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EX-21 - EXHIBIT 21 - Willbros Group, Inc.\NEW\c13751exv21.htm
EX-32.1 - EXHIBIT 32.1 - Willbros Group, Inc.\NEW\c13751exv32w1.htm
EX-32.2 - EXHIBIT 32.2 - Willbros Group, Inc.\NEW\c13751exv32w2.htm
EX-31.2 - EXHIBIT 31.2 - Willbros Group, Inc.\NEW\c13751exv31w2.htm
EX-23.1 - EXHIBIT 23.1 - Willbros Group, Inc.\NEW\c13751exv23w1.htm
EX-31.1 - EXHIBIT 31.1 - Willbros Group, Inc.\NEW\c13751exv31w1.htm
EX-10.40 - EXHIBIT 10.40 - Willbros Group, Inc.\NEW\c13751exv10w40.htm
EX-10.52 - EXHIBIT 10.52 - Willbros Group, Inc.\NEW\c13751exv10w52.htm
EX-10.41 - EXHIBIT 10.41 - Willbros Group, Inc.\NEW\c13751exv10w41.htm
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
(Mark One)
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
Commission file number 1-11953
Willbros Group, Inc.
(Exact name of registrant as specified in its charter)
     
Delaware
(State or other jurisdiction of
incorporation or organization)
  30-0513080
(I.R.S. Employer Identification Number)
4400 Post Oak Parkway
Suite 1000
Houston, TX 77027
Telephone No.: 713-403-8000

(Address, including zip code, and telephone number, including
area code, of principal executive offices of registrant)
Securities registered pursuant to Section 12(b) of the Act:
     
    Name of each exchange
Title of each class   on which registered
     
Common Stock, $.05 Par Value   New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No þ
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of the Regulation S-T during the preceding 12 months (or such shorter period that the Registrant was required to submit and post such files). Yes o No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
             
Large accelerated filer o   Accelerated filer þ   Non-accelerated filer o   Smaller Reporting Company o
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value of the Registrant’s Common Stock held by non-affiliates of the Registrant on the last business day of the Registrant’s most recently completed second fiscal quarter (based on the closing sales price on the New York Stock Exchange on June 30, 2010) was $292,241,954.
The number of shares of the Registrant’s Common Stock outstanding at March 10, 2011 was 47,965,707.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s 2011 Proxy Statement for the Annual Meeting of Stockholders to be held on May 23, 2011 are incorporated by reference into Part III of this Form 10-K.
 
 

 

 


 

WILLBROS GROUP, INC.
FORM 10-K
YEAR ENDED DECEMBER 31, 2010
TABLE OF CONTENTS
         
    Page  
PART I
 
       
    4  
 
       
    29  
 
       
    43  
 
       
    43  
 
       
    44  
 
       
    44  
 
       
PART II
 
       
    46  
 
       
    47  
 
       
    49  
 
       
    74  
 
       
    76  
 
       
    132  
 
       
    132  
 
       
    133  
 
       
PART III
 
       
    134  
 
       
    134  
 
       
    134  
 
       
    134  
 
       
    134  
 
       
PART IV
 
       
    135  
 
       
    141  
 
       
 Exhibit 10.40
 Exhibit 10.41
 Exhibit 10.52
 Exhibit 21
 Exhibit 23.1
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32.1
 Exhibit 32.2

 

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FORWARD-LOOKING STATEMENTS
This Form 10-K includes “forward-looking statements”. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments which we expect or anticipate will or may occur in the future, including such things as future capital expenditures (including the amount and nature thereof), oil, gas, gas liquids and power prices, demand for our services, the amount and nature of future investments by governments, expansion and other development trends of the oil and gas, refinery, petrochemical and power industries, business strategy, expansion and growth of our business and operations, the outcome of government investigations and legal proceedings and other such matters are forward-looking statements. These forward-looking statements are based on assumptions and analyses we made in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties. As a result, actual results could differ materially from our expectations. Factors that could cause actual results to differ from those contemplated by our forward-looking statements include, but are not limited to, the following:
   
curtailment of capital expenditures and the unavailability of project funding in the oil and gas, refinery, petrochemical and power industries;
   
increased capacity and decreased demand for our services in the more competitive industry segments that we serve;
   
reduced creditworthiness of our customer base and higher risk of non-payment of receivables;
   
inability to lower our cost structure to remain competitive in the market;
   
inability of the energy service sector to reduce costs in the short term to a level where our customers’ project economics support a reasonable level of development work;
   
inability to predict the timing of an increase in energy sector capital spending, which results in staffing below the level required when the market recovers;
   
reduction of services to existing and prospective clients as they bring historically out-sourced services back in-house to preserve intellectual capital and minimize layoffs;
   
the consequences we may encounter if we fail to comply with the terms and conditions of our final settlements with the Department of Justice (“DOJ”) and the Securities and Exchange Commission (“SEC”), including the imposition of civil or criminal fines, penalties, enhanced monitoring arrangements, or other sanctions that might be imposed by the DOJ and SEC;
   
the issues we may encounter with respect to the federal monitor appointed under our Deferred Prosecution Agreement with the DOJ and any changes in our business practices which the monitor may require;
   
the commencement by foreign governmental authorities of investigations into the actions of our current and former employees, and the determination that such actions constituted violations of foreign law;
   
difficulties we may encounter in connection with the previous sale and disposition of our Nigeria assets and Nigeria based operations, including obtaining indemnification for any losses we may experience if, due to the non-performance by the purchaser of these assets, claims are made against any parent company guarantees we provided, to the extent those guarantees may be determined to have continued validity;
   
the dishonesty of employees and/or other representatives or their refusal to abide by applicable laws and our established policies and rules;
   
adverse weather conditions not anticipated in bids and estimates;
   
project cost overruns, unforeseen schedule delays and the application of liquidated damages;
   
the occurrence during the course of our operations of accidents and injuries to our personnel, as well as to third parties, that negatively affect our safety record, which is a factor used by many clients to pre-qualify and otherwise award work to contractors in our industry;
   
cancellation of projects, in whole or in part, for any reason;

 

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failing to realize cost recoveries on claims or change orders from projects completed or in progress within a reasonable period after completion of the relevant project;
   
political or social circumstances impeding the progress of our work and increasing the cost of performance;
   
inability to obtain and maintain legal registration status in one or more foreign countries in which we are seeking to do business;
   
failure to obtain the timely award of one or more projects;
   
inability to identify and acquire suitable acquisition targets or to finance such acquisitions on reasonable terms;
   
inability to hire and retain sufficient skilled labor to execute our current work, our work in backlog and future work we have not yet been awarded;
   
inability to execute cost-reimbursable projects within the target cost, thus eroding contract margin and, potentially, contract income on any such project;
   
inability to obtain sufficient surety bonds or letters of credit;
   
inability to obtain adequate financing;
   
loss of the services of key management personnel;
   
the demand for energy moderating or diminishing;
   
downturns in general economic, market or business conditions in our target markets;
   
changes in and interpretation of U.S. and foreign tax laws that impact our worldwide provision for income taxes and effective income tax rate;
   
the potential adverse effects on our operating results if our non-U.S. operations became taxable in the United States;
   
changes in applicable laws or regulations, or changed interpretations thereof, including climate change legislation;
   
changes in the scope of our expected insurance coverage;
   
inability to manage insurable risk at an affordable cost;
   
enforceable claims for which we are not fully insured;
   
incurrence of insurable claims in excess of our insurance coverage;
   
the occurrence of the risk factors listed elsewhere in this Form 10-K or described in our periodic filings with the SEC; and
   
other factors, most of which are beyond our control.
Consequently, all of the forward-looking statements made in this Form 10-K are qualified by these cautionary statements and there can be no assurance that the actual results or developments we anticipate will be realized or, even if substantially realized, that they will have the consequences for, or effects on, our business or operations that we anticipate today. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by law.
Unless the context requires or is otherwise noted, all references in this Form 10-K to “Willbros”, the “Company”, “we”, “us” and “our” refer to Willbros Group, Inc., its consolidated subsidiaries and their predecessors. Unless the context requires or is otherwise noted, all references in this Form 10-K to dollar amounts, except share and per share amounts, are expressed in thousands.

 

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PART I
Items 1 and 2. Business and Properties
General
We are a provider of services to global end markets serving the oil and gas, refinery, petrochemical and power industries. Our services, which include engineering, procurement and construction (either individually or together as an integrated “EPC” service offering), turnaround, maintenance and other specialty services, are critical to the ongoing expansion and operation of energy infrastructure. Within the global energy market, we specialize in designing, constructing, upgrading and repairing midstream infrastructure such as pipelines, compressor stations and related facilities for onshore and coastal locations as well as downstream facilities, such as refineries. We also provide specialty turnaround services, tank services, heater services, construction services and safety services and fabricate specialty items for hydrocarbon processing units. Our services include maintenance and small capital projects for transmission and distribution facilities for electric and natural gas utilities as well as larger capital projects for renewable power generation and electric transmission projects. We believe our engineering, planning and project management expertise, as it relates to optimizing the structure and execution of a project, provides us with competitive advantages in the markets we serve.
Our near term focus is on the North American markets for natural gas and electric infrastructure. We believe our service offering is well aligned for these markets and that we can generate more attractive risk adjusted returns in North America than in other locations around the world. However, depending upon market conditions and our assessment of an appropriate risk-adjusted return, we may work in developing countries. Through our legacy international pipeline construction business we have constructed approximately 124,000 miles (200,000 kilometers) of pipelines in our history, building a global reputation for performing quality work on time, often under challenging conditions. Having performed work in over 60 countries, we believe our experience gives us a competitive advantage in frontier areas where experience in dealing with project logistics is an important consideration for project award and execution. We complement our pipeline construction market expertise with service offerings to the downstream hydrocarbon processing market, providing integrated solutions for turnaround, maintenance and capital projects for the refining and petrochemical industries. We have performed these downstream services for over 100 refineries in the United States and have experience in certain international markets. We offer our clients full asset lifecycle services and in some cases provide the entire scope of services for a project, from front-end engineering and design to procurement, construction, and commissioning as well as ongoing facility operations and maintenance. Our Utility Transmission & Distribution segment (“Utility T&D”) (acquired with the purchase of the InfrastruX Group), expands our services reach into the transmission and distribution markets for both electricity and natural gas. With operations in the Northeast, South Central and Midwest regions of the United States, and customer relationships established for as many as 50 years, we are positioned to participate in the anticipated electric transmission build-out linking new renewable generation facilities to end markets and in the reliability improvements planned for aging transmission grids. With over 100 years of experience in the global energy infrastructure market, our full asset lifecycle services are utilized by major pipeline transportation companies, exploration and production companies, refining companies, and electric utilities as well as government entities worldwide.
We maintain our headquarters at 4400 Post Oak Parkway, Suite 1000, Houston, TX 77027; our telephone number is 713-403-8000. All significant operations are carried out by the following material direct or indirect subsidiaries:
   
Willbros United States Holdings, Inc.;
   
Willbros Construction (U.S.), LLC;
   
Willbros Canada Holdings ULC;
   
Willbros Downstream, LLC;
   
Wink Engineering, LLC;
   
Willbros Engineers (U.S.), LLC;
   
Willbros Project Services (U.S.), LLC;
   
Willbros Construction Services (Canada) L.P.;
   
Willbros Midwest Pipeline Construction (Canada) L.P.;
   
Willbros Government Services (U.S.), LLC;

 

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Willbros Middle East, Ltd.;
   
Willbros (Overseas) Ltd.;
   
The Oman Construction Company (TOCO), L.L.C.;
   
Construction & Turnaround Services (U.S.), L.L.C.;
   
W International Limited;
   
InfrastruX Group, LLC.;
   
Chapman Construction Co., L.P.;
   
Texas Electric Utility Construction, Ltd.;
   
InterCon Construction, Inc.; and
   
Hawkeye, LLC.;
The Willbros corporate structure is designed to comply with jurisdictional and registration requirements and to minimize worldwide taxes. Additional subsidiaries may be formed in specific work countries where such subsidiaries are necessary or useful to comply with local laws or tax objectives.
Our public internet site is http://www.willbros.com. We make available free of charge through our internet site via a link to Edgar Online, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. Our common stock is traded on the New York Stock Exchange under the symbol “WG”.
In addition, we currently make available on our internet site annual reports to stockholders. You will need to have the Adobe Acrobat Reader software on your computer to view these documents which are in the .PDF format. A link to Adobe Systems Incorporated’s internet site is provided to assist with obtaining this software.
Willbros Background
We are the successor to the pipeline construction business of Williams Brothers Company, which was started in 1908 by Miller and David Williams and eventually became The Williams Companies, Inc., a major U.S. energy company (“Williams”).
In December 1975, Williams elected to discontinue its pipeline construction activities and sold substantially all of the non-U.S. assets and international entities comprising its pipeline construction division to a newly formed, independently owned Panamanian corporation. Ownership of the new privately-held company (eventually renamed Willbros Group, Inc.) changed infrequently during the 1980s and 1990s until an initial public offering of common stock was completed in August 1996.
Having been in business for over 100 years, we have achieved many milestones, which are summarized as follows:
             
 
    1908     Miller and David Williams form the construction business of Williams Brothers Company.
 
           
 
    1915     Began pipeline work in the United States.
 
           
 
    1923     First project outside the United States performed in Canada.
 
           
 
    1939     Began pipeline work in Venezuela, first project outside North America.
 
           
 
    1942-44     Served as principal contractor on the “Big Inch” and “Little Big Inch” War Emergency Pipelines in the United States which delivered Gulf Coast crude oil to the Eastern Seaboard.
 
           
 
    1954-55     Built Alaska’s first major pipeline system, consisting of 625 miles of petroleum products pipeline, housing, communications, two tank farms, five pump stations, and marine dock and loading facilities.
 
           
 
    1960     Built the first major liquefied petroleum gas pipeline system, the 2,175-mile Mid-America Pipeline in the United States, including six delivery terminals, two operating terminals, 13 pump stations, communications and cavern storage.
 
           
 
    1962     Began operations in Nigeria with the commencement of construction of the TransNiger Pipeline, a 170-mile crude oil pipeline.

 

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    1964-65     Built the 390-mile Santa Cruz to Sica Sica crude oil pipeline in Bolivia. The highest altitude reached by this line is 14,760 feet (4,500 meters) above sea level.
 
           
 
    1965     Began operations in Oman with the commencement of construction of the 175-mile Fahud to Muscat crude oil pipeline system.
 
           
 
    1970-72     Built the Trans-Ecuadorian Pipeline, crossing the Andes Mountains, consisting of 315 miles of 20-inch and 26-inch pipeline, seven pump stations, four pressure-reducing stations and six storage tanks. Considered the most logistically difficult pipeline project ever completed at the time.
 
           
 
    1974-76     Led a joint venture which built the northernmost 225 miles of the Trans Alaska Pipeline System.
 
           
 
    1984-86     Constructed, through a joint venture, the All-American Pipeline System, a 1,240-mile 30-inch heated pipeline, including 23 pump stations, in the United States.
 
           
 
    1988-92     Performed project management, engineering, procurement and field support services to expand the Great Lakes Gas Transmission System in the northern United States. The expansion involved modifications to 13 compressor stations and the addition of 660 miles of 36-inch pipeline in 50 separate loops.
 
           
 
    1992-93     Rebuilt oil field gathering systems in Kuwait as part of the post-war reconstruction effort.
 
           
 
    1996     Listed shares, upon completion of an initial public offering of common stock, on the New York Stock Exchange under the symbol “WG.”
 
           
 
    2002     Completed engineering and project management of the Gulfstream project, a $1.6 billion natural gas pipeline system from Mobile, Alabama crossing the Gulf of Mexico and serving markets in central and southern Florida.
 
           
 
    2003     Completed an EPC contract for the 665-mile 30-inch crude oil Chad—Cameroon Pipeline Project, through a joint venture with another international contractor.
 
           
 
    2007     Completed the sale of our Nigerian interests in February 2007. Acquired Midwest Management (1987) Ltd. (“Midwest”) in July 2007 and Integrated Service Company in November 2007 (renamed Willbros Downstream, LLC (“InServ”) in 2010).
 
           
 
    2008     Completed two 36-inch loops in Northern Alberta for TransCanada. This was the first major project in Canada following the Midwest acquisition.
 
           
 
          Completed approximately 190 miles of the Southeast Supply Header, LLC (“SESH”) project that connects the Perryville Hub in northeast Louisiana with the Gulfstream Natural Gas System, L.L.C. pipeline in Mobile County, Alabama.
 
           
 
    2009     Changed our corporate domicile from Panama to Delaware on March 3, 2009.
 
           
 
          Acquired the engineering business of Wink Companies, LLC in July 2009 (renamed Wink Engineering, LLC (“Wink”) in February 2010).
 
           
 
          Established new quality, productivity and safety performance standards on the Texas Independence Pipeline project, 143 miles of 42-inch natural gas pipeline in East Texas.
 
           
 
    2010     Completed a major portion of the Fayetteville Express Pipeline on schedule, 145 miles of 42-inch natural gas pipeline in Arkansas and Mississippi.
 
           
 
          Acquired the InfrastruX Group on July 1, 2010, entering the services market for electric transmission and distribution infrastructure.
Business Segments
Prior to the InfrastruX acquisition, we operated through two business segments: Upstream Oil & Gas and Downstream Oil & Gas. These segments operate primarily in the United States, Canada and Oman. On July 1, 2010, we closed on the acquisition of InfrastruX. InfrastruX is a provider of electric power and natural gas transmission and distribution maintenance and construction solutions to customers from their regional operating centers in the South Central, Midwest and East Coast regions of the United States. This acquisition significantly diversifies our capabilities and end markets. The acquired InfrastruX assets and business operations have been designated as a newly established segment: Utility T&D.

 

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During the third quarter of 2009, we acquired the engineering business of Wink Companies, LLC. In conjunction with the Wink acquisition, we redefined our business segments from Engineering, Upstream Oil & Gas and Downstream Oil & Gas to two segments by integrating the existing Engineering segment into the Upstream Oil & Gas segment and Wink into the Downstream Oil & Gas segment. We believe the inclusion of engineering services within each segment will make our EPC offering even more effective by improving internal connectivity and providing dedicated, specialized engineering services to both the upstream and downstream markets.
Our segments are comprised of strategic business units that are defined by the industry segments served and are managed separately as each has different operational requirements and strategies. Management evaluates the performance of each operating segment based on operating income. To support our segments we have a focused corporate operation led by our executive management team, which, in addition to oversight and leadership, provides general, administrative and financing functions for the organization. The costs to provide these services are allocated, as are certain other corporate costs, to the three operating segments.
Through our business segments we have been employed by more than 400 clients to carry out work in over 60 countries. These segments currently operate primarily in the United States, Canada and Oman. Within the past 10 years, we have worked in North America, the Middle East, Africa, and South America. Private sector clients have historically accounted for the majority of our revenue. Governmental entities and agencies have accounted for the remainder. Our top 10 clients were responsible for 49.4 percent of our revenue from continuing operations in 2010 (73.0 percent in 2009 and 65.0 percent in 2008).
See Note 15 — Segment Information in Item 8 of this Form 10-K for more information on our operating segments.
Services Provided
Upstream Oil & Gas
We provide individual engineering, procurement and construction, or fully-integrated EPC, expertise (including systems, equipment and personnel) to design, build or replace large-diameter cross-country pipelines; fabricate engineered structures, process modules and facilities; and build oil and gas production facilities, pump stations, flow stations, gas compressor stations, gas processing facilities, gathering lines and related facilities. We provide a broad array of engineering, project management, pipeline integrity and field services to increase our equipment and personnel utilization. We currently provide these services primarily in the United States, Canada and Oman, and, with our international experience, can enter (or re-enter) individual country markets when conditions there are attractive to us and present an acceptable risk-adjusted return.
Construction Services
Our earliest success was attributed to our focus and execution of upstream infrastructure projects, which we have grown into our current construction offering encompassing pipeline systems, compressor and pump stations, as well as fabrication and ongoing maintenance services, to major upstream customers. In addition to our core upstream infrastructure construction and maintenance competencies, we have developed a wide range of specialty services that allow us to maximize our resource utilization by providing solutions to difficult problems for our clients.
Pipeline Construction. Pipeline construction for both liquids and gas is capital intensive. We own, lease, operate and maintain a fleet of specialized equipment necessary for operations in this business. We prefer targeting construction of large diameter cross-country pipelines in remote areas and harsh climates where we believe our experience gives us a competitive advantage and higher revenue and margins can be achieved. We also perform construction of smaller diameter pipelines, including gathering lines, utilizing dedicated resources appropriately structured to meet the unique cost and execution needs of our customers. In our history, we have constructed approximately 124,000 miles of pipelines, which we believe positions us in the top tier of pipeline contractors in the world. We have developed the expertise to employ automatic welding processes in the onshore construction of large-diameter (greater than 30-inch) natural gas pipelines and have extensive experience using automatic welding processes in the United States, Canada and Oman.
The construction of a cross-country pipeline involves a number of sequential operations along the designated pipeline right-of-way. These operations are virtually the same for all overland pipelines, but personnel and equipment may vary widely depending upon such factors as the time required for completion, general climatic conditions, seasonal weather patterns, the number of road crossings, the number and size of river crossings, terrain considerations, extent of rock formations, density of heavy timber and amount of swamp.

 

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Special equipment and techniques are required to construct pipelines across wetlands and offshore. We have used swamp pipe-laying methods extensively in past international projects. This expertise is applicable in wetland regions elsewhere and can provide a competitive advantage for projects in geographies such as southern Louisiana, where we expect to see additional work opportunities.
Fabrication. Fabrication services can be a more efficient means of delivering engineered, process or production equipment with improved schedule certainty and quality. We provide fabrication services and are capable of fabricating such diverse deliverables as process modules, station headers, valve stations and flare pipes and tips. We currently operate two fabrication facilities in Alberta, Canada, allowing us the opportunity to provide process modules and other fabricated assemblies to the heavy oil market in northern Alberta. In addition, our fabrication facility in Edmonton applies chrome carbide overlay (“CCO”), a process which increases the wear life of pipe used in transporting the bitumen and sand slurry.
Facilities Construction. Companies in the hydrocarbon value chain require various facilities in the course of producing, processing, storing and moving oil, gas, refined products and chemicals. We are experienced in and capable of constructing facilities such as pump stations, flow stations, gas processing facilities, gas compressor stations and metering stations. We provide a full range of services for the engineering, design, procurement and construction of processing, pumping, compression and metering facilities. We are capable of building such facilities onshore, offshore in shallow water or in swamp locations. The construction of station facilities, while not as capital-intensive as pipeline construction, is generally characterized by complex logistics and scheduling, particularly on projects in locations where seasonal weather patterns limit construction options, and in countries where the importation process is difficult. Our capabilities have been enhanced by our experience in dealing with such challenges in numerous countries around the world.
Engineering Services
We specialize in providing engineering services to assist clients in designing, engineering and constructing or expanding pipeline systems, compressor stations, pump stations, fuel storage facilities and field gathering and production facilities. We have developed expertise in addressing the unique engineering challenges involved with pipeline systems and associated facilities.
Natural Gas Transmission Systems. We believe we have established a strong position as a leading supplier of project management and engineering services to natural gas pipeline transmission companies in the United States. Since 1988, we have provided engineering services for over 20 major natural gas transmission projects in the United States, including the Gulfstream Natural Gas System and both Phase I and Phase II of the Guardian Pipeline Project.
Liquids Pipelines and Storage Facility Design. We have engineered a number of crude oil and refined petroleum products systems throughout the world, and have become recognized for our expertise in the engineering of systems for the storage and transportation of petroleum products and crude oil. In 2001, we provided engineering and field services for conversion of a natural gas system in the mid-western United States, involving over 797 miles of 24-inch to 26-inch diameter pipeline to serve the upper Midwest with refined petroleum products. In 2003, we completed EPC services for the expansion of a petroleum products pipeline to the Midwest involving 12 new pump stations, modifications to another 13 pump stations and additional storage. In 2009, we completed an engineering, procurement, construction management project for a gas liquids pipeline system in the United States from Wyoming to Kansas.
Design of Peripheral Systems. Our expertise extends to the engineering of a wide range of project peripherals, including various types of support buildings and utility systems, power generation and electrical transmission, communications systems, fire protection, water and sewage treatment, water transmission, roads and railroad sidings.
In addition to our broad infrastructure engineering service offerings we have also developed capabilities that are unique to the upstream market and critical to successful execution of the most challenging projects, such as:
Climatic Constraints. In the design of pipelines and associated facilities to be installed in harsh environments, special provisions for metallurgy of materials and foundation design must be addressed. We are experienced in designing pipelines for arctic conditions, desert conditions, mountainous terrain, swamps and offshore.

 

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Environmental Impact of River Crossings/Wetlands. We have considerable capability to design pipeline crossings of rivers, streams and wetlands in such a way as to minimize environmental impact. We possess expertise to determine the optimal crossing techniques, such as open cut, directionally-drilled or overhead, and to develop site-specific construction methods to minimize bank erosion, sedimentation and other environmental impacts.
Seismic Design and Stress Analysis. Our engineers are experienced in seismic design of pipeline crossings of active faults and areas where soil liquefaction or slope instability may occur due to seismic events. Our engineers also carry out specialized stress analyses of piping systems that are subjected to expansion and contraction due to temperature changes, as well as loads from equipment and other sources.
Hazardous Materials. Special care must be taken in the design of pipeline systems transporting sour gas. Sour gas not only presents challenges regarding personnel safety since hydrogen sulfide leaks can be extremely hazardous, but also requires that material be specified to withstand highly corrosive conditions. Our engineers have extensive natural gas experience which includes design of sour gas systems.
Hydraulics Analysis for Fluid Flow in Piping Systems. We employ engineers with the specialized knowledge necessary to properly address the effects of both steady-state and transient flow conditions for a wide-variety of fluids transported by pipelines, including natural gas, crude oil, refined petroleum products, natural gas liquids, carbon dioxide and water. This expertise is important in optimizing the capital costs of pipeline projects where pipe material costs typically represent a significant portion of total project capital costs.
Procurement Services. Because procurement plays a critical part in the success of any project, we maintain an experienced staff to carry out the procurement of all materials and services. Procurement services are provided to clients as a complement to the engineering services performed for a project. Material and services procurement is especially critical to the timely completion of construction on the EPC contracts we undertake. We maintain a computer-based material procurement, tracking and control system, which utilizes software enhanced to meet our specific requirements.
Pipeline Integrity Testing, Management & Maintenance. In addition to the capital projects discussed above, we also offer our considerable upstream infrastructure construction expertise to our clients through our management and maintenance (“Manage & Maintain”) offerings. This allows us to support our clients with our EPC, engineering, procurement or construction capabilities on a recurring basis through alliance agreements whereby we will be the provider of program development, project management, design, engineering, geographic information systems (“GIS”), integrity and maintenance services with respect to existing pipeline systems. In 2009, we entered into our most significant alliance agreement with NiSource Gas Transmission & Storage (“NGT&S”), a unit of NiSource Inc. (NYSE: NI). We believe this form of alliance, which includes participation in the development of the annual NGT&S capital, maintenance, GIS and integrity programs, will yield significant benefits to both parties and serve as a model for future work, much of which is currently performed by our customers.
EPC Services
EPC projects often yield profit margins on the engineering and construction components consistent with stand-alone contracts for similar services; however, the benefits from performing EPC projects include the incremental income associated with project management and the income associated with the procurement component of the contract. Both of these income generating activities are relatively low risk compared with the construction aspect of the project. In performing EPC contracts, we participate in numerous aspects of a project and are, therefore, able to determine the most efficient design, permitting, procurement and construction sequence for a project in connection with making engineering and constructability decisions. EPC contracts enable us to deploy our resources more efficiently and capture those efficiencies in the form of improved margins on the engineering and construction components of these projects, at the same time optimizing the overall project solution and execution for the client. While EPC contracts carry lower margins for the procurement component, the increased control over all aspects of the project, coupled with competitive market margins for engineering and construction portions makes these types of contracts attractive to us and, we believe, to our customers.
Specialty Services
We utilize the skill sets and resources from our engineering, construction and EPC services to provide a wide range of support and ancillary services related to the construction, operation, repair and rehabilitation of pipelines and other hydrocarbon processing facilities. Frequently, such services require the utilization of specialized equipment, which is costly and requires specific operating expertise. Due to the initial equipment cost and operating expertise required, many client companies hire us to perform these services. We own and operate a variety of specialized equipment that is used to support construction projects and to provide a wide range of oilfield and plant services.

 

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Downstream Oil & Gas
We provide integrated, full-service specialty construction, turnaround, repair and maintenance services to the downstream energy infrastructure market, which consists primarily of major integrated oil companies, independent refineries, product terminals and petrochemical companies. We also provide services to select EPC firms, independent power producers, government entities, specialty process facilities and ammonia and fertilizer manufacturing plants and facilities. We provide these services primarily in the United States; however, our experience includes international projects. Our principal services include:
   
construction, maintenance and turnaround services for downstream facilities, including revamp/reconditioning of fluid catalytic cracking (“FCC”) units, one of the main process units in a refinery, which have three to five year required maintenance intervals in order to maintain production efficiency;
   
manufacturing services for process heaters, heater coils, alloy piping, specialty components and other equipment for installation in oil refineries;
   
heater services, including design, manufacture and installation of fired heaters in refining and process plants;
   
tank services for construction, maintenance or repair of petroleum storage tanks, typically located at pipeline terminals and refineries;
   
safety services for supplementing a refinery’s safety personnel, permitting, procedures and providing safety equipment;
   
government services through building and managing fueling depots and other fueling systems; and evaluating, maintaining and building petroleum, oil and lubricant (“POL”) facilities;
   
multi-disciplinary engineering services to clients in the petroleum refining, chemicals and petrochemicals and oil and gas industries; and
   
EPC services through program management and EPC project services.
Construction, Maintenance and Turnaround Services. When performing a construction and maintenance project as part of a refinery turnaround, detailed planning and execution is imperative in order to minimize the length of the outage, which can cost owners millions of dollars in downtime. Our experience includes successful turnaround execution on the largest, most complex FCC units. Our record in providing a construction-driven approach with attention to planning, scheduling and safety places us at the forefront of qualified bidders in North America for work on FCC units and qualifies us for most turnaround projects of interest. These services include refractory services, furnace re-tube and revamp projects, stainless and alloy welding services and heavy rigging and equipment setting. The skills and experience gained from our turnaround performance is complementary to our construction services for new units, expansions and revamp projects.
Manufacturing Services. We have manufacturing facilities with specialty welding and plate cutting and rolling capabilities located on two sites in the Tulsa, Oklahoma area, with easy access to truck, rail, air and river barge transportation through the inland most ice-free port in the United States, the Kerr-McClellan Navigation System. Specialty equipment that can be fabricated includes FCC components, reactors and regenerators, refractory, process heater coils and components, and process piping spools (alloy and carbon steel). Our Mohawk facility consists of 150,000 square feet of manufacturing space, which includes significant convection section fabrication capacity and which also allows us to fabricate process heaters and furnace components. We believe our ability to combine the quality fabrication and timely manufacturing of these components is complementary to other services we provide and offers a competitive advantage for us.
Heater Services. As a vertically-integrated provider of process heater services in North America, we can perform engineering studies; process, mechanical, structural and instrumentation and electrical design; fabrication and manufacture; and installation and erection of fired heaters in a one-stop shop. We also specialize in modifications to existing fired heaters for expanded service or process improvement.

 

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Tank Services. We provide services to the above-ground storage tank industry. Our capabilities include: American Petroleum Institute (“API”) compliant tank maintenance and repair; floating roof seals; floating roof installations and repairs; secondary containment bottoms, cone roof and structure replacements; and new API compliant aboveground storage tanks. We provide these services as stand-alone or in combination, including EPC solutions.
Safety Services. We provide both safety services and equipment to support the safety and quality requirements of our clients. We can provide safety supervisors, confined space and fire watch services, confined space rescue and training, safety planning services, technicians, training, drug screening and medical personnel. Our safety services also include safety service vehicles to support the services offered and to provide necessary equipment, including first aid equipment, fire retardant clothing, fall protection equipment, fresh air equipment, gas detectors and breathing air supply trailers. We are an authorized dealer for fire-retardant and Nomex® safety clothing and a variety of equipment lines.
U.S. Government Services. We provide government services, primarily in building and managing fueling systems. Since 1981, we have established our position with U.S. government agencies as a leading engineering contractor for jet fuel storage as well as aircraft fueling facilities, having performed the engineering for major projects at eight U.S. military bases, including three air bases outside the United States. The award of these projects was based largely on contractor experience and personnel qualifications. In the past 10 years, we have also won six “Design-Build-Own-Operate-Maintain” projects to provide fueling facilities at military bases in the United States for the U.S. Defense Energy Support Center. From time to time we add additional features to these facilities such as tanks and pumps for alternative fuels. In 2009, we were selected as a contractor by the U.S. Navy’s Naval Facilities Engineering Command (“NAVFAC”). We compete for task orders under the Engineering Service Center’s multiple-award Indefinite Delivery, Indefinite Quantity (“IDIQ”) contract for assessments, inspections, repair and construction services for POL systems at U.S. Navy locations worldwide. The total contract value is up to $350 million. In August 2010, the NAVFAC awarded Willbros Government Services five separate task orders under its global $350 million IDIQ construction and construction services contract for POL fuel systems. The task orders include various inspections, construction and repair at Eielson Air Force Base, AK; Misawa Air Force Base, Japan; Naval Air Station Oceana, Virginia Beach, VA; Naval Support Activity, Panama City, FL; and Naval Air Weapons Station, China Lake, CA. The work began in August and is scheduled for completion in early 2011. We continue to compete for additional task orders under this IDIQ contract.
Engineering Services. The acquisition of Wink in July 2009 enables us to provide project management, engineering and material procurement services to the refining industries and government agencies, including chemical/process, mechanical, civil, structural, electrical, instrumentation/controls and environmental. We provide our engineering services through resources located at the project site or at our offices in Louisiana.
Our comprehensive services include, among others:
   
project development, conceptual design, front-end engineering and feasibility studies;
   
project engineering services;
   
definitive design and drafting services;
   
project management, estimating, scheduling and controls;
   
turnkey EPC arrangements;
   
field engineering and construction liaison services;
   
material and services procurement;
   
planning and management of maintenance programs; and
   
topographic, hydrographic and engineering as-built surveying, including the establishment of rights-of-way for public utilities and industrial uses.
These services are furnished to a number of oil, gas, power, refining and government clients on a stand-alone basis, as well as part of EPC contracts undertaken by us.

 

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EPC Services. The refining and process industries strive to minimize costs through operating efficiencies and hiring experienced process engineering as needed. It is often more cost effective to engage a contractor to oversee and manage the planning, engineering, procurement, installation and commissioning of new capacity additions, revamps or new process units to support the need to meet new refining or manufacturing specifications. Our experience and capability covers the breadth of all process units in a refinery allowing us to offer clients a single source solution for expansion and revamp programs. We seek to do this in the most efficient, competitive manner and supply both our own personnel and supplemental services of other contractors as needed.
Utility T&D
We provide a wide range of services in electric power and natural gas transmission and distribution, which include comprehensive maintenance and construction, repair and restoration of utility infrastructure.
Electric Power T&D Services
We provide a broad spectrum of overhead and underground electric power T&D services, from the maintenance and construction of high-voltage transmission lines to the installation of local service lines and meters.
Electric Power Transmission and Substation. We maintain and construct overhead and underground transmission lines up to 500-kV. Overhead transmission services include the installation, maintenance and repair of transmission structures involving wood, concrete, steel pole and steel lattice tower configurations. Underground transmission services include the installation and maintenance of underground transmission cable and its associated duct, conduit and manhole systems. Electric power transmission also includes substation services, which involve the maintenance, construction, expansion, calibration and testing of electric power substations and components. We subcontract related electric power design and engineering work if required.
Electric Power Distribution. We maintain, construct and upgrade underground and overhead electric power distribution lines from 34.5-kV to household voltage levels. Our services encompass all facets of electric power distribution systems, including primary and secondary voltage cables, wood and steel poles, transformers, switchgear, capacitors, underground duct, manhole systems, residential and commercial and electric meter installation.
Emergency Storm Response. Our nationwide emergency storm response capabilities span both electric power transmission and distribution systems. We provide storm response services for our existing customers (“on-system”) as well as customers with which we have no ongoing Master Service Agreement (“MSA”) relationships (“off-system”). Typically with little notice, our crews deploy nationally in response to hurricanes, ice storms, tornadoes, floods and other natural disasters which damage critical electric T&D infrastructure. Some notable examples of major emergency storm response deployments in 2008 include the rebuilding of electric power distribution systems damaged by Hurricane Gustav in Louisiana, Hurricane Ike in Texas and ice storms in New England.
Cable Restoration and Assessment. In the U.S. and internationally, we offer two complementary services for the restoration and assessment of underground power cables to utilities:
   
CableCURE® is a proprietary process for the restoration of aged underground electric power cables. Using the process, we inject silicone-based CableCURE® fluid into electrical cables at a transformer or other termination point while the lines remain energized. The fluid extends the life of electric power cables by creating a barrier to moisture and repairs and prevents damage caused by water treeing (a type of progressive failure of the insulation caused by water absorption). We perform initial testing to determine if the cable can be treated using CableCURE® technology, treat cables that we determine are good candidates and often provide replacement services for those that are not. We have a worldwide exclusive license for this technology from Dow Corning, which holds the patents on the CableCURE® fluid. We also hold a number of patents on certain of the materials associated with the treatment process including Dimethyldibutoxysilane fluid developed by UtilX Corporation. We have injected over 17,000 miles of cable to date backed by a 20 year warranty.
   
CableWISE® is a proprietary, non-destructive online electrical system-condition assessment process that enables electric power utilities and a wide range of commercial and industrial facilities to evaluate the condition of cable systems, transformers and switchgear. Knowing a cable system’s weaknesses enables owners, asset managers and reliability engineers to be proactive in finding and fixing problems before they cause outages. We hold the patent and trademark to CableWISE®.

