10-K 1 amrc1231201710-k.htm 10-K Document
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, 2017
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: 001-34811
Ameresco, Inc.
(Exact name of registrant as specified in its charter)
Delaware
 
04-3512838
(State or Other Jurisdiction of
Incorporation or Organization)
 
(I.R.S. Employer
Identification No.)
111 Speen Street, Suite 410
Framingham, Massachusetts
 
01701
(Address of Principal Executive Offices)
 
(Zip Code)
(508) 661-2200
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Class A Common Stock,
par value $0.0001 per share
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 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 Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes þ     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 Annual Report on Form 10-K or any amendment to this Annual Report on Form 10-K.   o
 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer o
Accelerated Filer  þ
Non-accelerated filer  o
Smaller reporting company o
Emerging growth company o
 
(Do not check if a smaller reporting company)
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuent to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o     No þ
The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold on the New York Stock Exchange on June 30, 2017, the last business day of the registrant’s most recently completed second fiscal quarter, was $155,530,275.
Indicate the number of shares outstanding of each of the registrant’s classes of common stock as of the latest practicable date.
Class
Shares outstanding as of March 5, 2018
Class A Common Stock, $0.0001 par value per share
27,320,918
Class B Common Stock, $0.0001 par value per share
18,000,000


Table of Contents                            



DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for our 2018 annual meeting of stockholders are incorporated by reference into Part III.
 
 



AMERESCO, INC.
TABLE OF CONTENTS
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



Table of Contents                            



NOTE ABOUT FORWARD LOOKING STATEMENTS

This Annual Report on Form 10-K contains “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (“the Exchange Act”). All statements, other than statements of historical fact, including statements regarding our strategy, future operations, future financial position, future revenues, projected costs, prospects, plans, objectives of management, expected market growth and other characterizations of future events or circumstances are forward-looking statements. These statements are often, but not exclusively, identified by the use of words such as “may,” “will,” “expect,” “believe,” “anticipate,” “intend,” “could,” “estimate,” “target,” “project,” “predict” or “continue,” and similar expressions or variations. These forward-looking statements include, among other things, statements about:
our expectations as to the future growth of our business and associated expenses;
our expectations as to revenue generation;
the future availability of borrowings under our revolving credit facility;
the expected future growth of the market for energy efficiency and renewable energy solutions;
our backlog, awarded projects and recurring revenue and the timing of such matters;
our expectations as to acquisition activity;
the impact of any restructuring;
the uses of future earnings;
our intention to repurchase shares of our Class A common stock;
the expected energy and cost savings of our projects; and
the expected energy production capacity of our renewable energy plants.
These forward-looking statements are based on current expectations and assumptions that are subject to risks, uncertainties and other factors that could cause actual results and the timing of certain events to differ materially and adversely from the future results expressed or implied by such forward-looking statements. Risks, uncertainties and factors that could cause or contribute to such differences include, but are not limited to, those discussed in the section titled “Risk Factors,” set forth in Item 1A of this Annual Report on Form 10-K and elsewhere in this report. The forward-looking statements in this Annual Report on Form 10-K represent our views as of the date of this Annual Report on Form 10-K. Subsequent events and developments may cause our views to change. However, while we may elect to update these forward-looking statements at some point in the future, we have no current intention of doing so and undertake no obligation to do so except to the extent required by applicable law. You should, therefore, not rely on these forward-looking statements as representing our views as of any date subsequent to the date of this Annual Report on Form 10-K.


