less favorable foreign currency exchange rates related to the strengthening of the U.S. dollar against the Canadian and Australian dollars.

2014 compared to 2013

Revenues. Revenues increased $1.34 billion, or 20.8%, to $7.75 billion for the year ended December 31, 2014. This increase was due in part to higher electric power infrastructure services revenues, which increased $760.7 million, or 16.7%, to $5.30 billion as a result of increased activity from electric power transmission, distribution and power generation projects in connection with increased capital spending by our customers and approximately $225 million in revenues generated by acquired companies. Also contributing to the increase were additional revenues from oil and gas infrastructure services, which increased $574.9 million, or 30.8%, to $2.44 billion, primarily due to approximately $500 million in revenues generated by acquired companies. Also favorably impacting oil and gas infrastructure services was increased capital spending by our customers.

Gross profit. Gross profit increased $181.9 million, or 18.4%, to $1.17 billion for the year ended December 31, 2014. This increase was primarily due to higher overall revenues earned during the year ended December 31, 2014 as compared to the year ended December 31, 2013. Gross profit as a percentage of revenues decreased to 15.1% for the year ended December 31, 2014 from 15.4% for the year ended December 31, 2013. This decrease in gross margin was primarily due to the negative impact of wet weather conditions, primarily in Canada and northern regions of the United States, as these areas experienced a late thaw from the winter season, as well as lower margins recognized on certain power generation projects ongoing during the year ended December 31, 2014 as compared to similar projects completed during the year ended December 31, 2013 and less favorable foreign currency exchange rates. These lower margins were partially offset by the contribution of mainline pipe revenues, which typically yield higher margins.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $220.4 million, or 45.4%, to $705.5 million for the year ended December 31, 2014. This increase was primarily attributable to an aggregate $102.5 million charge to provision for long-term contract receivable recorded in the third and fourth quarters of 2014 associated with an electric power infrastructure services project completed in 2012 and an aggregate $38.8 million expense associated with an adverse arbitration decision regarding a contract dispute on a 2010 directional drilling project, $68.2 million in incremental general and administrative costs associated with acquired companies, $11.6 million in higher professional fees and $7.6 million in higher ancillary administration costs. These increases were partially offset by $13.2 million in lower compensation and incentive costs associated with levels of profitability during the year ended December 31, 2014. Selling, general and administrative expenses as a percentage of revenues increased to 9.1% for the year ended December 31, 2014 from 7.6% for the year ended December 31, 2013, due primarily to the impact of the provision for long-term contract receivable and the arbitration expense discussed above. The impact of these items was partially offset by better absorption of general and administrative expenses due to the higher revenues described above.

Amortization of intangible assets. Amortization of intangible assets increased $8.4 million to $34.3 million for the year ended December 31, 2014. This increase was primarily due to increased amortization of intangibles associated with acquired companies.

Interest expense. Interest expense increased $2.1 million to $4.8 million for the year ended December 31, 2014 as compared to the year ended December 31, 2013 due to increased borrowing activity, commitment fees associated with an increase in the unused capacity of our credit facility and higher amortization of deferred financing costs following the amendment and restatement of our credit agreement in 2013.

Interest income. Interest income was $3.7 million and $3.4 million for the years ended December 31, 2014 and 2013. The increase was primarily due to a higher volume of cash in foreign banks during the year ended December 31, 2014, which generally had a higher rate of return than balances in domestic banks, partially offset by lower foreign currency exchange rates in the year ended December 31, 2014 as compared to the year ended December 31, 2013.

Equity in earnings (losses) of unconsolidated affiliates. Equity in earnings (losses) of unconsolidated affiliates was a loss of $0.3 million and income of $112.7 million for the years ended December 31, 2014 and 2013. During the fourth quarter of 2013, we sold all of our equity ownership interest in HEP for proceeds of approximately $220.9 million in cash which resulted in a pre-tax gain of approximately $112.7 million.

Provision for income taxes. The provision for income taxes was $139.0 million for the year ended December 31, 2014, with an effective tax rate of 32.6%. The provision for income taxes was $196.9 million for the year ended December 31, 2013, with an effective tax rate of 33.5%. The effective tax rates for 2014 and 2013 were impacted by the recording of net tax benefits in the amounts of $8.1 million in 2014 and $9.9 million in 2013 associated with decreases in reserves for uncertain tax positions resulting from the expiration of various federal and state statute of limitations periods. Excluding the tax benefits from decreases in reserves for uncertain tax positions, the effective tax rates would have been 34.5% and 35.2% for the years ended December 31, 2014 and 2013. The lower effective tax rate for the year ended December 31, 2014 was primarily due to a higher proportion of income before taxes earned from international jurisdictions, which are generally taxed at lower statutory rates.

Other comprehensive income (loss). Other comprehensive income (loss), net of taxes was a loss of $86.1 million in the year ended December 31, 2014 compared to a loss of $51.7 million in the year ended December 31, 2013. These losses were primarily due to less favorable foreign currency exchange rates related to the strengthening of the U.S. dollar against the Canadian and Australian dollars.

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,
	2015					2014					2013
Revenues:
Electric Power Infrastructure	$	4,937,289		65.2	%	$	5,302,671		68.4	%	$	4,541,962		70.8	%
Oil and Gas Infrastructure		2,635,147		34.8			2,444,558		31.6			1,869,615		29.2

Consolidated revenues from external customers	$	7,572,436		100.0	%	$	7,747,229		100.0	%	$	6,411,577		100.0	%

Operating income (loss):
Electric Power Infrastructure	$	362,328		7.3	%	$	462,985		8.7	%	$	523,355		11.5	%
Oil and Gas Infrastructure		142,929		5.4			162,797		6.7			138,543		7.4
Corporate and non-allocated costs		(267,754	)	N/A			(196,722	)	N/A			(185,899	)	N/A

Consolidated operating income	$	237,503		3.1	%	$	429,060		5.5	%	$	475,999		7.4	%

2015 compared to 2014

Electric Power Infrastructure Services Segment Results

Revenues for this segment decreased $365.4 million, or 6.9%, to $4.94 billion for the year ended December 31, 2015. Revenues from electric power infrastructure services were adversely impacted by reduced customer spending and delays in project timing due to regulatory and permitting issues associated with large electric transmission projects. The revenues contributed from our international operations were negatively impacted by approximately $132 million as a result of less favorable foreign currency exchange rates in the year ended December 31, 2015 as compared to the year ended December 31, 2014, primarily attributable to the strengthening of the U.S. dollar against the Canadian and Australian dollars. Also contributing to the decrease was $23.4 million in lower emergency restoration services revenues. Partially offsetting these decreases was the contribution of approximately $85 million in revenues generated by acquired companies and increased activity from smaller scale transmission and electric distribution projects due to increased spending by our customers.

Operating income decreased $100.7 million, or 21.7%, to $362.3 million for the year ended December 31, 2015. Operating income as a percentage of segment revenues decreased to 7.3% for the year ended December 31, 2015 from 8.7% for the year ended December 31, 2014. These decreases were primarily due to a decrease in revenues from large electric transmission projects mentioned above, which typically yield higher margins, and a corresponding increase in lower margin revenues from smaller scale transmission work. This change in revenue mix also resulted in increased inefficiencies associated with transitioning between smaller projects that are not experienced during continuous production on larger projects, as well as certain large transmission resources being underutilized during the year ended December 31, 2015. In addition, operating income and operating income as a percentage of segment revenues decreased in 2015 due to the negative impact of approximately $66 million in aggregate losses recorded during the year ended December 31, 2015 on two projects due to increased costs associated with performance and site related factors that adversely impacted production. These projects include a power plant project in Alaska expected to be complete in mid-2016 and an electric transmission project in Canada that was substantially completed during the third quarter of 2015. Also contributing to the decreases was the negative impact on production for various projects due to heavy snowfall and other unfavorable weather conditions in certain areas of Canada and the northern United States during the first three months of 2015 and a property and equipment impairment of $6.6 million related to certain international renewable energy services operations. Additionally, lower emergency restoration services revenues impacted margins since such services typically yield higher margins. Operating income and margins during 2014 were negatively impacted by the $102.5 million charge to provision for long-term contract receivable associated with an electric power infrastructure services project completed in 2012 described above.

Oil and Gas Infrastructure Services Segment Results

Revenues for this segment increased $190.6 million, or 7.8%, to $2.64 billion for the year ended December 31, 2015. Revenues for the year ended December 31, 2015 were favorably impacted by approximately $290 million in revenues generated by acquired companies. Increased revenues from distribution and other services also impacted revenues in 2015. These increases were partially offset by reduced demand for services due to lower oil prices and their impact on customer spending, fluctuations in large project timing and regulatory delays on certain other large mainline pipe projects that shifted work from the second half of 2015 into 2016. Revenues for the year ended December 31, 2015 also reflect the negative impact of changes in foreign currency exchange rates, which negatively impacted revenues contributed by our international operations by approximately $95 million as a result of the strengthening of the U.S. dollar against the Canadian and Australian dollars.