 

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Natural Gas T&D Services
We provide a full spectrum of natural gas T&D services, from the maintenance and construction of large diameter transmission pipelines through the installation of residential natural gas service.
Natural Gas Transmission. We construct, maintain and upgrade steel natural gas transmission pipelines in diameters up to 42 inches. Our services include right-of-way clearing, trenching, transporting, welding and laying pipe, post-construction testing and restoration. We construct and maintain upstream gathering systems, including well connects and compressor stations, for our natural gas and, to a lesser extent, oil industry customers. While most of our projects have been in support of natural gas transmission, we have also constructed, maintained and upgraded pipelines for transportation of other gases and liquids. Additionally, we offer other complementary services, including pipeline integrity assessments, hydrostatic testing, cathodic protection and spill remediation.
Natural Gas Distribution Pipeline. We construct, maintain and upgrade natural gas distribution pipelines. Our services include trenching, transporting, welding or fusing and laying pipe, post-construction integrity testing, site restoration and meter setting.
Specialty Services
We also provide other specialty services to customers nationwide. These services include:
   
Utility-line Locating. Our crews locate underground electric power, gas, telecom, water, cable and sewer utilities prior to excavation. Our locating services sometimes require a physical visit to the location whereby our employees will locate and mark utility infrastructure. In other cases we are able to provide the excavating party a clearance to dig without having to physically visit the location.
   
Stray Voltage and Gas Leak Detection. Our crews test for stray voltage and gas leaks in areas where these problems are suspected. Stray voltage typically arises through a failure to properly ground electrical equipment and may result in injury to the public. Similarly, gas leaks often occur as a result of the deterioration of gas distribution infrastructure.
   
Large-Bore Horizontal Directional Drilling (HDD). We provide HDD services nationwide with a total of five large-bore directional drills ranging from 220,000 to one million pounds of pullback force. These HDD rigs are typically deployed in support of large pipeline construction projects as well as underground crossings of environmentally sensitive areas and can be deployed on projects throughout North America.
   
Telecommunications. Our crews install and maintain overhead and underground telecommunications infrastructure, including conventional telephone cables, fiber optic installation cables, fiber to the premises (commonly referred to as FTTP), cellular towers, broadband-over-powerline and cable television lines.
   
Other. On a limited basis, we also offer certain commercial electric power, environmental remediation, water and sewer and civil construction services.
Current Market Conditions
We continue to advance our strategic objective of becoming a more diversified, global engineering and construction company delivering discrete and integrated engineering, procurement, construction, program management, maintenance and life cycle extension solutions tailored to the needs of our customers. The economic challenges over the past two years appear to be abating and we believe the long term fundamentals continue to support increased activity in the industries we serve. However, near term uncertainties may continue to impact capital and maintenance expenditure decisions of our customers in 2011. Inquiry levels in all three segments of our business have improved over the past two quarters, and contract awards have risen, but not to a level that corresponds to the increase in inquiries. The level of uncertainty around new projects and investments in our markets has diminished, but we continue to be challenged to forecast future impacts on our business, particularly with respect to timing.

 

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Upstream Oil & Gas
In the Upstream Oil & Gas segment, we believe additional pipeline infrastructure build-out is required to meet requirements from drilling activities that began years ago in the prolific natural gas shale and other unconventional gas plays in North America. Record levels of natural gas storage in the United States have receded in the winter months of 2010, and, despite depressed industrial demand, we continue to see new investment by major integrated oil companies, such as ExxonMobil, in North American shale gas plays. Historically, our upstream business is characterized by larger, complex projects which evolve over time as engineering and environmental studies and regulatory filings precede actual construction. The high levels of activity in the shale plays in North America are led by exploration and production companies and we believe a shift in our customer base is underway as more capital flows into field development, gathering systems and lateral line development. We anticipate that one consequence of this shift will be more projects of smaller scope and scale. We expect our customers to place more emphasis on local presence, integrated service delivery and flexible response to projects with short timelines and urgent completion dates. We believe the build-out of large diameter cross country pipeline systems has outpaced the smaller lines and field infrastructure and that the market will reflect less activity for large diameter projects. Delays of certain major projects anticipated to be underway in 2011 have also caused us to view the smaller, regional projects as a larger part of the market for our services going forward, particularly in 2011. We expect bidding for projects in 2011 to be highly competitive, but we also believe our pricing, and, therefore, our value proposition, will enable us to win work with appropriate risk-adjusted margins.
As pipeline system owners seek ways to decrease their maintenance and system integrity costs, we believe there are opportunities to expand our Manage & Maintain services beyond the current alliance with NiSource. We believe, over time, other owners will consider outsourcing Manage & Maintain activities to expert service providers such as ourselves in order to focus on their core competencies and strategic objectives. Additionally, we expect the outcome of these programs to create more opportunities for our specialty services offering, which provides services related to the operation, repair and rehabilitation of pipelines and other hydrocarbon processing facilities.
Markets in Canada, driven by activity related to the oil sands reserves, should continue to attract capital as a result of the perceived low political risk and higher crude prices. We have begun to see large capital projects, such as Imperial’s Kearl Oil Sands, Suncor’s Firebag and Canadian Natural Resources’ Horizon expansion, reinitiated in Western Canada as a result of more favorable economics related to lower input prices, primarily steel and labor, and increased crude prices. There has been margin pressure on services associated with the obligatory maintenance for oil sands production, and owners are seeking cost savings. We believe our understanding of our customers’ needs allows us to identify mutual cost savings and as such provides increased opportunities for us to deliver solutions that align with their expectations.
We believe that our successful business model in Oman, where we have been active and profitable since 1965, is a viable business model that we can leverage to establish a commercial presence in other Middle East locations, but current unrest in North Africa and the Middle East reinforces our focus on North America. Our investment in establishing a presence in Libya, while resulting in contract awards, did not yield any notice to proceed on the subject awards and we exited this market at the end of 2010.
Green initiatives may present market opportunities to evaluate certain sequestration and transportation projects (for example, carbon dioxide pipelines) as government policy supports environmental projects through initiatives and grants.
Downstream Oil & Gas
We believe the current business environment dictates additional reduction in refinery capacity which will ultimately increase utilization rates, leading to improved economics for the remaining market participants. It is our expectation that, with improved utilization rates and recovery in product demand, the refining industry will resume investments in capital projects not only to maintain and improve process efficiency, but also to address expectations for more stringent regulatory requirements and shifting crude compositions. We believe our integrated services offering, enhanced by the acquisition of our Downstream engineering unit, favorably positions us to participate in this expected increase in small, high return capital projects. The timing of the anticipated recovery of the small capital projects market remains uncertain and we have reduced our costs in this segment to enhance our returns in a tight market. We believe we can sustain the level of performance generated in the past two quarters until the industry improves its utilization rates and refining margins. For 2011, we expect a turnaround and maintenance services market similar to that experienced in 2010, with similar levels of activity and risk of delays and cancellations.

 

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Our government services business is benefiting from increased management focus as highlighted by our selection as a contractor by the U.S. Navy on the NAVFAC IDIQ contract, allowing us to compete for $350 million in task orders for petroleum, oil and lubricants maintenance and rehabilitation assignments. This contract is now in the second of a three year term and we anticipate additional opportunities from our government services group, particularly in the area of fuels storage and handling which aligns with our relevant experience.
Utility T&D
We believe we are entering a period of substantial activity in the electric transmission construction market in the United States. Over 16,000 miles of new electric transmission lines are planned for the five year period ending in 2015. We are confident our experience and management tools used to manage for the growth we experienced in our legacy pipeline construction business will enable us to take full advantage of this anticipated opportunity. Our alliance with Oncor, which is expected to provide over $500 million in construction assignments to us on the Texas Competitive Renewable Energy Zones (“CREZ”) transmission line construction work committed to Oncor over the next three years, gives us the opportunity to bring these skills and tools into our new segment and to expand our capability and capacity to compete for and perform construction projects in this burgeoning market. We also believe we are well-positioned in the Northeast to gain more experience and further enhance our qualifications to perform major transmission line construction in this region, exemplified by recent additions to backlog for transmission line construction in Maine. Our electric distribution business is still hampered by the downturn in new housing starts, but we believe this business has troughed, although the pace of recovery is still uncertain. According to at least one infrastructure research report, the market fundamentals indicate a capacity shortage for transmission construction could develop in the next two years, followed by a similar shortage for electric distribution construction.
Our Vision
We continue to believe that long-term fundamentals support increasing demand for our services and substantiate our vision for Willbros to be a diversified, global provider of professional engineering, construction and maintenance solutions addressing the entire asset lifecycle of global energy infrastructure.
To accomplish this, we are actively working towards achieving the following objectives:
   
Integrating the InfrastruX acquisition, which we believe advances our desire to diversify our end markets and geographic exposure to better serve clients and mitigate market specific risk;
   
Increasing professional services (project/program management, engineering, design, procurement and logistics) capabilities to minimize cyclicality and risk associated with large capital projects in favor of recurring service work;
   
Positioning Willbros as a service provider and employer of choice;
   
Developing long-term client partnerships and alliances by exceeding performance expectations and focusing team driven sales efforts on key clients; and
   
Establishing industry best practices, particularly for safety and performance.
Our Values
We believe the values we adhere to as an organization shape the relationships and performance of our company. We are committed to strong Leadership across the organization to achieve Excellence, Accountability and Compliance in everything we do, recognizing that Compliance is the catalyst for successfully applying all of our values. Our core values are:
   
Safety — always perform safely for the protection of our people and our stakeholders;
   
Honesty & Integrity — always do the right thing;
   
Our People — respect and care for their well being and development; maintain an atmosphere of trust, empowerment and teamwork; ensure the best people are in the right position;
   
Our Customers — understand their needs and develop responsive solutions; promote mutually beneficial relationships and deliver a good job on time;
   
Superior Financial Performance — deliver earnings per share and cash flow and maintain a balance sheet which places us at the forefront of our peer group;

 

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Vision & Innovation — understand the drivers of our business environment; promote constant curiosity, imagination and creativity about our business and opportunities; seek continuous improvement; and
   
Effective Communications — present a clear, consistent and accurate message to our people, our customers and the public.
We believe that adhering to and living these values will result in a high performance organization which can differentiate itself and compete effectively, providing incremental value to our customers, our employees and all our stakeholders.
Our Strategy
We work diligently to apply these values every day and use them to guide us in the development and execution of our strategy which we believe will increase stockholder value by leveraging the full resources and core competencies of an integrated Willbros business platform. Key elements of our strategy are as follows:
Stabilize the Revenue Stream with Recurring Services
We believe increasing the level of revenue generated by recurring services will make our business model more predictable and allow us to reduce our dependence on large capital projects which are more cyclical in nature. Additionally, we believe a more stable revenue stream will enable us to profitably scale our offerings to match changing market conditions. To that end, we have emphasized our Manage & Maintain service offering and continue to pursue new alliances with owner/operators of major infrastructure facilities, whereby we provide core teams of engineers and project managers having the ability to flex with the engineering and project management needs of the client. Our July 2010 acquisition of InfrastruX also significantly increases our recurring services component through the high level of revenue generated by Master Service Agreements (“MSAs”), which account for 77 percent of revenue generated by our Utility T&D segment.
Focus on Managing Risk
We have implemented a core set of business conduct practices and policies that have fundamentally improved our risk profile. Examples include diversifying our service offerings and end markets to reduce market specific exposure, and focusing on contract execution risk starting with our opportunity review process and ending at job completion. In today’s economic environment, acknowledging the importance of risk management is paramount to success. It is emphasized throughout our organization and covers all aspects of a project from strategic planning and bidding to contract management and financial reporting.
   
Focus resources in markets with the highest risk-adjusted return. The majority of our resources are focused on North America as we believe North America continues to offer us significant opportunities with attractive risk-adjusted returns. Opportunities for our expanded service offerings are expected to result from the ongoing development of unconventional gas production in shale gas plays, increased emphasis on the maintenance and integrity of existing infrastructure and facilities, high value-added small capital projects to meet environmental, regulatory and product slate requirements in the refining sector, and new electric infrastructure development opportunities. We will focus on integration and optimization of our complementary service offerings to deliver superior results.
     
While our operations are currently concentrated in North America, we have examined the markets for opportunities to further diversify our geographic footprint into international markets that provide attractive risk-adjusted returns. We have concluded that North America continues to offer the most attractive risk-adjusted returns at this time. Our extensive international experience remains a differentiator for us and we will continue to selectively consider international opportunities.
   
Maintain a conservative contract portfolio and limit contract execution risk. While we will continue to pursue a balanced contract portfolio, current market dynamics indicate our U.S. pipeline operations, as well as other service offerings, are in a much more competitive period, characterized by competitive pricing and more fixed price contracts. We believe our fixed price execution experience, our recent initiatives to realign our cost structure to the rapidly changing market, our improved systems and our ongoing focus on risk management provide us a competitive advantage versus many of our competitors. We prefer to maintain a risk-limited project portfolio.

 

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Configure operating segments to minimize market risk. We have recognized and responded to shifts in the markets addressed by both our Upstream Oil & Gas and Downstream Oil & Gas segments by reducing equipment and personnel levels to hold certain resources, key teams and skill sets and maximize their chargeability, keeping in mind future opportunities and commitments. We are currently addressing our Utility T&D segment and corresponding requirements as we have previously done with our other two segments.
Leverage Industry Position and Reputation into a Broader Service Offering
We believe the long term dynamics supporting the global energy infrastructure market will continue to provide attractive opportunities. Our established service platform, capabilities and track record position us to expand our expertise into a broader range of related service offerings. We intend to leverage our project management, engineering and construction skills to provide additional service offerings, such as instrumentation and electrical services, turbo-machinery services and environmental services, and to enhance our ability to offer sole source solutions and develop alliances and frame agreements with strategic customers. We believe that a more balanced mix of recurring services, such as program management and maintenance services, together with our traditional project work, will enhance the earnings profile of our business.
We have pursued selective acquisitions to complement our organic expansion strategies and to reduce our dependence on the cyclical large-diameter cross-country pipeline construction market. We began this process in 2007 with the InServ and Midwest acquisitions that expanded our service offerings as well as the geographies where we deliver those services. Our July 2007 acquisition of Midwest significantly enhanced our presence in mainline pipeline construction in Western Canada. Our November 2007 acquisition of InServ complemented our service offerings to our traditional market of engineering and construction services in the midstream hydrocarbon transportation industry. In July 2009, our acquisition of the engineering business of Wink Companies, LLC (“Wink” or “Downstream engineering business unit”), when combined with our existing downstream offering, created a platform to provide integrated EPC services to the downstream market, mirroring our upstream capabilities. More recently, on July 1, 2010, we closed on the acquisition of InfrastruX, an electric power and natural gas transmission and distribution contractor with service delivery capabilities from regional operating centers based primarily in the South Central, Midwest and East Coast energy corridors. We believe this acquisition gives us a viable position in the large and fast growing market for electric transmission infrastructure as well as completing our capability to provide fully integrated services from engineering through construction and integrity services for the full spectrum of natural gas transmission and distribution. Our near term focus will be on integration and optimization of this transformational acquisition. We take a long term perspective on acquisitions which we believe will build strong, diversified platforms to drive future stockholder value.
Maintain Financial Flexibility
Maintaining the financial flexibility to meet the material, equipment and personnel needs to support our project commitments, as well as the ability to pursue our expansion and diversification objectives, is critical to our growth. We view financial strength and flexibility as a fundamental requirement to fulfilling our strategy. As of December 31, 2010, we had cash and cash equivalents of $141,101. On July 1, 2010, and as part of the transaction financing for the acquisition of InfrastruX, we entered into the 2010 Credit Agreement that provides for a $475,000 senior secured credit facility consisting of a four-year $300,000 Term Loan and a three year revolving credit facility of $175,000. The 2010 Credit Agreement replaces our three-year $150,000 senior secured credit facility, which was scheduled to expire in November 2010. On March 4, 2011, we amended our 2010 Credit Agreement (the “Amendment”). The Amendment allows us to make certain dispositions of equipment, real estate and business units. In most cases, proceeds from these dispositions would be required to pay down the existing Term Loan made pursuant to the Credit Agreement. Financial covenants and associated definitions, such as Consolidated EBITDA, were also amended to permit us to carry out our business plan and to clarify the treatment of certain items. We have agreed to limit our revolver borrowings under the Credit Agreement to $25,000, with the exception of proceeds from revolving borrowings used to make any payments in respect of our Convertible Senior Notes until our total leverage ratio is 3.0 to 1 or less. However, the Amendment does not change the limit on obtaining letters of credit. The Amendment also modifies the definition of Excess Cash Flow to include proceeds from the TransCanada Pipeline Arbitration, which would require us to use all or a portion of such proceeds to further pay down the Term Loan in the following fiscal year of receipt.

 

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Leverage Core Service Expertise into Additional Full EPC Contracts
Our core expertise and service offerings allow us to provide our customers with a single source EPC solution which creates greater efficiencies and benefits both our customers and our company. We believe our upstream EPC and our downstream EPC, which are focused on small to mid-sized capital projects, are relatively unique in our respective markets, providing us with a competitive advantage in providing these services. In performing integrated EPC contracts, we often perform front-end engineering and design services while establishing ourselves as overall project managers from the earliest stages of project inception and are, therefore, better able to efficiently determine the design, permitting, procurement and construction sequence for a project in connection with making engineering decisions. Our customers benefit from a more seamless execution; while for us, these contracts often yield consistent profit margins on the engineering and construction components of the contract compared to stand-alone contracts for similar services. Additionally, this contract structure allows us to deploy our resources more efficiently and capture the engineering, procurement and construction components of these projects. The acquisition of Wink enabled us to provide EPC services to the downstream market, thus mirroring our upstream capabilities.
GEOGRAPHIC REGIONS
We operate globally, but have concentrated our operations in recent years on certain markets in North America and the Middle East. Our continuing operations contract revenue by geographic region for recent years is shown in the following table:
                                                 
    Year Ended December 31,  
    2010     2009     2008  
    Amount     Percent     Amount     Percent     Amount     Percent  
Contract Revenue
                                               
United States
  $ 924,590       77.5 %   $ 939,985       74.6 %   $ 1,440,239       75.3 %
Canada
    193,841       16.3 %     254,420       20.2 %     387,498       20.3 %
Oman
    73,589       6.2 %     65,368       5.2 %     84,967       4.4 %
Other
    392       0.0 %           0.0 %           0.0 %
 
                                   
Total
  $ 1,192,412       100.0 %   $ 1,259,773       100.0 %   $ 1,912,704       100.0 %
 
                                   
United States
Upstream Oil & Gas We believe that the United States will continue to be an important market for our services. Pipeline infrastructure demand in the United States is currently driven by unconventional natural gas and Canadian oil sands development. The February 2011 Oil & Gas Journal survey of planned worldwide pipeline construction indicates planned projects, for 2011 and beyond, in the United States and Canada, of nearly 13,000 miles, a decrease of approximately 31 percent from 2010. Proposal activity, a leading indicator for large diameter pipeline construction has plateaued, and, while we are actively pursuing a similar dollar volume of projects as at the end of 2009, the market is comprised of more and smaller contracts, with less large diameter work being offered. Our acquisition of InfrastruX in July 2010 adds complementary small pipe gathering and field infrastructure capabilities and extends our service reach to the city gate and into the gas distribution market. The acquisition also gives us regional presence in the active shale plays in the Northeast, South Central and Southwest markets for natural gas and liquids infrastructure. Based on inquiries and announced projects, we anticipate the number of miles constructed will be down again in 2011. It is uncertain that any increase will be noted in 2012 or 2013. Additionally, we can observe that the industry has returned to more seasonal patterns of execution from early spring to late fall, which will compress project activity into a nine-month period.
In the current environment, oil and gas energy producers appear to be focusing development budget spending on preserving acreage that must be drilled and exploiting those areas which offer more oil and gas liquids production, given the great disparity in oil and gas prices. This implies that near term activity will be greater in the “oilier” shale plays such as the Eagle Ford, Niobrara and Bakken, hence our strategic initiative to devolve our U.S. construction model to one of more regionally dispersed resources. With natural gas now viewed as cheap and abundant, we expect to see more opportunities to participate in gas fueled electric generation projects, particularly to replace retiring coal plants. While liquefied natural gas (“LNG”) appears to be disadvantaged in the current North American market, there could be opportunity to participate in LNG export projects going forward. Environmental concerns will likely continue to require careful, thorough and specialized professional engineering and planning for all new facilities within the oil, gas and power sectors. Furthermore, the demand for replacement and rehabilitation of pipelines is expected to increase as pipeline systems in the United States approach the end of their design lives and population trends influence overall energy distribution needs. Our Manage & Maintain service offering, which focuses on pipeline systems maintenance and integrity could benefit from increased regulatory scrutiny of aging pipeline systems. We are recognized as an industry leader in the United States for providing project management, engineering, procurement and construction services. We maintain a staff of experienced management, construction, engineering and support personnel in the United States. We provide these services through engineering offices located in Denver, Colorado, Tulsa, Oklahoma, Kansas City, Missouri, and Houston, Texas. Construction operations based in Houston, Texas, with regional offices in the major shale plays, provide the majority of construction services in the United States.

 

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Downstream Oil & Gas — The United States remains the primary market for our downstream oil and gas services. With a nationwide reach, we have experience serving over 100 of the operable refineries in the country. While capital budget reductions and project delays invoked by our customers have diminished spending on capital construction projects of the type performed by our Downstream Oil & Gas segment, many of our services are less dependent upon capital expenditures. In particular, turnaround and maintenance projects are performed on a more routine basis and are typically less susceptible to fluctuations in hydrocarbon prices, although many of these projects were delayed in the difficult environment of the past year. With the Clean Air Act of 1990 pushing the refining industry to meet stringent limitations on the sulfur content in gasoline fuels, Downstream Oil & Gas benefited from the influx of Clean Fuels projects from 2000 to 2005. We expect a similar scenario in the next few years, as refiners will be required to meet other mandates by the Environmental Protection Agency (“EPA”), including reducing the sulfur content level in diesel fuels and reducing the benzene content in other motor fuels; however, forecasting the timing of such projects remains challenging. Many U.S. refinery operators have delayed their maintenance and turnaround projects to the extent possible, and, while we believe certain facilities have reached the limit on delays due to both safety and operational considerations, last minute delays and cancellations are still possible in an uncertain business environment. We believe we have successfully rationalized our downstream model to be competitive and to operate profitably in this tight market. Our integrated service offering, led by our downstream engineering group, should position us for an anticipated improvement in the small capital project market, although the timing of the anticipated improvement remains uncertain. The storage tank market does offer a bright spot as we have seen an increase in both the number and size of inquiries over the past two quarters.
We have also provided significant engineering and facility management services to U.S. government agencies during the past 25 years, particularly in fuel storage and distribution systems and aircraft fueling facilities. Based on our recent selection by the U.S. Navy as a contractor to compete for task orders under the NAVFAC IDIQ contract for assessments, inspections, repair and construction services for petroleum, oil and lubricant systems at U.S. Navy locations worldwide, we expect to continue to grow our presence in this market.
Utility T&D — Our acquisition of InfrastruX in July 2010 gives us presence and relevant experience in the electric transmission and distribution markets, particularly in the Northeast and Southwest. In the Northeast we provide both transmission and distribution maintenance and construction services and have recently increased our visibility with contract awards in Maine for transmission line construction and in New York for solar powered generation plant construction. We believe continued focus on system reliability will provide additional transmission line construction opportunities in this region and the large base of both transmission and distribution infrastructure in place affords recurring services work under existing MSAs. In the Southwest, our model is anchored by our alliance agreement with Oncor. Under this agreement, we are the preferred contractor for the construction of Oncor’s portion of the CREZ work that is scheduled to be completed in 2013. We expect this assignment to generate over $500 million in construction revenue for our Utility T&D segment over the next three years. Our Utilty T&D segment also participates in regional markets through offices in the Midwest and provides specialty electric cable restoration services through its Utilx business unit. We believe we are entering a period of substantial activity in the electric transmission construction market in the United States.
Canada
Rapid declines in global oil prices since mid-2008, following significant cost escalations in the 2006-2008 period, increased uncertainty regarding the near term economic viability of many investments in the oil sands region of northern Alberta, Canada. As a result, many key participants in the region reduced capital expenditure plans during 2009 and, in some cases, delayed significant capital projects. However, the Canadian Energy Research Institute projections forecast investment by the end of 2020 in excess of Cdn $180 billion. Installed capacity, combined with ongoing investment, offers prospective fabrication and installation work as well as maintenance opportunities. Additionally, several options are under consideration with respect to transporting processed crude oil or unrefined bitumen to markets in the United States and Asia via export pipelines from the region. Unconventional shale gas and oil is also expected to drive additional infrastructure needs as the Bakken, Horn River and Muskwa shale plays are developed. Unrest in North Africa and the Middle East has caused oil prices to rise above $100/bbl in early 2011. Uncertainty and political risk are expected to result in additional investment and projects in the oil sands in Canada. Our construction, fabrication and maintenance services in Canada are provided primarily through facilities and resources located in Ft. McMurray and Edmonton, Alberta, where we maintain fabrication facilities. These facilities include capabilities for CCO to reduce erosion in transmission piping. CCO is a process of cladding pipe to withstand the highly abrasive bitumen sand slurry transported from mining sites to separation facilities. We also expect to have opportunities to participate in the expansion of storage tank capacity, which is required to support expansion of production in the oil sands. Our pipeline construction assets in Canada have visibility through the first quarter of 2012 and at December 31, 2010, were fully utilized with three major projects underway.

 

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Middle East
Our operations in the Middle East date back to 1948. We have worked in most of the countries in the region, with particularly heavy involvement in Kuwait, Oman and Saudi Arabia. Currently, we have ongoing operations in Oman, where we have been continuously active for more than 45 years. We maintain a fully staffed facility in Oman with equipment repair facilities and spare parts on site and offer construction expertise, repair and maintenance services, engineering support, oil field transport services, materials procurement and a variety of related services to our clients. We believe our presence in Oman and our experience throughout the region will enable us to successfully win and perform projects in this region. We have evaluated the opportunities in the Middle East and determined that we should focus our efforts on continued development of our operations in Oman and the extension of that expertise and capability into the markets in Bahrain and the United Arab Emirates, although current unrest in the region may preclude near-term expansion out of Oman. The recent discovery by PDO in Oman of 1 billion barrels of oil in place near the al-Ghubar field represents additional market opportunity.
Africa
Africa has been, over time, an important strategic market for us. We will continue to evaluate it among our international opportunities. Due to delays and the identification of other more attractive opportunities, we exited the Libyan market at the end of 2010.
Asia-Pacific
In Australia, our project-specific joint venture with Nacap, a well-known international pipeline contractor, to leverage our complementary capabilities and experience was unsuccessful in the pursuit of multiple large diameter pipeline EPC opportunities associated with proposed large coal seam methane to LNG developments. We currently do not have any identified attractive prospects in this region, but will entertain and evaluate any that arise.
South America
The political situation in several South American countries remains uncertain, and projects in these countries continue to be delayed. Because the governments of these countries continue to pursue agendas which include nationalization and/or renegotiation of contracts with foreign investors, we view these markets as having limited opportunities, but we consider opportunities on a case by case basis.
Backlog
In our industry, backlog is considered an indicator of potential future performance because it represents a portion of the future revenue stream. Our strategy is focused on backlog additions and capturing quality backlog with margins commensurate with the risks associated with a given project.
Backlog broadly consists of anticipated revenue from the uncompleted portions of existing contracts and contracts whose award is reasonably assured. Historically, our backlog has only included estimated work under MSAs for a period of 12 months or the remaining term of the contract, whichever is less. However, with the July 2010 acquisition of InfrastruX, we gained a significant alliance agreement with Oncor. Under this agreement, we are the preferred contractor for the construction of Oncor’s portion of the CREZ work that is scheduled to be completed in 2013. We expect this assignment to generate over $500 million in construction revenue for our Utility T&D segment over the next three years. With this as the primary catalyst, we have updated our backlog presentation to reflect not only the 12 month estimate, but also the full-term value of the contract as we believe that this information is helpful in providing additional long-term visibility. We determine the amount of backlog for work under ongoing maintenance contracts, or MSAs, by using recurring historical trends inherent in the MSAs, factoring in seasonal demand and projecting customer needs based upon ongoing communications with the customer. We also include in backlog our share of work to be performed under contracts signed by joint ventures in which we have an ownership interest.

 

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We believe the backlog figures are firm, subject only to the cancellation and modification provisions contained in various contracts. Additionally, due to the short duration of many jobs, revenue associated with jobs performed within a reporting period will not be reflected in quarterly backlog reports. We generate revenue from numerous sources, including contracts of long or short duration entered into during a year as well as from various contractual processes, including change orders, extra work, variations in the scope of work and the effect of escalation or currency fluctuation formulas. These revenue sources are not added to backlog until realization is assured. For the past several years we have put processes and procedures in place to identify contractual and execution risks in new work opportunities and believe we have instilled in the organization the discipline to price, accept and book only work which meets stringent criteria for commercial success and profitability. For additional discussion of backlog, see Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this Form 10-K.
The following table shows our backlog from continuing operations by operating segment and geographic location as of December 31, 2010 and 2009:
                                                                 
    As of December 31,  
    2010     2009  
    12 Month     Percent     Total     Percent     12 Month     Percent     Total     Percent  
Upstream Oil & Gas
  $ 311,326       32.9 %   $ 653,671       30.0 %   $ 243,194       62.5 %   $ 283,130       66.0 %
Downstream Oil & Gas
    107,077       11.3 %     107,077       5.0 %     146,156       37.5 %     146,156       34.0 %
Utility T&D
    527,912       55.8 %     1,415,279       65.0 %           0.0 %           0.0 %
 
                                               
Backlog
  $ 946,315       100.0 %   $ 2,176,027       100.0 %   $ 389,350       100.0 %   $ 429,286       100.0 %
 
                                               
                                 
    As of December 31,  
    2010     2009  
    Total     Percent     Total     Percent  
Total Backlog by Geographic Region
                               
United States
  $ 1,593,241       73.2 %   $ 398,744       92.9 %
Canada
    532,589       24.5 %     9,639       2.2 %
Middle East/North Africa
    45,728       2.1 %     20,903       4.9 %
Other International
    4,469       0.2 %            
 
                       
Backlog
  $ 2,176,027       100.0 %   $ 429,286       100.0 %
 
                       
                                         
    As of December 31,  
    2010     2009     2008     2007     2006  
12 Month Backlog
  $ 946,315     $ 389,350     $ 655,494     $ 1,305,441     $ 602,272  
Competition
We operate in a highly competitive environment. We compete against government-owned or supported companies and other companies that have financial and other resources substantially in excess of those available to us. In certain markets, we compete against national and regional firms against which we may not be price competitive. We have different competitors in different markets as recapped below.
Globally
   
Engineering — CH2M Hill, Gulf Interstate, Universal Pegasus, Trigon, Mustang Engineering and ENGlobal Engineering.

 

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United States
   
Upstream Oil & Gas Segment Construction — Associated Pipeline Contractors, Price Gregory Services, Sheehan Pipeline Construction, U.S. Pipeline and Welded Construction, Quanta Services, MasTec, Henkels & McCoy, Northern Pipeline Construction, Michels Corporation and Miller Pipeline. In addition, there are a number of regional competitors, such as Sunland, Dyess, Flint and Jomax.
   
Downstream Oil & Gas Segment — AltairStrickland, JV Industrial Companies, Plant Performance Services, KBR, Chicago Bridge & Iron and Matrix Services.
   
Utility T&D Segment — Quanta Services, MYR Group, MasTec and Pike Electric and larger privately-held companies such as Henkels & McCoy, Northern Pipeline Construction, Michels Corporation and Miller Pipeline.
Canada
   
Onshore Pipeline Construction — North American Energy Services, Flint Energy Services and OJ Pipelines.
   
Maintenance and field services — North American Energy Services, Flint Energy Services and Ledcor.
Oman
   
Oil Field Transport Services — Ofsat and TruckOman, both Omani companies.
   
Construction and the Installation of Flow Lines and Mechanical Services — Gulf Petrochemical Services (Oman), CCC (Greece), Dodsal (India), Saipem (Italy), Special Technical Services (Oman) and Galfar (Oman).
Other International
   
Construction — Technip (France), CCC (Greece), Saipem (Italy), Spie-Capag (France), Techint (Argentina), Bechtel (U.S.), Stroytransgaz (Russia), Tekfen (Turkey) and Nacap (Netherlands).
Contract Provisions and Subcontracting
Most of our revenue is derived from engineering, construction and EPC contracts. The majority of our contracts fall into the following basic categories:
   
firm fixed-price or lump sum fixed-price contracts, providing for a single price for the total amount of work or for a number of fixed lump sums for the various work elements comprising the total price;
   
cost plus fixed fee contracts where income is earned solely from the fee received;
   
unit-price contracts, which specify a price for each unit of work performed;
   
time and materials contracts where personnel and equipment are provided under an agreed-upon schedule of daily rates with other direct costs being reimbursable; and
   
a combination of the above (including lump sum payment for certain items and unit rates for others).
Changes in scope-of-work are subject to change orders to be agreed upon by both parties. Change orders not agreed to in either scope or price result in claims to be resolved in a dispute resolution process. These change orders and claims can affect our contract revenue either positively or negatively.
We usually obtain contracts through either competitive bidding or negotiations with long-standing clients. We are typically invited to bid on projects undertaken by our clients who maintain approved bidder lists. Bidders are pre-qualified on the basis of their prior performance for such clients, as well as their experience, reputation for quality, safety record, financial strength and bonding capacity.
In evaluating bid opportunities, we consider such factors as the client and their geographic location, the difficulty of the work, current and projected workload, the likelihood of additional work, the project’s cost and profitability estimates, and our competitive advantage relative to other likely bidders. We give careful thought and consideration to the political and financial stability of the country or region where the work is to be performed. The bid estimate forms the basis of a project budget against which performance is tracked through a project control system, enabling management to monitor projects effectively.

 

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All U.S. government contracts and many of our other contracts provide for termination of the contract for the convenience of the client. In addition, some contracts are subject to certain completion schedule requirements that require us to pay liquidated damages in the event schedules are not met as the result of circumstances within our control.
We act as the primary contractor on a majority of the construction projects we undertake. In our capacity as the primary contractor and when acting as a subcontractor, we perform most of the work on our projects with our own resources and typically subcontract only such specialized activities as hazardous waste removal, horizontal directional drills, non-destructive inspection, catering and security. In the construction industry, the prime contractor is normally responsible for the performance of the entire contract, including subcontract work. Thus, when acting as the primary contractor, we are subject to the risk associated with the failure of one or more subcontractors to perform as anticipated.
Under a fixed-price contract, we agree on the price that we will receive for the entire project, based upon specific assumptions and project criteria. If our estimates of our own costs to complete the project are below the actual costs that we may incur, our margins will decrease possibly resulting in a loss. The revenue, cost and gross profit realized on a fixed-price contract will often vary from the estimated amounts because of unforeseen conditions or changes in job conditions and variations in labor and equipment productivity over the term of the contract. If we are unsuccessful in mitigating these risks, we may realize gross profits that are different from those originally estimated and may incur losses on projects. Depending on the size of a project, these variations from estimated contract performance could have a significant effect on our operating results for any quarter or year. In some cases, we are able to recover additional costs and profits from the client through the change order process. In general, turnkey contracts to be performed on a fixed-price basis involve an increased risk of significant variations. This is a result of the long-term nature of these contracts and the inherent difficulties in estimating costs, and of the interrelationship of the integrated services to be provided under these contracts whereby unanticipated costs or delays in performing part of the contract can have compounding effects by increasing costs of performing other parts of the contract. Our accounting policy related to contract variations and claims requires recognition of all costs as incurred. Revenue from change orders, extra work and variations in the scope of work is recognized when an agreement is reached with the client as to the scope of work and when it is probable that the cost of such work will be recovered in a change in contract price. Profit on change orders, extra work and variations in the scope of work are recognized when realization is assured beyond a reasonable doubt. Also included in contract costs and recognized income not yet billed on uncompleted contracts are amounts we seek or will seek to collect from customers or others for errors or changes in contract specifications or design, contract change orders in dispute or unapproved as to both scope and price, or other customer-related causes of unanticipated additional contract costs (unapproved change orders). These amounts are recorded at their estimated net realizable value when realization is probable and can be reasonably estimated. Unapproved change orders and claims also involve the use of estimates, and it is reasonably possible that revisions to the estimated recoverable amounts of recorded unapproved change orders may be made in the near term. If we do not successfully resolve these matters, a net expense (recorded as a reduction in revenues), may be required, in addition to amounts that have been previously provided.
Contractual Arrangements
We provide services under MSAs and on a project-by-project basis. MSAs are typically one to three years in duration, but can be longer. Under our MSAs, our customers generally agree to use us to provide certain services in a specified geographic region on stipulated terms and conditions, including pricing and escalation. However, most of our contracts, including MSAs and our alliance agreement with Oncor, may be terminated by our customers on short notice. Further, although our customers assign work to us under our MSAs, our customers often have no obligation to assign work to us and are not required to use us exclusively, in some cases subject to our right of first refusal. In addition, many of our contracts, including our MSAs, are opened to public bid and generally attract multiple bidders. Work performed under MSAs is typically billed on a unit-price or time-and-materials basis. In addition, any work encountered in the course of a unit-price project that does not have a defined unit is generally completed on a time-and-materials basis.
Although the terms of our contracts vary considerably, pricing is typically based on a unit-price or fixed-price structure. Under our unit-price contracts, we agree to perform identified units of work for an agreed price. A “unit” can be as small as the installation of a single bolt or a foot of cable or as large as a transmission tower or foundation. The resulting profitability of a particular unit is primarily dependent upon the labor and equipment hours expended to complete the task that comprises the unit. Under fixed-price contracts, we agree to perform the contract for a fixed fee based on our estimate of the aggregate costs of completing the particular project. We are sometimes unable to fully recover cost overruns on our fixed-price contracts. We expect that industry trends could result in an increase in the proportion of our contracts being performed on a unit-price or fixed-price basis resulting in more profitability risk.