Table of Contents                            



Item 1. Business
Company Overview
Founded in 2000, Ameresco, Inc. is a leading independent provider of comprehensive energy services, including energy efficiency, infrastructure upgrades, energy security and resilience, asset sustainability and renewable energy solutions for businesses and organizations throughout North America and Europe. Ameresco’s sustainability services include capital and operational upgrades to a facility’s energy infrastructure and the development, construction, ownership and operation of renewable energy plants. Ameresco has successfully completed energy saving, environmentally responsible projects with federal, state and local governments, healthcare and educational institutions, housing authorities, and commercial and industrial customers. With its corporate headquarters in Framingham, MA, Ameresco has more than 1,000 employees across more than 68 offices providing local expertise in the United States, Canada, and the United Kingdom.
Strategic acquisitions of complementary businesses and assets have been an important part of our historical development. Since inception, we have completed numerous acquisitions, which have enabled us to broaden our service offerings and expand our geographical reach.
Our principal service is the development, design, engineering and installation of projects that reduce the energy and operations and maintenance (“O&M”) costs of our customers’ facilities. These projects generally include a variety of measures that incorporate innovative technology and techniques, customized for the facility and designed to improve the efficiency of major building systems, such as heating, ventilation, cooling and lighting systems, while enhancing the comfort and usability of the buildings. Such measures may include a combination of the following: water reclamation, light-emitting diode (“LED”) lighting, smart metering, intelligent micro-grids, battery storage, combine heat and power (“CHP”) or the installation of renewable energy, such as solar photovoltaic (“PV”). We also offer the ability to incorporate analytical tools that provide improved building energy management capabilities and enable customers to identify opportunities for energy cost savings. We typically commit to customers that our energy efficiency projects will satisfy agreed upon performance standards upon installation or achieve specified increases in energy efficiency. In most cases, the forecasted lifetime energy and operating cost savings of the energy efficiency measures we install will defray all or almost all of the cost of such measures. In many cases, we assist customers in obtaining third-party financing, grants or rebates for the cost of constructing the facility improvements, resulting in little or no upfront capital expenditure by the customer. After a project is complete, we may operate, maintain and repair the customer’s energy systems under a multi-year O&M contract, which provides us with recurring revenue and visibility into the customer’s evolving needs.
We also serve certain customers by developing and building small-scale renewable energy plants located at or close to a customer’s site. Depending upon the customer’s preference, we will either retain ownership of the completed plant or build it for the customer. Most of our small-scale renewable energy plants to date consist of solar PV installations and plants constructed adjacent to landfills, that use landfill gas (“LFG”) to generate energy. We have also designed and built, as well as own, operate and maintain, plants that utilize biogas from wastewater treatment processes. Our largest renewable energy project that we operate for a customer uses biomass as the primary source of energy. In the case of most of the plants that we own, the electricity, thermal energy or processed renewable gas fuel generated by the plant is sold under a long-term supply contract with the customer, which is typically a utility, municipality, industrial facility or other purchaser of large amounts of energy. For information on how we finance the projects that we own and operate, please see the disclosures under Note 2, “Summary of Significant Accounting Policies”, Note 7, “Long-Term Debt” and Note 9, “Investment Funds” to our Consolidated Financial Statements appearing in Item 8 of this Annual Report on Form 10-K.
As of December 31, 2017, we had backlog of approximately $572.5 million in expected future revenues under signed customer contracts for the installation or construction of projects, which we sometimes refer to as fully-contracted backlog; and we also had been awarded projects for which we had not yet signed customer contracts, which we sometimes refer to as awarded projects, with estimated total future revenues of an additional $1,199.0 million. As of December 31, 2016, we had backlog of approximately $534.1 million in expected future revenues under signed customer contracts for the installation or construction of projects; and we also had been awarded projects for which we had not yet signed customer contracts, with estimated total future revenues of an additional $957.6 million. As of December 31, 2015, we had backlog of approximately $390.4 million in expected future revenues under signed customer contracts for the installation or construction of projects; and we also had been awarded projects for which we had not yet signed customer contracts with estimated total future revenues of an additional $955.8 million. The contracts reflected in our fully-contracted backlog typically have a construction period of 12 to 36 months and we typically expect to recognize revenue for such contracts over the same period. Where we have been awarded a project, but have not yet signed a customer contract for that project, we would not begin recognizing revenue unless