Operating income decreased $19.9 million, or 12.2%, to $142.9 million for the year ended December 31, 2015. Operating income as a percentage of segment revenues decreased to 5.4% for the year ended December 31, 2015 from 6.7% for the year ended December 31, 2014. The decreases were primarily due to a decrease in transmission revenues, which typically yield higher margins, and project losses of approximately $7 million on a directional drilling project in Canada that was completed in the fourth quarter of 2015. Also contributing to the decrease in operating income as a percentage of revenues was lower demand for services associated with certain operations as a result of lower oil prices, which negatively impacted this segment’s ability to cover fixed and overhead costs. These decreases were partially offset by the impact during the year ended December 31, 2014 of an aggregate $38.8 million expense associated with an adverse arbitration decision regarding a contract dispute on a 2010 directional drilling project as well as an increase in the estimated withdrawal liability associated with the Central States, Southeast and Southwest Areas Pension Plan (the Central States Plan) based on an increase in the estimated range of possible liability.

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, 2015 increased $71.0 million to $267.8 million as compared to the year ended December 31, 2014. This increase was primarily due to the $51.9 million previously described goodwill and intangible asset impairment charges recorded in the year ended December 31, 2015, $10.9 million in higher salaries and benefits associated with cost of living increases and increased personnel, $8.1 million in higher costs associated with ongoing technology and business development initiatives, and $3.6 million in higher consulting and professional fees. These increases were partially offset by a $6.8 million decrease in acquisition and integration costs due to the smaller size and reduced complexity of our acquisitions closed in 2015.

2014 compared to 2013

Electric Power Infrastructure Services Segment Results

Revenues for this segment increased $760.7 million, or 16.7%, to $5.30 billion for the year ended December 31, 2014. Revenues were positively impacted by increased activity from electric power transmission, distribution and power generation projects primarily as a result of increased capital spending by our customers and approximately $225 million in revenues generated by acquired companies. Partially offsetting these increases was the negative impact of fluctuations in foreign currency exchange rates in 2014 as compared to 2013, primarily attributable to the strengthening of the U.S. dollar against the Canadian dollar.

Operating income decreased $60.4 million, or 11.5%, to $463.0 million for the year ended December 31, 2014. Operating income as a percentage of segment revenues decreased to 8.7% for the year ended December 31, 2014 from 11.5% for the year ended December 31, 2013. These decreases were primarily due to the impact of the $102.5 million provision for long-term contract receivable described above, as well as the negative impact on production of wet weather conditions in the year ended December 31, 2014 as compared to the year ended

December 31, 2013, primarily in Canada and northern regions of the United States. Additionally, lower margins were recognized on certain power generation projects ongoing during the year ended December 31, 2014 as compared to projects completed during the year ended December 31, 2013. These decreases were partially offset by higher segment revenues described above, which improved this segment’s ability to cover fixed and overhead costs.

Oil and Gas Infrastructure Services Segment Results

Revenues for this segment increased $574.9 million, or 30.8%, to $2.44 billion for the year ended December 31, 2014. Revenues for the year ended December 31, 2014 were favorably impacted by approximately $500 million in revenues generated by acquired companies in the United States, Canada and Australia, the majority of which were related to transmission projects. Additionally, revenues were favorably impacted by increased capital spending by our customers, primarily related to distribution projects. Partially offsetting these increases was the negative impact of fluctuations in foreign currency exchange rates in 2014 as compared to 2013, primarily attributable to the strengthening of the U.S. dollar against the Canadian and Australian dollars.

Operating income increased $24.3 million, or 17.5%, to $162.8 million for the year ended December 31, 2014. This increase was primarily due to the increase in segment revenues described above, including contributions from mainline pipe projects in the United States and Australia, which typically yield higher margins, and the favorable settlement of certain contract change orders. Operating income as a percentage of segment revenues decreased to 6.7% for the year ended December 31, 2014 from 7.4% for the year ended December 31, 2013. This decrease was primarily due to the aggregate $38.8 million arbitration expense described above, as well as to the impact of an increase in the estimated withdrawal liability associated with the the Central States Plan based on an increase in the estimated range of possible liability.

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, 2014 increased $10.8 million to $196.7 million as compared to the year ended December 31, 2013. This increase was due to $8.4 million in higher amortization expense primarily due to the amortization of newly acquired intangible assets from 2014 and 2013 acquisitions, $8.0 million in higher consulting and other professional fees, $6.4 million in higher acquisition and integration costs and $2.1 million in higher ongoing technology and business development initiatives. These increases were partially offset by $15.4 million in lower compensation and incentive costs associated with current levels of profitability and due to the impact of approximately $4.3 million of non-cash stock-based compensation expense recognized in 2013 and related to the retirement of the former Executive Chairman of our board of directors.

Liquidity and Capital Resources

Cash Requirements

Our cash and cash equivalents totaled $128.8 million and $190.5 million as of December 31, 2015 and 2014. As of December 31, 2015 and 2014, cash and cash equivalents held in domestic bank accounts were approximately $16.1 million and $127.2 million, and cash and cash equivalents held in foreign bank accounts were approximately $112.7 million and $63.3 million. As of December 31, 2015 and 2014, cash and cash equivalents held by our investments in joint ventures, which are either consolidated or proportionately consolidated, were approximately $24.9 million and $19.1 million, of which $11.9 million and $19.1 million related to domestic joint ventures. Cash and cash equivalents held by the joint ventures are available to support the operations of the related joint ventures, and we do not have access to that cash for our other operations. Under the terms of the partnership agreements, we generally have no right to the joint ventures’ cash other than participating in distributions and in the event of dissolution.

We were in compliance with the covenants under our credit agreement at December 31, 2015. We anticipate that our cash and cash equivalents on hand, existing borrowing capacity under our 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, as well as facilitate our ability to grow in the foreseeable future.

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. Capital expenditures related to continuing operations are expected to total $200 million to $220 million for 2016.

We also evaluate opportunities for strategic acquisitions from time to time that may require cash, as well as opportunities to make investments in customer-sponsored projects 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 in the form of 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 investment policies to be conservative in that we maintain a diverse portfolio of what we believe to be high-quality cash 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 investments or our ability to rely upon our credit facility for funds. To date, we have experienced no loss of or lack of access to our cash or cash equivalents or funds under our credit facility; however, we can provide no assurances that access to our invested cash and cash equivalents or availability under our credit facility will not be impacted in the future by adverse conditions in the financial markets.

Through December 31, 2015, we have not provided U.S. income taxes on approximately $269.8 million of unremitted foreign earnings. If we were to repatriate cash that is indefinitely reinvested outside the United States, we could be subject to additional U.S. income and foreign withholding taxes. Because of the number and variability of assumptions required, it is not practicable to determine the amount of any additional U.S. tax liability that may result if we decide to no longer indefinitely reinvest foreign earnings outside the United States. If our intentions or U.S. tax laws change in the future, there may be a significant negative impact on the provision for income taxes and cash flows as a result of recording an incremental tax liability in the period such change occurs.

Sources and Uses of Cash

As of December 31, 2015, we had cash and cash equivalents of $128.8 million and working capital of $1.07 billion. We also had $307.0 million of outstanding letters of credit and bank guarantees, $220.0 million of which was denominated in U.S. dollars and $87.0 million of which was denominated in Australian or Canadian dollars. We also had $466.9 million of outstanding revolving loans under our credit facility, $400.0 million of which was denominated in U.S. dollars and $66.9 million of which was denominated in Canadian dollars. As of December 31, 2015, our $1.81 billion senior secured revolving credit facility, which matures on December 18, 2020, had $1.04 billion available for revolving loans or issuing new letters of credit or bank guarantees.

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 both changes in 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 the regions in which we operate. 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 which can be impacted by project delays or accelerations and other economic factors that may affect customer spending.

Operating activities of continuing operations provided net cash of $618.2 million during 2015 as compared to $247.7 million during 2014 and $370.6 million during 2013. The increase in cash flow from operating activities of continuing operations for the year ended December 31, 2015 compared to the year ended December 31, 2014 was partially due to decreased working capital requirements associated with a decrease in the number of certain large electric transmission jobs ramping up during 2015. Also impacting cash flow from operating activities of continuing operations for the year ended December 31, 2015 was the receipt of $86.8 million related to favorable billing terms for certain projects with production beginning in 2016, and the receipt of a $65 million cash payment in settlement of the Sunrise Powerlink project receivable in the first quarter of 2015. Cash flow from operating activities of continuing operations for the year ended December 31, 2014 was also negatively impacted by weather related delays in part of North America, the timing of project close-outs that affected the achievement of certain billing milestones, and a $28.3 million payment associated with an arbitration decision. In comparison, the cash flow from operating activities of continuing operations during the year ended December 31, 2013 was positively impacted by the collection of receivables during the first quarter of 2013 that were attributable to significantly higher levels of emergency restoration services provided in the fourth quarter of 2012 which did not recur in the fourth quarter of 2013.