 

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Our storm restoration work, which involves high labor and equipment utilization, is typically performed on a time-and-materials basis and is generally more profitable when performed off-system rather than for customers with which we have MSAs. Our ability to allocate resources to storm restoration work depends on our capacity at that time and permission from existing customers to release some portion of our workforce from their projects.
Oncor alliance agreement
On June 12, 2008, we entered into a non-exclusive agreement with Oncor. Due to the extensive scope and long duration of the agreement, we refer to it as an alliance agreement. We summarize below the principal terms of the agreement. This summary is not a complete description of all the terms of the agreement.
Term, Renewals and Extensions. The agreement became effective on August 1, 2008 and will continue until expiration on December 31, 2018, unless extended, renewed or terminated in accordance with its terms.
Provision of Services, Spending Levels and Pricing. Under the agreement, it is anticipated that we will provide Oncor transmission construction and maintenance services (“TCM”), and distribution construction and maintenance services (“DCM”), pursuant to fixed-price, unit-price and time-and-materials structures. The fees we charge Oncor under unit-price and time-and-materials structures are set forth in the agreement, most of which are adjusted annually according to indices provided in the agreement. The agreement also includes a provision whereby Oncor receives pricing at least as favorable as we charge other customers for any “similar services” (which is not a defined term in the agreement). Management believes, based on our pricing practices and the nature and scope of the services we provide to Oncor, that we are in compliance with this provision.
We frequently hold meetings with Oncor to discuss its forecasted monthly and annual TCM and DCM spending levels. The agreement provides for agreed incentives and adjustments for us and for Oncor according to Oncor’s projected spending levels. Calculations based on projected spending levels are subject to subsequent adjustments based on actual spending levels. The agreement also requires that we provide dedicated resources to Oncor and that we meet or exceed minimum service levels as measured by specified performance indicators.
Termination. Oncor could in some cases seek to terminate for cause or limit our activity or seek to assess penalties against us under the agreement. Oncor may terminate the agreement upon 90-days notice or any work request thereunder without prior notice in each case at its sole discretion and may terminate the agreement upon 30-days notice in the event there is an announcement of the intent to undertake or an actual occurrence of a change in control of Oncor or InfrastruX. Oncor consented to the change of control of InfrastruX that resulted from our acquisition of InfrastruX. Oncor may also terminate the agreement for cause if, among other things, we breach and fail to adequately cure a representation or warranty under the agreement, we materially or repeatedly default in the performance of our material obligations under the agreement or we become insolvent.
In the event Oncor terminates the agreement for convenience or due to an anticipated or actual change of control of Oncor, Oncor must pay us a termination fee.

 

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Employees
At December 31, 2010, we directly employed a multi-national work force of 7,271 persons, of which approximately 85.1 percent were citizens of the respective countries in which they work. Although the level of activity varies from year to year, we have maintained an average work force of approximately 5,426 over the past five years. The minimum employment during that period has been 3,714 and the maximum was 7,271. At December 31, 2010, approximately 19.5 percent of our employees were covered by collective bargaining agreements. We believe relations with our employees are satisfactory. The following table sets forth the location of employees by work countries as of December 31, 2010:
                 
    Number of        
    Employees     Percent  
U.S. Upstream Oil & Gas
    540       7.4 %
U.S. Downstream Oil & Gas
    977       13.5 %
U.S. Utility T&D
    3,070       42.2 %
U.S. Administration
    112       1.6 %
Canada
    1,056       14.5 %
Oman
    1,500       20.6 %
Utility T&D International
    15       0.2 %
Other International — Libya
    1       0.0 %
 
           
Total
    7,271       100.0 %
 
           
Equipment
We own, lease and maintain a fleet of generally standardized construction, transportation and support equipment. In 2010 and 2009, expenditures for capital equipment were approximately $18,000 and $13,000, respectively. At December 31, 2010, the net book value of our property, plant and equipment was approximately $229,000.
All equipment is subject to scheduled maintenance to maximize fleet readiness. We continue to evaluate expected equipment utilization, given anticipated market conditions, and may buy or lease new equipment and dispose of underutilized equipment from time to time. In December 2010, we completed the sale of equipment having a net book value of $12,226 receiving proceeds of $15,103. Additionally, we have committed to a plan to dispose of $18,867 in additional properties and equipment, which is expected to be completed in 2011.
Facilities
The principal facilities that we utilize to operate our business are:
             
Principal Facilities
Business Unit   Location   Description   Ownership
U.S. Upstream Oil & Gas
  Houston, TX(1)   Equipment yard, maintenance facility, warehouse and office space   Own
 
           
 
  Houston, TX   Office space   Leased
 
           
 
  Kansas City, MO   Office space   Leased
 
           
 
  Tulsa, OK   Office space   Own
 
           
U.S. Downstream Oil & Gas
  Baton Rouge, LA   Office Space   Lease
 
           
 
  Catoosa, OK   Manufacturing, general warehousing and office space   Own

 

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Principal Facilities
Business Unit   Location   Description   Ownership
 
  Houston, TX   Office space   Lease
 
           
 
  St. Rose, LA   Office space   Lease
 
           
 
  Tulsa, OK   Manufacturing, general warehousing and office space   Own
 
           
U.S. Utility T&D
  Seattle, WA   Office space   Leased
 
           
 
  Buckeburg, Germany   Office and general warehouse   Leased
 
           
 
  Kent, WA   Office and general warehouse   Leased
 
           
 
  Pittsburgh, PA   Office and general warehouse   Leased
 
           
 
  Fitchburg, WI   Office and general warehouse   Leased
 
           
 
  Trafford, PA   Office and general warehouse   Leased
 
           
 
  Sherman, TX   Office and general warehouse   Leased
 
           
 
  McKinney, TX   Office and general warehouse   Own
 
           
 
  Ft. Worth, TX   Office space   Leased
 
           
 
  Henrietta, TX   Office and general warehouse   Leased
 
           
 
  Hauppauge, NY   Office and general warehouse   Leased
 
           
 
  Jacksonville, VT   Office and general warehouse   Leased
 
           
 
  Eunice, NM   Office and general warehouse   Leased
 
           
Canada
  Ft. McMurray, Alberta, Canada (1)   Fabrication and maintenance facility   Own
 
           
 
  Ft. McMurray, Alberta, Canada   Lay down area   Leased
 
           
 
  Ft. McMurray, Alberta, Canada   Office space   Leased
 
           
 
  Edmonton, Alberta, Canada   Fabrication and Module facility   Own
 
           
 
  Acheson, Alberta, Canada   Office space and equipment yard   Own
 
           
 
  Sherwood Park, Alberta, Canada   Office space   Leased
 
           
 
  Calgary, Alberta, Canada   Office space   Leased
 
           
Oman
  Oman   Office space, fabrication and maintenance facility   Leased
 
           
Headquarters
  Houston, TX   Office Space   Leased
     
(1)  
Location is currently classified as held for sale.
We lease other facilities used in our operations, primarily sales/shop offices, equipment sites and expatriate housing units in the United States, Canada and Oman. Rent expense for all leased facilities was approximately $12,400 in 2010 and $5,200 in 2009.

 

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Insurance and Bonding
Operational risks are analyzed and categorized by our risk management department and are insured through major international insurance brokers under a comprehensive insurance program, which includes commercial insurance policies, consisting of the types and amounts typically carried by companies engaged in the worldwide engineering and construction industry. We maintain worldwide master policies written mostly through highly-rated insurers. These policies cover our property, plant, equipment and cargo against all normally insurable risks, including war risk, political risk and terrorism in third-world countries. Other policies cover our workers and liabilities arising out of our operations. Primary and excess liability insurance limits are consistent with the level of our asset base. Risks of loss or damage to project works and materials are often insured on our behalf by our clients. On other projects, “builders all risk insurance” is purchased when deemed necessary. Substantially all insurance is purchased and maintained at the corporate level, with the exceptions being certain basic insurance, which must be purchased in some countries in order to comply with local insurance laws.
The insurance protection we maintain may not be sufficient or effective under all circumstances or against all hazards to which we may be subject. An enforceable claim for which we are not fully insured could have a material adverse effect on our results of operations. In the future, our ability to maintain insurance, which may not be available or at rates we consider reasonable, may be affected by events over which we have no control, such as those that occurred on September 11, 2001. In 2010, we were not constrained by our ability to bond new projects, nor have we been negatively impacted in early 2011.
Global Warming and Climate Change
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to warming of the earth’s atmosphere. As a result, there have been a variety of regulatory developments, proposals or requirements and legislative initiatives that have been introduced in the United States (as well as other parts of the world) that are focused on restricting the emission of carbon dioxide, methane and other greenhouse gases.
In 2007, the United States Supreme Court held that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act, if it represents a health hazard to the public. In December 2009, the EPA responded to that holding and issued a finding that the current and projected concentrations of greenhouse gases in the atmosphere threaten the public health and welfare of current and future generations, and that certain greenhouse gases contribute to the atmospheric concentrations of greenhouse gases and hence to the threat of climate change.
In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009 (sometimes referred to as the Waxman-Markey global climate change bill). The U.S. Senate considered but did not approve such legislation. The 2009 bill included many provisions that could potentially have had a significant impact on us as well as our customers. The bill proposed a cap and trade regime, a renewable portfolio standard, electric efficiency standards, revised transmission policy and mandated investments in plug-in hybrid infrastructure and smart grid technology. The net effect of the bill was to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas. Although proposals have been introduced in the U.S. Senate, including a proposal that would require greater reductions in greenhouse gas emissions than the American Clean Energy and Security Act of 2009, it is uncertain at this time whether, and in what form, legislation will be adopted by the U.S. Senate. For legislation to become law, both chambers of the U.S. Congress would be required to approve identical legislation. Both President Obama and the Administrator of the EPA have repeatedly indicated their preference for comprehensive legislation to address this issue and create the framework for a clean energy economy.
In September 2009, the EPA finalized a rule requiring nation-wide reporting of greenhouse gas emissions beginning January 1, 2010. The rule applies primarily to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent greenhouse gas emissions per year, and to most upstream suppliers of fossil fuels and industrial greenhouse gas, as well as to manufacturers of vehicles and engines.

 

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We do not know and cannot predict whether any of the proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business segments. Depending on the final provisions of such rules or legislation, it is possible that such future laws and regulations could result in increasing our compliance costs or additional operating restrictions as well as those of our customers. It is also possible that such future developments could curtail the demand for fossil fuels, which could adversely affect the demand for some of our services, which in turn could adversely affect our future results of operations. Likewise, we cannot predict with any certainty whether any changes to temperature, storm intensity or precipitation patterns as a result of climate change (or otherwise) will have a material impact on our operations.
Compliance with applicable environmental requirements has not, to date, had a material effect on the cost of our operations, earnings or competitive position. However, as noted above in connection with our discussion of the regulation of greenhouse gases, compliance with amended, new or more stringent requirements of existing environmental regulations or requirements may cause us to incur additional costs or subject us to liabilities that may have a material adverse effect on our results of operations and financial condition.

 

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Item 1A.  
Risk Factors
The nature of our business and operations subjects us to a number of uncertainties and risks.
RISKS RELATED TO OUR BUSINESS
Our business is highly dependent upon the level of capital expenditures by oil and gas, refinery, petrochemical and electric power companies on infrastructure.
Our revenue and cash flow are primarily dependent upon major engineering and construction projects. The availability of these types of projects is dependent upon the economic condition of the oil and gas, refinery, petrochemical and electric power industries, and specifically, the level of capital expenditures of oil and gas, refinery, petrochemical and electric power companies on infrastructure. The credit crisis in 2009, which continues to some extent, and related distress in the global financial system, including capital markets, as well as the global recession, continue to have an adverse impact on the level of capital expenditures of oil and gas, refinery, petrochemical and electric power companies and/or their ability to finance these expenditures. Our failure to obtain major projects, the delay in awards of major projects, the cancellation of major projects or delays in completion of contracts are factors that could result in the under-utilization of our resources, which would have an adverse impact on our revenue and cash flow. There are numerous factors beyond our control that influence the level of capital expenditures of these companies, including:
   
current and projected oil, gas and electric power prices, as well as refining margins;
   
the demand for gasoline and electricity;
   
the abilities of oil and gas, refinery, petrochemical and electric power companies to generate, access and deploy capital;
   
exploration, production and transportation costs;
   
the discovery rate of new oil and gas reserves;
   
the sale and expiration dates of oil and gas leases and concessions;
   
regulatory restraints on the rates that electric power companies may charge their customers;
   
local and international political and economic conditions;
   
the ability or willingness of host country government entities to fund their budgetary commitments; and
   
technological advances.
Our settlements with the DOJ and the SEC, and the prosecution of former employees, may negatively impact our ongoing operations.
In May 2008, the United States Department of Justice (“DOJ”) filed an Information and Deferred Prosecution Agreement (“DPA”) in the United States District Court in Houston concluding its investigation into violations of the Foreign Corrupt Practices Act (“FCPA”) by Willbros Group, Inc. and its subsidiary, Willbros International, Inc. (“WII”). Also in May 2008, we reached a final settlement with the SEC to resolve its previously disclosed investigation of possible violations of the FCPA and possible violations of the Securities Act of 1933 and the Securities Exchange Act of 1934. These investigations stemmed primarily from our former operations in Bolivia, Ecuador and Nigeria. The settlements together require us to pay, over approximately three years, a total of $32.3 million in penalties and disgorgement, plus post-judgment interest on $7.725 million of that amount. See Note 9 of our condensed consolidated financial statements included herein.
As part of our agreement with the DOJ, we are subject to ongoing review and regulation of our business operations, including the review of our operations and compliance program by a government-approved independent monitor. The independent monitor was appointed effective September 25, 2009. The activities of the independent monitor have had, and will continue to have, a material cost to us and will require significant changes in our processes and operations, the outcome of which we are unable to predict. In addition, the settlements, and the prosecution of former employees, may impact our operations or result in legal actions against us, including actions by foreign governments, in countries that are the subject of the settlements.

 

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Our failure to comply with the terms of settlement agreements with the DOJ and SEC would have a material adverse effect on our business.
Under our settlement with the DOJ, we are subject to the DPA, which has an initial term of three years and may be extended under certain circumstances, and, with respect to the SEC settlement, we are permanently enjoined from committing any future violations of the federal securities laws. As provided for in the DPA, with the approval of the DOJ, we retained a government-approved independent monitor, at our expense, for a two and one-half year period, who is reporting to the DOJ on our compliance with the DPA. Since the appointment of the monitor, we have cooperated and provided the monitor with access to information, documents, records, facilities and employees. On March 1, 2010, the monitor filed with the DOJ the first of three required reports under the DPA. In the report, the monitor reported numerous findings and recommendations with respect to the need for the improvement of our administrative internal controls, policies and procedures for detecting and preventing violations of applicable anti-corruption laws.
Findings and recommendations have been made concerning the need for improvement of policies and processes and internal controls related to the vetting of new employees, agents and consultants, disclosure, tracking and internal communications of conflicts of interest, our FCPA training program, the FCPA certification process, procurement and project controls and other administrative control procedures, as well as to improve our ability to detect and prevent violations of applicable anti-corruption laws.
The report also sets out for the DOJ’s review the monitor’s findings relating to incidents that came to the monitor’s attention during the course of his review which he found to be significant, as well as recommendations to address these incidents. We and the monitor have met separately with the DOJ concerning certain of these incidents. The monitor, in his report, did not conclude whether any of these incidents or any other matters constituted a violation of the FCPA. We do not believe that any of these incidents or matters constituted a violation of the FCPA based on our own investigations of the incidents and matters raised in the report. Notwithstanding our assessment, the DOJ could perform further investigation at its discretion of any incident or matter raised by the report.
We are now in the process of improving our hiring procedures and conflict of interest policies and have openly discussed these matters with the DOJ in the course of our compliance with the terms of the DPA. On May 1, 2010, we responded to the monitor’s report and advised the DOJ that we intend to implement all of the monitor’s recommendations. We have undertaken a disciplined approach to implementing the monitor’s recommendations and have incurred, and will continue to incur, significant costs as well as significant management oversight time to effectively implement the recommendations. The monitor’s second annual review occurred in the first quarter of 2011, and we expect to receive the second report of the monitor near the end of the first quarter of 2011.
The DOJ could determine during the term of the DPA that we have violated the FCPA or other laws based on the monitor’s findings or otherwise or not complied with the terms of the DPA, which requires our cooperation with the monitor and the DOJ, or that we have not been successful in implementing the monitor’s recommendations. Our failure to comply with the terms of the settlements with the DOJ and SEC could result in resumed prosecution and other regulatory sanctions. A criminal conviction of the charges that are subject to the DPA, or of other charges, could result in fines, civil and criminal penalties and equitable remedies, including profit disgorgement and injunctive relief, and would have a material adverse effect on our business. The settlements and the findings of the independent monitor could also result in third-party claims against us, which may include claims for special, indirect, derivative or consequential damages.
In addition, if we fail to make timely payment of the penalty amounts due to the DOJ and/or the disgorgement amounts specified in the SEC settlement, the DOJ and/or the SEC will have the right to accelerate payment, and demand that the entire balance be paid immediately. Our ability to comply with the terms of the settlements is dependent on the success of our ongoing compliance program, including:
   
our supervision, training and retention of competent employees;
   
the efforts of our employees to comply with applicable law and our Foreign Corrupt Practices Act Compliance Manual and Code of Business Conduct and Ethics;
   
our continuing management of our agents and business partners; and
   
our successful implementation of the recommendations of the independent monitor to further improve our compliance program and internal controls.

 

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We may continue to experience losses associated with our prior Nigeria-based operations which could have a material adverse effect on us.
On February 7, 2007, Willbros Global Holdings, Inc., formerly known as Willbros Group, Inc., a Panama corporation (“WGHI”), which is now a subsidiary of the Company and holds a portion of the Company’s non-U.S. operations, sold its Nigeria assets and Nigeria-based operations in West Africa to Ascot Offshore Nigeria Limited (“Ascot”), a Nigerian oilfield services company, for total consideration of $155 million (later adjusted to $130 million). The sale was pursuant to a Share Purchase Agreement by and between WGHI and Ascot dated as of February 7, 2007 (the “Agreement”), providing for the purchase by Ascot of all of the share capital of WG Nigeria Holdings Limited (“WGNHL”), the holding company for Willbros West Africa, Inc. (“WWAI”), Willbros (Nigeria) Limited, Willbros (Offshore) Nigeria Limited and WG Nigeria Equipment Limited.
In connection with the sale of its Nigeria assets and operations, WGHI and WII, another subsidiary of the Company, entered into an indemnity agreement with Ascot and Berkeley Group plc (“Berkeley”), the parent company of Ascot (the “Indemnity Agreement”), pursuant to which Ascot and Berkeley agreed to indemnify WGHI and WII for any obligations incurred by WGHI or WII in connection with the parent company guarantees (the “Guarantees”) that WGHI and WII previously issued and maintained on behalf of certain former subsidiaries now owned by Ascot under certain working contracts between the subsidiaries and their customers. Either WGHI, WII or both may be contractually obligated, in varying degrees, under the Guarantees with respect to the performance of work related to several ongoing projects. Among the Guarantees covered by the Indemnity Agreement are five contracts under which the Company estimates that, at February 7, 2007, there was aggregate remaining contract revenue, excluding any additional claim revenue, of $352 million and aggregate estimated cost to complete of $293 million. At the February 7, 2007 sale date, one of the contracts covered by the Guarantees was estimated to be in a loss position with an accrual for such loss of $33 million. The associated liability was included in the liabilities acquired by Ascot and Berkeley.
Approximately one year after the sale of the Nigeria assets and operations, WGHI received its first notification asserting various rights under one of the outstanding parent guarantees. On February 1, 2008, WWAI, the Ascot company performing the West African Gas Pipeline (“WAGP”) contract, received a letter from West African Gas Pipeline Company Limited (“WAPCo”), the owner of WAGP, wherein WAPCo gave written notice alleging that WWAI was in default under the WAGP contract, as amended, and giving WWAI a brief cure period to remedy the alleged default. We understand that WWAI responded by denying being in breach of its WAGP contract obligations, and apparently also advised WAPCo that WWAI “requires a further $55 million, without which it will not be able to complete the work which it had previously undertaken to perform.” We understand that, on February 27, 2008, WAPCo terminated the WAGP contract for the alleged continuing non-performance of WWAI.
Also, in February 2008, WGHI received a letter from WAPCo reminding WGHI of its parent guarantee on the WAGP contract and requesting that WGHI remedy WWAI’s default under that contract, as amended. WGHI responded to WAPCo, consistent with its earlier communications, that, for a variety of legal, contractual, and other reasons, it did not consider the prior WAGP contract parent guarantee to have continued application. In February 2009, WGHI received another letter from WAPCo formally demanding that WGHI pay all sums payable in consequence of the non-performance by WWAI with WAPCo and stating that quantification of that amount would be provided sometime in the future when the work was completed. In spite of this letter, we continued to believe that the parent guarantee was not valid. WAPCo disputes WGHI’s position that it is no longer bound by the terms of WGHI’s prior parent guarantee of the WAGP contract and has reserved all its rights in that regard.
On February 15, 2010, WGHI received a letter from attorneys representing WAPCo seeking to recover from WGHI under its prior WAGP contract parent company guarantee for losses and damages allegedly incurred by WAPCo in connection with the alleged non-performance of WWAI under the WAGP contract. The letter purports to be a formal notice of a claim for purposes of the Pre-Action Protocol for Construction and Engineering Disputes under the rules of the High Court in London, England. The letter claims damages in the amount of $265 million. At February 7, 2007, when WGHI sold its Nigeria assets and operations to Ascot, the total WAGP contract value was $165 million and the WAGP project was estimated to be approximately 82.0 percent complete. The remaining costs to complete the project at that time were estimated at slightly under $30 million. We are seeking to understand the magnitude of the WAPCo claim relative to the WAGP project’s financial status three years earlier.

 

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On August 2, 2010, we received notice that WAPCo had filed suit against WGHI under English law in the London High Court on July 30, 2010, for a sum of $273 million. WGHI has several possible defenses to this claim and is contesting the matter vigorously, but we cannot provide any assurance as to the outcome. We expect the litigation process to be lengthy; trial of the matter is scheduled to commence in June of 2012.
We currently have no employees working in Nigeria and have no intention of returning to Nigeria. If ultimately it is determined by an English Court that WGHI is liable, in whole or in part, for damages that WAPCo may establish against WWAI for WWAI’s alleged non-performance of the WAGP contract, or if WAPCo is able to establish liability against WGHI directly under the parent company guarantee, and, in either case, WGHI is unable to enforce its rights under the indemnity agreement entered into with Ascot and Berkeley in connection with the WAGP contract, WGHI may experience substantial losses, which could have a material adverse effect on our financial condition and liquidity. However, at this time, we cannot predict the outcome of the London High Court litigation, or be certain of the degree to which the indemnity agreement given in WGHI’s favor by Ascot and Berkeley will protect WGHI.
We have not established a reserve for potential losses in connection with the foregoing.
Our management has concluded that we did not maintain effective internal control over financial reporting as of December 31, 2010 because of the existence of a material weakness in our internal control over financial reporting. We have also had material weaknesses in our internal control over financial reporting in prior fiscal years. Failure to maintain effective internal control over financial reporting could adversely affect our ability to report our financial condition and results of operations accurately and on a timely basis. As a result, our business, operating results and liquidity could be harmed.
We have identified a material weakness in our internal control over financial reporting as of December 31, 2010. A description of this material weakness is included in Item 9A, “Controls and Procedures,” in this Form 10-K, together with our remediation plan.
As disclosed in our annual reports on Form 10-K for 2007, 2006, 2005 and 2004, management’s assessment of our internal control over financial reporting identified several material weaknesses. These material weaknesses led to the restatement of our previously issued consolidated financial statements for fiscal years 2002 and 2003 and the first three quarters of 2004. We believe that all of these material weaknesses have been successfully remediated. Our management concluded that we maintained effective internal control over financial reporting as of December 31, 2009 and 2008.
InfrastruX had a material weakness in its reporting systems as well. In connection with its fiscal 2008 audit, InfrastruX identified a material weakness related to its entity-level processes for monitoring and assessing financial reporting risks and ensuring that appropriate procedures and controls are implemented in response to changes. Specifically, this material weakness arose from the combined effect of deficiencies related to (i) insufficient resources with the appropriate level of experience and training in the application of technical accounting guidance and (ii) inadequate monitoring, review and approval of the policies and procedures implemented to address new or non-recurring accounting transactions, including those designed to ensure relevant, sufficient and reliable data is accumulated to support assumptions and judgments. This material weakness resulted in errors in the reporting of goodwill and income taxes and required the restatement of InfrastruX’s 2006 and 2007 consolidated financial statements. As of the date of our acquisition of InfrastruX, InfrastruX believed this material weakness had been successfully remediated.
Our failure to maintain effective internal control over financial reporting could adversely affect our ability to report our financial results on a timely and accurate basis, which could result in a loss of investor confidence in our financial reports or have a material adverse effect on our ability to operate our business or access sources of liquidity. Furthermore, because of the inherent limitations of any system of internal control over financial reporting, including the possibility of human error, the circumvention or overriding of controls and fraud, even effective internal controls may not prevent or detect all misstatements.
Our international operations are subject to political and economic risks of developing countries.
We have operations in the Middle East (Oman) and anticipate that a portion of our contract revenue will be derived from, and a portion of our long-lived assets will be located in, developing countries.
Conducting operations in developing countries presents significant commercial challenges for our business. A disruption of activities, or loss of use of equipment or installations, at any location in which we have significant assets or operations, could have a material adverse effect on our financial condition and results of operations. Accordingly, we are subject to risks that ordinarily would not be expected to exist to the same extent in the United States, Canada, Australia or Western Europe. Some of these risks include:
   
civil uprisings, terrorism, riots and war, which can make it impractical to continue operations, adversely affect both budgets and schedules and expose us to losses;
   
repatriating foreign currency received in excess of local currency requirements and converting it into dollars or other fungible currency;

 

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exchange rate fluctuations, which can reduce the purchasing power of local currencies and cause our costs to exceed our budget, reducing our operating margin in the affected country;
   
expropriation of assets, by either a recognized or unrecognized foreign government, which can disrupt our business activities and create delays and corresponding losses;
   
availability of suitable personnel and equipment, which can be affected by government policy, or changes in policy, which limit the importation of skilled craftsmen or specialized equipment in areas where local resources are insufficient;
   
governmental instability, which can cause investment in capital projects by our potential customers to be withdrawn or delayed, reducing or eliminating the viability of some markets for our services;
   
decrees, laws, regulations, interpretations and court decisions under legal systems, which are not always fully developed and which may be retroactively applied and cause us to incur unanticipated and/or unrecoverable costs as well as delays which may result in real or opportunity costs; and
   
restrictive governmental registration and licensing requirements, which can limit the pursuit of certain business activities.
Our operations in developing countries may be adversely affected in the event any governmental agencies in these countries interpret laws, regulations or court decisions in a manner which might be considered inconsistent or inequitable in the United States, Canada, Australia or Western Europe. We may be subject to unanticipated taxes, including income taxes, excise duties, import taxes, export taxes, sales taxes or other governmental assessments, which could have a material adverse effect on our results of operations for any quarter or year.
These risks may result in a material adverse effect on our results of operations.
We may be adversely affected by a concentration of business in a particular country.
Due to a limited number of major projects worldwide, we expect to have a substantial portion of our resources dedicated to projects located in a few countries. Therefore, our results of operations are susceptible to adverse events beyond our control that may occur in a particular country in which our business may be concentrated at that time. Economic downturns in such countries could also have an adverse impact on our operations.
Special risks associated with doing business in highly corrupt environments may adversely affect our business.
Our international business operations may include projects in countries where corruption is prevalent. Since the anti-bribery restrictions of the FCPA make it illegal for us to give anything of value to foreign officials in order to obtain or retain any business or other advantage, we may be subject to competitive disadvantages to the extent that our competitors are able to secure business, licenses or other preferential treatment by making payments to government officials and others in positions of influence.
Our backlog is subject to unexpected adjustments and cancellations and is, therefore, an uncertain indicator of our future earnings.
We cannot guarantee that the revenue projected in our backlog will be realized or profitable. Projects may remain in our backlog for an extended period of time. In addition, project cancellations, terminations, or scope adjustments may occur, from time to time, with respect to contracts reflected in our backlog and could reduce the dollar amount of our backlog and the revenue and profits that we actually earn. Many of our contracts have termination for convenience provisions in them, in some cases without any provision for penalties or lost profits. Therefore, project terminations, suspensions or scope adjustments may occur from time to time with respect to contracts in our backlog. Finally, poor project or contract performance could also impact our backlog and profits.

 

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Managing backlog in our Utility T&D segment also has other challenges. Backlog for anticipated projects in this segment is determined based on recurring historical trends, seasonal demand and projected customer needs, but the agreements in this segment rarely have minimum volume or spending obligations, and many of the contracts may be terminated by the customers on short notice. For projects in this segment on which we have commenced work that are cancelled, we may be reimbursed for certain costs, but typically have no contractual right to the total revenues included in our backlog.
Federal and state legislative and regulatory developments that we believe should encourage electric power transmission and natural gas pipeline infrastructure spending may fail to result in increased demand for our Utility T&D services.
In recent years, federal and state legislation has been passed and resulting regulations have been adopted that could significantly increase spending on electric power transmission and natural gas pipeline infrastructure, including the Energy Act of 2005, the American Recovery and Reinvestment Act of 2009 (“ARRA”) and state Renewable Portfolio Standard (“RPS”) programs. However, much fiscal, regulatory and other uncertainty remains as to the impact this legislation and regulation will ultimately have on the demand for our Utility T&D services. For instance, regulations implementing provisions of the Energy Act of 2005 that may affect demand for our Utility T&D services remain, in some cases, subject to review in various federal courts. In one such case, decided in February 2009, a federal court of appeals vacated FERC’s interpretation of the scope of its backstop transmission line siting authority for electric power transmission projects. Accordingly, the effect of these regulations, once finally implemented, is uncertain and may not result in increased spending on the electric power transmission infrastructure. Continued uncertainty regarding the implementation of the Energy Act of 2005 and ARRA may result in slower growth in demand for our Utility T&D services.
Renewable energy initiatives, including Texas’ CREZ plan, other RPS initiatives and ARRA, may not lead to increased demand for our Utility T&D services. While 29 states and Washington D.C. have mandatory RPS programs that require certain percentages of power to be generated from renewable sources, the RPS programs adopted in many states became law during periods of substantially higher oil and natural gas prices. As a result, or for budgetary or other reasons, states may reduce those mandates or make them optional or extend deadlines, which could reduce, delay or eliminate renewable energy development in the affected states. In addition, states may limit, delay or otherwise alter existing RPS programs in anticipation of a potential federal renewable energy standard. Furthermore, renewable energy is generally more expensive to produce and may require additional power generation sources as backup. Funding for RPS programs may not be available or may be further constrained as a result of the significant declines in government budgets and subsidies and in the availability of credit to finance the significant capital expenditures necessary to build renewable generation capacity. These factors could lead to fewer projects resulting from RPS programs than anticipated or a delay in the timing of these projects and the related infrastructure, which would negatively affect the demand for our Utility T&D services. Moreover, even if the RPS programs are fully developed and funded, we cannot be certain that we will be awarded any resulting contracts. In addition, we cannot predict when programs under ARRA will be implemented or the timing and scope of any investments to be made under these programs, particularly in light of capital constraints on potential developers of these projects. Infrastructure projects such as those envisioned by CREZ and RPS initiatives are also subject to delays or cancellation due to local factors such as siting disputes, protests and litigation. Before we will receive revenues from infrastructure buildouts associated with any of these projects, substantial advance preparations are required such as engineering, procurement, and acquisition and clearance of rights-of-way, all of which are beyond our control. Investments for renewable energy and electric power infrastructure under ARRA may not occur, may be less than anticipated or may be delayed, may be concentrated in locations where we do not have significant capabilities, and any resulting contracts may not be awarded to us, any of which could negatively impact demand for our Utility T&D services.
In addition, the increase in long-term demand for natural gas that we believe will benefit from anticipated U.S. greenhouse gas regulations, such as a cap-and-trade program or carbon taxes, may be delayed or may not occur. For example, we cannot predict whether or in what form cap-and-trade provisions and renewable energy standards such as those in the bill passed by the U.S. House of Representatives in 2009 will become law, especially in light of Senate Majority Leader Reid’s 2010 decision to advance an energy bill which does not include cap-and-trade provisions. It is difficult to accurately predict the timing and scope of any potential greenhouse gas regulations that may ultimately be adopted or the extent to which demand for natural gas will increase as a result of any such regulations.

 

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Our failure to recover adequately on claims against project owners for payment could have a material adverse effect on us.
We occasionally bring claims against project owners for additional costs exceeding the contract price or for amounts not included in the original contract price. These types of claims occur due to matters such as owner-caused delays or changes from the initial project scope, which result in additional costs, both direct and indirect. These claims can be the subject of lengthy arbitration or litigation proceedings, and it is often difficult to accurately predict when these claims will be fully resolved. When these types of events occur and unresolved claims are pending, we may invest significant working capital in projects to cover cost overruns pending the resolution of the relevant claims. A failure to promptly recover on these types of claims could have a material adverse impact on our liquidity and financial condition.
Our failure to resolve matters related to a facility construction project termination could have a material adverse impact on us.
On January 13, 2010, TransCanada Pipelines, Ltd. (“TCPL”) notified us that we were in breach of contract and were being terminated for cause immediately on a cost reimbursable plus fixed fee construction contract for seven pump stations in Nebraska and Kansas that was awarded to us in September 2008. At the time of termination, we had completed approximately 96.0 percent of our scope of work.
We have disputed the validity of the termination for cause and have challenged the contractual procedure followed by TCPL for termination for cause, which allows for a 30-day notification period during which time we are supposed to have an opportunity to remedy the alleged default. Despite not being granted this time, we agreed in good faith to cooperate with TCPL in an orderly demobilization and handover of the remaining work. As of December 31, 2010, we have outstanding receivables related to this project of $71.2 million and unapproved change orders for additional work of $4.2 million which have not been billed. Additionally, there are claims for additional fees totaling $16.4 million. It is our policy not to recognize revenue or income on unapproved change orders or claims until they have been approved. Accordingly, the $4.2 million in pending change orders and the $16.4 million of claims have been excluded from our revenue recognition. The preceding balances are partially offset by an unissued billing credit of $2.0 million related to a TCPL mobilization prepayment.
If the termination for cause is determined to be valid and enforceable, we could be held liable for damages resulting from the alleged breach of contract, including but not limited to costs incurred by TCPL to hire a replacement contractor to complete the remainder of the work less the cost that we would have incurred to perform the same scope of work. Although we do not believe we are in breach of contract and intend to pursue our contractual and legal remedies, including having commenced arbitration and filed liens on constructed facilities, the resolution of this matter could have a material adverse effect on our financial condition or results of operations. TCPL’s response to the notice of arbitration included a counterclaim for damages of $23.1 million for the alleged breach of contract, inclusive of the unissued billing credit of $2.0 million for mobilization prepayment. TCPL has also disclaimed responsibility for payment of the current receivable balance outstanding at December 31, 2010, the unapproved change orders, and claims for additional fee. TransCanada has removed us from TransCanada’s bid list.
Our business is dependent on a limited number of key clients.
We operate primarily in the oil and gas, refinery, petrochemical and electric power industries, providing services to a limited number of clients. Much of our success depends on developing and maintaining relationships with our major clients and obtaining a share of contracts from these clients. The loss of any of our major clients could have a material adverse effect on our operations. One client is responsible for 22.2 percent of our 12 month backlog and 39.8 percent of our total backlog at December 31, 2010.
Our use of fixed price contracts could adversely affect our operating results.
A significant portion of our revenues are currently generated by fixed price contracts. Under a fixed price contract, we agree on the price that we will receive for the entire project, based upon a defined scope, which includes specific assumptions and project criteria. If our estimates of our own costs to complete the project are below the actual costs that we may incur, our margins will decrease, and we may incur a loss. The revenue, cost and gross profit realized on a fixed price contract will often vary from the estimated amounts because of unforeseen conditions or changes in job conditions and variations in labor and equipment productivity over the term of the contract. If we are unsuccessful in mitigating these risks, we may realize gross profits that are different from those originally estimated and incur reduced profitability or losses on projects. Depending on the size of a project, these variations from estimated contract performance could have a significant effect on our operating results for any quarter or year. In general, turnkey contracts to be performed on a fixed price basis involve an increased risk of significant variations. This is a result of the long-term nature of these contracts and the inherent difficulties in estimating costs and of the interrelationship of the integrated services to be provided under these contracts, whereby unanticipated costs or delays in performing part of the contract can have compounding effects by increasing costs of performing other parts of the contract.