1

Table of Contents                            



and until a customer contract has been signed and we treat the project as fully-contracted backlog. Recently, awarded projects typically have been taking 12 to 24 months from award to having a signed contract and thus convert to fully-contracted backlog. It may take longer, however, depending upon the size and complexity of the project. Generally, the larger and more complex the project, the longer it takes to take it from award to signed contract. Historically, approximately 90% of our awarded projects ultimately have resulted in a signed contract.
See “We may not recognize all revenues from our backlog or receive all payments anticipated under awarded projects and customer contracts” and “In order to secure contracts for new projects, we typically face a long and variable selling cycle that requires significant resource commitments and requires a long lead time before we realize revenues” in Item 1A, Risk Factors of this Annual Report on Form 10-K.
Revenues generated from backlog, which we refer to as project revenues, were $506.6 million, $454.2 million and $434.4 million for the twelve months ended December 31, 2017, 2016 and 2015, respectively.
We also expect to realize recurring revenues both from long-term O&M contracts and from energy output sales for renewable energy operating assets that we own. In addition, we expect to generate revenues from the sale of photovoltaic solar energy products and systems (“integrated-PV”) and other services, such as consulting services and enterprise energy management services. Information about revenues from these other service and product offerings may be found in Note 18, “Business Segment Information” of our Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K, which information is incorporated herein by reference.
Ameresco’s Lines of Business
Projects
Our principal service is energy efficiency projects, which entails the design, engineering and installation of, and assisting with the arranging of financing for an ever-increasing array of innovative technologies and techniques to improve the energy efficiency, and control the operation, of a building’s energy- and water- consuming systems. In certain projects, we also design and construct for a customer a central plant or cogeneration system providing power, heat and/or cooling to a building, or a small-scale plant that produces electricity, gas, heat or cooling from renewable sources of energy. Our projects generally range in size and scope from a one-month project to design and retrofit a lighting system to a more complex 30-month project to design and install a central plant or cogeneration system or other small-scale plant. Projects we have constructed or are currently working on include designing, engineering and installing energy conservation measures across school buildings; large, complex energy conservation and energy security projects for the federal government; and municipal-scale street lighting projects incorporating smart-city controls.
O&M
After an energy efficiency or renewable energy project is completed, we often provide ongoing O&M services under a multi-year contract. These services include operating, maintaining and repairing facility energy systems such as boilers, chillers and building controls, as well as central power and other small-scale plants. For larger projects, we frequently maintain staff on-site to perform these services.
Energy Assets
Our service offering also includes the sale of electricity, processed renewable gas fuel, heat or cooling from the portfolio of assets that we own and operate.
We have constructed and are currently designing and constructing a wide range of renewable energy plants using LFG, wastewater treatment biogas, solar, biomass, other bio-derived fuels, wind and hydro sources of energy. Most of our renewable energy projects to date have involved the generation of electricity from solar PV and LFG or the sale of processed LFG. We purchase the LFG that otherwise would be combusted or vented, process it, and either sell it or use it in our energy plants. We have also designed and built, as well as own, operate and maintain, plants that take biogas generated in the anaerobic digesters of wastewater treatment plants and turn it into renewable natural gas that is either used to generate energy on-site or that can be sold through the nation’s natural gas pipeline grid. Where we own and operate energy producing assets, we typically enter into a long-term power purchase agreement (“PPA”) for the sale of the energy.
As of December 31, 2017, we owned and operated 73 small-scale renewable energy plants and solar PV installations. Of the owned plants, 23 are renewable LFG plants, two are wastewater biogas plants, and 48 are solar PV installations. The 73