Days sales outstanding (DSO) as of December 31, 2015 was 75 days, as compared to 84 days as of December 31, 2014. This decrease was primarily due to inclusion of the previously mentioned $86.8 million prepayment recorded to billings in excess of costs due to favorable billing terms for certain projects with production beginning in 2016 and increased accounts receivable collections in the fourth quarter of 2015. DSO as of December 31, 2014 was also negatively impacted by an additional seven days due to the reclassification of the remaining $65 million receivable for the Sunrise Powerlink project from long-term to current assets and the impact of an acquisition closed in the fourth quarter of 2014, as both events did not have any material corresponding revenues during 2014. 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 2015, we used net cash in investing activities of continuing operations of $307.1 million as compared to $488.6 million and $278.4 million used in investing activities of continuing operations in 2014 and 2013. Investing activities of continuing operations in 2015 included $210.0 million used for capital expenditures and $112.9 million used in connection with acquisitions, partially offset by $26.2 million of proceeds from the sale of equipment. Investing activities of continuing operations in 2014 included $247.2 million used for capital expenditures and $262.2 million used in connection with acquisitions, partially offset by $14.4 million of proceeds from the sale of equipment. Investing activities of continuing operations in 2013 included $221.9 million used for capital expenditures, $283.8 million used in connection with acquisitions and $10.0 million used for other investments (primarily comprised of the capital lease of an internally constructed electric power transmission asset). These amounts were partially offset by investments in and return on equity from unconsolidated affiliates of $186.2 million, which includes gross proceeds from the sale of all of our equity ownership in HEP of approximately $220.9 million, the release of $36.5 million of restricted cash balances associated a newly acquired company, and $14.8 million of proceeds from the sale of equipment.

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. 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 2015, net cash used in financing activities of continuing operations was $1.22 billion as compared to net cash used by financing activities of continuing operations of $58.3 million and $16.7 million in 2014 and 2013. Financing activities of continuing operations during 2015 included $1.61 billion for common stock repurchases under our stock repurchase programs, $21.2 million of cash payments to non-controlling interests as distributions of joint venture profits, partially offset by $413.6 million of net proceeds associated with borrowings under our credit facility. Financing activities of continuing operations in 2014 included $93.5 million of common stock repurchases under a stock repurchase program approved by Quanta’s board of directors during the fourth quarter of 2013 (the 2013 Repurchase Program), $30.4 million of debt repayments primarily related to debt of acquired companies that was repaid shortly after the respective acquisition dates and $14.4 million of cash payments to non-controlling interests as distributions of joint venture profits, partially offset by $71.8 million of net proceeds from borrowings under our credit facility. Financing activities of continuing operations in 2013 included $17.6 million of cash payments to non-controlling interests as distributions of joint venture profits, $3.2 million of loan costs related to the amendment and restatement of our credit agreement on October 30, 2013 and the positive impact of $3.7 million related to the tax impact of stock-based awards.

On August 4, 2015, we completed the sale of our fiber optic licensing operations for a purchase price of approximately $1 billion in cash, resulting in after-tax net proceeds of approximately $848 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 approximately $134 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 the consolidated statement of cash flows for the year ended December 31, 2015. An additional $13 million is anticipated to be paid in 2016 for state income taxes on the gain.

Stock Repurchases

The 2013 Repurchase Program authorized us to purchase, from time to time through December 31, 2016, up to $500.0 million of our outstanding common stock. No shares were repurchased under the 2013 Repurchase Program during the year ended December 31, 2013. During the year ended December 31, 2014, we repurchased a total of 3.0 million shares valued at $93.5 million pursuant to the 2013 Repurchase Program. During the third quarter of 2015, we completed the 2013 Repurchase Program.

Also during the third quarter of 2015, our board of directors approved a new stock repurchase program authorizing 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). Repurchases under the 2015 Repurchase Program can be made in open market or privately negotiated transactions, including pursuant to an accelerated share repurchase arrangement, an issuer repurchase plan or otherwise, at our discretion, based on market and business conditions, applicable contractual and legal requirements and other factors. The 2015 Repurchase Program does not obligate us to acquire any specific amount of common stock and may be modified or terminated by our board of directors at any time at its sole discretion and without notice.

On August 7, 2015, we entered into an accelerated share repurchase arrangement (the ASR) to repurchase $750.0 million of our common stock under the 2015 Repurchase Program. Under the terms of the ASR, we paid $750.0 million to JPMorgan Chase Bank, National Association, London Branch (JPMorgan) and initially received 25.7 million shares of our common stock. The fair market value of these 25.7 million shares at the time of delivery was approximately $600.0 million, and the repurchased shares and the related cost to acquire them were accounted for as an adjustment to the balance of treasury stock during the quarter ended September 30, 2015, reducing the weighted-average number of basic and diluted common shares used to calculate our earnings per share for the year ended December 31, 2015. The $150.0 million remaining under the ASR was recorded as an adjustment to additional paid-in capital (APIC) during the quarter ended September 30, 2015 and will be reclassified from APIC to treasury stock upon final settlement of the ASR.

The final number of shares that we will repurchase under the ASR will be based on a volume-weighted average share price of our common stock during the term of the ASR, minus a discount and, subject to other adjustments pursuant to the terms and conditions of the ASR. Final settlement of the ASR is scheduled to occur in the second quarter of 2016, but the ASR may be terminated early or extended in certain circumstances. At settlement, we may be entitled to receive additional shares of our common stock from JPMorgan or, under certain circumstances, we may be required to deliver shares or make a cash payment (at our option) to JPMorgan. In addition to the initial share delivery under the ASR, during the third and fourth quarters of 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 year ended December 31, 2015, we repurchased a total of 59.3 million shares valued at $1.46 billion pursuant to both the 2013 Repurchase Program and the 2015 Repurchase Program. The shares and the related cost to acquire them have been accounted for as an adjustment to the balance of treasury stock. As of December 31, 2015, approximately $200.1 million remained available under the 2015 Repurchase Program; however, $150.0 million of that amount had been paid under the ASR for additional shares expected to be delivered upon final settlement of the ASR, as discussed above.

Debt Instruments

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 maturing on December 18, 2020. The entire amount available under the 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 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 facility may be used for swing line loans in U.S. dollars, up to $50.0 million of the facility may be used for swing line loans in Canadian dollars and up to $30.0 million of the 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, 2015, we had approximately $307.0 million of outstanding letters of credit and bank guarantees, $220.0 million of which was denominated in U.S. dollars and $87.0 million of which was denominated in Australian and Canadian dollars. We also had $466.9 million of outstanding revolving loans under the credit facility, $400.0 million of which was denominated in U.S. dollars and $66.9 million of which was denominated in Canadian dollars. The remaining $1.04 billion was available for revolving loans or issuing new letters of credit or bank guarantees.

Under our current credit agreement, amounts borrowed in U.S. dollars bear 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 bear interest at a rate equal to the Eurocurrency Rate plus 1.125% to 2.125%, as determined based on our Consolidated Leverage Ratio. Standby letters of credit issued under the credit agreement are 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 are 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 a maximum Consolidated Leverage Ratio and a minimum Consolidated Interest Coverage Ratio (as defined 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. As of December 31, 2015, we were in compliance with all of the covenants in the credit agreement.

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 recent amendment and restatement of our credit agreement and after April 1, 2014, amounts borrowed bore interest at the same rates as above, and we were subject to the same commitment fees as above. Prior to April 1, 2014, amounts borrowed in U.S. dollars bore interest, at our option, at a rate equal to either (i) the Eurocurrency Rate plus 1.25%, or (ii) the Base Rate plus 0.25%, and amounts borrowed as revolving loans in any currency other than U.S. dollars bore interest at a rate equal to the Eurocurrency Rate plus 1.25%. Prior to April 1, 2014, standby letters of credit issued under the credit agreement were also subject to a letter of credit fee of 1.25%, Performance Letters of Credit issued in support of certain contractual obligations were subject to a letter of credit fee of 0.75%, and we were also subject to a commitment fee of 0.20% on any unused availability under the credit agreement.

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 liabilities associated with non-cancelable operating leases, letter of credit obligations, commitments to purchase equipment, surety guarantees related to performance bonds, certain multiemployer pension plan liabilities and obligations relating to our investments and joint venture arrangements. Certain joint

venture structures involve risks not directly reflected in our balance sheets. For certain joint ventures, we have guaranteed all of the obligations of the joint venture under a contract 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 venturer 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. Other than as discussed in this report, we have not engaged in any material off-balance sheet financing arrangements through special purpose entities, and we have no material guarantees of the work or obligations of third parties.

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 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, 2015, the maximum guaranteed residual value was approximately $487.1 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 are disbursing on our behalf, such as to beneficiaries under our self-funded insurance programs. In addition, from time to time, certain customers require us to post letters of credit to ensure payment to our subcontractors and vendors under those contracts and to 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, 2015, we had $307.0 million in outstanding letters of credit and bank guarantees to secure our casualty insurance program and various contractual commitments. These are irrevocable stand-by letters of credit with maturities generally expiring at various times throughout 2016. 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 under a contract or to pay subcontractors and vendors, 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. Posting letters of credit in favor of the sureties or our customers would reduce the borrowing availability under our 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, 2015, the total amount of outstanding performance bonds was estimated to be approximately $2.6 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 $906 million as of December 31, 2015.