 

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In addition, our Utility T&D segment also generates substantial revenue under unit price contracts under which we have agreed to perform identified units of work for an agreed price, which have similar associated risks. A “unit” can be as small as the installation of a single bolt or a foot of cable or as large as a transmission tower or foundation. The resulting profitability of a particular unit is primarily dependent upon the labor and equipment hours expended to complete the task that comprises the unit. Failure to accurately estimate the costs of completing a particular project could result in reduced profits or losses.
Percentage-of-completion method of accounting for contract revenue may result in material adjustments that would adversely affect our operating results.
We recognize contract revenue using the percentage-of-completion method on long-term fixed price contracts. Under this method, estimated contract revenue is accrued based generally on the percentage that costs to date bear to total estimated costs, taking into consideration physical completion. Estimated contract losses are recognized in full when determined. Accordingly, contract revenue and total cost estimates are reviewed and revised periodically as the work progresses and as change orders are approved, and adjustments based upon the percentage-of-completion are reflected in contract revenue in the period when these estimates are revised. These estimates are based on management’s reasonable assumptions and our historical experience, and are only estimates. Variation of actual results from these assumptions or our historical experience could be material. To the extent that these adjustments result in an increase, a reduction or an elimination of previously reported contract revenue, we would recognize a credit or a charge against current earnings, which could be material.
Terrorist attacks and war or risk of war may adversely affect our results of operations, our ability to raise capital or secure insurance, or our future growth.
The continued threat of terrorism and the impact of military and other action will likely lead to continued volatility in prices for crude oil and natural gas and could affect the markets for our operations. In addition, future acts of terrorism could be directed against companies operating both outside and inside the United States. Further, the U.S. government has issued public warnings that indicate that pipelines and other energy assets might be specific targets of terrorist organizations. These developments may subject our operations to increased risks and, depending on their ultimate magnitude, could have a material adverse effect on our business.
Our operations are subject to a number of operational risks.
Our business operations include pipeline construction, fabrication, pipeline rehabilitation services and construction and turnaround and maintenance services to refiners and petrochemical facilities. These operations involve a high degree of operational risk. Natural disasters, adverse weather conditions, collisions and operator error could cause personal injury or loss of life, severe damage to and destruction of property, equipment and the environment, and suspension of operations. In locations where we perform work with equipment that is owned by others, our continued use of the equipment can be subject to unexpected or arbitrary interruption or termination. The occurrence of any of these events could result in work stoppage, loss of revenue, casualty loss, increased costs and significant liability to third parties.
The insurance protection we maintain may not be sufficient or effective under all circumstances or against all hazards to which we may be subject. An enforceable claim for which we are not fully insured could have a material adverse effect on our financial condition and results of operations. Moreover, we may not be able to maintain adequate insurance in the future at rates that we consider reasonable.
Our goodwill may become impaired.
We have a substantial amount of goodwill following our acquisitions of InfrastruX, Integrated Service Company, Midwest Management (1987) Ltd. and Wink Companies, LLC. At least annually, we evaluate our goodwill for impairment based on the fair value of each operating unit. This estimated fair value could change if there were future changes in our capital structure, cost of debt, interest rates, capital expenditure levels or ability to perform at levels that were forecasted. These changes could result in an impairment that would require a material non-cash charge to our results of operations. A significant decrease in expected cash flows or changes in market conditions may indicate potential impairment of recorded goodwill. We have continued to experience sustained adverse market conditions, primarily in our downstream market space. During the third quarter of 2010, in connection with the completion of the preliminary forecast for 2011, it became evident that a goodwill impairment at Downstream Oil & Gas was probable. As a result, a preliminary step one analysis for that segment was performed. Using a preliminary discounted cash flow analysis supported by comparative market multiples to determine the fair value of the segment versus its carrying value, an estimated range of likely impairment was determined and an impairment charge of $12,000 was recorded during the third quarter of 2010. During the fourth quarter of 2010, we completed our annual evaluation of goodwill, which resulted in an additional, non-cash, pre-tax charge of $48,000. We will continue to monitor the carrying value of our goodwill.

 

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We may become liable for the obligations of our joint ventures and our subcontractors.
Some of our projects are performed through joint ventures with other parties. In addition to the usual liability of contractors for the completion of contracts and the warranty of our work, where work is performed through a joint venture, we also have potential liability for the work performed by our joint ventures. In these projects, even if we satisfactorily complete our project responsibilities within budget, we may incur additional unforeseen costs due to the failure of our joint ventures to perform or complete work in accordance with contract specifications.
We act as prime contractor on a majority of the construction projects we undertake. In our capacity as prime contractor and when acting as a subcontractor, we perform most of the work on our projects with our own resources and typically subcontract only such specialized activities as hazardous waste removal, nondestructive inspection and catering and security. However, with respect to EPC and other contracts, including those in our Utility T&D segment, we may choose to subcontract a portion or substantial portion of the project. In the construction industry, the prime contractor is normally responsible for the performance of the entire contract, including subcontract work. Thus, when acting as a prime contractor, we are subject to the risk associated with the failure of one or more subcontractors to perform as anticipated.
Governmental regulations could adversely affect our business.
Many aspects of our operations are subject to governmental regulations in the countries in which we operate, including those relating to currency conversion and repatriation, taxation of our earnings and earnings of our personnel, the increasing requirement in some countries to make greater use of local employees and suppliers, including, in some jurisdictions, mandates that provide for greater local participation in the ownership and control of certain local business assets. In addition, we depend on the demand for our services from the oil and gas, refinery, petrochemical and electric power industries, and, therefore, our business is affected by changing taxes, price controls and laws and regulations relating to these industries generally. The adoption of laws and regulations by the countries or the states in which we operate that are intended to curtail exploration and development drilling for oil and gas or the development of electric power generation facilities for economic and other policy reasons, could adversely affect our operations by limiting demand for our services.
Our operations are also subject to the risk of changes in laws and policies which may impose restrictions on our business, including trade restrictions, which could have a material adverse effect on our operations. Other types of governmental regulation which could, if enacted or implemented, adversely affect our operations include:
   
expropriation or nationalization decrees;
   
confiscatory tax systems;
   
primary or secondary boycotts directed at specific countries or companies;
   
embargoes;
   
extensive import restrictions or other trade barriers;
   
mandatory sourcing and local participation rules;
   
stringent local registration or ownership requirements;
   
oil, gas or electric power price regulation;
   
unrealistically high labor rate and fuel price regulation; and
   
registration and licensing requirements.
Our future operations and earnings may be adversely affected by new legislation, new regulations or changes in, or new interpretations of, existing regulations, and the impact of these changes could be material.

 

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Our strategic plan relies in part on acquisitions to sustain our growth. Acquisitions of other companies present certain risks and uncertainties.
Our strategic plan involves growth through, among other things, the acquisition of other companies. Such growth involves a number of risks, including:
   
inherent difficulties relating to combining previously separate businesses;
   
diversion of management’s attention from ongoing day-to-day operations;
   
the assumption of liabilities of an acquired business, including both foreseen and unforeseen liabilities;
   
failure to realize anticipated benefits, such as cost savings and revenue enhancements;
   
potentially substantial transaction costs associated with business combinations;
   
difficulties relating to assimilating the personnel, services and systems of an acquired business and to integrating marketing, contracting, commercial and other operational disciplines;
   
difficulties in applying and integrating our system of internal controls to an acquired business; and
   
failure to retain key or essential employees or customers of, or any government contracts held by, an acquired business.
In addition, we can provide no assurance that we will continue to locate suitable acquisition targets or that we will be able to consummate any such transactions on terms and conditions acceptable to us. Acquisitions may bring us into businesses we have not previously conducted and expose us to additional business risks that are different than those we have traditionally experienced.
We may not be able to successfully integrate our acquisition of InfrastruX, which could cause our business to suffer.
Our acquisition of InfrastruX is significant. InfrastruX total assets account for approximately 55.0 percent of our total assets as of December 31, 2010. We may not be able to successfully combine the operations, personnel and technology of InfrastruX with our operations. Because of the size and complexity of InfrastruX’s business, if integration is not managed successfully by our management, we may experience interruptions in our business activities, a decrease in the quality of our services, a deterioration in our employee and customer relationships, increased costs of integration and harm to our reputation, all of which could have a material adverse effect on our business, financial condition and results of operations. We entered new lines of business when we acquired InfrastruX that we do not have experience managing, such as the electrical transmission business. Particularly because we will have to learn how to manage new lines of business, the integration of InfrastruX with our operations will require significant attention from management, which may decrease the time management will have to serve existing customers, attract new customers and develop new services and strategies. We may also experience difficulties in combining corporate cultures, maintaining employee morale and retaining key employees. The integration with InfrastruX may also impose substantial demands on our operations or other projects. We will have to actively strive to demonstrate to our existing customers that the acquisition will not result in adverse changes in our standards or business focus. The integration of InfrastruX also involved a significant capital commitment, and the return that we achieve on any capital invested may be less than the return achieved on our other projects or investments. There will be challenges in consolidating and rationalizing information technology platforms and administrative infrastructures. In addition, any delays or increased costs of combining the companies could adversely affect our operations, financial results and liquidity.
We may not realize the growth opportunities and cost synergies that are anticipated from our acquisition of InfrastruX.
The benefits we expect to achieve as a result of our acquisition of InfrastruX will depend, in part, on our ability to realize anticipated growth opportunities and cost synergies. Our success in realizing these growth opportunities and cost synergies, and the timing of this realization, depends on the successful integration of InfrastruX’s business and operations with our business and operations. Even if we are able to integrate our business with InfrastruX’s business successfully, this integration may not result in the realization of the full benefits of the growth opportunities and cost synergies we currently expect from this integration within the anticipated time frame or at all. For example, we may be unable to eliminate duplicative costs. Moreover, we anticipate that we will incur substantial expenses in connection with the integration of our business with InfrastruX’s business. While we anticipate that certain expenses will be incurred, such expenses are difficult to estimate accurately, and may exceed current estimates. Accordingly, the benefits from the proposed acquisition may be offset by costs incurred or delays in integrating the companies, which could cause our revenue assumptions to be inaccurate.

 

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The acquisition of InfrastruX may expose us to unindemnified liabilities.
As a result of the recent acquisition, we acquired InfrastruX subject to all of its liabilities, including contingent liabilities. If there are unknown InfrastruX obligations, our business could be materially and adversely affected. We may learn additional information about InfrastruX’s business that adversely affects us, such as unknown liabilities, issues that could affect our ability to comply with the Sarbanes-Oxley Act or issues that could affect our ability to comply with other applicable laws. As a result, we can provide no assurance that the acquisition of InfrastruX will be successful or will not, in fact, harm our business. Among other things, if InfrastruX’s liabilities are greater than expected, or if there are material obligations of which we were not aware until after the time of completion of the acquisition, our business could be materially and adversely affected. If we become responsible for liabilities not covered by indemnification rights or substantially in excess of amounts covered through any indemnification rights, we could suffer severe consequences that would substantially reduce our revenues, earnings and cash flows. Further, given the amount of indebtedness that we incurred to fund the acquisition, we may not be able to obtain additional financing required for any significant expenditures on favorable terms or at all.
We are self-insured against many potential liabilities.
Although we maintain insurance policies with respect to automobile liability, general liability, workers’ compensation and employee group health claims, many of those policies are subject to substantial deductibles, and we are self-insured up to the amount of the deductible. Since most claims against us do not exceed the deductibles under our insurance policies, we are effectively self-insured for substantially all claims. We actuarially determine any liabilities for unpaid claims and associated expenses, including incurred but not reported losses, and reflect those liabilities in our balance sheet as other current and noncurrent liabilities. The determination of such claims and expenses and the appropriateness of the liability is reviewed and updated quarterly. However, insurance liabilities are difficult to assess and estimate due to many relevant factors, the effects of which are often unknown, including the severity of an injury, the determination of our liability in proportion to other parties, the number of incidents not reported and the effectiveness of our safety program. If our insurance claims increase or costs exceed our estimates of insurance liabilities, we could experience a decline in profitability and liquidity. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Insurance.”
Our historical and pro forma combined financial information may not be representative of our results as a combined company.
The pro forma combined financial information that we file with the SEC is constructed from the separate financial statements of Willbros Group, Inc. and InfrastruX and does not purport to be indicative of the financial information that will result from operations of the combined companies. In addition, the pro forma combined financial information that we file with the SEC is based in part on certain assumptions regarding the acquisition that we believe are reasonable. We cannot assure you that our assumptions will prove to be accurate over time. Accordingly, the historical and pro forma combined financial information that we file with the SEC does not purport to be indicative of what our results of operations and financial condition would have been had we been a combined entity during the periods presented, or what our results of operations and financial condition will be in the future. The challenge of integrating previously independent businesses makes evaluating our business and our future financial prospects difficult. Our potential for future business success and operating profitability must be considered in light of the risks, uncertainties, expenses and difficulties typically encountered by recently combined companies.
Our operations expose us to potential environmental liabilities.
Our U.S. and Canadian operations are subject to numerous environmental protection laws and regulations which are complex and stringent. We regularly perform work in and around sensitive environmental areas, such as rivers, lakes and wetlands. Part of the business in our Utility T&D segment is done in the southwestern U.S. where there is a greater risk of fines, work stoppages or other sanctions for disturbing Native American artifacts and archeological sites. Significant fines, penalties and other sanctions may be imposed for non-compliance with environmental laws and regulations, and some environmental laws provide for joint and several strict liabilities for remediation of releases of hazardous substances, rendering a person liable for environmental damage, without regard to negligence or fault on the part of such person. In addition to potential liabilities that may be incurred in satisfying these requirements, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances. These laws and regulations may expose us to liability arising out of the conduct of operations or conditions caused by others, or for our acts which were in compliance with all applicable laws at the time these acts were performed.

 

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We own and operate several properties in the United States and Canada that have been used for a number of years for the storage and maintenance of equipment and upon which hydrocarbons or other wastes may have been disposed or released. Any release of substances by us or by third parties who previously operated on these properties may be subject to the Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”), the Resource Compensation and Recovery Act (“RCRA”), and/or analogous state, provincial or local laws. CERCLA imposes joint and several liabilities, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of hazardous substances into the environment, while RCRA governs the generation, storage, transfer and disposal of hazardous wastes. Under these or similar laws, we could be required to remove or remediate previously disposed wastes and clean up contaminated property. This could have a significant impact on our future results.
Our operations outside of the United States and Canada are oftentimes potentially subject to similar governmental or provincial controls and restrictions relating to the environment.
We are unable to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business segments.
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to warming of the earth’s atmosphere. As a result, there have been a variety of regulatory developments, proposals or requirements and legislative initiatives that have been introduced and/or issued in the United States (as well as other parts of the world) that are focused on restricting the emission of carbon dioxide, methane and other greenhouse gases. Although it is difficult to accurately predict how such legislation or regulations, including those introduced or adopted in the future, would impact our business and operations, it is possible that such laws and regulations could result in greater compliance costs or operating restrictions for us and/or our customers and could adversely affect the demand for some of our services.
Our industry is highly competitive, which could impede our growth.
We operate in a highly competitive environment. A substantial number of the major projects that we pursue are awarded based on bid proposals. We compete for these projects against government-owned or supported companies and other companies that have substantially greater financial and other resources than we do. In some markets, there is competition from national and regional firms against which we may not be able to compete on price. Our growth may be impacted to the extent that we are unable to successfully bid against these companies. The global recession has intensified competition in the industries in which we operate as our competitors in these industries pursue reduced work volumes. Our competitors may have lower overhead cost structures, greater resources or other advantages and, therefore, may be able to provide their services at lower rates than ours or elect to place bids on projects that drive down margins to lower levels than we would accept.
We also face competition in new arenas resulting from our acquisition of InfrastruX. For example, in recent years our cable restoration business in our Utility T&D segment has begun to face increasing competition from alternative technologies. Our CableCURE® product sales may be adversely affected by technological improvements by one or more of our competitors and/or the expiration of our exclusive intellectual property rights in such technology. If we are unable to keep pace with current or future technological advances in cable restoration, our business, financial condition and results of operations could suffer.

 

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Our operating results could be adversely affected if our non-U.S. operations became taxable in the United States.
If any income earned before our change of domicile in March 2009 by Willbros Group, Inc. or its non-U.S. subsidiaries from operations outside the United States constituted income effectively connected with a U.S. trade or business, and as a result became taxable in the United States, our consolidated operating results could be materially and adversely affected.
We are dependent upon the services of our executive management.
Our success depends heavily on the continued services of our executive management. Our management team is the nexus of our operational experience and customer relationships. Our ability to manage business risk and satisfy the expectations of our clients, stockholders and other stakeholders is dependent upon the collective experience and relationships of our management team. The InfrastruX acquisition will further test our management team as we continue to absorb a significant new business without significantly expanding the size of our management team. We also may not be able to retain InfrastruX’s operating unit managers, project managers and field supervisors, who are personnel that are critical to the continued growth of InfrastruX’s business. We do not maintain key man life insurance for these individuals. The loss or interruption of services provided by one or more of our senior officers could adversely affect our results of operations.
Our storm restoration revenues are highly volatile and unpredictable, which could result in substantial variations in, and uncertainties regarding, our results of operations generated by our Utility T&D business.
Revenues derived from our storm restoration services are highly volatile and uncertain due to the unpredictable nature of weather-related events. InfrastruX’s annual storm restoration revenues have been as high as $67.0 million in 2008 when InfrastruX experienced the largest storm restoration revenues in its history as several significant hurricanes impacted the Gulf Coast and Florida and ice storms affected the Northeast, but storm restoration revenues were substantially lower in 2009. Therefore, InfrastruX’s storm restoration revenues for 2008 are not indicative of the revenues that this business typically generates in any period or can be expected to generate in any future period. Our Utility T&D segment’s revenues and operating income will likely continue to be subject to significant variations and uncertainties due to the volatility of our storm restoration volume. We may not be able to generate incremental revenues from storm activities to the extent that we do not receive permission from our regular customers (including Oncor) to divert resources to the restoration work for customers with which we do not have ongoing MSA relationships, sometimes referred to in this Form 10-K as “off-system” work. In addition, our storm restoration revenues are offset in part by declines in our transmission and distribution (“T&D”) services because we staff storm restoration mobilizations by diverting resources from our T&D services.
Seasonal variations and inclement weather may cause fluctuations in our operating results, profitability, cash flow and working capital needs related to our Utility T&D segment.
We have not historically considered seasonality a significant risk, but because a significant portion of our business in our Utility T&D segment is performed outdoors, our results of operations are exposed to seasonal variations and inclement weather. Our Utility T&D segment performs less work in the winter months, and work is hindered during other inclement weather events. Our Utility T&D segment revenue and profitability often decrease during the winter months and during severe weather conditions because work performed during these periods is more costly to complete. During periods of peak electric power demand in the summer, utilities generally are unable to remove their electric power T&D equipment from service, decreasing the demand for our maintenance services during such periods. The seasonality of this segment’s business also causes our working capital needs to fluctuate. Because this segment’s operating cash flow is usually lower during and immediately following the winter months, we typically experience a need to finance a portion of this segment’s working capital during the spring and summer.
We depend on our ability to protect our intellectual property and proprietary rights in our cable restoration and testing businesses, and we cannot be certain of their confidentiality and protection.
Our success in the cable restoration and testing markets depends in part on our ability to protect our proprietary products and services. If we are unable to protect our proprietary products and services, our cable restoration and testing business may be adversely affected. To protect our proprietary technology, we rely primarily on trade secrets and confidentiality restrictions in contracts with employees, customers and other third parties. We also have a license to the patents Dow Corning Corporation holds from the U.S. Patent and Trademark Office relating to our CableCURE® product. In addition, we hold a number of U.S. and international patents, most of which relate to certain materials used in treating cables with CableCURE®. We also hold the patent and trademark to CableWISE®. If we fail to protect our intellectual property rights adequately, our competitors may gain access to that technology, and our cable restoration business may be harmed. Any of our intellectual property rights may be challenged by others or invalidated through administrative processes or litigation proceedings. Despite our efforts to protect our proprietary technology, unauthorized persons may be able to copy, reverse engineer or otherwise use some of our proprietary technology. Furthermore, existing laws may afford only limited protection, and the laws of certain countries in which we operate do not protect proprietary technology as well as established law in the U.S. For these reasons, we may have difficulty protecting our proprietary technology against unauthorized copying or use or maintaining our market share with respect to our proprietary technology offerings. In addition, litigation may be necessary to protect our proprietary technology. This type of litigation is often costly and time consuming, with no assurance of success.

 

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We contribute to multi-employer plans that could result in liabilities to us if those plans are terminated or we withdraw from those plans.
We contribute to several multi-employer pension plans for employees covered by collective bargaining agreements. These plans are not administered by us and contributions are determined in accordance with provisions of negotiated labor contracts. The Employee Retirement Income Security Act of 1974, as amended by the Multi-employer Pension Plan Amendments Act of 1980, imposes certain liabilities upon employers who are contributors to a multi-employer plan in the event of the employer’s withdrawal from, or upon termination of, such plan. We do not routinely review information on the net assets and actuarial present value of the multi-employer pension plans’ unfunded vested benefits allocable to us, if any, and we are not presently aware of the amounts, if any, for which we may be contingently liable if we were to withdraw from any of these plans. In addition, if the funding of any of these multi-employer plans becomes in “critical status” under the Pension Protection Act of 2006, we could be required to make significant additional contributions to those plans.
RISKS RELATED TO OUR COMMON STOCK
Our common stock, which is listed on the New York Stock Exchange, has from time to time experienced significant price and volume fluctuations. These fluctuations are likely to continue in the future, and you may not be able to resell your shares of common stock at or above the purchase price paid by you.
The market price of our common stock may change significantly in response to various factors and events beyond our control, including the following:
   
the risk factors described in this Item 1A;
   
a shortfall in operating revenue or net income from that expected by securities analysts and investors;
   
changes in securities analysts’ estimates of our financial performance or the financial performance of our competitors or companies in our industries generally;
   
general conditions in our customers’ industries; and
   
general conditions in the securities markets.
Our certificate of incorporation and bylaws may inhibit a takeover, which may adversely affect the performance of our stock.
Our certificate of incorporation and bylaws may discourage unsolicited takeover proposals or make it more difficult for a third party to acquire us, which may adversely affect the price that investors might be willing to pay for our common stock. For example, our certificate of incorporation and bylaws:
   
provide for a classified board of directors, which allows only one-third of our directors to be elected each year;
   
deny stockholders the ability to take action by written consent;
   
establish advance notice requirements for nominations for election to our Board of Directors and business to be brought by stockholders before any meeting of the stockholders;
   
provide that special meetings of stockholders may be called only by our Board of Directors, Chairman, Chief Executive Officer or President; and
   
authorize our Board of Directors to designate the terms of and issue new series of preferred stock.
Future sales of our common stock may depress our stock price.
Sales of a substantial number of shares of our common stock in the public market or otherwise, either by us, a member of management or a major stockholder, or the perception that these sales could occur, may depress the market price of our common stock and impair our ability to raise capital through the sale of additional equity securities.

 

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In the event we issue stock as consideration for certain acquisitions or to fund our corporate activities, we may dilute share ownership.
We grow our business organically as well as through acquisitions. One method of acquiring companies or otherwise funding our corporate activities is through the issuance of additional equity securities. If we do issue additional equity securities, such issuances may have the effect of diluting our earnings per share as well as our existing stockholders’ individual ownership percentages in our company.
Our prior sale of common stock, warrants and convertible notes, and our outstanding warrants and convertible notes may lead to further dilution of our issued and outstanding stock.
In November 2007, we completed an underwritten public offering of 7,906,250 shares of our common stock. In October 2006, we sold 3,722,360 shares of our common stock and warrants to purchase an additional 558,354 shares (of which, warrants to purchase 536,925 shares of common stock remained outstanding at December 31, 2010). The issuance of warrants and the prior issuance of $70.0 million in aggregate principal amount of our 2.75% Convertible Senior Notes due 2024 (the “2.75% Notes”) and $84.5 million of our 6.5% Senior Convertible Notes due 2012 (the “6.5% Notes”) may cause a significant increase in the number of shares of common stock currently outstanding. In May 2007, we induced the conversion of approximately $52.5 million in aggregate principal amount of our outstanding 6.5% Notes into a total of 2,987,582 shares of our common stock. In addition, certain holders have exercised their right to convert the 2.75% Notes, converting approximately $10.6 million in aggregate principal amount of the 2.75% Notes into 546,633 shares of our common stock as of December 31, 2010. As of December 31, 2010, 3,048,642 shares of common stock are issuable upon conversion of approximately $59.4 million in aggregate principal amount of the 2.75% Notes and 1,825,587 shares of common stock are issuable upon conversion of approximately $32.1 million in aggregate principal amount of the 6.5% Notes. If we elect to induce the conversion of additional convertible notes or holders elect to convert additional convertible notes, there may be a significant increase in the number of shares of our common stock outstanding.
Our authorized shares of common stock consist of 70 million shares. The issuance of additional common stock or securities convertible into our common stock would result in further dilution of the ownership interest in us held by existing stockholders. We are authorized to issue, without stockholder approval, one million shares of preferred stock, which may give other stockholders dividend, conversion, voting and liquidation rights, among other rights, which may be superior to the rights of holders of our common stock. While our Board of Directors has no present intention of issuing any such preferred stock, other than pursuant to any earnout payments that may be made in connection with our acquisition of InfrastruX, it reserves the right to do so in the future.
Item 1B.  
Unresolved Staff Comments
None.
Item 3.  
Legal Proceedings
For information regarding legal proceedings, see the discussion under the captions “Contingencies — Facility Construction Project Termination” in Note 16 — Contingencies, Commitments and Other Circumstances and “Nigeria Assets and Nigeria-Based Operations — Share Purchase Agreement” in Note 21 — Discontinuance of Operations, Asset Disposals and Transition Services Agreement of our “Notes to Consolidated Financial Statements” in Item 8 of Part II of this Form 10-K, which information from Notes 16 and 21 is incorporated by reference herein.
We are a party to a number of other legal proceedings. We believe that the nature and number of these other proceedings are typical for a company of our size engaged in our type of business and that none of these other proceedings will result in a material adverse effect on our business, results of operations or financial condition.

 

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Item 4.  
Reserved
Item 4A.  
Executive Officers of the Registrant
The following table sets forth information regarding our executive officers. Officers are elected annually by, and serve at the discretion of, the Board of Directors.
             
Name   Age     Position(s)
Robert R. Harl
    60     Director, President and Chief Executive Officer
Van A. Welch
    56     Senior Vice President and Chief Financial Officer
James L. Gibson
    60     Senior Vice President and Chief Operating Officer
Peter W. Arbour
    62     Senior Vice President and General Counsel
J. Robert Berra
    43     Executive Vice President, Sales & Marketing
Jerrit M. Coward
    42     Senior Vice President and President of Upstream Oil & Gas
Richard E. Cellon
    54     Senior Vice President and President of Downstream Oil & Gas
Robert R. Harl was elected to the Board of Directors and President and Chief Operating Officer of Willbros Group, Inc. in January 2006 and as Chief Executive Officer in January 2007. Mr. Harl has over 30 years experience working with Kellogg Brown & Root, a global engineering, construction and services company (“KBR”), and its subsidiaries in a variety of officer capacities, serving as President of several of KBR’s business units. Mr. Harl’s experience includes executive management responsibilities for units serving both upstream and downstream oil and gas sectors as well as power, governmental and infrastructure sectors. He was President and Chief Executive Officer of KBR from March 2001 until July 2004 when he was appointed Chairman, a position he held until January 2005. KBR filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code in December 2003 in order to discharge certain asbestos and silica personal injury claims. The order confirming KBR’s plan of reorganization became final in December 2004, and the plan of reorganization became effective in January 2005. Mr. Harl was engaged as a consultant to Willbros from August 2005 until he became an executive officer and member of the Board of Directors of Willbros in January 2006. In October 2010, Mr. Harl resigned from the office of Chief Operating Officer prior to Mr. Gibson’s election to that office.
Van A. Welch joined Willbros in 2006 as Senior Vice President, Chief Financial Officer and Treasurer of Willbros Group, Inc.; he served as Treasurer until September 2007. Mr. Welch has over 28 years experience in project controls, administrative and finance positions with KBR, a global engineering, construction and services company, and its subsidiaries, serving in his last position as Vice President — Finance and Investor Relations and as a member of KBR’s executive leadership team. From 1998 to 2006, Mr. Welch held various other positions with KBR including Vice President, Accounting and Finance of the Engineering and Construction Division, Vice President, Accounting and Finance of Onshore Operations and Senior Vice President of Shared Services. Mr. Welch is a Certified Public Accountant.
James L. Gibson was named Chief Operating Officer of Willbros in October 2010. Mr. Gibson joined Willbros in March 2008. He was named President, Willbros Canada in July 2008, and appointed President of Downstream Oil & Gas in February 2010. Mr. Gibson brings more than 39 years of diversified construction experience in managing all aspects of project performance including: cost, schedules, quality, safety, budget, regulatory requirements and subcontracting. Prior to joining Willbros, he was employed by KBR, for the majority of his career, beginning in 1972. He held a number of positions at KBR in project management services performing work in refineries and chemical plants. He has managed projects for Syncrude Canada Limited in Alberta and other projects in the oil sands industry in the Fort McMurray area. Mr. Gibson holds several contractor certifications and licenses and graduated from the University of Texas with a Bachelor of Science in Engineering.
Peter W. Arbour joined Willbros in May 2010 as Senior Vice President, General Counsel, and Corporate Secretary. Before joining Willbros, he served in senior legal positions with the Expro International Group from August 2006 to April 2010, Power Well Services from August 2004 to July 2006, and KBR, where he managed a worldwide Law Department for over 10 years. KBR filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code in December 2003 in order to discharge certain asbestos and silica personal injury claims. The order confirming KBR’s plan of reorganization became final in December 2004, and the plan of reorganization became effective in January 2005. Mr. Arbour’s legal experience includes work with mergers and acquisitions, engineering and construction contracts, construction claims, litigation management, and compliance matters. He has extensive experience in overseas projects, particularly in the Middle East, Asia Pacific, and Latin America. Mr. Arbour is a member of the state bar associations of Texas and Louisiana and holds undergraduate and Juris Doctorate degrees from Louisiana State University. Mr. Arbour resigned from the office of Corporate Secretary in December 2010.

 

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J. Robert Berra joined Willbros in February 2011 as Executive Vice President, Sales & Marketing. Mr. Berra has over 20 years’ experience in the energy industry including the oil and gas, refining, petrochemicals, LNG, offshore, government and technology sectors, and has worked in capacities ranging from engineering, construction, program management, business development, operations and executive management. Prior to joining Willbros, from December 2008 to February 2011, Mr. Berra served as Senior Vice President, Commercial Operations for Foster Wheeler USA Corporation, a global engineering and construction contractor, where he was responsible for sales, marketing, proposals and estimating, and executive oversight of its heavy oil technology portfolio and chemicals business line. During his tenure with ConocoPhillips, from August 2006 to December 2008, Mr. Berra served in senior management positions in the Project Development function where he was responsible for global EPC contracting and led the portfolio management for major pipeline projects. Mr. Berra has also served in senior leadership positions with engineering and construction contractors, The Shaw Group from November 2004 to August 2006 and KBR from May 1990 to October 2004. Mr. Berra graduated from The University of Texas at Austin with a Bachelor of Science in Mechanical Engineering and is a licensed professional engineer in the State of Texas. He is a member of the executive board of the Engineering Construction and Contracting (ECC) Association, and served as chairman of this organization in 2010.
Jerrit M. Coward joined Willbros in 2002 as a Project Manager, and assumed full operations responsibility for our Nigerian operations in 2005, overseeing the discontinuation and sale of our Nigerian interests. He was promoted to President of our Upstream Oil & Gas segment in January 2008 and also currently serves as a Senior Vice President of the Company. Prior to joining Willbros, he worked for Global Industries as Project Manager, Operations Manager and Commercial Manager. He has held foreign assignments in Nigeria and Mexico as well as executing international projects in various other countries. He has worked his entire professional career in the oil and gas construction industry. Mr. Coward is a graduate of Texas A&M University at Galveston with a Bachelor of Science in Maritime Systems Engineering.
Richard E. Cellon was named President Downstream Oil & Gas and Senior Vice President of the Company in October 2010. Mr. Cellon joined Willbros in January 2010 and was named as President, Government Services. He was named President, Government, Tank, & Construction Tank Services within the Downstream Oil & Gas segment in July 2010. Prior to joining Willbros, Mr. Cellon had more than 30 years of federal government leadership experience with the United States Navy in facilities management, construction, and acquisition, as well as contingency operations. His breadth of experience includes strategic planning, financial management, and operations management of multi-year construction programs, including global leadership of the Naval Construction Force of 16,000 Seabees. Mr. Cellon holds degrees from the U.S. Naval Academy, the Naval War College, the University of Florida and completed the Advanced Management Program at the Wharton School, University of Pennsylvania. He retired from the U.S. Navy as a Rear Admiral in 2009.

 

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PART II
Item 5.  
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock commenced trading on the New York Stock Exchange on August 15, 1996, under the symbol “WG.” The following table sets forth the high and low sale prices per share of our common stock as reported by the New York Stock Exchange for the periods indicated:
                 
    High     Low  
For the year ended December 31, 2010:
               
First Quarter
  $ 18.51     $ 11.57  
Second Quarter
    13.76       8.93  
Third Quarter
    9.75       6.80  
Fourth Quarter
    10.02       6.84  
 
               
For the year ended December 31, 2009:
               
First Quarter
  $ 11.64     $ 5.85  
Second Quarter
    17.01       9.21  
Third Quarter
    15.58       10.78  
Fourth Quarter
    18.11       12.59  
Substantially all of our stockholders maintain their shares in “street name” accounts and are not, individually, stockholders of record. As of March 10, 2011, our common stock was held by 123 holders of record and an estimated 7,400 beneficial owners.
Dividend Policy
Since 1991, we have not paid any cash dividends on our capital stock, except dividends in 1996 on our outstanding shares of preferred stock, which were converted into shares of common stock on July 15, 1996. We anticipate that we will retain earnings to support operations and to finance the growth and development of our business. Therefore, we do not expect to pay cash dividends in the foreseeable future. Our 2010 Credit Facility prohibits us from paying cash dividends on our common stock.
Issuer Purchases of Equity Securities
The following table provides information about purchases of our common stock by us during the fourth quarter of 2010:
                                 
                            Maximum  
                    Total Number of     Number (or  
                    Shares     Approximate  
                    Purchased as     Dollar Value) of  
                    Part of     Shares That May  
                    Publicly     Yet Be  
    Total Number     Average     Announced     Purchased  
    of Shares     Price Paid     Plans or     Under the Plans  
    Purchased(1)     Per Share(2)     Programs     or Programs  
 
                               
October 1, 2010 — October 31, 2010
    950     $ 9.46              
November 1, 2010 — November 30, 2010
    12,780       7.09              
December 1, 2010 — December 31, 2010
    681       9.82              
 
                       
Total
    14,411     $ 7.38              
 
                       
     
(1)  
Represents shares of common stock acquired from certain of our officers and key employees under the share withholding provisions of our 1996 Stock Plan and 2010 Stock and Incentive Compensation Plan for the payment of taxes associated with the vesting of shares of restricted stock granted under such plans.
 
(2)  
The price paid per common share represents the closing sales price of a share of our common stock as reported by the New York Stock Exchange on the day that the stock was acquired by us.

 

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Item 6.  
Selected Financial Data
SELECTED CONSOLIDATED FINANCIAL AND OTHER DATA
(Dollar amounts in thousands, except per share data)
                                         
    Year ended December 31,  
    2010     2009     2008     2007     2006  
Statement of Operations Data:
                                       
Contract revenue
  $ 1,192,412     $ 1,259,773     $ 1,912,704     $ 947,691     $ 543,259  
Operating expenses:
                                       
Contract (1)
    1,080,391       1,115,224       1,650,156       845,743       496,271  
Amortization of intangibles(1)
    9,724       6,515       10,420       794        
General and administrative(1)
    118,427       82,345       118,027       68,071       58,054  
Goodwill impairment
    60,000             62,295              
Changes in fair value of contingent earn-out liability
    (45,340 )                        
Other charges
    3,771       12,694                    
Acquisition costs
    10,055       2,499                    
Government fines
                      22,000        
 
                             
Operating income (loss)
    (44,616 )     40,496       71,806       11,083       (11,066 )
Interest expense, net
    (27,565 )     (8,328 )     (9,032 )     (6,055 )     (11,820 )
Other income (expense)
    5,474       819       7,891       (3,477 )     569  
Loss on early extinguishment of debt
                      (15,375 )      
 
                             
Income (loss) from continuing operations before income taxes
    (66,707 )     32,987       70,665       (13,824 )     (22,317 )
Provision (benefit) for income taxes
    (36,150 )     8,734       25,942       14,503       2,308  
 
                             
Income (loss) from continuing operations
    (30,557 )     24,253       44,723       (28,327 )     (24,625 )
Income (loss) from discontinued operations net of provision for income taxes
    (5,272 )     (4,613 )     745       (21,414 )     (83,402 )
 
                             
Net income (loss)
    (35,829 )     19,640       45,468       (49,741 )     (108,027 )
Less: Income attributable to noncontrolling interest
    (1,207 )     (1,817 )     (1,836 )     (2,210 )     (1,036 )
 
                             
Net income (loss) attributable to Willbros Group, Inc.
  $ (37,036 )   $ 17,823     $ 43,632     $ (51,951 )   $ (109,063 )
 
                             
Reconciliation of net income attributable to Willbros Group, Inc.
                                       
Income (loss) from continuing operations
  $ (31,764 )   $ 22,436     $ 42,887     $ (30,537 )   $ (25,661 )
Income (loss) from discontinued operations
    (5,272 )     (4,613 )     745       (21,414 )     (83,402 )
 
                             
Net income (loss) attributable to Willbros Group, Inc.
  $ (37,036 )   $ 17,823     $ 43,632     $ (51,951 )   $ (109,063 )
 
                             
Basic income (loss) per share attributable to Company shareholders:
                                       
Continuing operations
  $ (0.74 )   $ 0.58     $ 1.12     $ (1.04 )   $ (1.14 )
Discontinued operations
    (0.12 )     (0.12 )     0.02       (0.73 )     (3.72 )
 
                             
Net income (loss)
  $ (0.86 )   $ 0.46     $ 1.14     $ (1.77 )   $ (4.86 )
 
                             
 
                                       
Diluted income (loss) per share attributable to Company shareholders:
                                       
Continuing operations
  $ (0.74 )   $ 0.58     $ 1.10     $ (1.04 )   $ (1.14 )
Discontinued operations
    (0.12 )     (0.12 )     0.02       (0.73 )     (3.72 )
 
                             
Net income (loss)
  $ (0.86 )   $ 0.46     $ 1.12     $ (1.77 )   $ (4.86 )
 
                             
 
                                       
Cash Flow Data:
                                       
Cash provided by (used in):
                                       
Operating activities
  $ 53,446     $ 53,879     $ 191,646     $ (15,793 )   $ (102,587 )
Investing activities
    (404,651 )     (34,036 )     (11,725 )     (150,601 )     33,373  
Financing activities
    291,220       (35,056 )     (60,044 )     219,340       50,785  
Effect of exchange rate changes
    2,402       6,135       (5,001 )     2,297       139  
Balance Sheet Data (at period end):
                                       
Cash and cash equivalents
  $ 141,101     $ 198,684     $ 207,762     $ 92,886     $ 37,643  
Working capital
    269,500       297,736       280,441       202,296       171,616  
Total assets
    1,285,802       728,378       787,344       778,391       580,654  
Total liabilities
    762,262       240,383       343,209       375,666       478,830  
Total debt
    387,933       104,037       120,514       141,578       149,697  
Stockholders’ equity
    523,540       487,995       444,135       402,725       101,824  
Other Financial Data (excluding discontinued operations):
                                       
12 Month Backlog (at period end)(2)
  $ 946,315     $ 389,350     $ 655,494     $ 1,305,441     $ 602,272  
Capital expenditures, excluding acquisitions
    18,300       13,107       53,048       74,548       23,481  
 
                                       
EBITDA (3)
    75,816       80,358       185,059       10,696       897  
 
                                       
Number of employees (at period end):
    7,271       3,714       6,512       5,475       4,156  

 

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(1)  
Historically, we have shown depreciation and amortization as a separate line item on our Consolidated Statements of Operations. Effective for the fiscal year ended December 31, 2007, depreciation and amortization related to operating activities is included in Contract and depreciation and amortization related to general and administrative activities is included General and Administrative (“G&A”). This change in presentation was made to bring our presentation of financial results in line with our peers and provide greater comparability of our results within the industry.
 