2

Table of Contents                            



small-scale renewable energy plants and solar PV installations that we own have the capacity to generate electricity or deliver renewable gas fuel producing an aggregate of more than 191 megawatt equivalents.
Other
Our service and product offerings also include integrated-PV and consulting and enterprise energy management services.
Customer Arrangements
For our energy efficiency projects, we typically enter into energy savings performance contracts (“ESPCs”), under which we agree to develop, design, engineer and construct a project and also commit that the project will satisfy agreed upon performance standards that vary from project to project. These performance commitments are typically based on the design, capacity, efficiency or operation of the specific equipment and systems we install. Depending on the project, the measurement and demonstration may be required only once, upon installation, based on an analysis of one or more sample installations, or may be required to be repeated at agreed upon intervals generally over periods of up to 20 years. We often assist these customers in identifying and obtaining financing, through rebate programs, grant programs, third-party lenders and other sources.
Under our contracts, we typically do not take responsibility for a wide variety of factors outside of our control and exclude or adjust for such factors in commitment calculations. These factors include variations in energy prices and utility rates, weather, facility occupancy schedules, the amount of energy-using equipment in a facility and the failure of the customer to operate or maintain the project properly. Typically, our performance commitments apply to the aggregate overall performance of a project rather than to individual energy efficiency measures. Therefore, to the extent an individual measure underperforms, it may be offset by other measures that overperform during the same period. In the event that an energy efficiency project does not perform according to the agreed upon specifications, our agreements typically allow us to satisfy our obligation by adjusting or modifying the installed equipment, installing additional measures to provide substitute energy savings or paying the customer for lost energy savings based on the assumed conditions specified in the agreement. Many of our equipment supply, local design and installation subcontracts contain provisions that enable us to seek recourse against our vendors or subcontractors if there is a deficiency in our energy reduction commitment. See “We may have liability to our customers under our ESPCs if our projects fail to deliver the energy use reductions to which we are committed under the contract” in Item 1A, Risk Factors.
The projects that we perform for governmental agencies are governed by particular qualification and contracting regimes. Certain states require qualification with an appropriate state agency as a precondition to performing work or appearing as a qualified energy service provider for state, county and local agencies within the state. Most of the work that we perform for the federal government is performed under indefinite delivery, indefinite quantity (“IDIQ”) agreements between government agencies and us or our subsidiaries. These IDIQ agreements allow us to contract with the relevant agencies to implement energy projects, but no work may be performed unless we and the agency agree on a task order or delivery order governing the provision of a specific project. The government agencies enter into contracts for specific projects on a competitive basis. We and our subsidiaries and affiliates are currently party to two IDIQ agreement with the U.S. Department of Energy. The earlier IDIQ was awarded in 2008 and expires in 2019, with an aggregate maximum potential ordering amount of $5 billion. The latter IDIQ was awarded in April 2017 and has a base ordering period of 60 months (expiring in 2022) with one 18-month option period. There is no guarantee the option will be exercised. The maximum value of the latter IDIQ is $55 billion and is allocated across all 4 contract holders and is inclusive of both the base and option period. We are also party to similar agreements with other federal agencies, including the U.S. Army Corps of Engineers and the U.S. General Services Administration. Payments by the federal government for energy efficiency measures are based on the services provided and products installed, but are limited to the savings derived from such measures, calculated in accordance with federal regulatory guidelines and the specific contract terms. The savings are typically determined by comparing energy use and O&M costs before and after the installation of the energy efficiency measures, adjusted for changes that affect energy use and O&M costs but are not caused by the energy efficiency measures.
Sales and Marketing
Our sales and marketing approach is to offer customers customized and comprehensive energy efficiency solutions tailored to meet their economic, operational and technical needs. The sales, design and construction process for energy efficiency and renewable energy projects recently has been averaging from 18 to 54 months. We identify project opportunities through referrals, requests for proposals (“RFPs”), conferences and events, website, online campaigns, telemarketing and repeat