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

Contractual Obligations

As of December 31, 2015, our future contractual obligations were as follows (in thousands):


	Total		2016		2017		2018		2019		2020		Thereafter
Long-term debt (1)	$	472,251	$	592	$	2,251	$	2,558	$	—	$	466,850	$	—
Short-term debt (1)		4,829		4,829		—		—		—		—		—
Operating lease obligations		234,703		78,971		56,488		42,608		25,065		14,290		17,281
Capital lease obligations (1)		5,351		1,646		1,618		1,378		709		—		—
Equipment purchase commitments		2,298		2,298		—		—		—		—		—
Capital commitment related to investments in unconsolidated affiliates (2)		64,078		10,173		31,010		—		22,895		—		—

Total	$	783,510	$	98,509	$	91,367	$	46,544	$	48,669	$	481,140	$	17,281

(1)	Amounts are recorded in our December 31, 2015 consolidated balance sheet.

(2)	A return of capital from unconsolidated affiliates of approximately $40.9 million is anticipated in August 2017 and is not included in these amounts.

Capital 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, 2015, production orders for approximately $2.3 million had been issued with delivery dates scheduled to occur throughout 2016. 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.

Unrecognized Tax Benefits

We are currently under examination by the Internal Revenue Service for tax years 2010, 2011 and 2012. Additionally, certain of our subsidiaries are 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 $27.5 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. While certain additional Quanta subsidiaries continued participation in the Central States Plan into 2012, we believe that such subsidiaries withdrew from the Central States Plan in 2012, thereby effecting a complete withdrawal as of December 30, 2012 for all Quanta entities.

In connection with the partial withdrawal in 2011, we recorded a withdrawal liability of approximately $32.6 million in the fourth quarter of 2011 based on estimates received from the Central States Plan. 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 of partial withdrawal liability in the amount of $39.6 million. 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 ruling in favor of the Central States Plan. Based on the outcome of the appeal, in January 2016, the Central States Plan issued a revised assessment of our withdrawal liability based on a 2011 partial withdrawal. The revised assessment claims $32.9 million of withdrawal liability against us and recognizes payments of approximately $11.0 million made by us against that amount as of the date of the revised assessment. We are still in the process of evaluating the revised assessment and the effect on its ultimate liability stake.

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 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.

The ultimate liability associated with the complete withdrawal of Quanta’s subsidiaries from the Central States Plan will depend on various factors, including interpretations of the terms of the collective bargaining agreements under which the subsidiaries participated and whether exemptions from withdrawal liability applicable to construction industry employers will be available. In March 2014, the Central States Plan provided revised estimates indicating that the total withdrawal liability based on certain withdrawal scenarios from 2011 through 2014 could range between $40.1 million and $55.4 million, and, as discussed above, in January 2016, the Central States Plan provided a revised assessment of our partial withdrawal liability. Although we continue to dispute the total liability owed to the Central States Plan, we continue to make monthly payments while the parties determine the final withdrawal liability. The amount owed upon resolution of this matter will be reduced by the payments made.

Based on the previous estimates of liability associated with a complete withdrawal from the Central States Plan, and allowing for the exclusion of amounts we believe to have been improperly included in such estimate, we recorded an adjustment to cost of services during the three months ended March 31, 2014 to increase the recognized withdrawal liability to an amount within the range communicated to us by the Central States Plan. We believe that the range of reasonable possible loss associated with a complete withdrawal from the Central States Plan is up to $55.4 million and is in the process of evaluating the effect of the revised assessment described above on this estimated range. Given the unknown nature of some of the factors mentioned above, the final

withdrawal liability cannot yet be determined with certainty. Accordingly, it is reasonably possible that the amount owed upon final resolution of these matters could be materially higher than the expense we have recognized through December 31, 2015.

Central States Plan Grievance Matter. In March 2014, the Teamsters Downstate Illinois Construction Industry Negotiating Committee and Association of General Contractors of Illinois Joint Grievance Committee concluded that one of our subsidiaries should have hired two Teamsters employees under a specific collective bargaining agreement to perform certain jobs. This grievance matter was subsequently resolved with the Teamsters, effectively resulting in an award of wages and benefits (including pension contributions) to the two Teamsters employees under an alternate collective bargaining agreement unrelated to the Central States Plan.

2013 Central States Plan Withdrawal Liability. On October 9, 2013, we acquired a company that experienced a complete withdrawal from the Central States Plan prior to the date of acquisition. The Central States Plan issued a Notice and Demand dated March 13, 2013 to the acquired company for a withdrawal liability in the total amount of $6.9 million, payable in installments. We took the position that the amount of withdrawal liability payable to the Central States Plan as a result of its complete withdrawal was $4.8 million, of which approximately $2.1 million remained outstanding as of December 31, 2015. In January 2016, the Central States Plan issued a revised assessment of the acquired company’s withdrawal liability. The revised assessment claims $4.8 million of withdrawal liability against the company and recognizes payments of approximately $2.7 million made against that amount as of the date of the revised assessment. Although we have challenged the amount of the asserted withdrawal liability by the Central States Plan, we will continue to make payments in accordance with the terms of the Notice and Demand while the dispute is ongoing. The amount of withdrawal liability payable to the Central States Plan in connection with this matter will ultimately depend on various factors, including the outcome of the PLCA litigation described above.

Approximately $2.1 million of the purchase price for the acquired company was deposited into an escrow account on October 9, 2013 to fund any withdrawal obligation in excess of the $4.8 million initially demanded. Accordingly, the acquired company’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 Fees and Commitment Fees

Also excluded from the Contractual Obligations table is interest associated with letters of credit fees and commitment fees under our credit facility because the outstanding letters of credit, availability and applicable interest rates and fees are variable. For additional information regarding the interest rates associated with borrowings under our credit facility, see Liquidity and Capital Resources — Debt Instruments — Credit Facility above.

Joint Venture Capital Commitments

We have also excluded from the Contractual Obligations table additional capital commitments associated with investments in unconsolidated affiliates related to planned midstream infrastructure projects of approximately $6.1 million because we are unable to determine the exact timing of these capital commitments but anticipate them to be paid by June 1, 2017. As specific amounts of capital commitments and their timing are determined, we will reflect such amounts in the Contractual Obligations table.

Self-Insurance

We are insured for employer’s liability, general liability, auto liability and workers’ compensation claims. Under these programs, the deductibles for general liability and auto liability are $10.0 million per occurrence, the deductible for workers’ compensation is $5.0 million per occurrence, and the deductible for employer’s liability is $1.0 million per occurrence. For the 2012-2013 policy year, the deductibles for general liability, auto liability and workers’ compensation were $5.0 million per occurrence and the deductible for employer’s liability was $1.0

million per occurrence. We are generally self-insured for all claims that do not exceed the amount of the applicable deductible. In connection with our casualty insurance programs, we are required to issue letters of credit to secure our self-insured 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 $375,000 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, 2015 and 2014, the gross amount accrued for insurance claims totaled $209.0 million and $170.2 million, with $153.5 million and $130.8 million considered to be long-term and included in other non-current liabilities. Related insurance recoveries/receivables as of December 31, 2015 and 2014 were $8.6 million and $9.1 million, of which $0.6 million and $0.8 million were included in prepaid expenses and other current assets and $8.0 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 the additional benefits obtained. 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.

Concentrations of Credit Risk

We are subject to concentrations of credit risk related primarily to our cash and cash equivalents and our accounts receivable, including amounts related to unbilled accounts receivable and costs and estimated earnings in excess of billings on uncompleted contracts. Substantially all of our cash investments 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 this cash in a diversified portfolio of what we believe to be high quality investments, which primarily include interest-bearing demand deposits, 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 investments 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 and Australia. Consequently, we are subject to potential credit risk related to changes in business and economic factors throughout the United States, Canada and Australia, 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, 2015, one customer accounted for approximately 12% of our consolidated net position. The services provided to this customer related primarily to our Electric Power Infrastructure Services segment. No customers represented 10% or more of our revenues for the years ended December 31, 2015, 2014 and 2013, and no other customers represented 10% or more of our consolidated net position as of December 31, 2015 or 2014.

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 liability 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. These 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, 2015, 2014 and 2013, inflation did not have a significant effect on our results.

New Accounting Pronouncements

Adoption of New Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (FASB) issued an update that changes the requirement for reporting discontinued operations. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the entity or group of components of an entity meets the criteria to be classified as held for sale or when it is disposed of by sale or other than by sale. The update also requires additional disclosures about discontinued operations, a disposal of an individually significant component of an entity that does not qualify for discontinued operations presentation in the financial statements, and an entity’s significant continuing involvement with a discontinued operation. We adopted this guidance effective January 1, 2015 and have incorporated the new requirements into our presentation of the disposition of our fiber optic licensing operations as discontinued operations.