(2)  
Backlog is anticipated contract revenue from uncompleted portions of existing contracts and contracts whose award is reasonably assured.
 
(3)  
EBITDA from continuing operations represents earnings from continuing operations before net interest, income taxes, depreciation and amortization and impairment of intangible assets. EBITDA from continuing operations is not intended to represent cash flows for the respective period, nor has it been presented as an alternative to operating income from continuing operations as an indicator of operating performance. It should not be considered in isolation or as a substitute for measures of performance prepared in accordance with accounting principles generally accepted in the United States. See our Consolidated Statements of Cash Flows in our Consolidated Financial Statements included elsewhere in this Form 10-K. EBITDA from continuing operations is included in this Form 10-K because it is one of the measures through which we assess our financial performance. EBITDA from continuing operations as presented may not be comparable to other similarly titled measures used by other companies. A reconciliation of EBITDA from continuing operations to GAAP financial information is provided in the table below.
                                         
    Year Ended December 31,  
    2010     2009     2008     2007     2006  
Reconciliation of non-GAAP financial measure:
                                       
Income (loss) from continuing operations attributable to Willbros Group, Inc.
  $ (31,764 )   $ 22,436     $ 42,887     $ (30,537 )   $ (25,661 )
Interest expense, net
    27,565       8,328       9,032       6,055       11,820  
Provision (benefit) for income taxes
    (36,150 )     8,734       25,942       14,503       2,308  
Depreciation and amortization
    56,165       40,860       44,903       20,675       12,430  
Goodwill impairment
    60,000             62,295              
 
                             
EBITDA from continuing operations
  $ 75,816     $ 80,358     $ 185,059     $ 10,696     $ 897  
 
                             

 

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Item 7.  
Management’s Discussion and Analysis of Financial Condition and Results of Operations (In thousands, except share and per share amounts or unless otherwise noted)
The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this Form 10-K. Additional sections in this Form 10-K which should be helpful to the reading of our discussion and analysis include the following: (i) a description of our services provided, by segment found in Items 1 and 2 “Business and Properties”—“Services Provided” (ii) a description of our business strategy found in Items 1 and 2 “Business and Properties”—“Our Strategy”; and (iii) a description of risk factors affecting us and our business, found in Item 1A “Risk Factors.”
Inasmuch as the discussion below and the other sections to which we have referred you pertain to management’s comments on financial resources, capital spending, our business strategy and the outlook for our business, such discussions contain forward-looking statements. These forward-looking statements reflect the expectations, beliefs, plans and objectives of management about future financial performance and assumptions underlying management’s judgment concerning the matters discussed, and accordingly, involve estimates, assumptions, judgments and uncertainties. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to any differences include, but are not limited to, those discussed below and elsewhere in this Form 10-K, particularly in Item 1A “Risk Factors” and in “Forward-Looking Statements.”
OVERVIEW
Willbros is a global provider of engineering and construction services to the oil, gas, refinery, petrochemical and power industries with a focus on infrastructure such as oil & gas pipeline systems, electric transmission and distribution (T&D) services and refinery downstream markets. Our offerings include engineering, procurement and construction (either individually or as an integrated “EPC” service offering), turnarounds, maintenance and other specialty services.
2010 Year in Review
During 2010, revenue decreased $67,361 (5.3 percent) to $1,192,412 from $1,259,773 in 2009. Operating income, excluding Special Items decreased $79,902 (197.3 percent) to an operating loss of $39,406 from operating income of $40,496 in 2009, and operating margin decreased 6.5 percentage points to a negative 3.3 percent in 2010 from an operating margin of 3.2 percent in 2009. Refer to the “Financial Summary” section included in this MD&A for further discussion and detail of our fourth quarter and full year operating results and for details on Special Items.
Although market conditions started to improve during the year, we continued to be challenged by weaker demand for our services, which was compounded by poor visibility for the timing of both committed projects, as well as anticipated projects. As a result, we found ourselves maintaining our operations at resource levels sufficient to initiate and complete these projects. This situation resulted in a misalignment of our fixed costs as a result of the uncertain timing of revenues.
We also incurred upfront costs to invest in the future of the Company by diversifying our end market exposure through the InfrastruX acquisition and expanding our service offerings through opening new offices in the gas shale play areas to increase our presence in our customers’ work areas. We believe these investments advance our strategy to diversify our end market exposure and to increase our revenue stream from recurring services. Growing our revenue stream associated with more recurring services will provide improved stability and predictability. Strategically, we are in the midst of a transformation. We have successfully refocused our business model on North America, expanded our addressable markets to include significant exposure to the second largest hydrocarbon reserves in the world — the oil sands in Canada, the massive unconventional shale play developments in the U.S., the industrial process and refining market and the expansion and improvement of the North American electric utility grid. We believe each of these markets carries with it significant recurring services opportunities.
Our acquisition of InfrastruX came with more costly debt than originally expected and substantial overhead and indirect costs. The delays, which we discussed in our third quarter earnings call, also contributed to our loss position and reduced our financial flexibility. For the projects that we have been awarded in our upstream and downstream businesses, the market remains highly competitive and we bid most of these projects with tighter margins, and results in Canada were negatively impacted by delays and cost overruns on certain projects.

 

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On the positive side, we had many successes. We had good results on our major project execution in the United States, which can be highlighted by our superior performance executing the Fayetteville Express Pipeline (“FEP”) project, which we completed under budget and on schedule. Additionally, our Upstream Oil & Gas engineering unit exceeded its plan and our Downstream Oil & Gas segment improved its performance to better than breakeven in the second half of the year as we anticipated.
Looking Forward to 2011
As we move into 2011, our number one priority is restoring our financial strength. Our management team is focused on four priority objectives:
  1.  
Reduce debt by approximately $50 to $100 million to significantly reduce interest expense and provide better financial flexibility. This should translate more of our EBITDA into earnings;
  2.  
Maintain our focus on North America. Our presence in the Canadian oil sands and the U.S. electric transmission markets present the best growth opportunities for us. This is where our key markets and resources come together to offer the best risk adjusted returns. Currently, we are not planning to pursue large international projects like we did in 2010;
  3.  
Continue to emphasize and improve our project management tools and capabilities. We have large projects in backlog that can make a significant impact on our bottom line; and
  4.  
Remain focused on Safety. Our objective for the year is to reduce injuries by 50 percent. We differentiate Willbros on this value both as an employer and as a provider of services.
 
These objectives overarch actions already underway including:
   
Fully integrating InfrastruX into Willbros;
   
Adapting our Upstream business to meet changing market conditions and execute the newly awarded and currently underway Acadian project to the same standards as FEP;
   
Reducing operating costs and creating efficiencies that will enhance our competitiveness and improve our bottom line; and
   
Continue moving our model to an operating company structure while fostering a common set of values and culture.
Our primary financial objective is reducing our leverage position by paying down debt. This requires us to modify some of our 2010 Credit Agreement covenants. On March 4, 2011, we reached an agreement with our lenders to amend our 2010 Credit Agreement which will allow us to sell equipment, real estate and business units; and in most cases, proceeds from these divestitures would be required to pay down the Term Loan. We are also continuing to evaluate under-utilized and non-strategic assets with the aim of monetizing assets to pay down debt. In 2010, we sold under-utilized equipment with a net book value of $12,226, and to date in 2011, we have identified additional properties and equipment with a net book value of $18,867. As part of this debt reduction process, we have a study underway to assist us in determining the strategic fit and potential future contributions of various business units. The outcome of this study is expected to yield targets for divestment, which will contribute to our overall debt reduction objective.
We are focused on executing our 2011 plan, while concurrently identifying opportunities to reduce operating costs and create efficiencies that will enhance our competitiveness and improve our bottom line. Our overhead and indirect costs are too high to sustain our desired financial performance level in a weak market. Accordingly, we are in the process of identifying additional cost reduction opportunities. We continue to audit our costs in all our segments, and we are encouraged that the new cost structure in our Downstream Oil & Gas has aided its return to profitability.
During 2011, we expect to see continued improvement from each of our businesses.

 

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Our Strategy
As expanded upon in detail in Items 1 and 2 — “Business and Properties” of this Form 10-K, our vision is to be a leading provider to the global infrastructure and government services markets of diversified professional construction and maintenance solutions addressing the entire asset lifecycle. Adherence to our values of safety, honesty and integrity, our people, our customers, superior financial performance, vision and innovation and effective communication will guide us in the execution of our strategy which consists of the following:
   
Stabilizing our revenue stream with recurring services;
   
Focusing on managing risk;
   
Leveraging our industry position and reputation into a broader service offering;
   
Maintaining financial flexibility; and
   
Leveraging our core service expertise into additional full EPC contracts.
Successfully executing our strategy will ensure that we are not only well positioned to address the challenges of 2011, but also are positioned for success and to drive shareholder value for years to come.
Significant Developments
Fayetteville Express Project (“FEP”). On April 1, 2010, we commenced work on the construction contract for spreads three and four of the FEP project. The approximately 185-mile natural gas pipeline originates in Conway County, Arkansas, continues eastward through White County, Arkansas, and terminates at an interconnection with Trunkline Gas Company in Panola County, Mississippi. FEP parallels existing utility corridors, where possible, to minimize the impact to the environment, communities and landowners. FEP is a joint venture between Energy Transfer Partners, L.P. and Kinder Morgan Energy Partners, L.P. Our scope of work included 120 miles of 42-inch pipeline, beginning near Bald Knob, Arkansas and ending at the Trunkline interconnection. This project concluded in the fourth quarter of 2010.
Williams Energy Canada Boreal Pipeline. In June 2010, our Canadian business was awarded construction of the Williams Energy Canada Boreal Pipeline. The new 12-inch diameter pipeline will transport high vapor pressure liquids approximately 420 km from Williams’ Liquid Extraction Plant north of Fort McMurray to their Redwater Olefins Facility northeast of Edmonton, Alberta. Construction will be completed in three construction seasons commencing in the fall of 2010 with final completion in the spring of 2012. This project commenced in the third quarter of 2010.
InfrastruX Acquisition. On July 1, 2010, we completed the acquisition of 100 percent of the outstanding stock of InfrastruX for a purchase price of approximately $486,000, before final working capital and other transaction adjustments. This acquisition significantly diversifies our capabilities and end markets. In addition to providing meaningful access to the attractive electric transmission and distribution market, the acquisition also expands the breadth of our natural gas capabilities and better positions us in targeted markets such as the Marcellus shale play. InfrastruX and its results of operations in the electric transmission and distribution end markets are included in a newly established segment, Utility T&D. Any goodwill recognized through this transaction will be allocated to this segment, which will also be the reporting unit. Goodwill associated with this transaction is not expected to be deductible for tax purposes.
The acquisition of InfrastruX diversifies our end-market exposure while expanding our capabilities into attractive geographies, including the Marcellus shale region where we are already expanding our presence and are providing services to a major alliance partner, and more liquids oriented plays such as the Eagle Ford and Bakken shales. The combination creates a higher component of recurring services and is expected to provide additional stability, through the many master service agreements (“MSA”) InfrastruX has in place, with longstanding client relationships, some as long as 50 years. In addition, we believe this acquisition will allow us to offer the complementary pipeline services of a larger InfrastruX subsidiary that is focused on smaller diameter, distribution and pipe-related field services. We believe the market for pipeline systems construction services will be characterized by more projects of smaller scope and scale, and that the combination of our large diameter pipeline construction, project management and engineering expertise with the InfrastruX model will better meet client needs and expectations going forward. We also recognize market fundamentals which lead us to believe the national transmission grid in the United States will undergo significant expansion to meet reliability goals and link new, renewable generation with distant end markets. Our new Utility T&D segment should benefit from our established and proven project management systems as we apply them to major electric transmission line construction opportunities.
Finally, this transaction significantly adds to our scale. We believe customers today are favoring players with the capabilities to provide a broader and more integrated set of services. With the larger geographic footprint, complementary service offerings and client bases, the InfrastruX acquisition broadens our prospects with additional cross-selling and integrated EPC opportunities.
Pembina Pump Stations. In August 2010, Pembina Pipeline Corporation awarded our Canadian business a project for the construction of six pump stations for the Nipisi Heavy Crude Pipeline Project. The scope of work includes site grading at select sites, piling, pipe rack, process pipe, installation of process pumps, underground drain tanks, concrete work and site fencing. The project began in August 2010 and is scheduled for completion in the first quarter of 2011.

 

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NAVFAC Task Orders. In August 2010, the Naval Facilities Engineering Command (NAVFAC) awarded our government services business five separate task orders under its global $350 million multiple-award indefinite delivery-indefinite quantity (IDIQ) construction and construction services contract for Petroleum, Oil and Lubricant (POL) fuel systems. The task orders include various inspections, construction and repair at Eielson Air Force Base, AK; Misawa Air Force Base, Japan; Naval Air Station Oceana, Virginia Beach, VA; Naval Support Activity, Panama City, FL; and Naval Air Weapons Station, China Lake, CA. The work began in August and is scheduled for completion in early 2011.
Nipisi Pipeline Project. In September 2010, our Canadian business executed a contract to perform construction of “Spread C” for Pembina Pipeline Corporation’s Nipisi & Mitsue Pipeline Projects. We will construct approximately 90 km of dual 20 inch and 8 inch pipeline near Slave Lake, Alberta. Construction began in November and the pipeline is expected to be in service in mid-2011. The two pipelines will expand Pembina’s operating system in the vicinity of Whitecourt, Swan Hills, Slave Lake and north to the existing Nipisi Terminal.
Oxy Elk Hills. In September 2010, CB&I selected our Upstream Oil & Gas segment to provide EPC of 45 miles of export pipelines associated with a new gas processing plant to be owned and operated by Occidental of Elk Hills, Inc. CB&I has been awarded the engineering, procurement and construction of the new processing plant at the Elk Hills oil and gas field in central California. Our portion of the total project is valued in excess of $40 million.
McKee Flare Gas Recovery. Diamond Shamrock Refining Company selected our Downstream Oil & Gas segment to provide EPC of the new Flare Gas Recovery Facilities at the Valero McKee Refinery located in Sunray, Texas. The project is valued at approximately $14 million.
Defense Logistics. In September 2010, our government services business, was awarded a contract for approximately $28 million by the Defense Logistics Agency-Energy (DLA-Energy) to design, build, own, and operate six automated fuel dispensing facilities at Camp Pendleton, California. The five-year contract includes options for three additional five-year periods. The facility will provide petroleum products and services for government operations.
BP Solar Project. In November 2010, BP Solar International awarded the Hawkeye unit of our Utility T&D segment a contract to construct an approximately 37 MW (direct current) solar photovoltaic project to be located in the Town of Brookhaven on Long Island, New York. The project commenced construction in November 2010 and is expected to be complete during the second half of 2011.
Central Maine Power. In December 2010, Central Maine Power Company awarded our Utility T&D business unit Hawkeye, LLC a contract to construct two regions of the Maine Power Reliability Program, comprising a total of approximately 60 miles of new single circuit 345 kV transmission lines and the rebuild of certain existing transmission lines in southern Maine. The work is expected to commence in spring 2011 and to be complete in early 2014.
Bangor Hydro Project. In December 2010, Bangor Hydro Electric Company awarded the Hawkeye unit of our Utility T&D segment a contract to rebuild Bangor Hydro’s existing 115kV Line 64 transmission line, which originates in Bangor, Maine and extends north to Chester, Maine, for a total of approximately 44 miles (“Line 64 Project”). The Line 64 Project is comprised of two segments: the Northern Segment, which extends from the Enfield Substation to the Keene Road Substation, for a distance of approximately 12 miles; and the Southern Segment, which extends from the Enfield Substation to the Gorham Substation, for a distance of approximately 32 miles. The work commenced in December 2010 and is expected to be complete in December 2011.
Haynesville Extension, Acadian Pipeline. In January 2011, Enterprise Products Partners awarded our U.S. Construction Segment 1 of the Haynesville Extension Project which includes approximately 106 miles of 42-inch pipeline. Segment 1 originates in the northwest portion of Red River Parish, LA and terminates near Boyce, LA. The work began in February 2011 and is expected to be complete in August 2011.

 

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Financial Summary
During 2010, we generated revenue from continuing operations of $1,192,412 and an operating loss of $44,616, resulting in a net loss of $31,764, or $0.74 per diluted share. There are two large non-cash transactions reflected in these results. In the third quarter, operating income was improved by $45,340 ($45,340 after tax) as a result of reducing our 2011 contingent earnout liability related to the March 11, 2010 agreement to purchase InfrastruX. Also in the third quarter, an initial $12,000 ($7,200 after tax) estimate was recorded as a minimum Downstream Oil & Gas segment goodwill impairment. The fourth quarter annual impairment testing resulted in a final $60,000 ($36,000 after tax) goodwill impairment; the additional $48,000 ($28,800 after tax) was charged to operating income in the fourth quarter. Excluding the impact of the contingent earnout adjustment and the goodwill impairment (collectively referred to as “Special Items”), the fourth quarter and full year results were as follows:
                                 
            Change in                
            Fair Value of             Before  
    As     Contingent     Goodwill     Special  
    Reported     Earnout     Impairment     Items(1)  
Three Months Ended December 31, 2010
                               
Operating income (loss)
  $ (87,406 )   $     $ 48,000     $ (39,406 )
Net income (loss) from continuing operations
  $ (66,302 )   $     $ 28,800     $ (37,502 )
 
                               
Diluted income (loss) per share from continuing operations
  $ (1.41 )   $     $ 0.61     $ (0.80 )
Fully diluted shares, as reported
    47,099,756       47,099,756       47,099,756       47,099,756  
 
                               
Year Ended December 31, 2010
                               
Operating income (loss)
  $ (44,616 )   $ (45,340 )   $ 60,000     $ (29,956 )
Net income (loss) from continuing operations
  $ (31,764 )   $ (45,340 )   $ 36,000     $ (41,104 )
 
                               
Diluted income (loss) per share from continuing operations
  $ (0.74 )   $ (1.05 )   $ 0.83     $ (0.96 )
Fully diluted shares, as reported
    43,013,934       43,013,934       43,013,934       43,013,934  
     
(1)  
Operating income (loss) before Special Items, Net income (loss) from continuing operations before Special Items and Diluted income (loss) per share from continuing operations before Special Items, non-GAAP financial measures, exclude items that management believes affect the comparison of results for the periods discussed below. Management also believes results excluding these items are more comparable to estimates provided by securities analysts and therefore are useful in evaluating operational trends of the Company and its performance relative to other engineering and construction companies. There were no Special Items during 2009.
Full Year 2010 Results
During 2010, revenue decreased $67,361 (5.3 percent) to $1,192,412 from $1,259,773 in 2009. This decrease is primarily due to a reduction of large diameter pipeline projects in our Upstream Oil & Gas segment, exacerbated by delays in execution schedules on pipeline and facilities work in our Canadian business, offset by $317,512 contributed by our newly acquired Utility T&D segment.
Operating income, excluding Special Items, decreased $79,902 (197.3 percent) to an operating loss of $39,406 from operating income of $40,496 in 2009, and operating margin decreased 6.5 percentage points to a negative 3.3 percent in 2010 from an operating margin of 3.2 percent in 2009. The legacy segments, Upstream Oil & Gas and Downstream Oil & Gas, both experienced substantial year-over-year reductions to their operating results. Upstream Oil & Gas decreased $28,283 or 70.7 percent to $11,714 and Downstream Oil & Gas decreased $15,714 to a loss of $15,215 as compared to operating income of $499 in 2009. These unfavorable variances reflect a full year of a very difficult economic cycle for the engineering and construction industry as compared to only a partial year in 2009, compounded by significant project losses in our Upstream Oil & Gas Canadian business previously discussed. Work carried forward from 2008 buffered the reduction to operating income in the first half of 2009. Almost two thirds of 2009’s revenue of $1,259,773 occurred in the first six months of the year.
Also contributing to the successive year operating loss was $26,455 in operating loss contributed by Utility T&D, representing six months of results for our new segment acquired July 1, 2010. The loss is attributable to a combination of a weak electric distribution business and large electric construction projects being delayed from 2010 into 2011. In addition, during 2010, we incurred acquisitions costs of $10,055, an increase of $7,556 from 2009, primarily from the pursuit and acquisition of InfrastruX.
Interest, net expense increased $19,237 (231.0 percent) to $27,565 from $8,328 in 2009. The increase in net expense is a direct result of the $300,000 Term Loan used to acquire InfrastruX on July 1, 2010.
Other, net income increased $4,655 (568.4 percent) to $5,474 from $819 in 2009. This change was primarily driven by approximately $3,300 in gains recognized on the sale of assets and $2,200 in certain goods and services tax (“GST”) refunds obtained in our Canadian business. We had $1,539 in gains on asset sales recognized, offset by $720 in other net expense during 2009.

 

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The provision for income taxes for 2010 decreased $44,884 to a tax benefit of $36,150 on losses from continuing operations before income taxes of $66,707, as compared to a provision for income taxes of $8,734 on income from continuing operations before income taxes of $32,987 in 2009. The decrease in the provision for income taxes is primarily due to the decrease in operating income recognized during 2010 and no tax expense recognized in connection with the release of $45,340 of the contingent earnout liability associated with the acquisition of InfrastruX.
Refer to the “Results of Operations” section for further discussion and detail of the operating results for each of our segments.
Fourth Quarter 2010 Results
In the fourth quarter of 2010, we incurred a net loss of $66,302 or $1.41 per basic and diluted share from continuing operations revenue of $398,496 as compared to net income of $36,698 from continuing operations revenue of $408,792 for the third quarter of 2010. Excluding the fourth quarter Special Item of $48,000, or $28,800 after-tax, the fourth quarter loss is reduced to $37,502. See the table above for a reconciliation of operating income and net income excluding Special Items.
The fourth quarter of 2010’s sequential quarter revenue was fairly consistent with the previous quarter. The revenue decrease of $10,296 (2.5 percent) is primarily attributable to the mechanical completion of a large U.S. pipeline project during the third quarter and the lack of U.S. pipeline and power construction activity during the fourth quarter as this work returns to a more seasonal pattern of execution concentrated from early spring to late fall (drier months). These factors were offset by the commencement of two large pipeline projects and one facilities project during the fourth quarter of 2010 in our Canadian business, which had minimal project revenue in the third quarter of 2010 and follows a seasonal pattern from late fall to early spring.
The corresponding sequential quarter decrease in operating income was $132,814 (292.5 percent). The fourth quarter of 2010 had an operating loss of $87,406 versus operating income of $45,408 in the third quarter of 2010. Excluding the Special Items, the sequential quarter decrease is $51,474 and is primarily the result of limited work by the higher margin U.S. Pipeline operations. Although the U.S. Pipeline revenue loss was partially made up by Canada pipeline and facilities projects, the recognized Canada margins were minimal. Two Canada projects reverted to loss projects in the fourth quarter because of schedule and adverse weather delays. The operating margins, excluding Special Items, for the fourth quarter and third quarter of 2010 were negative 6.8 percent and positive 3.0 percent, respectively.
Other Financial Measures
Backlog
In our industry, backlog is considered an indicator of potential future performance as it represents a portion of the future revenue stream. Our strategy is focused on capturing quality backlog with margins commensurate with the risks associated with a given project, and for the past several years we have put processes and procedures in place to identify contractual and execution risks in new work opportunities and believe we have instilled in the organization the discipline to price, accept and book only work which meets stringent criteria for commercial success and profitability.
We believe the backlog figures are firm, subject only to the cancellation and modification provisions contained in various contracts. Additionally, due to the short duration of many jobs, revenue associated with jobs performed within a reporting period will not be reflected in quarterly backlog reports. We generate revenue from numerous sources, including contracts of long or short duration entered into during a year as well as from various contractual processes, including change orders, extra work and variations in the scope of work. These revenue sources are not added to backlog until realization is assured.
Backlog broadly consists of anticipated revenue from the uncompleted portions of existing contracts and contracts whose award is reasonably assured. Historically, our backlog has only included estimated work under MSAs for a period of 12 months or the remaining term of the contract, whichever is less. However, with the July 2010 acquisition of InfrastruX, we gained a significant alliance agreement with Oncor and other customers with work defined by MSAs. Under the Oncor MSA, we are the preferred contractor for the construction of Oncor’s portion of the Competitive Renewable Energy Zone (“CREZ”) work that is scheduled to be completed in 2013. We expect this assignment to generate over $500 million in construction revenue for our Utility T&D segment over the next three years. With this as the primary catalyst, we have updated our backlog presentation to reflect not only the 12 month MSA work estimate, but also the full-term value of the contract as we believe that this information is helpful in providing additional long-term visibility. We determine the amount of backlog for work under ongoing MSA maintenance and construction contracts by using recurring historical trends inherent in the MSAs, factoring in seasonal demand and projecting customer needs based upon ongoing communications with the customer. We also include in backlog our share of work to be performed under contracts signed by joint ventures in which we have an ownership interest.

 

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At December 31, 2010, 12 month backlog from continuing operations increased $556,965 (143.0 percent) to $946,315 from $389,350 at December 31, 2009, driven primarily by an additional $527,912 of 12 month backlog contributed by the newly acquired Utility T&D segment. The Upstream Oil & Gas segment, with a 12 month backlog of $311,326, also contributed to the overall rise in backlog by increasing $68,132, or 28% from the 2009 12 month backlog level. These increases were offset by a decrease in the Downstream Oil & Gas segment 12 month backlog of $39,079 or 27%.
In our Upstream Oil & Gas segment, 12 month backlog increased $68,132 from 2009 driven primarily by our Canadian and engineering businesses, which experienced year over year increases of $199,545 and $48,299, respectively. This was offset, however, by a decrease of $179,712 in all other business units primarily due to the completion of our largest 2010 pipeline construction project, FEP, not replaced with equivalently sized work in the latter part of 2010. Our pipeline construction services contracting has experienced a return to a historical North America contracting model that is characterized by competitive fixed price bids and short time periods from project bid to execution, except for large EPC contracts that can span more than one year. With the return to historical contracting patterns, we expect to experience lower backlog numbers partially as a result of eliminating the much longer lead times between the award of and the execution of projects.
The Downstream Oil & Gas segment continued to experience a slower than expected return to business levels realized in 2008. During 2010, turnaround work continued to be completed faster than new work was added.
In our Utility T&D segment, six customer relationships are expected to contribute $209,400 in revenue during 2011. As previously discussed, a significant portion of the Utility T&D backlog is associated with recurring services on MSA contracts that extend beyond 2011.
When factoring in the backlog beyond the current 12 months, an additional $1,229,712 in revenue is anticipated. MSA agreements account for $1,178,191 of this amount. The remaining $51,521 is attributable to current lump sum projects in the Upstream Oil & Gas and Utility T&D segments. The Utility T&D segment currently accounts for $854,367 of the reported MSA backlog beyond 12 months and is derived from agreements extending until July of 2017. The remaining $323,824 is associated with Upstream Oil & Gas segment MSA work and is primarily comprised of work from a single Canada MSA extending through 2017 and valued at $303,000.
Backlog for discontinued operations was $0 at December 31, 2010 and $2,392 at December 31, 2009.
The following table shows our backlog by operating segment as of December 31, 2010 and 2009:
                                                                 
    As of December 31,  
    2010     2009  
    12 Month     Percent     Total     Percent     12 Month     Percent     Total     Percent  
Upstream Oil & Gas
  $ 311,326       32.9 %   $ 653,671       30.0 %   $ 243,194       62.5 %   $ 283,130       66.0 %
Downstream Oil & Gas
    107,077       11.3 %     107,077       5.0 %     146,156       37.5 %     146,156       34.0 %
Utility T&D
    527,912       55.8 %     1,415,279       65.0 %           0.0 %           0.0 %
 
                                               
Total backlog
  $ 946,315       100.0 %   $ 2,176,027       100.0 %   $ 389,350       100.0 %   $ 429,286       100.0 %
 
                                               
EBITDA and Adjusted EBITDA from Continuing Operations
We use EBITDA (earnings before net interest, income taxes, depreciation and amortization) as part of our overall assessment of financial performance by comparing EBITDA between accounting periods. We believe that EBITDA is used by the financial community as a method of measuring our performance and of evaluating the market value of companies considered to be in businesses similar to ours.

 

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EBITDA from continuing operations for 2010 decreased $4,542 (5.6 percent) to $75,816 from $80,358 in 2009. The decrease in EBITDA during 2010 is primarily a result of the $45,340 change in fair value of the contingent earnout liability recognized in the third quarter of 2010 and an overall decrease in restructuring costs of $8,923, offset by decreased contract income of $23,110 (excluding depreciation) and an increase in G&A of $35,646 (excluding depreciation).
In addition to EBITDA, management uses Adjusted EBITDA for:
   
Comparing normalized operating results with corresponding historical periods and with the operational performance of other companies in our industry; and
   
Presentations made to analysts, investment banks and other members of the financial community who use this information in order to make investment decisions about us.
Adjustments to EBITDA broadly consist of items which management does not consider representative of the ongoing operations of the Company. These generally include costs or benefits that are unusual, non-cash or one-time in nature. These adjustments are included in various performance metrics under our credit facilities and other financing arrangements. The EBITDA adjustments to determine Adjusted EBITDA are itemized in the following table. You are encouraged to evaluate these adjustments and the reasons we consider them appropriate for supplemental analysis. In evaluating Adjusted EBITDA, you should be aware that in the future we may incur expenses that are the same as, or similar to, some of the adjustments in this presentation. Our presentation of Adjusted EBITDA should not be construed as an inference that our future results will be unaffected by unusual or non-recurring items.
EBITDA and Adjusted EBITDA are not financial measurements recognized under U.S. generally accepted accounting principles, or U.S. GAAP, and when analyzing our operating performance, investors should use EBITDA and Adjusted EBITDA in addition to, and not as an alternative for, net income, operating income, or any other performance measure derived in accordance with U.S. GAAP, or as an alternative to cash flow from operating activities as a measure of our liquidity. Because all companies do not use identical calculations, our presentation of EBITDA and Adjusted EBITDA may be different from similarly titled measures of other companies.
A reconciliation of EBITDA and Adjusted EBITDA from continuing operations to U.S. GAAP financial information follows:
                         
    Year Ended December 31,  
    2010     2009     2008  
Net income from continuing operations attributable to Willbros Group, Inc.
  $ (31,764 )   $ 22,436     $ 42,887  
Interest, net
    27,565       8,328       9,032  
Provision (benefit) for income taxes
    (36,150 )     8,734       25,942  
Depreciation and amortization
    56,165       40,860       44,903  
Goodwill impairment
    60,000             62,295  
 
                 
EBITDA
    75,816       80,358       185,059  
 
                 
 
                       
Changes in fair value of contingent earnout liability
    (45,340 )            
DOJ monitor cost
    4,002       2,582       530  
Stock based compensation
    7,957       9,549       11,652  
Restructuring and reorganization costs
    3,771       12,694        
Acquisition related costs
    10,055       2,499        
(Gains) on sales of equipment
    (3,538 )     (1,082 )     (7,081 )
Noncontrolling interest
    1,207       1,817       1,836  
 
                 
Adjusted EBITDA
  $ 53,930     $ 108,417     $ 191,996  
 
                 

 

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Discontinued Operations
For the year ended December 31, 2010, loss from discontinued operations was $5,272 or $0.12 per share. This compares to a loss from discontinued operations of $4,613 or $0.12 per share for the year ended December 31, 2009. The 2010 loss from discontinued operations is primarily due to the classification of our Libyan operations as discontinued operations as of December 31, 2010. Our investment in establishing a presence in Libya, while resulting in contract awards, has not yielded any notice to proceed on subject awards, and we have, therefore, exited this market due to the delays and identification of other more attractive opportunities.
Transition Services Agreement (“TSA”)
The TSA expired on February 7, 2009, which ended our obligation to provide any further support or other services to Ascot in West Africa or otherwise. Although the Transition Services Agreement expired, we continue to incur legal fees related to the West African Gas Pipeline Company Limited (‘WAPCo”) parent company guarantee assertions as further discussed in Note 21 — Discontinuance of Operations, Asset Disposals and Transition Services Agreement. These legal fees are expected to escalate and continue over the next several years. At this time, we are unable to estimate the likely total legal costs.
Parent Company Guarantees
Although the Nigeria letters of credit and the TSA have expired, we continue to have potential financial exposure from parent company performance guarantees related to several projects in Nigeria that were contracted by our subsidiary, Willbros West Africa, Inc. (“WWAI”), at the time of our February 7, 2007 sale of WWAI to Ascot. On February 15, 2010, we received a letter from attorneys representing WAPCo advising us that we were liable for approximately $265,000 of damages allegedly incurred by WAPCo to complete the remaining portion of the scope of work (a portion of the West Africa Gas Pipeline project or “WAGP”) originally contracted by WWAI. After WWAI was sold to Ascot, on February 27, 2008, WAPCo provided WWAI with notice of termination of the WAGP contract. We intend to contest this claim for damages vigorously. At this time, no estimate can be made on the likely outcome of what is expected to be a prolonged period of litigation.
Additional financial disclosures and information on discontinued operations and the February 15, 2010 WAPCo letter are provided in Note 21 — Discontinuance of Operations, Asset Disposals and Transition Services Agreement included in Item 8 and in Item 1A — Risk Factors of this Form 10-K.
RESULTS OF OPERATIONS
Our contract revenue and contract costs are significantly impacted by the capital budgets of our clients and the timing and location of development projects in the oil and gas, refinery, petrochemical and power industries worldwide. Contract revenue and cost vary by country from year-to-year as the result of: entering and exiting work countries; the execution of new contract awards; the completion of contracts; and the overall level of demand for our services.
Our ability to be successful in obtaining and executing contracts can be affected by the relative strength or weakness of the U.S. dollar compared to the currencies of our competitors, our clients and our work locations.
Fiscal Year Ended December 31, 2010 Compared to Fiscal Year Ended December 31, 2009
Contract Revenue
Contract revenue decreased $67,361 (5.3 percent) to $1,192,412 from $1,259,773. A year-to-year comparison of revenue is as follows:
                                 
    Year Ended December 31,  
                    Increase     Percent  
    2010     2009     (Decrease)     Change  
Upstream Oil & Gas
  $ 573,796     $ 982,523     $ (408,727 )     (41.6 )%
Downstream Oil & Gas
    301,104       277,250       23,854       8.6 %
Utility T&D
    317,512       N/A       317,512       100.0 %
 
                         
Total
  $ 1,192,412     $ 1,259,773     $ (67,361 )     (5.3 )%
 
                         
Upstream Oil & Gas revenue decreased $408,727 (41.6 percent) to $573,796 from $982,523 in 2009. We believe the decrease in revenue was the result of our customers’ reduction in capital and maintenance spending in 2010 as a continued reaction to the overall global economic recession. This was evidenced by an overall decrease in large diameter pipeline projects available for bid. Further, projects that were initially being bid for 2010 completion were postponed or cancelled. As a result of these conditions, the segment began to pursue midstream pipeline projects which opened a new market in one of the major regional shale plays. This market generated $41,518 in revenue for

 

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us in 2010. The engineering business also contributed higher than expected revenues of $66,206 as a result of developing alliances. Overall, our North American Upstream Oil & Gas business units experienced revenue decreases from 9.4 percent to 56.7 percent. The sole business unit to grow revenue year-over-year was in Oman, where revenue grew 12.6 percent driven by maintenance services. The majority of our 2010 revenue (57.5 percent) was awarded and executed in 2010, with the largest exception being the FEP project that was awarded for approximately $195,000 in 2009 and executed in 2010. This marks a return to the business environment where we expect short lead-times between award and execution for our construction projects in the United States.
Our U.S. business units’ revenues decreased $341,009 (51.4 percent) to $321,791 from $662,800 in 2009. This was primarily due to reduced utilization of large-diameter cross-country pipeline construction assets of $264,927 and a reduction of pipeline facility construction work of $98,711. We believe the reduction of pipeline construction revenue was directly linked to the reduced capital budgets approved and executed by our core customer base in 2010. We believe the reduction of facility construction revenue was also impacted by significantly reduced capital budgets for our core customers. These decreases were partially offset by increased revenue from our regional pipeline construction activity of $41,518 and increased revenue from our engineering services of $4,321. We believe the increased demand for our engineering services, while modest at 10.1 percent, demonstrates a turning point in the market for front-end design work for gas and liquid transportation systems which is the precursor to construction of these systems.
Our Canada business unit revenue decreased $75,935 (29.9 percent) to $178,418 from $254,353 in 2009. The decrease was primarily due to reduced capital budgets of the oil-sand producers and pipeline companies, driven by uncertain crude pricing. Revenue from our pipeline construction group decreased $35,355, revenue from our field services group declined $22,698, and revenue from our facility construction group declined $18,277. Our Oman business unit revenue increased $8,221 (12.6 percent) to $73,589 from $65,368 in 2009. This increase was largely attributable to increased work order activity from our largest customers for which we provide both capital construction and maintenance services.
Downstream Oil & Gas revenue increased primarily as a result of increased maintenance and turnaround activity and development of downstream services in Canada. We experienced revenue increases of 17.5 percent to 78.8 percent in several of our business units and revenue decreases from 35.5 percent to 75.2 percent in our other business units. Revenue increased quarter-over-quarter throughout 2010 as we worked off existing backlog from 2009 and filled in the year with new contract awards.
Our Construction Services business unit revenue decreased $25,193 (75.2 percent) to $8,290 from $33,484 in 2009. While this business unit has maintained a consistent level of consulting services for our customers’ long-term capital expansion projects, our involvement in the physical construction of these projects has decreased from six projects in 2009 to one project in 2010. Our consulting services arrangements were largely negotiated in prior years for projects that are still ongoing. New capital project activity and construction opportunities relating to our consulting services have decreased since the latter part of 2008.
Our Manufacturing Services business unit revenue decreased $13,478 (35.5 percent) to $24,514 from $37,992 in 2009, primarily due to a 62.0 percent decrease in revenue from fabrication of process heaters. As capital spending by our customers decreased throughout 2009, we worked off existing backlog but were unable to replace that work in 2010. As our customers’ capital budgets increase, we fully expect that the demand for process heaters will increase. Partially offsetting the revenue decline from fabrication of process heaters was a 221.4 percent increase in revenue from fabrication of replacement transfer lines, which represents maintenance expenditures for our customers.
Our Tank Services business unit revenue increased $16,322 (64.5 percent) to $41,620 from $25,298 in 2009. Our 2009 and 2010 investments in expanding tank services into Canada resulted in our first contract award in 2010. We realized revenue of $15,355 from this contract in 2010 and are actively pursuing additional contract awards in Canada. Services provided in the U.S. consisted of less new tank construction than in previous years as a result of decreased capital spending by our customers in 2009 and early 2010. We were able to win additional tank inspection and repair work in 2010 to offset the decrease in new tank construction awards. Proposal requests from our customers for new tank construction projects increased during the latter half of 2010, resulting in several multiple-tank construction contract awards that began in late 2010.