3

Table of Contents                            



business from existing customers. Our direct sales force develops and follows up on customer leads. As of December 31, 2017, we had 116 employees in direct sales.
In preparation for a proposal, our team typically conducts a preliminary audit of the customer’s needs and requirements, and identifies areas to enhance efficiencies and reduce costs. We collect and analyze the customer’s utility bill and other data related to energy use. If the bills are complex or numerous, we often utilize Ameresco’s enterprise energy management software tools to scan, compile and analyze the information. Our experienced engineers visit and assess the customer’s current energy systems and infrastructure. Through our knowledge of the federal, state, local governmental and utility environment, we assess the availability of energy, utility or environmental-based payments for usage reductions or renewable power generation, which helps us optimize the economic benefits of a proposed project for a customer. Once awarded a project, we perform a more detailed audit of the customer’s facilities, which serves as the basis for the final specifications of the project and final contract terms.
For renewable energy plants that are not located on a customer’s site or use sources of energy not within the customer’s control, the sales process also involves the identification of sites with attractive sources of renewable energy and obtaining necessary rights and governmental permits to develop a plant on that site. For example, for LFG projects, we start with gaining control of a LFG resource located close to the prospective customer. For solar and wind projects, we look for sites where utilities are interested in purchasing renewable energy power at rates that are sufficient to make a project feasible. Where governmental agencies control the site and resource, such as a landfill owned by a municipality, the customer may be required to issue an RFP to use the site or resource. Once we believe we are likely to obtain the rights to the site and the resource, we seek customers for the energy output of the potential project, with whom we can enter into a long-term PPA.
Customers
In 2017, we served customers throughout the United States, Canada and the United Kingdom (“U.K”). Historically, including for the years ended December 31, 2017, 2016 and 2015, approximately 77% of our revenues have been derived from federal, state, provincial or local government entities, including public housing authorities and public universities. Our federal customers include various divisions of the U.S. federal government. The U.S. federal government, which is considered a single customer for reporting purposes, constituted 32.0%, 27.3% and 20.2% of our consolidated revenues for the years ended December 31, 2017, 2016 and 2015, respectively. For the year ended December 31, 2017, our largest 20 customers accounted for approximately 54.9% of our total revenues. Other than the U.S. federal government, no one customer represented more than 10% of our revenues during this period.
See “Provisions in our government contracts may harm our business, financial condition and operating results” in Item 1A, Risk Factors for a discussion of special considerations applicable to government contracting.
Competition
While we face significant competition from a large number of companies, we believe few offer the full range of services that we provide.
Our principal competitors for our core business include Constellation Energy (an Exelon company), Energy Systems Group, Honeywell, Johnson Controls, McKinstry, NORESCO, Opterra and Siemens Building Technologies. We compete primarily on the basis of our comprehensive, independent offering of energy efficiency and renewable energy services and the breadth and depth of our expertise.
For renewable energy plants, we compete primarily with many large independent power producers and utilities, as well as a large number of developers of renewable energy projects. In the LFG market, our principal competitors include national project developers and owners of landfills who self-develop projects using LFG from their landfills, such as Waste Management. In the solar PV market, our principal competitors are Apex Clean Energy, Borrego Solar, Dominion, Duke Energy, G&S Solar, SCE&G (a Scana company), Tesla, Southern Company and SunPower. We compete for renewable energy projects primarily on the basis of our experience, reputation and ability to identify and complete high quality and cost-effective projects.
For O&M services, our principal competitors are Emcorp Group, Fluor, Honeywell, Johnson Controls and Veolia. In this area, we compete primarily on the basis of our expertise and quality of service.
See “We operate in a highly competitive industry, and our current or future competitors may be able to compete more effectively than we do, which could have a material adverse effect on our business, revenues, growth rates and market share” in Item 1A, Risk Factors for further discussion of competition.