In November 2015, the FASB issued an update that requires deferred tax assets and liabilities, as well as related valuation allowances, to be classified as non-current in a classified balance sheet. For public business entities, the update is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early application is permitted as of the beginning of an interim or annual reporting period. We adopted this guidance during the quarter ended December 31, 2015, and the guidance has been applied retrospectively to all periods presented. As a result of adopting this guidance, we recorded a reduction to prepaid expenses and other current assets of $49.2 million, a reduction to other assets, net of $0.2 million, a reduction to accounts payable and accrued expenses of $31.0 million and a reduction to deferred tax liabilities of $18.4 million as of December 31, 2014. Additionally, there was a $9.0 million reduction to current assets of discontinued operations and a corresponding reduction to non-current liabilities of discontinued operations as of December 31, 2014. There was no impact on results of operations or cash flows as a result of the adoption of this guidance.

Accounting Standards Not Yet Adopted

In May 2014, the FASB issued an update that supersedes most current revenue recognition guidance as well as some cost recognition guidance. The update requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be

entitled in exchange for those goods or services. This update also requires new qualitative and quantitative disclosures about the nature, amount, timing and uncertainty of revenues and cash flows arising from customer contracts, including significant judgments and changes in judgments, information about contract balances and performance obligations, and assets recognized from costs incurred to obtain or fulfill a contract. On July 9, 2015, the FASB affirmed its proposal to defer the effective date until fiscal years beginning on or after December 15, 2017. The guidance can be applied on a full retrospective or modified retrospective basis whereby the entity records a cumulative effect of initially applying this update at the date of initial application. We are currently evaluating the potential impact of this authoritative guidance on our consolidated financial statements and are planning to adopt this guidance effective January 1, 2018.

In August 2014, the FASB issued guidance to address the diversity in practice in determining when there is substantial doubt about an entity’s ability to continue as a going concern and when and how an entity must disclose certain relevant conditions and events. This update requires an entity to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern for a period of one year after the date that the financial statements are issued (or available to be issued). If such conditions or events exist, an entity should disclose that there is substantial doubt about the entity’s ability to continue as a going concern for a period of one year after the date that the financial statements are issued (or available to be issued), along with the principal conditions or events that raise substantial doubt, management’s evaluation of the significance of those conditions or events in relation to the entity’s ability to meet its obligations and management’s plans that are intended to mitigate those conditions or events. The guidance is effective for annual and interim periods ending after December 15, 2016. This guidance will impact the disclosure and presentation of any substantial doubt about our ability to continue as a going concern, if such substantial doubt were to exist. We will adopt this guidance effective January 1, 2017.

In February 2015, the FASB issued an update which amends existing consolidation guidance, including amending the guidance related to determining whether an entity is a variable interest entity. The update is effective for interim and annual periods beginning after December 15, 2015, although early adoption is permitted. The guidance may be applied using a modified retrospective approach whereby the entity records a cumulative effect of adoption at the beginning of the fiscal year of initial application. A reporting entity may also apply the amendments on a full retrospective basis. The adoption of the update is not expected to have a significant impact on our consolidated financial statements or related disclosures. We will adopt this guidance effective January 1, 2016.

In April 2015, the FASB issued an update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with the presentation of debt discounts and premiums. The standard is effective for interim and annual reporting periods beginning after December 15, 2015, although early adoption is permitted. The update is required to be adopted retroactively for all periods presented. In August 2015, the FASB issued another update that states that the Securities Exchange Commission (SEC) staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The adoption of the update is not expected to have a significant impact on our consolidated financial statements or related disclosures. We will adopt this guidance effective January 1, 2016.

In April 2015, the FASB issued an update that provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. The standard is effective for interim and annual reporting periods beginning after December 15, 2015. An entity can elect to adopt the amendments either prospectively to all arrangements entered into or materially modified after the effective date or retrospectively. The adoption of the update is not expected to have a significant impact on our consolidated financial statements or related disclosures. We will adopt this guidance effective January 1, 2016.

In July 2015, the FASB issued an update that requires inventory to be measured at the lower of either cost or net realizable value. When evidence exists that the net realizable value of inventory is lower than its cost, the difference will be recognized as a loss in earnings in the period in which it occurs. The update is required to be adopted prospectively and is effective for interim and annual reporting periods beginning after December 15, 2016, although early adoption is permitted. We are currently evaluating the potential impact of this authoritative guidance on our consolidated financial statements and will adopt this guidance by January 1, 2017.

In September 2015, the FASB issued an update that requires an acquiring company to recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which such adjustments are determined. An acquiring company must record any effect on earnings from changes in depreciation or amortization or other income effects, calculated as if the accounting had been completed at the acquisition date. The acquiring company must also present separately on the face of the income statement or disclose in the notes the amount recorded in current-period earnings that would have been recorded in previous reporting periods if the adjustment had been recognized as of the acquisition date. The standard is effective for interim and annual reporting periods beginning after December 15, 2015. The update is required to be adopted prospectively to adjustments that occur after the effective date with earlier application permitted for financial statements that have not yet been issued. The adoption of the update is not expected to have a significant impact on our consolidated financial statements or related disclosures. We will adopt this guidance effective January 1, 2016.

In January 2016, the FASB issued an update that addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. The new standard is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for financial statements of fiscal years or interim periods that have not been previously issued. We are evaluating the impact of the new standard on our consolidated financial statements and will adopt the new standard by January 1, 2018.

In February 2016, the FASB issued an update that requires companies that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those assets. The new standard is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted for financial statements of fiscal years or interim periods that have not been previously issued. We are evaluating the impact of the new standard on our consolidated financial statements and will adopt the new standard by January 1, 2019.

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

Through our Electric Power Infrastructure Services and Oil and Gas Infrastructure Services segments, we design, install and maintain networks for customers in the electric power and oil and gas industries. These services may be provided 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. Under these contracts, we recognize revenue as units are completed based on pricing established between us and the customer for each unit of delivery, 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. These contracts provide for a fixed amount of revenues for the entire project. 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 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 total contract value and the total estimated costs to complete those contracts and therefore, our profit recognition. 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 corresponding 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. If actual results significantly differ from our estimates used for revenue recognition and claim assessments, our financial condition and results of operations could be materially impacted. Our operating results for the years ended December 31, 2015 and 2014 were impacted by less than 5% as a result of changes in contract estimates related to projects that were in progress at December 31, 2014 and 2013.

The current asset “Costs and estimated earnings in excess of billings on uncompleted contracts” represents revenues recognized in excess of amounts billed for fixed price contracts. The current liability “Billings in excess of costs and estimated earnings on uncompleted contracts” represents billings in excess of revenues recognized for fixed price contracts.

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 a cost of contract performance in the period incurred if it is not probable that the costs will be recovered or will recognize revenue if it is probable that the contract price will be adjusted and can be reliably estimated.

As of December 31, 2015 and 2014, we had approximately $137.2 million and $106.8 million of change orders and/or claims that had been included as contract price adjustments on certain contracts which were in the process of being negotiated 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.

Self-Insurance.

As discussed in Liquidity and Capital Resources — Self-Insurance, we are insured for employer’s liability, general liability, auto liability, group health and workers’ compensation claims.

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 Division Infrastructure Services 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, and we have determined that our individual operating units represent our reporting units for the purpose of assessing goodwill impairments.

We have the option to first assess qualitative factors to determine whether it is necessary to perform the two-step 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. Otherwise, no further testing 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 step one of the 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 the reporting units.

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

We 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, as in management’s opinion, this method currently results in the most accurate calculation of a reporting unit’s fair value. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, discount rates, weighted average costs of capital and future market conditions, among others. 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, 2015, 2014 and 2013:


	2015	2014	2013
Years of cash flows before terminal value	5	5	5
Discount rates	12% to 16%	12% to 14%	12% to 14%
EBITDA multiples	5.0 to 6.5	5.0 to 6.0	5.0 to 8.0
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 step one impairment test may indicate an implied fair value that is substantially similar to the reporting unit’s carrying value. 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 2015, a two-step 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 implied fair value of each of our reporting units, other than recently acquired reporting units and two reporting units in our Oil and Gas Infrastructure Services Division, was substantially in excess of its carrying value. Following the analysis, management concluded that an impairment was indicated at two reporting units in our Oil and Gas Infrastructure Services Division. Accordingly, during the fourth quarter of 2015, we recorded a $39.8 million non-cash charge for the impairment of goodwill, which primarily resulted from lower forecasted oil and gas services revenues for our Gulf of Mexico operations and certain operations in Australia, due to the extended low commodity price environment.

As discussed generally above, when evaluating the 2015 step one impairment test results, management considered many factors in determining whether or not an impairment of goodwill for any reporting unit was reasonably likely to occur in future periods, including future market conditions and the economic environment in which our reporting units were operating. Additionally, management considered the sensitivity of its fair value estimates to changes in certain valuation assumptions and, after giving consideration to at least a 10% decrease in the fair value of each of our reporting units, the results of the assessment at December 31, 2015 did not change. However, circumstances such as market declines, unfavorable economic conditions, the loss of a major customer or other factors could increase the risk of impairment of goodwill in future periods.