 

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Our Maintenance and Turnaround business unit revenue increased $25,804 (17.5 percent) to $172,980 from $147,176 in 2009. We benefited in 2010 from our position as a contractor of choice for our customers’ maintenance and turnaround needs, the impact of delayed maintenance activities in 2009, and our investments in equipment to provide exchanger tube bundle extraction services.
Our Engineering business unit revenue increased $17,634 (59.2 percent) to $47,428 from $29,794 in 2009. We experienced a $19,958 increase in revenue resulting from a full year of activity for Downstream Engineering, acquired in July 2009. Engineering revenue declined during the latter half of 2010 as several significant contracts were completed. Bid activity on new capital work remains high. However, we continue to experience customer-imposed delays on awarded contracts. The decline in engineering revenue during the latter half of 2010 was partially offset by the award of an EPC contract from an existing customer in Texas. This project began late in the third quarter of 2010. We continue to market our EPC service offering to new and existing customers.
Our Government Services business unit revenue increased $2,765 (78.8 percent) to $6,272 from $3,507 in 2009. This resulted primarily from the reclassification of Government Services from the Upstream Oil & Gas segment to the Downstream Oil & Gas segment in July 2009. We were successful in winning nine task orders from the U.S. Navy under the Engineering Service Center’s IDIQ contract, six of which commenced during the second half of 2010 and will continue into 2011. We continue to bid on task orders under this contract as they are released.
Utility T&D, a new segment, resulting from the acquisition of InfrastruX, contributed revenue of $317,512 as a result of revenues derived from a broad range of transmission and distribution construction and maintenance services from July 1, 2010 through December 31, 2010. This segment includes the business units of Hawkeye, Chapman Construction, and Willbros T&D, which accounted for $75,778, $57,143 and $40,873, respectively, or 54.7% of the segment’s total revenue. Hawkeye’s contract revenue is driven primarily by MSA contracts related to overhead and underground transmission, distribution and telecommunication systems. The business generated revenue of $61,880 for the six months ended December 31, 2010 as a direct result of established MSAs. These agreements vary in length from one month to three years. Chapman generated $44,948 or 78.6% of the business units’ revenue through an alliance agreement with Oncor providing turnkey transmission and substation construction and maintenance solutions. Willbros T&D produced $28,289 or 72.1% of that business unit’s revenue through an alliance agreement with Oncor to provide overhead and underground utility construction services.
Operating Income
Operating income decreased $130,452 (322.1 percent) to a loss of $89,956 from income of $40,496 in 2009. A year-to-year comparison of operating income is as follows:
                                                 
            Operating             Operating             Percent  
    2010(1)     Margin %     2009     Margin %     Change     Change  
 
Upstream Oil & Gas
  $ 11,714       2.0 %   $ 39,997       4.1 %   $ (28,283 )     (70.7 )%
Downstream Oil & Gas
    (75,215 )     (25.0 )%     499       0.2 %     (75,714 )     (15,173.1 )%
Utility T&D
    (26,455 )     (8.3 )%     N/A       N/A       (26,455 )     (100.0 )%
 
                                         
Total
  $ (89,956 )     (7.5 )%   $ 40,496       3.2 %   $ (130,452 )     (322.1 )%
 
                                         
     
(1)  
This table does not reflect change in fair value of contingent earnout consideration of $45,340 in 2010 which is included in operating results. The change in fair value of contingent earnout consideration was characterized as a corporate change in estimate and is not allocated to the reporting segments.
Upstream Oil & Gas operating income decreased $28,283 (70.7 percent) to $11,714 from $39,997 in 2009. The decrease was caused by reduced revenue across the segment, as noted above. Our operating margin was consistent year-over-year primarily due to improved project margins in the United States partially offset by reduced margins in Canada as well as increased general and administrative (“G&A”) expense as a percent of revenue, across the segment. The increased G&A was primarily attributed to increased proposal activity as well as growth initiatives expanding our regional service delivery capabilities.
Operating income for our United States business units decreased $468 (1.8 percent) to $25,741 from $26,209 in 2009. Our operating income remained constant in-spite of significant revenue declines of 51.4% for these businesses. Our construction business suffered the most from revenue decline, but our focus on execution of the available work allowed us to improve our contract margins and still deliver strong operating income at a significantly smaller volume. This continued profitability came as we saw the market shift back fully to lump-sum contracting terms, marking the end of the cost-reimbursable work that we completed in 2009 for large diameter cross-country pipeline construction. Our engineering business experienced a much more modest revenue decline, but had a significant improvement in profitability. In 2009, our engineering business had significant operating losses, which were reversed in 2010 to significant operating income due to stronger market demand for our services and active cost management.

 

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Operating income for our Canada business unit decreased $29,826 (371.4 percent) to a loss of $21,796 from income of $8,030 in 2009. This decrease was primarily caused by loss projects in our pipeline and facility construction groups, compounded by the reduction of recurring oil-sands maintenance contracts in northern Alberta. The four lump-sum projects that were in a loss position as of year-end accounted for approximately $19,000 of contract losses. In 2010, we were awarded a multiple year extension for our maintenance work for Syncrude in Canada. Operating income for our Oman business unit increased $749 (7.7 percent) to $10,509 from $9,760 in 2009. The increase in operating income is primarily attributable to a revenue increase which we feel is driven by our long-term recurring service contracts with key customers in Oman. These recurring services helped to insulate this business unit from the constraints of capital spending that we experienced in other parts of our business in 2010. Operating losses for our other international business units decreased $550 (18.0 percent) to a loss of $2,502 from a loss of $3,052 in 2009. These costs are primarily related to international new business development and pursuing new opportunities, as well as the proposal costs associated with submitting multiple qualified international bids in places like Libya and Australia in 2010.
Downstream Oil & Gas operating income decreased primarily as a result of the $60,000 goodwill impairment charge taken in the third and fourth quarters of 2010 and the previously discussed decreases in revenue from our Manufacturing Services and Construction Services business units, as well as operating losses contributed by our Engineering business unit ($6,148) and Tank Services business unit ($4,537). Our Maintenance and Turnaround business unit contributed an operating loss for the year that was driven largely by a loss on a fixed price contract early in the year.
Contract margins declined in each business unit during 2010. These declines were caused by continued pricing pressure from our customers and a more competitive bidding environment. As a result, our fixed price bids and our rates on cost reimbursable projects subsequently awarded and performed during 2010 reflected lower margins. These lower bid margins, combined with losses experienced on several contracts, resulted in contract margin decreases of 12.8 percent in Tank Services, 13.4 percent in Manufacturing Services, and 2.9 percent in Maintenance and Turnaround Services. Contract margins for the Downstream Oil & Gas segment decreased 5.9 percent, driven primarily by these three business units.
As part of our continuing effort to decrease costs in this segment and remain competitive in our market, we successfully reduced indirect contract costs and G&A costs by $12,750 and $7,095, respectively, compared to 2009. Included in operating costs is $536 in costs associated with headcount reductions.
The Utility T&D segment generated an operating loss of $26,455. The segment incurred costs totaling $26,309 of which non-recurring acquisition costs of $9,814, and restructuring fees of $2,638 associated with the Seattle office closure were recorded for the six months ended December 31, 2010. Other significant costs charged to the segment were labor of $2,889 and depreciation of $1,267.
The Willbros T&D business experienced an operating loss of $3,597 as a result of lower volumes and a shift in the mix in transmission construction revenues associated with the Oncor work in Texas, resulting in a heavier mix of lower margin work. In addition, these lower volumes and delays created an underutilization of equipment. For the six months ended December 31, 2010, Willbros T&D incurred equipment rental expense of $2,994 and depreciation expense of $2,144 associated with an underutilized fleet.
Hawkeye reported an operating loss of $3,280 primarily due to the project delays experienced in the Northeast (both of which are currently underway); and in general a weaker market for electric and gas distribution work. In addition, depreciation costs on an underutilized fleet were $3,310.
Partially offsetting the operating losses were UtilX with operating income of $5,379 and Chapman with operating income of $3,661. Utilx’s international operations performed well due to Cablewise® projects in Europe and increased royalty revenue. Chapman provided operating income despite a shift in the mix of transmission construction revenue associated with the CREZ build out.

 

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Non-Operating Items
Interest, net expense increased $19,237 (231.0 percent) to $27,565 from $8,328 in 2009. The increase in net expense is primarily a result of increased interest expense of $16,106 related to the new Term Loan, debt issuance cost amortization of $1,994 related to the 2010 Credit Agreement and a reduction in interest income of $1,211 due to lower levels of and rates of return on invested cash.
Other, net income increased $4,655 (568.4 percent) to a net income of $5,474 from net income of $819 in 2009. The increase in income is attributed to increased gains on the sale of assets of $1,748 in 2010 as compared to 2009, a reduction in expense of $1,210 related to asset write-downs taken in 2009, $879 in income recorded in the second quarter of 2010 as a result of a refund of GST based on certain deductions made in 2010, and a reduction in foreign exchange losses of $235 on U.S. dollar to Canadian dollar transactions.
Provision for income taxes decreased $44,884 (513.9 percent) to a benefit of $36,150 from a provision of $8,734 in 2009. During 2010, we recognized a tax benefit of $36,150 on a loss from continuing operations before income taxes of $66,707 as compared to income tax expense of $8,734 on income from continuing operations before income taxes of $32,987 in 2009. The decrease in the provision for income taxes is due to the decrease in operating income recognized during 2010 and no tax expense incurred in connection with the release of the contingent earnout liability in the amount of $45,340 associated with the acquisition of InfrastruX.
Income (Loss) from Discontinued Operations, Net of Taxes
Income (loss) from discontinued operations, net of taxes increased $659 (14.3 percent) to a loss of $5,272 from a loss of $4,613 in 2009. As of December 31, 2010, we classified our Libyan operations as discontinued operations for all periods presented. Our investment in establishing a presence in Libya, while resulting in contract awards, has not yielded any notice to proceed on subject awards, and we have therefore exited this market due to the delays and identification of other more attractive opportunities. Our loss from discontinued operations related to Libya was $3,179 for the year ended December 31, 2010 and $3,116 for the year ended December 31, 2009. The loss during the twelve months ended December 31, 2010 is also related to the legal fees incurred in connection with the previously discussed WAPCo parent company guarantee assertions. The legal fees are expected to escalate and continue over the next several years. At this time, we are unable to estimate the likely total legal fees. The change is also related to a $1,750 charge taken during the second quarter of 2009 to write-off the net book value of the note related to the Venezuela sale, as management determined it unlikely to collect due to the nationalization of various oil contractors within the country.

 

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Fiscal Year Ended December 31, 2009 Compared to Fiscal Year Ended December 31, 2008
Contract Revenue
Contract revenue decreased $652,931 (34.1 percent) to $1,259,773 from $1,912,704 primarily due to decreased Upstream Oil & Gas revenue, although Downstream Oil & Gas did incur a significant percentage decrease in revenue. A year-to-year comparison of revenue is as follows:
                                 
    Year Ended December 31,  
                            Percent  
    2009     2008     Decrease     Change  
 
Upstream Oil & Gas
  $ 982,523     $ 1,545,629     $ (563,106 )     (36.4 )%
Downstream Oil & Gas
    277,250       367,075       (89,825 )     (24.5 )%
 
                         
Total
  $ 1,259,773     $ 1,912,704     $ (652,931 )     (34.1 )%
 
                         
Upstream Oil & Gas revenue decreased $563,106 (36.4 percent) to $982,523 from $1,545,629 in 2008. We believe the decrease in revenue was the result of our customers’ reduction in capital and maintenance spending in 2009 as a reaction to the overall global economic recession. At each of our Upstream Oil & Gas business units, we experienced revenue decreases from 23.0 percent to nearly 70.0 percent. The majority of our 2009 revenue (67.6 percent) was earned in the first six-months of 2009 as we worked off existing backlog from 2008.
Our U.S. Construction business unit revenue decreased $253,305 (30.0 percent) to $589,736 from $843,041 in 2008. This was primarily due to reduced utilization of large-diameter cross-country pipeline construction assets of $156,263 and a reduction of pipeline construction EPC work of $126,754. We believe both of these reductions were directly linked to the reduced capital budgets of our primary client base for this business. These decreases were partially offset by increased revenue from our facility construction group of $21,985 and increased revenue from our Manage & Maintain group of $6,825. The facility construction revenue was primarily attributable to one large project that included the construction of seven pump stations.
Our Canada business unit revenue decreased $133,143 (34.4 percent) to $254,355 from $387,498 in 2008. The decrease was primarily due to reduced capital budgets of the oil-sand producers and pipeline companies, driven by the decline in crude oil prices year-over-year and the production costs associated with the oil-sands. Revenue from our pipeline construction group decreased $109,602. Additionally, our long-term contracts for recurring maintenance at the oil-sand production facilities generated $24,782 less in revenue in 2009.
Our U.S. Engineering business unit revenue decreased $159,495 (68.6 percent) to $73,064 from $232,559 in 2008. Revenue from core engineering services declined $95,403, reflecting the significant drop-off in market demand for front-end design work for gas and liquid transportation systems. The EPC component of our offering, which declined $68,748, was affected by reduced capital expenditure budgets combined with owners increasing their risk tolerance associated with managing multiple aspects of these large projects.
Our Oman business unit revenue decreased $19,599 (23.1 percent) to $65,368 from $84,967 in 2008. This decrease was largely due to reduced work order activity of $21,124 from our primary client, to whom we provide both capital construction and maintenance services. This reduction was partially offset by an increase of $3,331 in our rig moving services.
Downstream Oil & Gas revenue decreased $89,825 (24.5 percent) to $277,250 from $367,075 in 2008, primarily as the result of declining construction revenue from capital projects. The decline in refining profit margins slowed the release of capital projects by our customers. As a result, while we continued to complete capital contracts awarded in 2008 and early 2009, we were not able to replace them to the same extent as in the prior year.
Construction services revenue decreased $72,616 (68.4 percent) to $33,484 primarily due to the completion of a major EPC project early in 2009, which was a significant source of construction services revenue in 2008. Tank construction revenue decreased $31,963 (55.8 percent) to $25,298. The slow release of capital projects has increased competition and impacted the volume of contract awards that we have been able to obtain in both of these business units in 2009.
The decline in profit margins in 2009 in the refining industry also resulted in the delay of several maintenance and turnaround projects from 2009 into 2010. This caused maintenance and turnaround revenue to decrease $6,695 (4.4 percent) to $147,176.

 

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Downstream engineering revenue increased $21,856 (275.4 percent) to $29,794 primarily the result of our acquisition of Wink in July 2009.
Operating Income
Operating income decreased $31,310 (43.6 percent) to $40,496 from $71,806 in 2008. A year-to-year comparison of operating income is as follows:
                                                 
    Year Ended December 31,  
            Operating             Operating             Percent  
    2009     Margin %     2008     Margin %     Change     Change  
Upstream Oil & Gas
  $ 39,997       4.1 %   $ 110,885       7.2 %   $ (70,888 )     (63.9 )%
Downstream Oil & Gas
    499       0.2 %     (39,079 )     (10.6 )%     39,578       101.3 %
 
                                         
Total
  $ 40,496       3.2 %   $ 71,806       3.8 %   $ (31,310 )     (43.6 )%
 
                                         
Upstream Oil & Gas operating income decreased $70,888 (63.9 percent) to $39,997 from $110,885 in 2008. The decrease was caused by reduced revenue across the segment, as noted above, combined with increased margin pressure for most of our service offerings. With fewer prospects available in 2009, the competition for each project grew, forcing us to reduce margin expectations across the segment. Our contract margins for 2009 were lower than 2008 at three of our four primary business units, suffering declines from 2.6 percentage points to 13.0 percentage points. The only business unit that improved contract income, year-over-year, was our U.S. Construction group, which improved 0.9 percentage points. In 2009, we focused on reducing our overhead expenses to remain competitive in a market with fewer opportunities. These efforts resulted in a reduction of our total G&A costs of $14,527 in 2009. As a percent of segment revenue, G&A costs represented 7.0 percent, although this was an increase as compared to the equivalent 5.3 percent in 2008. G&A costs reductions lagged behind the 36.4 percent revenue decline in 2009.
Operating income for our U.S. Construction business unit decreased $11,419 (25.9 percent) to $32,702 from $44,121 in 2008. While operating income was down, operating margin was steady year-over-year, increasing 0.3 percentage point to 5.5 percent from 5.2 percent in 2008. In the face of increased competition and an overall weaker economy, this performance helped support the Upstream Oil & Gas segment. While this business unit was able to improve contract margin year-over-year, this improvement did not offset the impact to operating income associated with the revenue decline of 30.0 percent. Contract margin improvement was largely driven by two key factors, the completion of the Midcontinent Express Pipeline project, a large multi-spread cost reimbursable pipeline project, and the successful transition to and completion of TIPS, a lump-sum two-spread pipeline construction project. TIPS performance exceeded expectations and contributed to the slight year-over-year margin improvement. By comparison, our 2008 contract margin was largely attributable to two large multi-spread pipeline construction projects with cost reimbursable terms, Southeast Supply Header (“SESH”) and MEP. The cost reimbursable nature of these jobs ensured our profitability, but negatively impacted margin as the size of the projects increased revenue while our profit opportunity remained fixed. These projects were also offset by smaller lump-sum pipeline construction projects that did not perform to the as-bid expectations. We reduced our U.S. Construction G&A costs by $7,645 in 2009.
Operating income for our Canada business unit decreased $19,356 (74.4 percent) to $6,656 from $26,012 in 2008. This decrease was primarily caused by the reduction of revenue associated with our pipeline construction group in Canada. Pipeline construction revenue decreased 60.2 percent year-over-year. In 2008, our two largest pipeline construction projects generated $181,688 of revenue, compared to our two largest projects in 2009 which generated $71,204. This significant decrease was representative of the overall reduction of oil-sands related pipeline construction projects in Canada. Our maintenance and fabrication services were relatively constant year-over-year, providing some insulation from the cyclical pipeline construction market. We reduced our Canada G&A costs by $3,976 in 2009.
Operating income for our U.S. Engineering business unit decreased $31,803 (125.5 percent) to a loss of $6,470 from income of $25,333 in 2008. A continuing reduction of our work load resulted in reduced utilization of resources throughout the year, and in response we initiated several reductions of force to match the resource base to the available work. We began the year with approximately 450 engineering and support staff, and we ended the year with approximately 250. In addition to these reductions, we continued to evaluate and make corresponding reductions in other support. In 2009, we reduced our U.S. Engineering G&A costs by $4,199.

 

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Operating income for our Oman business unit decreased $5,780 (37.2 percent) to $9,760 from $15,540 in 2008. The decrease in operating income is primarily attributable to reduced revenue in 2009 as noted previously. Our contract margins decreased 3.3 percent year-over-year, negatively impacting operating income. These reductions were the result of fewer work-orders and qualified prospects compounded by a more competitive bidding environment. These decreases were partially offset by a reduction of overall business unit G&A costs of $4,287.
Operating income for our other international business units decreased $1,494 (94.7 percent) to a loss of $3,072 from a loss of $1,578 in 2008. These costs are primarily related to international new business development and pursuing new opportunities, as well as the proposal costs associated with submitting multiple qualified bids.
Downstream Oil & Gas operating income increased $39,578 (101.3 percent) to $499 from a loss of $39,079 in 2008, primarily from the $62,295 impairment charge taken in 2008. This increase is partially offset by an operating income decrease of $22,717 caused primarily by the previously discussed revenue variances, as well as declining margins across most business units.
Construction services operating income decreased $2,907 (78.8 percent) to $782 primarily as a result of the slow release of capital work. Tank services operating income decreased $7,606 (95.0 percent) to $403 due to the slow release of capital work and fewer fixed price contract awards, which traditionally result in higher margins, in 2009 as compared to 2008. The reduction in fixed price work was caused by pricing pressures from our customers and also contributed to the $5,793 (77.3 percent) reduction in maintenance and turnaround operating income.
Downstream engineering operating income decreased $6,694 to a loss of $5,476 as a result of our acquisition of Wink in July 2009.
Downstream Oil & Gas incurred $3,141 in other charges in 2009, of which $1,963 occurred in the engineering business unit almost entirely related to lease impairment charges taken on Wink’s leased office space.
Non-Operating Items
Interest, net expense decreased $704 (7.8 percent) to $8,328 from $9,032 in 2008. The decrease in net expense is the result of a decrease in interest expense of $2,285 primarily due to decreased capital lease obligations as a result of buy-outs during the second quarter of 2009, offset by $1,581 of decreased interest income earned on cash and cash equivalents due to declining interest rates throughout 2009.
Other, net income decreased $7,072 (89.6 percent) to a net income of $819 from net income of $7,891 in 2008. The decrease was primarily a result of selling one of our fabrication facilities located in Edmonton, Alberta, Canada, which resulted in a gain on sale of $7,694 during 2008.
Provision for income taxes decreased $17,208 (66.3 percent) to $8,734 from $25,942 in 2008. During 2009, we recognized $8,734 of income tax expense on income from continuing operations before income taxes of $32,987 as compared to income tax expense of $25,942 on income from continuing operations before income taxes of $70,665 in 2008. The decrease in the provision for income taxes is due to the decrease in operating income recognized during 2009 and a decrease in effective tax rate primarily due to the reversal of uncertain tax positions.
Income (Loss) from Discontinued Operations, Net of Taxes
Income (loss) from discontinued operations, net of taxes decreased $5,358 (719.2 percent) to a loss of $4,613 from income of $745 in 2008. During 2009, a $1,750 charge to write off the net book value of a note receivable related to the sale of our Venezuela assets and operations was recorded. Management determined the collection of this outstanding commitment was highly unlikely due to nationalization of various oil-field service contractors within the country. The income recognized during the same period in 2008 was the result of two pre-Nigeria sale insurance claim recoveries totaling $3,004 for events of loss we suffered prior to the sale of our Nigeria operations. Additionally, as of December 31, 2010 we classified our Libyan operations as discontinued operations. We recognized a loss from discontinued operations related to Libya of $3,116 and $2,012 respectively for the years ended December 31, 2009, and 2008.

 

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LIQUIDITY AND CAPITAL RESOURCES
Our financing objective is to maintain financial flexibility to meet the material, equipment and personnel needs to support our project commitments, and pursue our expansion and diversification objectives, while reducing debt. As of December 31, 2010, we had cash and cash equivalents of $141,101. Our cash and cash equivalent balances held in the United States and foreign countries were $59,437 and $81,664, respectively. We have analyzed our operations in all jurisdictions and while our current operating strategy is to reinvest any earnings of operations internationally rather than to distribute dividends to the U.S. parent or its U.S. affiliates, we are continually evaluating the use of cash available in our foreign subsidiaries for use to pre-pay debt. No dividends were paid from foreign operations to Willbros Group, Inc. or its domestic subsidiaries during 2010. At this time, there are other avenues available to management to consider for pre-payment of debt and the likelihood that cash would be repatriated from foreign operations is low.
We are also able to secure funds from a three year revolving credit facility of $175,000 that was established primarily to provide letters of credit. As of December 31, 2010, we had no outstanding borrowings and $25,678 of letters of credit outstanding under our 2010 Credit Facility, leaving remaining capacity of $149,322. Our ability to use the 2010 Credit Facility for revolving loans, however, has been restricted as a result of the amendment to the 2010 Credit Facility in March of 2011 as discussed below.
During 2010, our working capital position for continuing operations decreased by $27,811 (9.4 percent) to $269,584 from $297,395 at December 31, 2009. This was primarily the result of a significant reduction in income from continuing operations due to a reduction of large diameter pipeline projects in our Upstream Oil & Gas segment, amplified by delays in execution schedules on pipeline and facilities work in our Canadian business, offset by additional working capital associated with our new Utility T&D segment in the second half of 2010.
Our overall cash balance has been negatively impacted by an ongoing contract dispute with TransCanada. See Note 16 in the accompanying financial statements for additional background information. As of December 31, 2010, we have $71,159 of unpaid TransCanada receivables. We have submitted this dispute to arbitration for resolution; however, final resolution may not occur for a year or more. We have not established a collectability reserve, and we believe adequate financial reserves are available during the interim period prior to receiving payment.
Additional Sources and Uses of Capital
2010 Credit Facility
Concurrent with our acquisition of InfrastruX, we entered into the 2010 Credit Agreement dated June 30, 2010, that consists of a four year, $300,000 Term Loan maturing in July 2014 and a three year revolving credit facility of $175,000, maturing in July 2013 and replaced our existing three year $150,000 senior secured credit facility, which was scheduled to expire in November 2010. The proceeds from the Term Loan were used to pay part of the cash portion of the merger consideration payable in connection with our acquisition of InfrastruX. See Note 10 — Long-term Debt in Item 8 of this Form 10-K for further discussion of the 2010 Credit Facility.
Our 2010 Credit Agreement (and the 6.5% Senior Convertible Notes for debt incurrence test only) contain various provisions that require us to, among other things, comply with the following requirements in which we were in compliance as of December 31, 2010:
   
minimum interest coverage ratio;
   
maximum total leverage ratio;
   
minimum tangible net worth;
   
debt incurrence test;
   
minimum consolidated EBITDA and a minimum cash balance during the Interim Period;
   
limitations on capital expenditures during the Interim Period, $60,000, and the greater of $70,000 or 25% of EBTIDA thereafter;
   
limitations on indebtedness;
   
limitations on liens;
   
limitations on certain asset sales and dispositions; and
   
limitations on certain acquisitions and asset purchases if certain liquidity levels are not maintained.

 

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Our 2010 Credit Agreement, 2.75% Convertible Senior Notes and 6.5% Senior Convertible Notes contain default and cross-default provisions. An Event of Default under the 2010 Credit Agreement would permit Crédit Agricole and the lenders to terminate their commitment to make cash advances or issue letters of credit, require the immediate repayment of any outstanding cash advances with interest and require the cash collateralization of outstanding letter of credit obligations. An Event of Default under the 2.75% Convertible Senior Notes and 6.5% Senior Convertible Notes would require an accelerated payment of such notes before the scheduled date of maturity. Events of Default in the 2010 Credit Agreement, 2.75% Convertible Senior Notes, or the 6.5% Senior Convertible Notes may trigger cross-default provisions under these debt instruments.
Events of Default under the 2010 Credit Agreement, 2.75% Convertible Senior Notes and 6.5% Senior Convertible Notes may include, but are not limited to, covenant breaches that are not waived or cured, a failure to make scheduled payments of interest or principal of any debt obligation greater than a certain amount, a change in control of the Company or certain insolvency proceedings.
Our 2010 Credit Agreement was amended on March 4, 2011 (the “Amendment”). The Amendment allows us to make certain dispositions of equipment, real estate and business units. In most cases, proceeds from these dispositions would be required to pay down the existing Term Loan made pursuant to the 2010 Credit Agreement. Financial covenants and associated definitions, such as Consolidated EBITDA, were also amended to permit us to carry out our business plan and to clarify the treatment of certain items. We have agreed to limit our revolver borrowings under the 2010 Credit Agreement to $25,000, with the exception of proceeds from revolving borrowings used to make any payments in respect of the Convertible Senior Notes, until our total leverage ratio is 3.0 to 1.0 or less. However, the Amendment does not change the limit on obtaining letters of credit. The Amendment also modifies the definition of Excess Cash Flow to include proceeds from the TransCanada Pipeline Arbitration, which would require us to use all or a portion of such proceeds to further pay down the existing Term Loan in the following fiscal year of receipt. For prepayments made with Net Debt Proceeds or Equity Issuance Proceeds (as those terms are defined in the 2010 Credit Agreement), the Amendment requires a prepayment premium of 4% of the principal amount of the Term Loans prepaid before December 31, 2011 and 1% of the principal amount of the Term Loans prepaid on and after December 31, 2011 but before December 31, 2012. Premiums for prepayments made with proceeds other than Net Debt Proceeds or Equity Issuance Proceeds remain the same as set forth under the 2010 Credit Agreement.
In connection with the Amendment, we incurred fees of $4,743 and $376 related to lender fees and third party legal costs, respectively, in the first quarter of 2011. Based on the Financial Accounting Standards Board (“FASB”) accounting standard on debt modifications, we have capitalized lender fees and will amortize them over the three and four-year terms of the revolving credit facility and Term Loan, respectively. Based on the same standard, the third party legal fees were expensed as incurred during the first quarter of 2011.
Cash Flows
Statements of cash flows for entities with international operations that use the local currency as the functional currency exclude the effects of the changes in foreign currency exchange rates that occur during any given period, as these are non-cash charges. As a result, changes reflected in certain accounts on the Consolidated Statements of Cash Flows may not reflect the changes in corresponding accounts on the Consolidated Balance Sheets.
As of December 31, 2010, we had cash and cash equivalents of $141,101, working capital excluding discontinued operations of $269,584 and long-term obligations of $304,470, net of current maturities. These long-term obligations consist of $272,420 on the Term Loan and $32,050 related to the 6.5% Notes, which have an aggregate principal amount of $316,300.
Operating Activities
Cash flow from operations is primarily influenced by demand for our services, operating margins and the type of services we provide, but can also be influenced by working capital needs such as the timing of collection of receivables and the settlement of payables and other obligations. Working capital needs are generally higher during the summer and fall months when the majority of our capital intensive projects are executed. Conversely, working capital assets are typically converted to cash during the winter months. Operating activities from continuing operations provided net cash to us of $58,293 during 2010 as compared to $57,425 during 2009 and $190,556 during 2008. The slight increase in operating cash flows in 2010 as compared to 2009 is due primarily to:
   
an increase in cash flow provided by working capital accounts of $57,032. This increase was driven primarily by improvement of our cash collection efforts during the fourth quarter of 2010 as evidenced by our reduction in days sales outstanding from 91 days at December 31, 2009 to 83 days at December 31, 2010. This increase can also be attributed to a greater focus on our overall working capital management by aligning payments on obligations with current contractual arrangements. This was almost entirely offset by
   
an increase in the cash consumed by continuing operations of $56,164, net of non-cash effects, which includes a $60,000 goodwill impairment charge and a $45,340 reduction in the contingent earnout liablity.

 

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Investing Activities
During 2010, we used net cash in investing activities of $404,651 as compared to $34,036 and $11,725 used in investing activities in 2009 and 2008, respectively. Investing activities in 2010 included:
   
$18,300 used for capital expenditures, offset by $18,331 of proceeds from the sale of under-utilized equipment. The newly acquired Utility T&D segment contributed capital expenditures of $6,437.
   
$421,182 of net cash used for the third quarter acquisition of InfrastruX.
   
$16,500 in net cash provided from the maturities of short-term investments during 2010.
During 2009 and 2008, we used $13,107 and $35,185, respectively, for capital expenditures, offset by $9,585 and $21,212 of proceeds from the sale of equipment. The decrease in capital expenditures of $22,078 in 2009 compared to 2008 is related primarily to a significant purchase of large construction equipment made during 2008. We monitor our real estate, fleet and equipment size and utilization, and to the extent both financially and operationally beneficial, we actively seek potential buyers or renters of such equipment in order to limit our financial exposure resulting from their under-utilization. In 2010, we began a process of analyzing all under-utilized property and equipment and adopted a plan to dispose of such assets. In December 2010, we completed the sale of equipment having a net book value of $12,226, receiving proceeds of $15,103. In addition, we have committed to a plan of disposal of additional properties and equipment having a carrying value of $18,867. These assets are expected to be sold in 2011 and have been separately presented in the Consolidated Balance Sheet in the caption “Assets held for sale.”
Financing Activities
In 2010, financing activities provided net cash of $291,220 as compared to $35,056 and $60,044 used by financing activities in 2009 and 2008, respectively. Net cash provided by financing activities in 2010 resulted primarily from:
   
$282,000 in net proceeds after the $18,000 original issue discount provided from the Term Loan issued in connection with the funding of the InfrastruX acquisition; and
   
$58,078 in proceeds received from the issuance of common stock which was used to fund the purchase of InfrastruX, offset by additional debt issuance costs of $16,238 for the new 2010 Credit Facility and Term Loan completed concurrently with our acquisition of InfrastruX.
Net cash used by financing activities in 2009 and 2008 resulted primarily from payments made on capital leases as well as government fines of $22,097 and $6,575 for 2009 and $31,402 and $12,575 for 2008, respectively.
Discontinued Operations
Net cash from discontinued operations used $4,847 in 2010 as compared to $3,546 used in 2009. This resulted primarily from additional G&A costs incurred related to our Libyan operations in 2010 as compared to 2009 as well as additional legal fees incurred related to our ongoing WAPCo parent company guarantee assertions. In 2008, our net cash from discontinued operations provided cash to us of $1,090, which was primarily the result of two pre-Nigeria sale insurance claim recoveries of $3,004 that more than offset the loss incurred related to our Libyan operations in the same period.
Capital Requirements
During 2010, $58,293 of cash was provided by our continuing operations activities. Capital expenditures by segment amounted to $9,586 spent by Upstream Oil & Gas, $951 for Downstream Oil & Gas, $6,437 for Utility T&D, and $1,326 by Corporate, for a total of $18,300. Approved capital spending of $960 has been carried forward to 2011.

 

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We believe that our financial results combined with our current liquidity, financial management and the 2010 Credit Facility, as amended and previously discussed, will ensure sufficient cash to meet our capital requirements for continuing operations. As such, we are focused on the following significant capital requirements:
   
providing working capital for projects in process and those scheduled to begin in 2011;
   
funding of our 2011 capital budget of approximately $29,700, inclusive of $960 of carry-forward from 2010;
   
redeeming of $59,357 of our 2.75% Notes (see “Contractual Obligations” below); and
   
making the final installment payment to the government related to fines and profit disgorgement.
We believe that we will be able to support our ongoing working capital needs through our cash on hand, operating cash flows, sales of idle and under-utilized equipment and potentially, the previously discussed 2010 Credit Facility.
Contractual Obligations
As of December 31, 2010, we had $299,250 of outstanding debt related to our Term Loan and $91,407 of outstanding debt related to the convertible notes. In addition, we have various capital leases of construction equipment and property resulting in aggregate capital lease obligations of $15,262 at December 31, 2010.
                                         
    Payments Due By Period  
            Less than     1-3     4-5     More than  
    Total     1 year     years     years     5 years  
Term Loan
  $ 299,250     $ 15,000     $ 30,000     $ 254,250     $  
Convertible notes
    91,407       59,357       32,050              
Capital lease obligations
    15,262       8,743       6,470       49        
Operating lease obligations
    143,175       39,581       54,372       22,620       26,602  
Equipment financing obligations
    2,118       1,343       775              
Contingent earnout
    10,000             10,000              
Government obligations
    6,575       6,575                    
Uncertain tax liabilities
    4,866                          
 
                             
Total
  $ 572,653     $ 130,599     $ 133,667     $ 276,919     $ 26,602  
 
                             
The holders of the 6.5% Notes had the right to require us to purchase the 6.5% Notes for cash, including unpaid interest, on December 15, 2010. None of the 6.5% Notes were surrendered for purchase pursuant to this put option. Accordingly, the 6.5% Notes remain outstanding as of December 31, 2010 and continue to be subject to the terms and conditions of the Indenture governing the 6.5% Notes. Following the expiration of the put option, an aggregate principal amount of $32,050 remains outstanding (net of $0 discount) and has been classified as long-term and included within “Long-term debt” on the Consolidated Balance Sheet at December 31, 2010.
Based on information received from BOKF, NA dba Bank of Texas, as paying agent for the 2.75% Notes, we announced on March 14, 2011, that all of the 2.75% Notes, with an aggregate principal amount of $59,357, were validly surrendered and not withdrawn pursuant to the option of the holders of the 2.75% Notes to require us to purchase on March 15, 2011, all or a portion of such holders’ 2.75% Notes. We will use our revolving credit facility to fund the purchase of the 2.75% Notes and the remaining unamortized discount of $682 will be expensed during the first quarter of 2011.
In connection with the acquisition of InfrastruX on July 1, 2010, InfrastruX shareholders are eligible to receive earnout payments of up to $125,000 if certain EBITDA targets are met. During the third quarter of 2010, we recorded a $45,340 adjustment to the estimated fair value of the contingent earnout liability. This change in estimated contingent earnout liability to the former InfrastruX shareholders was due to a third quarter decrease in the probability-weighted estimated achievement of EBITDA targets as set forth in the merger agreement. Accordingly, $10,000 in contingent earnout liability is presented as a long term liability on the Consolidated Balance Sheet at December 31, 2010.