If an operating unit experiences prolonged periods of declining revenues, operating margins or both, it may be at risk of failing step one of the goodwill impairment test. Certain operating units have experienced declines over the short-term due to challenging macroeconomic conditions in certain geographic areas, the decline in oil prices which has impacted customer spending, and delays due to regulatory and permitting issues. We will continue to monitor these conditions and others to determine if it is necessary to perform step two of the fair-value based impairment test for one or more operating units.

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 2015 assessment, projected annual growth rates by reporting unit varied with ranges from (28)% to 54%.

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 value 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 any amount of 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. Any goodwill or other intangible impairment would be included in the consolidated statements of operations.

Based on the first step of the goodwill impairment analysis, we compared the sum of fair values of our reporting units to our market capitalization at December 31, 2015 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, 2015 was approximately $3.10 billion, and our total stockholders’ equity was approximately $3.09 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 value 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.

We and our customers continue to operate in an uncertain business environment, with increasing regulatory and environmental requirements, stringent permitting processes and only gradual recovery in the economy from recessionary levels. We are closely monitoring our customers and the effect that changes in economic and market conditions have had or may have on them. Certain of our customers have reduced spending in recent years, which we attribute to the negative economic and market conditions, and we anticipate that these negative conditions may continue to affect demand for some of our services in the near-term. We continue to evaluate the impact of the economic environment on our reporting units and the valuation of recorded goodwill. Although we are not aware of circumstances that would lead to a goodwill impairment at a reporting unit currently, 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.

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.

Valuation of Other Intangibles.

Our intangible assets include customer relationships, backlog, trade names, non-compete agreements, patented rights and developed technology, all 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. The excess earnings analysis consists of discounting to present value the projected cash flows attributable to the customer relationships, with consideration given to customer contract renewals and estimated customer attrition rates, the importance or lack thereof of existing customer relationships to our business plan, income taxes and required rates of return. We value backlog for acquired businesses as of the acquisition date based upon the contractual nature of the backlog within each service line, using the income approach to discount back to present value the cash flows attributable to the backlog. The value of trade names is estimated using the relief-from-royalty method of the income approach. This approach is based on the assumption that in lieu of ownership, a company would be willing to pay a royalty in order to exploit the related benefits of this intangible asset.

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

During the fourth quarter of 2015, we recorded an impairment charge of $12.1 million related to customer relationships, trade names and non-compete agreement intangible assets. These intangible asset impairments primarily resulted from lower forecasted oil and gas services revenues for our Gulf of Mexico operations and certain operations in Australia, due to the extended low commodity price environment. The two reporting units impacted 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 value would be expensed and reflected in income (loss) from operations in the consolidated statements of operations. In addition, we estimate the useful lives of our long-lived assets and periodically review these estimates to determine whether these lives are appropriate.

During the fourth quarter of 2015, in conjunction with our annual test for goodwill impairment, we also recorded a property and equipment impairment of $6.6 million related to certain international renewable energy services operations based on the estimated future undiscounted cash flows associated with the asset group as compared to the carrying value before the impairment. Future events and unanticipated changes to assumptions could require additional provisions for impairment in future periods.

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. In addition to balances that have been outstanding for 90 days or more, 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 from them. 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, 2015 and 2014 were approximately $250.1 million and $307.3 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, 2015 and 2014 were $4.5 million and $19.6 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, 2015 and 2014, the balances of unbilled receivables included in accounts receivable were approximately $233.6 million and $163.1 million.

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. 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 are classified in the provision for income taxes.

The 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 and statements of operations and comprehensive income.

Outlook

We believe there are growth opportunities across all the industries we serve. However, we and our customers continue to operate in an uncertain business environment, with gradual improvement in the economy yet continuing uncertainty in the marketplace. Significant decreases in oil and natural gas prices since mid-2014 have adversely impacted certain of our end markets. Our customers also face stringent regulatory and environmental requirements as they develop projects to enhance and expand their infrastructure. In addition, regulatory delays have impacted our business, particularly for large electric transmission and mainline pipe projects. These economic, regulatory and other factors have negatively affected our results in the past and may continue to create some uncertainty as to the timing of anticipated customer spending. We believe that our financial and operational strengths will enable us to manage these challenges and uncertainties, and we remain optimistic about our near-term and long-term opportunities.

Electric Power Infrastructure Services Segment

The North American electric grid is aging and requires significant upgrades, maintenance and expansion to meet current and future demands for reliable power delivery. Over the past several years, many utilities across North America have begun to implement plans to improve their transmission systems in order to improve reliability and reduce congestion. Among other things, these activities include new construction, structure change-outs, line upgrades and maintenance projects on many transmission systems. In addition, state renewable portfolio standards, which set required or voluntary standards for how much power is to be generated from renewable energy sources, can result in the need for additional transmission lines and substations to transport the power from these facilities, which are often in remote locations, to demand centers. Other factors, such as the reliability standards issued by the North American Electric Reliability Corporation (NERC) and other regulatory actions, are also driving transmission system upgrades and expansions. We believe these factors create significant opportunities for our transmission infrastructure services.

Demand for electricity in North America is expected to grow over the long term. North America’s electric power grid was not designed or constructed to serve today’s power needs and is not adequate to efficiently serve the power needs of the future. The electric power grid is aging, continues to deteriorate and lacks redundancy. The increasing demand for electricity, coupled with the aging infrastructure, has affected and will continue to affect reliability, requiring utilities to upgrade and expand their existing transmission and distribution systems. Current federal legislation also requires the power industry to meet federal reliability standards for its transmission and distribution systems. We expect these system upgrades will result in increased spending and increased demand for our services over the long term.

As demand for power grows, the need for new power generation facilities is expected to grow as well. The development of new traditional power generation facilities, as well as renewable energy sources such as solar, wind and certain types of natural gas generation facilities, requires new or expanded transmission infrastructure to transport power to demand centers. Renewable energy in particular often requires significant transmission infrastructure due to the remote location of renewable sources of energy. As a result, we anticipate that future development of new power generation will lead to increased demand over the long term for our electric transmission design and construction services as well as our substation engineering and installation services.

The significant improvement in access to natural gas resources from unconventional shale formations in the United States and Canada, driven by technological advancements, has dramatically increased the near- and long-term supply of natural gas in North America. This increase in supply has also resulted in low natural gas prices for the past several years and the anticipation that natural gas prices will remain at lower levels going forward. As a result, it is anticipated that the amount of electricity generated by natural gas powered plants will increase and the majority of new fossil fuel generation facilities built in North America for the foreseeable future will be fueled by natural gas. Further, the Environmental Protection Agency (EPA) has implemented certain emissions regulations that are resulting in the development of natural gas generation facilities to replace coal generation plants that are being retired in order to comply with the new regulations. These dynamics are anticipated to result in the need for new transmission and substation infrastructure to be built in North America to interconnect new natural gas fired generation facilities. It is also anticipated that modifications to and reengineering of existing transmission and substation infrastructure will be required when existing coal generation facilities are retired or shut down.

We consider renewable energy, including solar, wind and certain types of natural gas generation facilities, to be an ongoing opportunity for our engineering, project management and installation services. Concerns about greenhouse gas emissions, as well as the goal of reducing reliance on power generation from fossil fuels, are creating the need for more renewable energy sources. Renewable portfolio standards (RPS), which mandate that renewable energy constitute a specified percentage of a utility’s power generation by a specified date, exist in many states. We believe that our comprehensive services, industry knowledge and experience in the design, installation and maintenance of renewable energy facilities will enable us to support our customers’ renewable energy efforts. Further, we have the financial strength to selectively provide financing solutions to customers in a modest but strategic way to help facilitate the development of renewable energy and other projects and also potentially create construction backlog for us.

The Federal Energy Regulatory Commission (FERC) issued FERC Order No. 1000 to promote more efficient and cost-effective development of new transmission facilities. The order establishes transmission planning and cost allocation requirements intended to facilitate multi-state electric transmission lines and to encourage competition by removing, under certain conditions, federal rights of first refusal from FERC-approved tariffs and agreements. FERC Order No. 1000 was affirmed by FERC in May 2012 with the issuance of FERC Order No. 1000-A. In the short-term, we believe FERC Order No. 1000 implementation and compliance has created some confusion and uncertainty amongst utilities and regulators that has adversely impacted the timing of some potential transmission projects and spending. However, as these challenges are worked through, we believe FERC Order No. 1000 has the potential to favorably impact electric transmission line development over time, particularly for large, high-voltage electric transmission projects.

We believe that utilities remain committed to the expansion and strengthening of their transmission infrastructure with planning, engineering and funding for many of their projects in place. 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 this spending. In the near-term, our electric power infrastructure services operations have been impacted by regulatory delays, particularly for large transmission projects. However, we expect many of these projects to move forward over a multi-year period. The timing and scope of projects can also be affected by other factors such as siting, right-of-way and unfavorable economic and market conditions. We anticipate many of these issues to be overcome and spending on

transmission projects to be active over the next few years. We currently have a number of these projects underway, and we expect this segment’s backlog to remain strong into 2016.

In the near-term, margins in our Electric Power Infrastructure Services segment have experienced pressure due to increased industry transmission resource availability as construction of several large, high-voltage transmission projects has been delayed due to the challenging regulatory approval and permitting environment. In response to this trend, over the past several quarters, we have reallocated many of our large transmission resources to the small and medium size transmission market. We believe these large transmission projects have been delayed and not canceled and that demand for our transmission services will remain strong over the next several years. As such, we have largely maintained our transmission resource posture in order to remain strategically positioned to pursue transmission projects in the future. We also believe there are excess transmission contractor resources in the small and medium sized transmission marketplace, which is resulting in increased competition and pricing pressure for those services. Despite these competitive pressures, we will remain focused on maintaining our pricing discipline. We believe this heightened competitive environment should be a relatively short-term dynamic and that competitive pressures could lessen as large, high-voltage transmission projects move forward over the coming quarters and the small and medium size transmission market continues to grow and/or contractors adjust to the current environment.

Several existing, pending or proposed legislative or regulatory actions may also positively affect demand for the services provided by this segment in the long term, 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 transmission line construction. We also anticipate increased infrastructure spending by our customers as a result of regulation requiring the power industry to meet federal reliability standards for its transmission and distribution systems and providing incentives to the industry to invest in and improve maintenance on its systems. Developments in environmental regulations concerning fossil fuel power generation plants are resulting in the need to retire or upgrade older coal-fired generation facilities to comply with new environmental and emission rules. Much of the electricity previously generated from retired coal-fired generation facilities will be replaced over the coming years by newly developed natural gas-fired and renewable generation facilities. We believe this “coal to gas” dynamic will require old transmission lines to be updated, rebuilt or replaced with higher voltage transmission infrastructure as well as the construction of new transmission infrastructure to connect new natural gas-fired generation facilities to the grid.

We benefited from increases in distribution spending throughout the last four years, despite continued economic and political uncertainties. Furthermore, as a result of reduced spending by utilities on their distribution systems during 2009 and 2010, combined with the need to meet reliability requirements, we believe there is an ongoing need for utilities to sustain investment in their distribution systems in order to properly maintain their systems. In addition, a number of utilities are implementing system upgrades or “hardening” programs in response to severe weather events that have occurred over the past few years, which is also 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.

The economic feasibility of renewable energy projects, and therefore the attractiveness of investment in the projects, may depend on the availability of tax incentive programs or the ability of the project developer to take advantage of such incentives, and there is no assurance that the government will extend existing tax incentives or create new incentive or funding programs in the future. Although we see developments of renewable energy projects, primarily utility-scale solar facilities, which could create increased demand for our engineering, procurement and construction services, we believe there is some uncertainty with these projects advancing towards award and construction.

The need to ensure available specialized labor resources for projects also drives strategic relationships with customers. In addition, several industry and market trends are prompting customers in the electric power industry

to seek outsourcing partners. These trends include an aging utility workforce and labor availability issues, increasing pressure to reduce cost and improve reliability, and increasing duration and complexity of customer capital programs. Due to these and other factors, we believe customer demand for labor resources will continue to increase, possibly outpacing the supply of industry resources. As a result, we believe the number of opportunities for strategic partnerships is growing.

Oil and Gas Infrastructure Services Segment

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. In the past, sustained periods of low prices for these products negatively impacted the development of related natural resources and infrastructure. The recent decline in prices has adversely impacted demand for some of our services, primarily infrastructure services in Australia, Canada and the Gulf of Mexico. Exploration and production companies, as well as midstream companies, have significantly reduced capital spending, and are expected to continue to operate with reduced budgets for the foreseeable future. A sustained period of lower prices, or the perceived risk of a sustained period of lower prices, may further reduce spending on exploration and production. Reduced capital spending on mainline pipe, gas gathering and compressor systems and other related infrastructure would result in less demand for our services. In particular, the demand for infrastructure services in areas where oil is the primary product, such as Australia, the Canadian Oil Sands, certain oil driven shale formations in the United States and offshore oil resources in the Gulf of Mexico, has been materially and adversely impacted by low oil prices. These markets could remain challenged if oil prices remain at lower levels for an extended period of time.

However, we continue to believe there are growth opportunities in our Oil and Gas Infrastructure Services segment, primarily in the installation and maintenance of mainline pipe and related facilities, as well as pipeline integrity, natural gas distribution systems and specialty services such as horizontal directional drilling. We also continue to believe the existing pipeline system infrastructure in North America is insufficient to support future development of unconventional shale formations and Canadian oil sands. We believe that the development of such resources, though declining in the near term, may continue over the long term and that building this infrastructure would take a number of years, which we believe should increase demand for our services over the long term.

We also believe the abundant natural gas supply, combined with lower gas prices, will increase demand for natural gas in the future. For example, the U.S. Energy Information Administration has stated that the number of natural gas-fired power plants built will increase significantly over the next two decades. Power generation from renewable energy sources also continues to increase and become a larger percentage of the overall power generation mix. We also believe natural gas will be the fuel of choice to provide backup power generation during times when renewable energy sources are not available. We believe these factors will result in increased development of natural gas power generation and demand for natural gas production over the long term, which should create a need for additional pipeline infrastructure to connect natural gas supplies to demand centers.

Environmental scrutiny, stringent regulatory requirements and cumbersome permitting processes caused delays of some mainline pipe projects during the past several years. These dynamics resulted in below average mainline pipe construction opportunities for us and the industry over the last few years. However, the mainline pipe market, in our view, began to improve in the later part of 2013, though regulatory delays for some projects have moderated the pace of recovery. The lack of mainline pipe opportunities over the last few years has negatively impacted our Oil and Gas Infrastructure Services segment margins, in part as a result of our inability to adequately cover certain fixed costs. Margins for mainline pipe projects are also subject to significant performance risk, which can arise from adverse weather conditions, challenging geography, customer decisions and crew productivity. Our specific opportunities in the mainline pipe business are sometimes difficult to predict because of the seasonality of the bidding and construction cycles within the industry.

A number of large mainline pipe projects from the Canadian oil sands and North American shale formations to refineries and other demand centers are in various stages of development. Many of these projects are still

developing, though several projects have been awarded to us and other pipeline construction contractors. Given the costs and time required to bring a mainline pipe project from conception to construction, we believe many of our customers view such projects as important, strategic pieces of infrastructure, have a long-term perspective regarding their needs, and are not primarily influenced by short term commodity fluctuations. If oil and natural gas prices further decline or remain at lower levels for a prolonged period, these views may change and demand for our oil and natural gas infrastructure services could be materially impacted. While there is risk that some of these projects will not move forward or could be delayed, we are encouraged by the proposed mainline pipe development plans and the progression of some mainline pipe projects, which could signal an improved and favorable mainline pipe market over the next several years in North America. Additionally, a number of the proposed oil mainline pipe projects that are under development have already secured oil production customers under contractual arrangements, making these projects economically viable despite the decline in oil prices. There are also a number of natural gas mainline projects in development, and we expect an increase in proposed natural gas mainline projects in the coming years, which could result in additional demand for our mainline services going forward.

The abundance, low price and long-term supply of North American natural gas has also resulted in efforts to develop liquefied natural gas (LNG) export facilities in the United States, Canada and Australia, which could provide pipeline and related facilities development opportunities for us. Natural gas prices in various international markets are significantly higher than North American natural gas prices, making the economics of exporting North American natural gas to international markets attractive. A number of LNG export facilities are in various stages of planning, permitting and development in the United States and Canada. Although we cannot be certain how many, if any, of these projects will move forward, as they could be affected by changing pricing and economic conditions, we believe our comprehensive service offerings and broad geographic presence enable us to competitively pursue opportunities that become available.

Over the past several years, we have expanded our service offerings into Canada and Australia, which have different market drivers and seasonality as compared to North America. In addition, our recent acquisitions of companies that provide pipeline logistics services to the natural gas and oil industry in the United States and specialty services to the offshore oil and gas industry further enhance the segment’s service offerings, customer base and end markets.

We also believe there are growth opportunities for some of our other pipeline services, including pipeline integrity, rehabilitation and replacement services over the long-term. The U.S. Department of Transportation has implemented regulatory legislation through the Pipeline and Hazardous Materials Safety Administration (PHMSA) relating to pipeline integrity requirements. PHMSA continues to develop, propose and implement additional safety and pipeline integrity regulation. For example, in October 2015, PHMSA proposed regulations to make critical safety improvements for hazardous liquid pipelines. The proposed regulations would strengthen requirements for operation, inspection and maintenance of hazardous liquid pipelines. We expect that these types of regulations will increase the demand for our pipeline integrity, rehabilitation and replacement services over the long-term. As pipeline integrity testing requirements increase in stringency and frequency, we believe more information will be gathered about the condition of the nation’s pipeline infrastructure, which could result in an increase in spending by our customers on pipeline integrity initiatives. We also operate an engineering, research and development business that develops and owns pipeline inspection tools. We believe our ability to offer a complete pipeline integrity turnkey solution to pipeline companies and gas utilities positions us to take advantage of available opportunities.