 

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At December 31, 2010, we had uncertain tax positions which ultimately could result in a tax payment. As the amount of the ultimate tax payment is contingent on the tax authorities’ assessment, it is not practical to present annual payment information.
As of December 31, 2010, there were no borrowings under the 2010 Credit Facility and there were $25,678 in outstanding letters of credit. All outstanding letters of credit relate to continuing operations.
We have unsecured credit facilities with banks in certain countries outside the United States. Borrowings under these lines, in the form of short-term notes and overdrafts, are made at competitive local interest rates. Generally, each line is available only for borrowings related to operations in a specific country. Credit available under these facilities is approximately $6,541 at December 31, 2010. There were no outstanding borrowings at December 31, 2010 or 2009.
Off-Balance Sheet Arrangements and Commercial Commitments
From time to time, we enter into commercial commitments, usually in the form of commercial and standby letters of credit, surety bonds and financial guarantees. Contracts with our customers may require us to provide letters of credit or surety bonds with regard to our performance of contracted services. In such cases, the commitments can be called upon in the event of our failure to perform contracted services. Likewise, contracts may allow us to issue letters of credit or surety bonds in lieu of contract retention provisions, in which the client withholds a percentage of the contract value until project completion or expiration of a warranty period.
The letters of credit represent the maximum amount of payments we could be required to make if these letters of credit are drawn upon. Additionally, we issue surety bonds customarily required by commercial terms on construction projects. U.S. surety bonds represent the bond penalty amount of future payments we could be required to make if we fail to perform our obligations under such contracts. The surety bonds do not have a stated expiration date; rather, each is released when the contract is accepted by the owner. Our maximum exposure as it relates to the value of the bonds outstanding is lowered on each bonded project as the cost to complete is reduced. As of December 31, 2010, no liability has been recognized for letters of credit or surety bonds.
A summary of our off-balance sheet commercial commitments for both continuing and Discontinued Operations as of December 31, 2010 is as follows:
                                 
    Expiration Per Period  
    Total     Less than             More Than  
    Commitment     1 year     1-2 Years     2 Years  
Letters of credit:
                               
U.S. — performance
  $ 23,023     $ 23,023     $     $  
Canada — performance
    2,657       2,657              
Other — performance and retention
    124       124              
 
                       
Total letters of credit
    25,804       25,804              
U.S. surety bonds — primarily performance
    530,152       485,788       44,364        
 
                       
Total commercial commitments
  $ 555,956     $ 511,592     $ 44,364     $  
 
                       
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
We prepare our consolidated financial statements in conformity with GAAP. In many cases, the accounting treatment of a particular transaction is specifically dictated by GAAP and does not require management’s judgment in application. There are also areas which require management’s judgment in selecting among available GAAP alternatives. We are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. Actual results may differ from our estimates and to the extent there are material differences between these estimates, judgments or assumptions and actual results, our financial statements will be affected. We believe the following accounting estimates are the most critical in understanding and evaluating our reported financial results. We have reviewed these critical accounting estimates and related disclosures with our Audit Committee.

 

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The following discussion of our critical accounting estimates should be read in conjunction with Note 1, “Summary of Significant Accounting Policies” of our Notes to Consolidated Financial Statements in this Form 10-K.
Revenue
A number of factors relating to our business affect the recognition of contract revenue. We typically structure contracts as unit-price, time and materials, fixed-price or cost plus fixed fee. We believe that our operating results should be evaluated over a time horizon during which major contracts in progress are completed and change orders, extra work, variations in the scope of work, cost recoveries and other claims are negotiated and realized. Revenue from unit-price and time and materials contracts is recognized as earned.
Revenue for fixed-price and cost plus fixed fee contracts is recognized using the percentage-of-completion method. Under this method, estimated contract income and resulting revenue is generally accrued based on costs incurred to date as a percentage of total estimated costs, taking into consideration physical completion. Total estimated costs, and thus contract income, are impacted by changes in productivity, scheduling, unit cost of labor, subcontracts, materials and equipment. Additionally, external factors such as weather, client needs, client delays in providing permits and approvals, labor availability, governmental regulation and politics may affect the progress of a project’s completion and thus the timing of revenue recognition. Certain fixed-price and cost plus fixed fee contracts include, or are amended to include, incentive bonus amounts, contingent on accomplishing a stated milestone. Revenue attributable to incentive bonus amounts is recognized when the risk and uncertainty surrounding the achievement of the milestone have been removed. We do not recognize income on a fixed-price contract until the contract is approximately five to ten percent complete, depending upon the nature of the contract. If a current estimate of total contract cost indicates a loss on a contract, the projected loss is recognized in full when determined.
We consider unapproved change orders to be contract variations on which we have customer approval for scope change, but not for price associated with that scope change. Costs associated with unapproved change orders are included in the estimated cost to complete the contracts and are expensed as incurred. We recognize revenue equal to cost incurred on unapproved changed orders when realization of price approval is probable and the estimated amount is equal to or greater than the cost related to the unapproved change order. Revenue recognized on unapproved change orders is included in contract costs and recognized income not yet billed on the balance sheet. Revenue recognized on unapproved change orders is subject to adjustment in subsequent periods to reflect the changes in estimates or final agreements with customers.
We consider claims to be amounts that we seek or will seek to collect from customers or others for customer-caused changes in contract specifications or design, or other customer-related causes of unanticipated additional contract costs on which there is no agreement with customers on both scope and price changes. Revenue from claims is recognized when agreement is reached with customers as to the value of the claims, which in some instances may not occur until after completion of work under the contract. Costs associated with claims are included in the estimated costs to complete the contracts and are expensed when incurred.
Goodwill and Other Intangible Assets
We utilize the purchase accounting method for business combinations and record intangible assets separate from goodwill. The FASB standard on goodwill stipulates a non-amortization approach to account for purchased goodwill and certain intangible assets with indefinite useful lives. Goodwill represents the excess of purchase price over fair value of net assets acquired. We do not have any other intangible assets with indefinite useful lives. We do have other intangible assets with finite lives. These other intangible assets consist of customer relationships and backlog recorded in connection with the acquisition of InServ in November 2007, customer relationships, trademarks and non-compete agreements recorded in connection with the acquisition of the engineering business of Wink, in July 2009 and customer relationships, tradenames and technology recorded in connection with the acquisition of InfrastruX in 2010. The value of existing customer relationships from the InServ, Wink and InfrastruX acquisitions was recorded at the estimated fair value determined by using a discounted cash flow method. Such acquired customer relationships have a finite useful life and are therefore being amortized over the estimated useful life of the relationships. Additionally, we were able to assign values to the trademarks and non-compete agreements purchased in the Wink acquisition. The trademarks and non-compete agreements were recorded at their fair value and are being amortized over the useful life of the contracts.

 

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Impairment of Long-Lived Assets and Intangible Assets with Finite Lives
Whenever indicators of impairment exist, we evaluate the carrying values of our long-lived assets for possible impairment. This evaluation is based upon our projections of anticipated future cash flows (undiscounted and without interest charges) from the assets being evaluated. If the sum of the anticipated future cash flows over the expected useful life of the assets is less than the assets’ carrying value, then a permanent non-cash write-down equal to the difference between the assets’ carrying value and the assets’ fair value is required to be charged to earnings. In estimating future cash flows, we generally use a probability weighted average expected cash flow method with assumptions based on those used for internal budgets. The determination of future cash flows, and, if required, fair value of a long-lived asset is by its nature a highly subjective judgment. Significant assumptions are required in the forecast of future operating results used in the preparation of the long-term estimated cash flows. Changes in these estimates could have a material effect on the evaluation of our long-lived assets.
Impairment of Goodwill
We estimate the fair value of goodwill using the discounted cash flows methodology and an analysis of comparable companies. The principal factors used in the discounted cash flow analysis requiring judgment are the projected results of operations, weighted average cost of capital (“WACC”) and terminal value assumptions. This analysis requires the input of several critical assumptions including future growth rates, cash flow projections, WACC, operating cost escalation rates, rate of return, terminal value assumptions and long-term earnings and merger multiples for comparable companies in both the upstream and downstream markets. The WACC takes into account the relative weights of each component of the Company’s consolidated capital structure (equity and debt) and represents the expected cost of new capital adjusted as appropriate to consider lower risk profiles associated with longer term contracts and barriers to market entry. The terminal value assumptions are applied to the final year of the discounted cash flow model.
According to accounting standards for goodwill, goodwill and other intangibles are required to be evaluated whenever indicators of impairment exist and at least annually. During the third quarter of 2010, in connection with the completion of our preliminary forecasts for 2011, it became evident that a goodwill impairment associated with the Downstream Oil & Gas segment was probable. Due to time restrictions with the filing of our third quarter Form 10-Q, we were unable to fully complete our two step impairment test. According to the accounting standards for goodwill, if the second step (“Step Two”) of the goodwill impairment test is not complete before the financial statements are issued or are available to be issued and a goodwill impairment loss is probable and can be reasonably estimated, the best estimate of that loss shall be recognized. Using a preliminary discounted cash flow analysis supported by comparative market multiples to determine the fair value of the segment versus its carrying value, an estimated range of likely impairment was determined and an impairment charge of $12,000 was recorded during the third quarter of 2010.
During the fourth quarter of 2010, we performed our required annual test for goodwill impairment. The results of the first step (“Step One”) are as follows:
                                         
Step One Summary                   Excess /     Associated     Implied  
Reporting Unit   Fair Value     Carrying Value     (Deficit)     Goodwill(2)     Impairment  
 
Downstream Oil & Gas
  $ 87,000     $ 146,846     $ (59,846 )   $ 61,754     Yes
Upstream Oil & Gas
    219,700       191,958       27,742       13,177     No
Utility T&D(1)
    N/A       N/A       N/A       184,822     No
     
(1)  
Under GAAP, a company has up to one year subsequent to closing an acquisition to perform its annual testing for goodwill impairment, unless indicators of an impairment exist. We closed on the acquisition of InfrastruX, or Utility T&D, during the third quarter of 2010. No indicators of impairment, including the events that led to the reduction in the contingent earnout liability, for the Utility T&D segment were identified by management during the fourth quarter of 2010. Accordingly, we have excluded them from our 2010 annual assessment of goodwill. We will perform impairment testing for this segment during the second quarter of 2011, or earlier should we identify any indicators of impairment.
 
(2)  
Represents goodwill prior to fourth quarter write-downs.
If an impairment is indicated in Step One of the assessment, Step Two is necessary and measures the amount of the impairment. Step Two is performed by comparing the “implied fair value” of our reporting units’ goodwill with the carrying value of the reporting units’ goodwill. For this purpose, the “implied fair value” of goodwill for each reporting unit that had goodwill associated with its operations was determined in the same manner as the amount of goodwill is determined in a business combination. Step Two was performed for the Downstream Oil & Gas segment’s as its carrying value did not exceed fair value. This assessment resulted in a further write-down of goodwill of $48,000 during the fourth quarter of 2010. As the Step One fair value exceeded the carrying value for the Upstream Oil & Gas by 15%, no impairment was taken.

 

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Additionally, we treated the write-down of goodwill as a triggering event for all long-lived assets with finite lives within the Downstream Oil & Gas segment. As such, we reviewed these assets for impairment. Based on our review, at December 1, 2010, the effective date of our annual goodwill impairment testing, estimated future cash flows over the expected useful life for these assets exceeded their carrying value by approximately $112,000. Accordingly, no impairment was taken.
At December 31, 2010, we have $211,753 in goodwill, of which $184,822 relates to our Utility T&D segment $13,754 relates to our Downstream Oil & Gas segment and $13,177 relates to our Upstream Oil & Gas segment.
Leases
We have entered into operating lease agreements, some of which contain provisions for future rent increases, rent free periods, or periods in which rent payments are reduced (abated). Consistent with the FASB’s standard on leases, the total amount of rental payments due over the lease term is being charged to rent expense on the straight-line method over the term of the lease. The difference between rent expense recorded and the amount paid is credited or charged to deferred rent obligation, which is included in “Accounts payable and accrued liabilities” in the Consolidated Balance Sheets.
Interest Rate Contracts
We have designated certain interest rate contracts as cash flow hedges. No components of the hedging instruments are excluded from the assessment of hedge effectiveness. All changes in fair value of outstanding derivatives in cash flow hedges, except any ineffective portion, are recorded in other comprehensive income until earnings are impacted by the hedged transaction. Classification of the gain or loss in the Consolidated Statements of Operations upon release from comprehensive income is the same as that of the underlying exposure.
When we discontinue hedge accounting because it is no longer probable that an anticipated transaction will occur in the originally expected period, or within an additional two-month period thereafter, changes to fair value accumulated in other comprehensive income are recognized immediately in earnings.
See Note 17 — “Fair Value Measurements” of our Notes to Consolidated Financial Statements in this Form 10-K for further discussion of our derivative financial instruments.
Insurance
We are insured for workers’ compensation, employer’s liability and general liability claims, subject to a deductible of $750 per occurrence. We are also insured for auto liability claims, subject to a deductible of $500 per occurrence. Additionally, our largest non-union employee-related health care benefit plan is subject to a deductible of $250 per claimant per year.
Losses are accrued based upon our estimates of the ultimate liability for claims incurred (including an estimate of claims incurred but not reported), with assistance from third-party actuaries. For these claims, to the extent we have insurance coverage above the deductible amounts, we have recorded a receivable reflected in “Other assets” in the Consolidated Balance Sheets. These insurance liabilities are difficult to assess and estimate due to unknown factors, including the severity of an injury, the determination of our liability in proportion to other parties and the number of incidents not reported. The accruals are based upon known facts and historical trends.
Income Taxes
The FASB standard for income taxes takes into account the differences between financial statement treatment and tax treatment of certain transactions. Deferred tax assets and liabilities are recognized for the expected future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date. At December 31, 2010, we had deferred tax assets of $27,574, of which $7,303 is related to state net operating losses with a

 

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valuation allowance of $7,170 against it, and deferred tax liabilities of $79,174. Additionally, in 2010 we wrote off $3,865 of deferred tax assets related to equity based compensation. We evaluate the realizability of our deferred tax assets in determination of our valuation allowance and adjust the amount of such allowance, if necessary. The factors used to assess the likelihood of realization are our forecast of future taxable income and available tax planning strategies that could be implemented to realize the net deferred tax assets. Failure to achieve forecasted taxable income in the applicable taxing jurisdictions could affect the ultimate realization of deferred tax assets and could result in an increase in our effective tax rate on future earnings. The provision or benefit for income taxes and the annual effective tax rate are impacted by income taxes in certain countries being computed based on a deemed profit rather than on taxable income and tax holidays on certain international projects.
ACCOUNTING PRONOUNCEMENTS
Recently Adopted
Effective January 1, 2009, we adopted the accounting standard that establishes the principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any noncontrolling interest in the acquiree and the goodwill acquired. The guidance also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of business combinations. This standard requires that income tax benefits related to business combinations that are not recorded at the date of acquisition are recorded as an income tax benefit in the statement of operations when subsequently recognized. Previously, unrecognized income tax benefits related to business combinations were recorded as an adjustment to the purchase price allocation when recognized. Beginning in 2009, all acquisitions have been recorded based on this standard.
In January 2010, the FASB issued guidance which expanded the required disclosures about fair value measurements. In particular, this guidance requires (i) separate disclosure of the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements along with the reasons for such transfers, (ii) information about purchases, sales, issuances and settlements to be presented separately in the reconciliation for Level 3 fair value measurements, (iii) expanded fair value measurement disclosures for each class of assets and liabilities and (iv) disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements that fall in either Level 2 or Level 3. This guidance is effective for annual reporting periods beginning after December 15, 2009 except for (ii) above which is effective for fiscal years beginning after December 15, 2010. The adoption of this standard did not have a material impact on our consolidated results of operations, financial position or cash flows. However, appropriate disclosures have been made. See Note 17 — “Fair Value Measurements” of our Notes to Consolidated Financial Statements in this Form 10-K.
In June 2009, the FASB issued a new accounting standard which provides amendments to previous guidance on the consolidation of variable interest entities (“VIE”). This standard clarifies the characteristics that identify a VIE and changes how a reporting entity identifies a primary beneficiary that would consolidate the VIE from a quantitative risk and rewards calculation to a qualitative approach based on which variable interest holder has controlling financial interest and the ability to direct the most significant activities that impact the VIE’s economic performance. This statement requires the primary beneficiary assessment to be performed on a continuous basis. It also requires additional disclosures about an entity’s involvement with a VIE, restrictions on the VIE’s assets and liabilities that are included in the reporting entity’s consolidated balance sheet, significant risk exposures due to the entity’s involvement with the VIE, and how its involvement with a VIE impacts the reporting entity’s consolidated financial statements. The standard was effective for fiscal years beginning after November 15, 2009. The adoption of the standard did not have any impact on our consolidated financial statements.

 

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On December 17, 2010, the FASB issued an update to its standard on goodwill impairment, which (1) does not change the prescribed method of calculating the carrying value of a reporting unit in the performance of Step One of the goodwill impairment test and (2) requires entities with a zero or negative carrying value to assess, considering qualitative factors such as the impairment indicators listed in FASB’s standard on goodwill, (whether it is more likely than not that a goodwill impairment exists. If an entity concludes that it is more likely than not that a goodwill impairment exists, the entity must perform Step Two of the goodwill impairment test. The update is effective for impairment tests performed during entities’ fiscal years (and interim periods within those years) that begin after December 15, 2010. The adoption of this update is not expected to have any impact on our consolidated financial statements.
Recently Proposed
In August 2010, the FASB issued a proposed accounting standard update on lease accounting that would require entities to recognize assets and liabilities arising from lease contracts on the balance sheet. The proposed accounting standard update states that lessees and lessors should apply a “right-of-use model” in accounting for all leases. Under the proposed model, lessees would recognize an asset for the right to use the leased asset, and a liability for the obligation to make rental payments over the lease term. The lease term is defined as the longest possible term that is “more likely than not” to occur. The accounting by a lessor would reflect its retained exposure to the risks or benefits of the underlying leased asset. A lessor would recognize an asset representing its right to receive lease payments based on the expected term of the lease. Comments on this exposure draft were due December 15, 2010 and the final standard is expected to be issued sometime in 2011. While we believe that the proposed standard, as currently drafted, will likely have a material impact on our reported financial position and reported results of operations, it will not have a material impact on our liquidity; however, until the proposed standard is finalized, such evaluation cannot be completed.
EFFECTS OF INFLATION AND CHANGING PRICES
Our operations are affected by increases in prices, whether caused by inflation, government mandates or other economic factors, in the countries in which we operate. We attempt to recover anticipated increases in the cost of labor, equipment, fuel and materials through price escalation provisions in certain major contracts or by considering the estimated effect of such increases when bidding or pricing new work.
Item 7A.  
Quantitative and Qualitative Disclosures about Market Risk
Our primary market risk is our exposure to changes in non-U.S. (primarily Canada) currency exchange rates. We attempt to negotiate contracts which provide for payment in U.S. dollars, but we may be required to take all or a portion of payment under a contract in another currency. To mitigate non-U.S. currency exchange risk, we seek to match anticipated non-U.S. currency revenue with expense in the same currency whenever possible. To the extent we are unable to match non-U.S. currency revenue with expense in the same currency, we may use forward contracts, options or other common hedging techniques in the same non-U.S. currencies. We had no forward contracts or options at December 31, 2010 and 2009.
The carrying amounts for cash and cash equivalents, accounts receivable, notes payable and accounts payable and accrued liabilities shown in the Consolidated Balance Sheets approximate fair value at December 31, 2010 due to the generally short maturities of these items. At December 31, 2010, we invested primarily in short-term dollar denominated bank deposits. We have the ability and expect to hold our investments to maturity.
Under the 2010 Credit Agreement, we are subject to hedging arrangements to fix or otherwise limit the interest cost of the Term Loan. Therefore, in September 2010, we entered into two 18—month forward interest rate swap agreements for a total notional amount of $150,000 in order to hedge changes in the variable rate interest expense of half of the $300,000 Term Loan maturing on June 30, 2014. Under the swap agreement, we receive interest at a floating rate of three-month LIBOR, conditional on three-month LIBOR exceeding 2 percent (to mirror variable rate interest provisions of the underlying hedged debt), and pays interest at a fixed rate of 2.685 percent, effective March 28, 2012 through June 30, 2014. The swap agreement is designated and qualifies as a cash flow hedging instrument and is deemed to be a highly effective hedge. The fair value of the swap agreement at December 31, 2010 was $104 and was based on using a model with Level 2 inputs including quoted market prices for contracts with similar terms and maturity dates.

 

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We also entered into two interest rate cap agreements for notional amounts of $75,000 each in order to limit exposure to an increase of the interest rate above 3 percent, effective September 28, 2010 through March 28, 2012. The cap agreements are designated and qualify as cash flow hedging instruments and are deemed to be highly effective hedges. The fair value of the interest rate caps was $12 and was based on using a model with Level 2 inputs including quoted market prices for contracts with similar terms and maturity dates.

 

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Item 8.  
Financial Statements and Supplementary Data
Index to Consolidated Financial Statements
         
    Page  
 
Consolidated Financial Statements of Willbros Group, Inc. and Subsidiaries
       
 
       
    77  
 
       
    80  
 
       
    81  
 
       
    82  
 
       
    84  
 
       
    86  

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Willbros Group, Inc.
We have audited the accompanying consolidated balance sheets of Willbros Group, Inc. (a Delaware corporation, formerly a Panama corporation) as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Willbros Group, Inc. as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Willbros Group, Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 14, 2011 expressed an adverse opinion and exclusion of Utility T&D segment.
/s/ GRANT THORNTON LLP
Houston, Texas
March 14, 2011

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Willbros Group, Inc.
We have audited Willbros Group, Inc.’s (a Delaware corporation, formerly a Panama corporation) internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Willbros Group Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting included in Item 9A (Management’s Report). Our responsibility is to express an opinion on Willbros Group Inc.’s internal control over financial reporting based on our audit. Our audit of, and opinion on, Willbros Group, Inc.’s internal control over financial reporting does not include internal control over financial reporting of InfrastruX Group, Inc., a wholly owned subsidiary, whose financial statements reflect total assets and revenues constituting 54.4 and 26.6 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2010. As indicated in Management’s Report, InfrastruX Group, Inc. was acquired during 2010 and therefore, management’s assessment of the effectiveness of Willbros Group, Inc.’s internal control over financial reporting excluded internal control over financial reporting of InfrastruX Group, Inc (Utility T&D segment).
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
A material weakness is a deficiency, or combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management’s assessment.
The Company identified a material weakness related to compliance with the established estimation process at its subsidiary in Canada. Management determined that project cost estimations were not prepared in sufficient detail to properly analyze job margin and management review was not thorough and did not include follow through on issues from prior month estimates. These operating deficiencies resulted in the failure to identify four loss contracts at the Canadian subsidiary in a timely manner.

 

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In our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, Willbros Group, Inc. has not maintained effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Willbros Group, Inc.’s consolidated balance sheets as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2010. The material weakness identified above was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2010 financial statements, and this report does not affect our report dated March 14, 2011, which expressed an unqualified opinion on those financial statements.
/s/ GRANT THORNTON LLP
Houston, Texas
March 14, 2011

 

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WILLBROS GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share amounts)
                 
    December 31,  
    2010     2009  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 141,101     $ 198,684  
Short-term investments
          16,559  
Accounts receivable, net
    319,874       162,414  
Contract cost and recognized income not yet billed
    35,059       45,009  
Prepaid expenses
    54,831       15,416  
Parts and supplies inventories
    10,108       4,666  
Deferred income taxes
    11,004       2,875  
Assets of discontinued operations
    240       692  
Assets held for sale
    18,867        
 
           
Total current assets
    591,084       446,315  
Property, plant and equipment, net
    229,179       132,879  
Goodwill
    211,753       85,775  
Other intangible assets, net
    195,457       36,772  
Deferred income taxes
    16,570       25,034  
Other assets
    41,759       1,603  
 
           
Total assets
  $ 1,285,802     $ 728,378  
 
           
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable and accrued liabilities
  $ 214,062     $ 81,470  
Contract billings in excess of cost and recognized income
    16,470       11,336  
Current portion of capital lease obligations
    5,371       5,824  
Notes payable and current portion of other long-term debt
    71,594       31,450  
Current portion of government obligations
    6,575       6,575  
Accrued income taxes
    2,356       1,605  
Other current liabilities
    4,832       9,968  
Liabilities of discontinued operations
    324       351  
 
           
Total current liabilities
    321,584       148,579  
Long-term debt
    305,227       56,071  
Capital lease obligations
    5,741       10,692  
Contingent earnout
    10,000        
Long-term portion of government obligations
          6,575  
Long-term liabilities for unrecognized tax benefits
    4,866       5,512  
Deferred income taxes
    76,020       11,356  
Other long-term liabilities
    38,824       1,598  
 
           
Total liabilities
    762,262       240,383  
 
               
Contingencies and commitments (Note 16)
               
Stockholders’ equity:
               
Preferred stock, par value $.01 per share, 1,000,000 shares authorized, none issued
           
Common stock, par value $.05 per share, 70,000,000 shares authorized (70,000,000 at December 31, 2009) and 48,546,817 shares issued at December 31, 2010 (40,106,498 at December 31, 2009)
    2,427       2,005  
Additional paid-in capital
    674,173       607,299  
Accumulated deficit
    (161,824 )     (124,788 )
Treasury stock at cost, 629,320 shares at December 31, 2010 (510,187 at December 31, 2009)
    (10,045 )     (9,045 )
Accumulated other comprehensive income
    17,938       11,725  
 
           
Total Willbros Group, Inc. stockholders’ equity
    522,669       487,196  
Noncontrolling interest
    871       799  
 
           
Total stockholders’ equity
    523,540       487,995  
 
           
Total liabilities and stockholders’ equity
  $ 1,285,802     $ 728,378  
 
           
See accompanying notes to consolidated financial statements.

 

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WILLBROS GROUP, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except share and per share amounts)
                         
    Year Ended December 31,  
    2010     2009     2008  
Contract revenue
  $ 1,192,412     $ 1,259,773     $ 1,912,704  
 
                       
Operating expenses:
                       
Contract
    1,080,391       1,115,224       1,650,156  
Amortization of intangibles
    9,724       6,515       10,420  
General and administrative
    118,427       82,345       118,027  
Goodwill impairment
    60,000             62,295  
Changes in fair value of contingent earnout liability
    (45,340 )            
Acquisition costs
    10,055       2,499        
Other charges
    3,771       12,694        
 
                 
 
    1,237,028       1,219,277       1,840,898  
 
                 
Operating income (loss)
    (44,616 )     40,496       71,806  
 
                       
Other income (expense):
                       
Interest income
    755       1,966       3,547  
Interest expense
    (28,320 )     (10,294 )     (12,579 )
Other, net
    5,474       819       7,891  
 
                 
 
                       
 
    (22,091 )     (7,509 )     (1,141 )
Income (loss) from continuing operations before income taxes
    (66,707 )     32,987       70,665  
 
                       
Provision (benefit) for income taxes
    (36,150 )     8,734       25,942  
 
                 
Income (loss) from continuing operations
    (30,557 )     24,253       44,723  
Income (loss) from discontinued operations net of provisions for income taxes
    (5,272 )     (4,613 )     745  
 
                 
Net income (loss)
    (35,829 )     19,640       45,468  
Less: Income attributable to noncontrolling interest
    (1,207 )     (1,817 )     (1,836 )
 
                 
Net income (loss) attributable to Willbros Group, Inc.
  $ (37,036 )   $ 17,823     $ 43,632  
 
                 
Reconciliation of net income attributable to Willbros Group, Inc.
                       
Income (loss) from continuing operations
  $ (31,764 )   $ 22,436     $ 42,887  
Income (loss) from discontinued operations
    (5,272 )     (4,613 )     745  
 
                 
Net income (loss) attributable to Willbros Group, Inc.
  $ (37,036 )   $ 17,823     $ 43,632  
 
                 
 
                       
Basic income (loss) per share attributable to Company Shareholders:
                       
Income (loss) from continuing operations
  $ (0.74 )   $ 0.58     $ 1.12  
Income (loss) from discontinued operations
    (0.12 )     (0.12 )     0.02  
 
                 
Net income (loss)
  $ (0.86 )   $ 0.46     $ 1.14  
 
                 
 
                       
Diluted income (loss) per share attributable to Company Shareholders:
                       
Income (loss) from continuing operations
  $ (0.74 )   $ 0.58     $ 1.11  
Income (loss) from discontinued operations
    (0.12 )     (0.12 )     0.02  
 
                 
Net Income (loss)
  $ (0.86 )   $ 0.46     $ 1.13  
 
                 
 
                       
Weighted average number of common shares outstanding:
                       
Basic
    43,013,934       38,687,594       38,269,248  
 
                 
Diluted
    43,013,934       38,883,077       38,764,167  
 
                 
See accompanying notes to consolidated financial statements.

 

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WILLBROS GROUP, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS)
(In thousands, except share and per share amounts)
                                                                         
                                            Accumulated     Total                
                                            Other     Stock-                
                                            Compre-     holders’             Total  
                    Additional                     hensive     Equity     Non-     Stock-  
    Common Stock     Paid-in     Accumul-     Treasury     Income     Willbros     controlling     holders’  
    Shares     Par Value     Capital     ated Deficit     Stock     (Loss)     Group, Inc.     Interest     Equity  
 
Balance, December 31, 2007
    38,276,545       1,913       571,827       (186,243 )     (3,298 )     17,199       401,398       1,327       402,725  
 
                                                                       
Net income
                      43,632                   43,632       1,836       45,468  
Foreign currency translation adjustments
                                  (21,635 )     (21,635 )           (21,635 )
 
                                                                 
 
                                                                       
Total comprehensive income
                                        21,997       1,836       23,833  
 
                                                                       
Discount amortization of convertible notes
                1,122                         1,122             1,122  
Dividend distribution to noncontrolling interest
                                              (1,584 )     (1,584 )
Stock-based compensation (excluding tax benefit)
                11,652                         11,652             11,652  
Stock-based compensation tax benefit
                2,691                         2,691             2,691  
Deferred restricted stock rights issuance
    225,000       11       (11 )                                          
Restricted stock grants
    552,159       28       (28 )                                    
Vesting of restricted stock rights
    23,603       1       (1 )                                    
Additions to treasury stock, vesting and forfeitures of restricted stock
                            (4,717 )           (4,717 )           (4,717 )
Exercise of stock options
    53,000       3       681                         684             684  
Expenses of a public offering
                (251 )                       (251 )           (251 )
Stock issued on conversion of 2.75% Convertible Senior Notes
    443,913       22       7,958                         7,980             7,980  
 
                                                     
 
                                                                       
Balance, December 31, 2008
    39,574,220       1,978       595,640       (142,611 )     (8,015 )     (4,436 )     442,556       1,579       444,135  
Net income
                      17,823                   17,823       1,817       19,640  
Foreign currency translation adjustments
                                  16,161       16,161             16,161  
 
                                                                 
 
                                                                       
Total comprehensive income
                                        33,984       1,817       35,801  
 
                                                                       
Dividend distribution to noncontrolling interest
                                              (2,597 )     (2,597 )
Stock-based compensation (excluding tax benefit)
                13,231                         13,231             13,231  
Stock-based compensation tax benefit (deficiency)
                (1,735 )                       (1,735 )           (1,735 )
Restricted stock grants
    477,079       24       (24 )                                    
Vesting of restricted stock rights
    37,699       2       (2 )                                    
Additions to treasury stock, vesting and forfeitures of restricted stock
                            (1,030 )           (1,030 )           (1,030 )
Exercise of stock options
    17,500       1       189                         190             190  
 
                                                     
Balance, December 31, 2009
    40,106,498     $ 2,005     $ 607,299     $ (124,788 )   $ (9,045 )   $ 11,725     $ 487,196     $ 799     $ 487,995  

 

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WILLBROS GROUP, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS)
(In thousands, except share and per share amounts)
                                                                         
                                            Accumulated     Total                
                                            Other     Stock-                
                                            Compre-     holders’             Total  
                    Additional                     hensive     Equity     Non-     Stock-  
    Common Stock     Paid-in     Accumul-     Treasury     Income     Willbros     controlling     holders’  
    Shares     Par Value     Capital     ated Deficit     Stock     (Loss)     Group, Inc.     Interest     Equity  
 
Balance, December 31, 2009
    40,106,498     $ 2,005     $ 607,299     $ (124,788 )   $ (9,045 )   $ 11,725     $ 487,196     $ 799     $ 487,995  
 
                                                                       
Net income (loss)
                      (37,036 )                 (37,036 )     1,207       (35,829 )
Foreign currency translation adjustments, net of tax
                                  6,194       6,194             6,194  
Derivatives, net of tax
                                            19       19             19  
 
                                                                   
 
                                                                       
Total comprehensive (loss)
                                        (30,823 )           (29,616 )
 
                                                                       
Dividend declared and distributed to noncontrolling interest
                                                (1,135 )     (1,135 )
Amortization of stock-based compensation
                8,404                         8,404             8,404  
Stock-based compensation tax benefit
                (956 )                       (956 )           (956 )
Stock issued under share-based compensation plans
    517,011       26       1,744                         1,770             1,770  
Stock issued in connection with acquisition of InfrastruX
    7,923,308       396       57,682                           58,078             58,078  
Additions to treasury stock, vesting and forfeitures of restricted stock
                            (1,000 )           (1,000 )           (1,000 )
 
                                                     
 
                                                                       
Balance, December 31, 2010
    48,546,817     $ 2,427     $ 674,173     $ (161,824 )   $ (10,045 )   $ 17,938     $ 522,669     $ 871     $ 523,540  
 
                                                     
See accompanying notes to consolidated financial statements.

 

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WILLBROS GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands, except share and per share amounts)
                         
    Year Ended December 31,  
    2010     2009     2008  
Cash flows from operating activities:
                       
Net income (loss)
  $ (35,829 )   $ 19,640     $ 45,468  
Reconciliation of net income (loss) to net cash provided by (used in) operating activities:
                       
(Income) loss from discontinued operations, net
    5,272       4,613       (745 )
Depreciation and amortization
    56,165       40,860       44,903  
Goodwill impairment
    60,000             62,295  
Changes in fair value of contingent earnout liability
    (45,340 )            
Stock-based compensation
    8,404       13,231       11,652  
Deferred income tax provision
    (30,669 )     (1,193 )     (9,546 )
Other non-cash
    8,653       5,669       (3,271 )
Changes in operating assets and liabilities:
                       
Accounts receivable, net
    (33,396 )     38,947       48,291  
Contract cost and recognized income not yet billed
    7,081       27,586       (19,571 )
Prepaid expenses and other assets
    3,755       1,618       7,722  
Accounts payable and accrued liabilities
    35,427       (84,426 )     6,975  
Accrued income taxes
    (31 )     (4,536 )     610  
Contract billings in excess of cost and recognized income
    5,072       (8,958 )     (4,227 )
Other liabilities
    13,729       4,374        
 
                 
Cash provided by operating activities of continuing operations
    58,293       57,425       190,556  
Cash provided by (used in) operating activities of discontinued operations
    (4,847 )     (3,546 )     1,090  
 
                 
Cash provided by operating activities
    53,446       53,879       191,646  
Cash flows from investing activities:
                       
Acquisition of subsidiaries, net of cash acquired and earnout
    (421,182 )     (13,955 )     333  
Proceeds from sales of property, plant and equipment
    18,331       9,585       21,212  
Purchases of property, plant and equipment
    (18,300 )     (13,107 )     (35,185 )
Rebates from purchases of property, plant and equipment
                1,915  
Maturities of short-term investments
    16,755              
Purchase of short-term investments
    (255 )     (16,559 )      
 
                 
Cash used in investing activities of continuing operations
    (404,651 )     (34,036 )     (11,725 )
Cash provided by (used in) investing activities of discontinued operations
                 
 
                 
Cash used in investing activities
    (404,651 )     (34,036 )     (11,725 )
Cash flows from financing activities:
                       
Proceeds from term loan issuance
    282,000              
Proceeds from stock issuance
    58,078              
Proceeds from exercise of stock options
          190       684  
Stock-based compensation tax benefit (deficiency)
    (956 )     (1,735 )     2,691  
Additional costs of public offering
                (251 )
Payments on capital leases
    (10,600 )     (22,097 )     (31,402 )
Payments on notes payable
    (12,354 )     (1,062 )     (12,724 )
Payments to reacquire common stock
    (1,000 )     (1,030 )     (4,717 )
Payments on government fines
    (6,575 )     (6,575 )     (12,575 )
Dividend distributed to noncontrolling interest
    (1,135 )     (2,597 )     (1,584 )
Costs of debt issues
    (16,238 )     (150 )     (166 )
 
                 
Cash provided by (used in) financing activities of continuing operations
    291,220       (35,056 )     (60,044 )
Cash provided by (used in) financing activities of discontinued operations
                 
 
                 
Cash provided by (used in) financing activities
    291,220       (35,056 )     (60,044 )

 

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WILLBROS GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands, except share and per share amounts)
                         
    Year Ended December 31,  
    2010     2009     2008  
 
                       
Effect of exchange rate changes on cash and cash equivalents
    2,402       6,135       (5,001 )
 
                 
Cash provided by (used in) all activities
    (57,583 )     (9,078 )     114,876  
Cash and cash equivalents, beginning of period
    198,684       207,762       92,886  
 
                 
Cash and cash equivalents, end of period
  $ 141,101     $ 198,684     $ 207,762  
 
                 
 
                       
Supplemental disclosures of cash flow information:
                       
Cash paid for interest (including discontinued operations)
  $ 17,042     $ 5,974     $ 8,355  
Cash paid for income taxes (including discontinued operations)
  $ 3,947     $ 19,883     $ 40,271  
 
                       
Supplemental non-cash investing and financing transactions:
                       
Initial contingent earnout liability
  $ 55,340     $     $  
Prepaid insurance obtained by note payable
  $ 11,687     $     $ 12,754  
Equipment received through like-kind exchange
  $ 3,629     $     $  
Equipment surrendered through like-kind exchange
  $ 2,735     $     $    
Equipment and property obtained by capital leases
  $     $     $ 17,863  
Common stock issued for conversion of 2.75% Convertible Senior Notes
  $     $     $ 7,980  
Deposit applied to capital lease obligation
  $     $     $ 1,432  
See accompanying notes to consolidated financial statements.