We are also experiencing 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. A number of states, particularly states in the northeast United States that have cities and areas with very old natural gas distribution infrastructure, have approved and are implementing regulations and multi-year programs to replace cast iron, wrought iron and bare steel natural gas infrastructure, which is prone to failure with age, with modern and safer pipe material. We expect this to take an extended period of time, which should provide attractive growth opportunities for this part of our business.

Overall, we remain cautiously optimistic about this segment’s operations going forward. The recent decline in oil and natural gas prices has impacted demand for some of our infrastructure services and could continue to do so if prices further decline or remain at lower levels. We believe that, over the long term, the market will correct the current oversupply, and as a result, oil prices could recover to higher levels. The timing of any recovery, however, is uncertain. From a medium- and longer-term perspective, we continue to believe that mainline pipe opportunities can provide strong profitability, although these projects and the profits they generate 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 offshore specialty services. We believe these measures, together with the potential for mainline pipe opportunities, will position us for profitable growth in this segment over the long-term.

Conclusion

Despite lower oil and natural gas prices, continuing challenges from uncertain economic conditions and restrictive regulatory requirements, including recent regulatory delays that have impacted our business in 2015 and outlook for 2016, particularly for large electric transmission and mainline pipe projects, we continue to see potential growth opportunities in the industries we serve.

We are benefiting from utilities’ increased spending on projects to upgrade and expand their electric power transmission infrastructure to improve system reliability and to deliver renewable electricity from new generation sources to demand centers. Favorable industry legislation is also creating incentives and a positive environment for utilities to invest in their electrical infrastructure, particularly for transmission infrastructure. Additional environmental regulations concerning fossil fuel power generation emissions create opportunities for transmission lines to be updated, rebuilt or replaced due to “coal to gas” facility replacements. We also expect utilities to outsource more of their work to companies like us, due in part to the challenges associated with their aging workforce. We believe that we remain the partner of choice for many utilities in need of broad infrastructure expertise, specialty equipment and workforce resources, particularly as capital budgets and infrastructure projects have become larger and more complex.

The recent decline in oil and natural gas prices creates uncertainty and has adversely impacted demand for some of the services in our Oil and Gas Infrastructure Services segment. This dynamic could continue should natural gas and oil prices further decline or remain at lower levels for an extended period of time. However, we believe long-term dynamics create growth opportunities going forward for our oil and gas infrastructure services operations. We believe that our overall size and breadth of service offerings provide competitive advantages that allow us to leverage these potential opportunities that arise in connection with development and production of resources from North American unconventional shale formations, the Canadian oil sands and coal seam gas and unconventional shale formations in Australia. We have seen encouraging indications that increases in mainline pipe project activity over the past several years that could continue through 2016. We also believe that our strategy to pursue midstream gathering system opportunities in certain unconventional shale formations in the United States, as well as the anticipated increase in demand for our pipeline integrity, rehabilitation and replacement services from pipeline integrity initiatives, and other services in adjacent markets that we have gained through recent acquisitions, will create attractive growth potential for us and also further diversify our service offerings in both the near and long term.

Demand for our electric and natural gas distribution services has increased over the past several years as the economy has stabilized and spending on maintenance to improve reliability has returned. We are optimistic that continued implementation of electric distribution reliability programs and the potential for improvement in the housing market will facilitate continued growth in demand for our electric distribution services. Gas distribution spending has been driven primarily by improving economic conditions and the lower cost of natural gas, and more recently by efforts to replace cast iron, wrought iron and base steel distribution pipeline systems.

Competitive pricing environments, project delays and effects from restrictive regulatory requirements have negatively impacted our margins in the past and could affect our margins in the future. Additionally, margins

may be negatively impacted on a quarterly basis due to adverse weather conditions, as well as timing of project starts or completions and other factors as previously described in Understanding Margins. We continue to focus on the elements of the business we can control, including costs, the margins we accept on projects, collecting receivables, ensuring quality service, rightsizing initiatives as needed to match the markets we serve, and safely executing on the projects we are awarded.

Capital expenditures for 2016 related to continuing operations are expected to be between $200 million to $220 million. We expect 2016 capital expenditures to be funded substantially from cash on hand, internal cash flows and borrowings under our credit facility.

We also continue to evaluate potential strategic acquisitions and similar investments to broaden our customer base, expand our geographic area of operation, grow our portfolio of services and increase opportunities across our operations. We believe that additional attractive acquisition candidates exist primarily as a result of the highly fragmented nature of the industry, the inability of many companies to expand and modernize due to capital constraints, and the desire of owners for liquidity. We also believe that our financial strength, entrepreneurial operating model and experienced management team are attractive to acquisition candidates.

Certain international regions present significant opportunities for growth over time across many of our operations. We are evaluating ways in which we can strategically apply our expertise to strengthen infrastructure in various foreign countries where infrastructure enhancements are increasingly important. For example, we are actively pursuing opportunities in growth markets where we can leverage our technology or proprietary work methods, such as our energized services, to establish a presence in these markets.

We believe that we are well-positioned to capitalize upon opportunities and trends in the industries we serve because of our full-service operations with broad geographic reach, our financial strength and our technical expertise. Additionally, we believe the industry opportunities and trends discussed herein will increase the demand for our services over the long-term, although the actual timing, magnitude and impact of these opportunities and trends on our results of operations, financial position and cash flows are difficult to predict.

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, earnings per share, margins, capital expenditures, and other projections of operating or financial results;

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

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

	•		Future capital allocation initiatives, including the amount, timing, availability and strategy with respect to future stock repurchases;

	•		The effects or results of the sale of our fiber optic licensing operations;

	•		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 oil and natural gas mainline pipe projects and their impact on our business or demand for our services;

	•		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 renewable energy initiatives, including mandated state renewable portfolio standards, the economic stimulus package and other existing or potential energy legislation;

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

	•		The potential benefits from acquisitions;

	•		The expected outcome of pending or threatened litigation;

	•		The business plans or financial condition of our customers;

	•		Our plans and strategies; and

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

These forward-looking statements are not guarantees of future performance and involve or rely on a number of risks, uncertainties, and assumptions that are difficult to predict or beyond our control. These forward-looking statements reflect our beliefs and assumptions based on information available to our management 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 wrong. 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 or political conditions outside our control;

	•		Quarterly variations in our operating results;

	•		Adverse economic and financial conditions, including weakness in the capital markets;

	•		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 environmental processes, project performance issues, 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 ability to attract skilled labor and retain key personnel and qualified employees;

	•		The potential shortage of skilled 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 impacts from weather;

	•		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 the resulting impact on demand for our services;

	•		The future development of natural resources in shale formations;

	•		Potential failure of renewable energy initiatives, the economic stimulus package or other existing or potential legislative actions to result in increased demand for our services;

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

	•		The possibility of further increases in the liability associated with our withdrawal from a multiemployer pension plan;

	•		Liabilities for claims that are self-insured or not insured;

	•		Unexpected costs or liabilities that may arise from lawsuits or indemnity claims asserted against us;

	•		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 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 unexcused delays, warranty claims, failure to meet performance guarantees, damages or contract terminations;

	•		The inability of our customers to pay for services;

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

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

	•		Budgetary or other constraints that may reduce or eliminate tax incentives for or government funding of projects, including stimulus 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 and compliance with the laws of foreign jurisdictions, as well as 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;

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

	•		The adverse impact of impairments of goodwill, receivables and other intangible 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 an information technology solution;

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

	•		Potential liabilities relating to occupational health and safety matters;

	•		Our dependence on suppliers, subcontractors and equipment manufacturers;

	•		Beliefs and assumptions about the collectability of receivables;

	•		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;

	•		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 continue to meet the requirements of the Sarbanes-Oxley Act of 2002;

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

	•		The impact of increased healthcare costs arising from healthcare reform legislation;

	•		The impact of regulatory changes on labor costs;

	•		The impact of significant fluctuations in foreign currency exchange rates;

	•		The business, accounting and other effects from the sale of our fiber optic licensing operations;

	•		The potential for claims or damages associated with the sale of our fiber optic licensing operations, including as a result of indemnity claims;

	•		The terms of any accelerated share repurchase arrangement or any other transaction we enter into to facilitate the repurchase of shares under our stock repurchase program, including factors affecting the amount of shares to be purchased thereunder;

	•		Events or actions by counterparties that result in termination of, or adjustments in the amount of shares purchased under, any accelerated share repurchase arrangement or any other transaction we enter into to facilitate the repurchase of shares under our stock repurchase program; and

	•		The other risks and uncertainties as are 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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