 

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WILLBROS GROUP, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In thousands, except share and per share amounts)
1. Summary of Significant Accounting Policies
Company — Willbros Group, Inc. (“WGI”), a Delaware corporation, and all of its majority-owned subsidiaries (the “Company”) is a provider of energy services to global end markets serving the oil and gas, refinery, petrochemical and power industries. The Company’s principal markets for continuing operations are the United States, Canada and Oman. The Company obtains its work through competitive bidding and through negotiations with prospective clients. Contract values may range from several thousand dollars to several hundred million dollars and contract durations range from a few weeks to more than a year.
The disclosures in the notes to the consolidated financial statements relate to continuing operations, except as otherwise indicated.
Discontinuance of Operations and Asset Disposals During 2006, the Company chose to exit Nigeria and Venezuela. During 2010, the Company chose to exit the Libyan market. These three businesses are presented as discontinued operations in the Company’s consolidated financial statements and collectively are referred to as “Discontinued Operations.” The net assets and net liabilities related to the Discontinued Operations are shown on the Consolidated Balance Sheets as “Assets of discontinued operations” and “Liabilities of discontinued operations”, respectively. The results of the Discontinued Operations are shown on the Consolidated Statements of Operations as “Income (loss) from discontinued operations net of provisions for income taxes” for all periods shown. For further discussion of Discontinued Operations, see Note 21 — Discontinuance of Operations, Asset Disposals and Transition Services Agreement.
Principles of Consolidation — The consolidated financial statements of the Company include the accounts of WGI, all of its majority-owned subsidiaries and all of its wholly-controlled entities. Inter-company accounts and transactions are eliminated in consolidation. The ownership interest of noncontrolling participants in subsidiaries that are not wholly-owned (principally in Oman) is included as a separate component of equity. The noncontrolling participants’ share of the net income is included as “Income attributable to noncontrolling interest” on the Consolidated Statements of Operations. Interests in the Company’s unconsolidated joint ventures are accounted for using the equity method in the Consolidated Balance Sheets.
Use of Estimates — The consolidated financial statements are prepared in accordance with generally accepted accounting principles in the United States and include certain estimates and assumptions made by management of the Company in the preparation of the consolidated financial statements. These estimates and assumptions relate to the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expense during the period. Significant items subject to such estimates and assumptions include: revenue recognition under the percentage-of-completion method of accounting, including estimates of progress toward completion and estimates of gross profit or loss accrual on contracts in progress; tax accruals and certain other accrued liabilities; quantification of amounts recorded for contingencies; valuation allowances for accounts receivable and deferred income tax assets; and the carrying amount of parts and supplies, property, plant and equipment and goodwill. The Company bases its estimates on historical experience and other assumptions that it believes relevant under the circumstances. Actual results could differ from these estimates.
Change in Estimate — The Company performed a review of the estimated useful lives of certain fixed assets at its Upstream Oil & Gas segment during the first quarter of 2010. This evaluation indicated that actual lives for the construction equipment were generally longer than the estimated useful lives used for depreciation purposes in the Company’s financial statements. As a result, the Company adjusted the estimated useful life on Upstream Oil & Gas segment’s construction equipment from a range of four to six years to a range of four to twelve years. The effect of this change in estimate was to reduce depreciation expense for the twelve months ended December 31, 2010 by $6,032 and increase income from continuing operations by $3,921, net of taxes, or $0.09 per basic share.
Consistency Effective January 1, 2010, the Company has reclassified certain indirect overhead expenses to general and administrative expenses to apply a consistent approach in the classification of overhead across the Upstream Oil & Gas and Downstream Oil & Gas segments. If the Company reclassified these same costs in the twelve- month period ended December 31, 2010, the reported general and administrative costs would have increased, accompanied by a corresponding decrease to contract costs of $5,265. The Company is currently in the process of evaluating the impact, if any, that the treatment of these costs would have on the Utility Transmission & Distribution (“Utility T&D”) segment.

 

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WILLBROS GROUP, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In thousands, except share and per share amounts)
1. Summary of Significant Accounting Policies (continued)
Commitments and Contingencies — Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties, and other sources are recorded when management assesses that it is probable that a liability has been incurred and the amount can be reasonably estimated. Recoveries of costs from third parties, which management assesses as being probable of realization, are separately recorded as assets in “Other assets” on the Consolidated Balance Sheets. Legal costs incurred in connection with matters relating to contingencies are expensed in the period incurred. See Note 16 — Contingencies, Commitments and Other Circumstances for further discussion of the Company’s commitments and contingencies.
Accounts Receivable Most of the accounts receivable and contract work in progress are from clients in the oil and gas, refinery, petrochemical and power industries around the world. Trade accounts receivable are recorded at the invoiced amount and do not bear interest. Most contracts require payments as the projects progress or, in certain cases, advance payments. The Company generally does not require collateral, but in most cases can place liens against the property, plant or equipment constructed or terminate the contract if a material default occurs. The allowance for doubtful accounts is the Company’s best estimate of the probable amount of credit losses in the Company’s existing accounts receivable. A considerable amount of judgment is required in assessing the realization of receivables. Relevant assessment factors include the creditworthiness of the customer and prior collection history. Balances over 90 days past due and over a specified minimum amount are reviewed individually for collectability. Account balances are charged off against the allowance after all reasonable means of collection are exhausted and the potential for recovery is considered remote. The allowance requirements are based on the most current facts available and are re-evaluated and adjusted on a regular basis and as additional information is received.
Inventories — Inventories, consisting primarily of parts and supplies, are stated at the lower of actual cost or market. Parts and supplies are evaluated at least annually and adjusted for excess and obsolescence. No excess or obsolescence allowances existed at December 31, 2010 or 2009.
Property, Plant and Equipment — Property, plant and equipment is stated at cost. Depreciation, including amortization of capital leases, is provided on the straight-line method using estimated lives as follows:
         
Construction equipment
  3-20 years
 
       
Furniture and equipment
  3-12 years
 
       
Buildings
  20 years
 
       
Transportation equipment
  3-17 years
 
       
Aircraft and marine equipment
  10 years
In connection with the acquisition of InfrastruX Group, Inc. (“InfrastruX”), the Company acquired $156,160 of property, plant and equipment.
Leasehold improvements are amortized on a straight-line basis over the shorter of their economic lives or the lease term. When assets are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is recognized in “Other, net” in the Consolidated Statements of Operations for the period. Normal repair and maintenance costs are charged to expense as incurred. Significant renewals and betterments are capitalized. Long-lived assets are evaluated for impairment annually and whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. This evaluation is based upon the Company’s projections of anticipated future cash flows (undiscounted and without interest charges) from the business units which own the assets being evaluated. If the sum of the anticipated future cash flows over the expected useful life of the assets is less than the assets’ carrying value, then a permanent write-down equal to the difference between the assets’ carrying value and the assets’ fair value is required to be charged to earnings. In estimating future cash flows, we generally use a probability weighted average expected cash flow method with assumptions based on those used for internal budgets. The determination of future cash flows, and, if required, fair value of a long-lived asset is, by its nature, a highly subjective judgment. Significant assumptions are required in the forecast of future operating results used in the preparation of the long-term estimated cash flows. Changes in these estimates could have a material effect on the evaluation of the Company’s long-lived assets.

 

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WILLBROS GROUP, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In thousands, except share and per share amounts)
1. Summary of Significant Accounting Policies (continued)
Goodwill and Other Intangible Assets — The Company utilizes the purchase accounting method for business combinations and records intangible assets separate from goodwill. The Company also performs an annual impairment test by applying a fair-value-based test. Intangible assets with finite lives continue to be amortized over their useful lives. The useful life of an intangible asset to an entity is the period over which the asset is expected to contribute directly or indirectly to the future cash flows of that entity.
Goodwill - Goodwill is originally recorded as the excess of purchase price over fair value of net assets acquired. The Company applies a non-amortization approach to account for purchased goodwill and performs an annual test for impairment during the fourth quarter of each fiscal year and more frequently if an event or circumstance indicates that impairment may have occurred. The Company performs the required annual impairment test for goodwill by determining the fair values of its reporting units using a discounted cash flow analysis supported by comparative market multiples.
The fair values of each reporting unit are then compared to their book values. When a possible impairment for a reporting unit is indicated by an excess of carrying value over fair value, the implied fair value of goodwill is calculated by deducting the fair value of net assets of the business, excluding goodwill, from the total fair value of the business. When the carrying amount of goodwill exceeds its implied fair value, an impairment charge is recorded to reduce the carrying value of goodwill to its implied value.
This analysis requires the input of several critical assumptions, including:
   
Long term earnings and cash flow projections based on the Company’s strategic budgeting process, subject to future revenue growth rates and operating cost escalation rates.
   
Merger multiples, based on enterprise value and EBITDA, for comparable companies in both the upstream and downstream markets, which are considered Level 3 inputs. For the definition of Level 3 inputs, see Note 17 — Fair Value Measurements.
   
Weighted average cost of capital, which takes into account the relative weights of each component of the Company’s consolidated capital structure (equity and debt) and represents the expected cost of new capital adjusted as appropriate to consider lower risk profiles associated with longer term contracts and barriers to market entry.
   
The U.S. Treasury 20-year rate was used as the risk free interest rate.
   
Terminal value assumptions are applied to the final year of the discounted cash flow model.
These critical assumptions require significant management judgment. Due to the many variables inherent in the estimation of a business’s fair value and the relative size of the recorded goodwill, differences in assumptions may have a material effect on the results of the Company’s impairment analysis.
Other Intangible Assets — The Company does not have any intangible assets with indefinite useful lives other than goodwill. The Company does have other intangible assets with finite lives. These other intangible assets consist of customer relationships and backlog recorded in connection with the acquisition of Integrated Service Company, LLC (“InServ”) in November 2007; customer relationships, trademarks and non-compete agreements recorded in connection with the acquisition of the engineering business of Wink Companies, LLC in July 2009 (renamed Wink Engineering, LLC (“Wink”) in February 2010); and tradenames, customer relationships, and technology recorded in connection with the acquisition of InfrastruX in July 2010. The value of existing customer relationships from the InServ, Wink and InfrastruX acquisitions was recorded at the estimated fair value determined by using a discounted cash flow method. Such acquired customer relationships have a finite useful life and are therefore being amortized over the estimated useful life of the relationships. Additionally, the Company was able to assign values to the trademarks, tradenames, non-compete agreements and technology purchased in the Wink and InfrastruX acquisitions. The trademarks, tradenames, non-compete agreements and technology were recorded at their fair value and are being amortized over the useful life of the intangibles. For further discussion of Goodwill and Other Intangible Assets, see Note 7 — Goodwill and Other Intangible Assets.

 

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WILLBROS GROUP, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In thousands, except share and per share amounts)
1. Summary of Significant Accounting Policies (continued)
Revenue A number of factors relating to the Company’s business affect the recognition of contract revenue. The Company typically structures contracts as unit-price, time and materials, fixed-price or cost plus fixed fee. The Company believes that its operating results should be evaluated over a time horizon during which major contracts in progress are completed and change orders, extra work, variations in the scope of work and cost recoveries and other claims are negotiated and realized. Revenue from unit-price and time and materials contracts is recognized as earned.
Revenue for fixed-price and cost plus fixed fee contracts is recognized using the percentage-of-completion method. Under this method, estimated contract income and resulting revenue is generally accrued based on costs incurred to date as a percentage of total estimated costs, taking into consideration physical completion. Total estimated costs, and thus contract income, are impacted by changes in productivity, scheduling, the unit cost of labor, subcontracts, materials and equipment. Additionally, external factors such as weather, client needs, client delays in providing permits and approvals, labor availability, governmental regulation and politics may affect the progress of a project’s completion and thus the estimated amount and timing of revenue recognition. Certain fixed-price and cost plus fixed fee contracts include, or are amended to include, incentive bonus amounts, contingent on accomplishing a stated milestone. Revenue attributable to incentive bonus amounts is recognized when the risk and uncertainty surrounding the achievement of the milestone have been removed. The Company does not recognize income on a fixed-price contract until the contract is approximately five to ten percent complete, depending upon the nature of the contract. If a current estimate of total contract cost indicates a loss on a contract, the projected loss is recognized in full when determined.
The Company considers unapproved change orders to be contract variations on which the Company has customer approval for scope change, but not for price associated with that scope change. Costs associated with unapproved change orders are included in the estimated cost to complete the contracts and are expensed as incurred. The Company recognizes revenue equal to cost incurred on unapproved change orders when realization of price approval is probable and the estimated amount is equal to or greater than the cost related to the unapproved change order. Revenue recognized on unapproved change orders is included in “Contract cost and recognized income not yet billed” on the Consolidated Balance Sheets. Revenue recognized on unapproved change orders is subject to adjustment in subsequent periods to reflect the changes in estimates or final agreements with customers.
The Company considers claims to be amounts that the Company seeks or will seek to collect from customers or others for customer-caused changes in contract specifications or design, or other customer-related causes of unanticipated additional contract costs on which there is no agreement with customers on both scope and price changes. Revenue from claims is recognized when agreement is reached with customers as to the value of the claims, which in some instances may not occur until after completion of work under the contract. Costs associated with claims are included in the estimated costs to complete the contracts and are expensed when incurred.
Depreciation — The Company depreciates assets based on their estimated useful lives at the time of acquisition using the straight-line method. Depreciation and amortization related to operating activities is included in contract costs; and depreciation and amortization related to general and administrative activities is included in “General and administrative” (“G&A”) expense in the Consolidated Statements of Operations. Contract costs and G&A expenses are included within “Operating expenses” in the Consolidated Statements of Operations. Further, amortization of assets under capital lease obligations is included in depreciation expense.
Insurance The Company is insured for workers’ compensation, employer’s liability and general liability claims, subject to a deductible of $750 per occurrence. The Company is also insured for auto liability claims, subject to a deductible of $500 per occurrence. Additionally, the Company’s largest non-union employee-related health care benefit plan is subject to a deductible of $250 per claimant per year.

 

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WILLBROS GROUP, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In thousands, except share and per share amounts)
1. Summary of Significant Accounting Policies (continued)
Losses are accrued based upon the Company’s estimates of the ultimate liability for claims incurred (including an estimate of claims incurred but not reported), with assistance from third-party actuaries. For these claims, to the extent the Company has insurance coverage above the deductible amounts, a receivable is recorded and reflected in “Other assets” in the Consolidated Balance Sheets. These insurance liabilities are difficult to assess and estimate due to unknown factors, including the severity of an injury, the determination of the Company’s liability in proportion to other parties and the number of incidents not reported. The accruals are based upon known facts and historical trends.
Income Taxes — The Financial Accounting Standards Board (“FASB”) standard for income taxes takes into account the differences between financial statement treatment and tax treatment of certain transactions. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date. The Company, or one of its subsidiaries, files income tax returns in the U.S. federal jurisdiction, and various state and foreign jurisdictions. With few exceptions, the Company is no longer subject to U.S. income tax examination by tax authorities for years before 2007 and no longer subject to Canadian income tax for years before 2001 or in Oman for years before 2006.
Other Current Liabilities — Included within other current liabilities is $3,154 and $6,072 of current deferred tax liabilities for the years ended December 31, 2010 and 2009.
Warranty Costs — In connection with the acquisition of InfrastruX, the Company warrants labor for new installations and construction and servicing of existing infrastructure. The anticipated costs are not considered significant and no reserve has been provided. One of the InfrastruX subsidiary companies maintains a warranty program which specifically covers its cable remediation services. A warranty reserve of $2,530 for cable remediation services is recorded in “Other long-term liabilities” on the Consolidated Balance Sheet as of December 31, 2010. Prior to the acquisition of InfrastruX, the Company has historically recorded an immaterial amount related to warranty reserve.
Retirement Plans and Benefits — The Company has a voluntary defined contribution retirement plan for U.S. based employees that is qualified, and is contributory on the part of the employees, and a voluntary savings plan for certain international employees that is non-qualified, and is contributory on the part of the employees. Additionally, the Company is subject to collective bargaining agreements with various unions. As a result, the Company participates with other companies in the unions’ multi-employer pension and other postretirement benefit plans. These plans cover all employees who are members of such unions.
Stock-Based Compensation Compensation cost resulting from all share-based payment transactions is recognized in the financial statements measured based on the grant-date fair value of the instrument issued and is recognized over the vesting period. The Company uses the Black-Scholes valuation method to determine the fair value of stock options granted as of the grant date. Share-based compensation related to restricted stock and restricted stock rights, also described collectively as restricted stock units (“RSU’s”), is recorded based on the Company’s stock price as of the grant date. Awards granted are expensed ratably over the vesting period of the award. Expense on awards granted prior to March 12, 2009 is accelerated upon reaching retirement age. This provision does not exist for awards granted on or after March 12, 2009.
Foreign Currency Translation — All significant monetary asset and liability accounts denominated in currencies other than United States dollars are translated into United States dollars at current exchange rates. Translation adjustments are accumulated in other comprehensive income (loss). Non-monetary assets and liabilities in highly inflationary economies are translated into United States dollars at historical exchange rates. Revenue and expense accounts are converted at prevailing rates throughout the year. Gains or losses on foreign currency transactions and translation adjustments in highly inflationary economies are recorded in income in the period in which they are incurred.
Concentration of Credit Risk The Company has a concentration of customers in the oil and gas, refinery, petrochemical and power industries which expose the Company to a concentration of credit risk within a single industry. The Company seeks to obtain advance and progress payments for contract work performed on major contracts. Receivables are generally not collateralized. The allowance for doubtful accounts was $4,499 and $1,936 at December 31, 2010 and 2009, respectively.

 

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WILLBROS GROUP, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In thousands, except share and per share amounts)
1. Summary of Significant Accounting Policies (continued)
Income (Loss) per Common Share — Basic income (loss) per share is calculated by dividing net income (loss), less any preferred dividend requirements, by the weighted-average number of common shares outstanding during the year. Diluted income (loss) per share is calculated by including the weighted-average number of all potentially dilutive common shares with the weighted-average number of common shares outstanding. Shares of common stock underlying the Company’s convertible notes are included in the calculation of diluted income per share using the “if-converted” method. Therefore, the numerator for diluted income per share is calculated excluding the after-tax interest expense associated with the convertible notes as long as the associated interest per weighted average convertible share does not exceed basic earnings per share.
Derivative Financial Instruments — The Company may use derivative financial instruments such as forward contracts, options or other financial instruments as hedges to mitigate non-U.S. currency exchange risk when the Company is unable to match non-U.S. currency revenue with expense in the same currency.
In conjunction with the 2010 Credit Agreement the Company entered into as of June 30, 2010, the Company is subject to hedging arrangements to fix or otherwise limit the interest cost of the term loans. The Company is subject to interest rate risk on its debt and investment of cash and cash equivalents arising in the normal course of business, as the Company does not engage in speculative trading strategies. In September 2010, the Company entered into two forward interest rate swap agreements in order to hedge changes in the variable rate interest expense. Also, in September 2010, the Company entered into two interest rate cap agreements in order to limit its exposure to an increase of the interest rate above 3 percent. The Company had no derivative financial instruments as of December 31, 2009.
Cash Equivalents — The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Short-term Investments — The Company may invest a portion of its cash in short-term time deposits, some of which may have early withdrawal penalties. All of such deposits have maturity dates that exceed three months. There was $0 and $16,559 of short-term investments outstanding as of December 31, 2010 and 2009, respectively.
Recently Adopted Accounting Standards — Effective January 1, 2009, the Company adopted the accounting standard that establishes the principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any noncontrolling interest in the acquiree and the goodwill acquired. The guidance also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of business combinations. This standard requires that income tax benefits related to business combinations that are not recorded at the date of acquisition are recorded as an income tax benefit in the statement of operations when subsequently recognized. Previously, unrecognized income tax benefits related to business combinations were recorded as an adjustment to the purchase price allocation when recognized. Beginning in 2009, all acquisitions have been recorded based on this standard.
In January 2010, the FASB issued guidance which expanded the required disclosures about fair value measurements. In particular, this guidance requires (i) separate disclosure of the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements along with the reasons for such transfers, (ii) information about purchases, sales, issuances and settlements to be presented separately in the reconciliation for Level 3 fair value measurements, (iii) expanded fair value measurement disclosures for each class of assets and liabilities and (iv) disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements that fall in either Level 2 or Level 3. This guidance is effective for annual reporting periods beginning after December 15, 2009 except for (ii) above which is effective for fiscal years beginning after December 15, 2010. The adoption of this standard did not have a material impact on the Company’s consolidated results of operations, financial position or cash flows. However, appropriate disclosures have been made. See Note 17 — Fair Value Measurements for further discussion of the Company’s derivative financial instruments.
In June 2009, the FASB issued a new accounting standard which provides amendments to previous guidance on the consolidation of variable interest entities (“VIE”). This standard clarifies the characteristics that identify a VIE and changes how a reporting entity identifies a primary beneficiary that would consolidate the VIE from a quantitative risk and rewards calculation to a qualitative approach based on which variable interest holder has controlling financial interest and the ability to direct the most significant activities that impact the VIE’s economic performance. This statement requires the primary beneficiary assessment to be performed on a continuous basis. It also requires additional disclosures about an entity’s involvement with a VIE, restrictions on the VIE’s assets and liabilities that are included in the reporting entity’s consolidated balance sheet, significant risk exposures due to the entity’s involvement with the VIE, and how its involvement with a VIE impacts the reporting entity’s consolidated financial statements. The standard was effective for fiscal years beginning after November 15, 2009. The adoption of the standard did not have any impact on the Company’s consolidated financial statements.

 

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WILLBROS GROUP, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In thousands, except share and per share amounts)
1. Summary of Significant Accounting Policies (continued)
On December 17, 2010, the FASB issued an update to its standard on goodwill impairment, which (1) does not change the prescribed method of calculating the carrying value of a reporting unit in the performance of step one of the goodwill impairment test and (2) requires entities with a zero or negative carrying value to assess, considering qualitative factors such as the impairment indicators listed in FASB’s standard on goodwill, (whether it is more likely than not that a goodwill impairment exists. If an entity concludes that it is more likely than not that a goodwill impairment exists, the entity must perform step two of the goodwill impairment test. The update is effective for impairment tests performed during entities’ fiscal years (and interim periods within those years) that begin after December 15, 2010. Based on management's review, the adoption of this update is not expected to have any impact on the Company’s consolidated financial statements.
2. Acquisitions
InfrastruX
On July 1, 2010, the Company completed the acquisition of 100 percent of the outstanding stock of InfrastruX for a purchase price of $485,800, before final working capital and other transaction adjustments. The Company paid $372,382 in cash, a portion of which was used to retire InfrastruX indebtedness and pay InfrastruX transaction expenses, and issued approximately 7.9 million shares of the Company’s common stock to the shareholders of InfrastruX. Cash paid was comprised of $72,382 in cash from operations and $300,000 from a new term loan facility. The acquisition was completed pursuant to an Agreement and Plan of Merger (the “Merger”), dated March 11, 2010.
Under the agreement, InfrastruX shareholders are eligible to receive earnout payments of up to $125,000 if certain EBITDA targets are met. Refer to Note 17 — Fair Value Measurements for further discussion of the contingent earnout.
InfrastruX was a privately-held firm based in Seattle, Washington and provides design, construction, maintenance, engineering and other infrastructure services to the utility industry across the U.S. market.
This acquisition provides the Company the opportunity to strengthen its presence in the infrastructure markets within the utility industry.
Consideration
Total consideration transferred in acquiring InfrastruX is summarized as follows:
         
Proceeds from newly issued term loan facility
  $ 300,000  
Cash provided from operations
    72,382  
 
     
Total cash consideration
    372,382  
Issuance of WG common stock
    58,078 (1)
Contingent consideration
    55,340 (2)
 
     
Total consideration
  $ 485,800  
 
     
     
(1)  
Represents 7,923,308 shares issued, which have been valued at the closing price of Company stock on July 1, 2010, the acquisition date.
 
(2)  
Estimated as of acquisition announcement based on a probability estimate of InfrastruX’s EBITDA achievements during the earnout period. See Note 17 — Fair Value Measurements.

 

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WILLBROS GROUP, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In thousands, except share and per share amounts)
2. Acquisitions (continued)
This transaction has been accounted for using the acquisition method of accounting which requires that, among other things, assets acquired and liabilities assumed be recorded at their fair values as of the acquisition date. The excess of the consideration transferred over those fair values is recorded as goodwill. The preliminary allocation of purchase price to acquired assets and liabilities is as follows:
         
Assets acquired:
       
Cash and cash equivalents
  $ 9,278  
Accounts receivable
    124,856  
Inventories
    4,501  
Prepaid expenses and other current assets
    39,565  
Property, plant and equipment
    156,160  
Intangible assets
    168,409 (1)
Goodwill
    184,822 (1)
Other long-term assets
    21,924 (1)
Liabilities assumed:
       
Accounts payable and other accrued liabilities
    (97,985 )
Capital lease obligations
    (4,977 )
Vendor related debt
    (2,761 )
Deferred income taxes and other tax liabilities
    (95,902 )
Other long-term liabilities
    (22,090 )
 
     
Net assets acquired
  $ 485,800  
 
     
     
(1)  
Includes post-acquisition purchase price adjustments.
The Company has consolidated InfrastruX in its financial results as the Utility T&D segment from the date of the acquisition. Our purchase price allocation has not been finalized due to the ongoing negotiation to determine working capital and other closing adjustments. These are expected to be finalized during the first quarter of 2011. However, under U.S. GAAP, the acquisition measurement period can last up to one year.
Property, plant and equipment (“PP&E”)
A step-up adjustment of $25,077 was recorded to present the PP&E acquired at its estimated fair value. The weighted average useful life used to calculate depreciation of the step up related to PP&E is approximately seven years.
Intangible assets
The following table summarizes the fair value estimates recorded for the identifiable intangible assets and their estimated useful lives:
                 
    Estimated Fair Value     Estimated Useful Life  
Trade name
  $ 12,779     10 years
Customer relationships
    150,130     15 years
Technology
    5,500     10 years
 
             
Total identifiable intangible assets
  $ 168,409          
 
             
The amortizable intangible assets have useful lives ranging between ten years and fifteen years and a weighted average useful life of 14.2 years. Goodwill represents the excess of the purchase price over the fair value of the net tangible and identifiable intangible assets acquired. Goodwill associated with this transaction is not expected to be deductible for tax purposes. The goodwill recorded in connection with this acquisition is included in the Utility T&D segment. A significant portion of the customer relationship intangible recorded in this transaction relates to a single customer.
Deferred taxes
The Company provided deferred taxes and other tax liabilities as part of the acquisition accounting related to the estimated fair market value adjustments for acquired intangible assets and PP&E. An adjustment of $95,902 was recorded to present the deferred taxes and other tax liabilities at fair value.

 

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WILLBROS GROUP, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In thousands, except share and per share amounts)
2. Acquisitions (continued)
Pro Forma Impact of the Acquisition
The following unaudited supplemental pro forma results present consolidated information as if the acquisition had been completed as of January 1, 2010 and January 1, 2009. The pro forma results include: (i) the amortization associated with an estimate of the acquired intangible assets, (ii) interest expense associated with debt used to fund a portion of the acquisition and reduced interest income associated with cash used to fund a portion of the acquisition, (iii) the impact of certain fair value adjustments such as additional depreciation expense for adjustments to property, plant and equipment and reduction to interest expense for adjustments to debt, and (iv) costs directly related to acquiring InfrastruX. The pro forma results do not include any potential synergies, cost savings or other expected benefits of the acquisition. Accordingly, the pro forma results should not be considered indicative of the results that would have occurred if the acquisition and related borrowings had been consummated as of January 1, 2009, or January 1, 2010, nor are they indicative of future results.
                 
    Year Ended  
    December 31,  
    2010     2009  
Revenues
  $ 1,500,729     $ 1,858,549  
Net income (loss) attributable to Company shareholders
    (53,089 )     (20,984 )
Basic net income (loss) per share
    (1.15 )     (0.45 )
Diluted net income (loss) per share
    (1.15 )     (0.45 )
Wink Companies, LLC
Effective July 9, 2009, the Company acquired the engineering business of Wink, a privately-held firm based in Baton Rouge, Louisiana. Wink serves primarily the U.S. market from its regional offices in Louisiana and Mississippi, providing multi-disciplinary engineering services to clients in the petroleum refining, chemicals and petrochemicals and oil and gas industries. This acquisition provides the Company the opportunity to offer fully integrated engineering, procurement, and construction (“EPC”) services to the downstream hydrocarbon industries. The total purchase price of $17,431 was comprised of $6,075 in cash paid, $10,236 in debt assumed and $1,120 related to the assumption of an unfavorable lease relative to market value. In addition, the Company incurred transaction-related costs of approximately $600.
The Company has consolidated Wink in its financial results as part of its Downstream Oil & Gas segment from the date of acquisition. The allocation of purchase price to acquired assets and liabilities is as follows:
         
Cash acquired
  $ 2,356  
Receivables, net
    5,876  
Other current assets acquired
    7,513  
Property and equipment
    6,441  
Other long-term assets
    80  
Amortizable intangible assets:
       
Customer relationships
    1,101 (1)
Trademark / Tradename
    1,300  
Non-compete agreement
    1,100  
Goodwill
    3,899 (1)
Liabilities assumed
    (12,235 )
 
     
Total purchase price
  $ 17,431  
 
     
     
(1)  
Includes an approximate $300 post-acquisition reclassification from customer relationships to goodwill.

 

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WILLBROS GROUP, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In thousands, except share and per share amounts)
2. Acquisitions (continued)
The amortizable intangible assets have useful lives ranging between five years and ten years and a weighted average useful life of 8.3 years. Goodwill represents the excess of the purchase price over the fair value of the net tangible and identifiable intangible assets acquired and is deductible for tax purposes. The goodwill recorded in connection with this acquisition is included in the Downstream Oil & Gas segment.
The results and operations for Wink have been included in the Consolidated Statements of Operations since the completion of the acquisition on July 9, 2009. This acquisition does not have a material impact on the Company’s results of operations. Accordingly, pro forma disclosures have not been presented.
3. Accounts Receivable
Accounts receivable, net as of December 31, 2010 and 2009 is comprised of the following:
                 
    December 31,  
    2010     2009  
Trade
  $ 260,091     $ 105,812  
Unbilled revenue
    47,652       18,314  
Contract retention
    14,905       38,357  
Other receivables
    1,725       1,867  
 
           
Total accounts receivable
    324,373       164,350  
Less: allowance for doubtful accounts
    (4,499 )     (1,936 )
 
           
Total accounts receivable, net
  $ 319,874     $ 162,414  
 
           
The Company expects all accounts receivable to be collected within one year. The provision for bad debts included in “General and administrative” expenses in the Consolidated Statements of Operations was $2,887, $664, and $2,403 for the years ended December 31, 2010, 2009 and 2008, respectively.
4. Contracts in Progress
Contract cost and recognized income not yet billed on uncompleted contracts arise when recorded revenues for a contract exceed the amounts billed under the terms of the contracts. Contract billings in excess of cost and recognized income arise when billed amounts exceed revenues recorded. Amounts are billable to customers upon various measures of performance, including achievement of certain milestones, completion of specified units or completion of the contract. Also included in contract cost and recognized income not yet billed on uncompleted contracts are amounts the Company seeks to collect from customers for change orders approved in scope but not for price associated with that scope change (unapproved change orders). Revenue for these amounts is recorded equal to the lesser of the expected revenue or cost incurred when realization of price approval is probable. Estimating revenues from unapproved change orders involve the use of estimates, and it is reasonably possible that revisions to the estimated recoverable amounts of recorded unapproved change orders may be made in the near-term. If the Company does not successfully resolve these matters, a reduction in revenues may be required to amounts that have been previously recorded.

 

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WILLBROS GROUP, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In thousands, except share and per share amounts)
4. Contracts in Progress (continued)
Contract cost and recognized income not yet billed and related amounts billed as of December 31, 2010 and 2009 were as follows:
                 
    December 31,  
    2010     2009  
Cost incurred on contracts in progress
  $ 896,987     $ 1,113,712  
Recognized income
    159,628       161,398  
 
           
 
    1,056,615       1,275,110  
Progress billings and advance payments
    (1,038,026 )     (1,241,437 )
 
           
 
  $ 18,589     $ 33,673  
 
           
 
               
Contract cost and recognized income not yet billed
  $ 35,059     $ 45,009  
Contract billings in excess of cost and recognized income
    (16,470 )     (11,336 )
 
           
 
  $ 18,589     $ 33,673  
 
           
Contract cost and recognized income not yet billed includes $3,216 and $1,551 at December 31, 2010 and 2009, respectively, on completed contracts.
5. Property, Plant and Equipment
Property, plant and equipment, which are used to secure debt or are subject to lien, at cost, as of December 31, 2010 and 2009 were as follows:
                 
    December 31,  
    2010     2009  
Construction equipment
  $ 126,896     $ 140,157  
Furniture and equipment
    50,634       44,119  
Land and buildings
    39,401       36,278  
Transportation equipment
    151,196       32,264  
Leasehold improvements
    17,748       16,221  
Aircraft
    7,410       7,410  
Marine equipment
    120       120  
 
           
Total property, plant and equipment
    393,405       276,569  
Less: accumulated depreciation
    (164,226 )     (143,690 )
 
           
Total property, plant and equipment, net
  $ 229,179     $ 132,879  
 
           
Amounts above include $3,698 and $4,401 of construction in progress as of December 31, 2010 and 2009, respectively. Depreciation expense included in operating expense for the years ended December 31, 2010, 2009 and 2008 was $46,441, $34,345 and $34,483, respectively.
6. Assets Held For Sale
In 2010, the Company began a process of analyzing all under-utilized property and equipment and adopted a plan to dispose of such assets. Pursuant to that plan, in December 2010, the Company completed the sale of equipment having a net book value of $12,226 receiving proceeds of $15,103. The resulting gain on sale of assets has been recorded within “Other, net” in the Consolidated Statements of Operations. In addition, the Company has committed to a plan of disposal of additional properties and equipment, which are expected to be sold in 2011. These assets have been separately presented in the Consolidated Balance Sheets in the caption ‘‘Assets held for sale’’ and are no longer depreciated. In connection with this plan of disposal, the Company determined that the carrying value of one facility within the Upstream Oil & Gas segment, exceeded its fair value. Consequently, the Company recorded an impairment loss of $931, which represents the excess of the carrying value over fair values, less cost to sell. The impairment loss is recorded within “Other, net” in the Consolidated Statements of Operations.

 

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WILLBROS GROUP, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In thousands, except share and per share amounts)
7. Goodwill and Other Intangible Assets
The Company’s goodwill by segment as of December 31, 2010 and 2009 was as follows:
                         
            Impairment        
Upstream Oil & Gas   Goodwill     Reserves     Total, Net  
Balance as of January 1, 2009
  $ 11,142     $     $ 11,142  
Goodwill from acquisitions
                 
Purchase price adjustments
                 
Impairment losses
                 
Translation adjustments and other
    1,496             1,496  
 
                 
Balance as of December 31, 2009
    12,638             12,638  
Goodwill from acquisitions
                 
Purchase price adjustments
                 
Impairment losses
                 
Translation adjustments and other
    539             539  
 
                 
Balance as of December 31, 2010
  $ 13,177     $     $ 13,177  
 
                 
                         
            Impairment        
Downstream Oil & Gas   Goodwill     Reserves     Total, Net  
Balance as of January 1, 2009
  $ 131,518     $ (62,295 )   $ 69,223  
Goodwill from acquisitions
    3,600             3,600  
Purchase price adjustments
    299             299  
Impairment losses
                 
Translation adjustments and other
    15             15  
 
                 
Balance as of December 31, 2009
    135,432       (62,295 )     73,137  
Goodwill from acquisitions
                 
Purchase price adjustments
    617             617  
Impairment losses
          (60,000 )     (60,000 )
Translation adjustments and other
                 
 
                 
Balance as of December 31, 2010
  $ 136,049     $ (122,295 )   $ 13,754  
 
                 
                         
            Impairment        
Utility T&D