4

Table of Contents                            



Regulatory
Various regulations affect the conduct of our business. Federal and state legislation and regulations enable us to enter into ESPCs with government agencies in the United States. The applicable regulatory requirements for ESPCs differ in each state and between agencies of the federal government.
Our projects must conform to all applicable electric reliability, building and safety, and environmental regulations and codes, which vary from place to place and time to time. Various federal, state, provincial and local permits are required to construct an energy efficiency project or renewable energy plant.
Renewable energy projects are also subject to specific governmental safety and economic regulation. States and the federal government typically do not regulate the transportation or sale of LFG unless it is combined with and distributed with natural gas, but this is not uniform among states and may change from time to time. States regulate the retail sale and distribution of natural gas to end-users, although regulatory exemptions from regulation are available in some states for limited gas delivery activities, such as sales only to a single customer. The sale and distribution of electricity at the retail level is subject to state and provincial regulation, and the sale and transmission of electricity at the wholesale level is subject to federal regulation. While we do not own or operate retail-level electric distribution systems or wholesale-level transmission systems, the prices for the products we offer can be affected by the tariffs, rules and regulations applicable to such systems, as well as the prices that the owners of such systems are able to charge. The construction of power generation projects typically is regulated at the state and provincial levels, and the operation of these projects also may be subject to state and provincial regulation as “utilities.” At the federal level, the ownership and operation of, and sale of power from, generation facilities may be subject to regulation under the Public Utility Holding Company Act of 2005 (“PUHCA”), the Federal Power Act (“FPA”), and Public Utility Regulatory Policies Act of 1978 (“PURPA”). However, because all of the plants that we have constructed and operated to date are small power “qualifying facilities” under PURPA, they are subject to less regulation under the FPA, PUHCA and related state utility laws than traditional utilities.
If we pursue projects employing different technologies or with a single project electrical capacity greater than 20 megawatts, we could become subject to some of the regulatory schemes which do not apply to our current projects. In addition, the state, provincial and federal regulations that govern qualifying facilities and other power sellers frequently change, and the effect of these changes on our business cannot be predicted.
LFG power generation facilities require an air emissions permit, which may be difficult to obtain in certain jurisdictions. See “Compliance with environmental laws could adversely affect our operating results” in Item 1A, Risk Factors. Renewable energy projects may also be eligible for certain governmental or government-related incentives from time to time, including tax credits, cash payments in lieu of tax credits, and the ability to sell associated environmental attributes, including carbon credits. Government incentives and mandates typically vary by jurisdiction.
Some of the demand reduction services we provide for utilities and institutional clients are subject to regulatory tariffs imposed under federal and state utility laws. In addition, the operation of, and electrical interconnection for, our renewable energy projects are subject to federal, state or provincial interconnection and federal reliability standards also set forth in utility tariffs. These tariffs specify rules, business practices and economic terms to which we are subject. The tariffs are drafted by the utilities and approved by the utilities’ state, provincial or federal regulatory commissions.
Employees
As of December 31, 2017, we had a total of 1,049 employees in offices located in 35 states, the District of Columbia, four Canadian provinces and the U.K.
Seasonality
See “Our business is affected by seasonal trends and construction cycles, and these trends and cycles could have an adverse effect on our operating results” in Item 1A, Risk Factors and “Overview — Effects of Seasonality” in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of seasonality in our business.
Segments and Geographic Information
Financial information about our domestic and international operations and about our segments may be found in Note 14, “Geographic Information” and 18, “Business Segment Information” respectively, of our Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K, which information is incorporated herein by reference.

5

Table of Contents                            



Additional Information
Ameresco was incorporated in Delaware in 2000 and is headquartered in Framingham, Massachusetts.
Periodic reports, proxy statements and other information are available to the public, free of charge, on our website, www.ameresco.com, as soon as reasonably practicable after they have been filed with the Securities and Exchange Commission (“SEC”), and through the SEC’s website, www.sec.gov. We include our website address in this report only as an inactive textual reference and do not intend it to be an active link to our website. None of the material on our website is part of this Annual Report on Form 10-K.
Executive Officers
The following is a list of our executive officers, their ages as of March 1, 2018 and their principal positions.
Name
 
Age
 
Position (s)
George P. Sakellaris
 
71

 
Chairman of the Board of Directors, President and Chief Executive Officer
David J. Anderson
 
57

 
Executive Vice President and Director
Michael T. Bakas
 
49

 
Executive Vice President, Distributed Energy Systems
Nicole A. Bulgarino
 
45

 
Executive Vice President and General Manager, Federal Solutions
David J. Corrsin
 
59

 
Executive Vice President, General Counsel and Secretary and Director
Joseph P. DeManche
 
61

 
Executive Vice President, Engineering and Operations
Louis P. Maltezos
 
51

 
Executive Vice President
John R. Granara, III
 
49

 
Executive Vice President, Chief Financial Officer and Treasurer
George P. Sakellaris: Mr. Sakellaris has served as chairman of our board of directors and our president and chief executive officer since founding Ameresco in 2000.
David J. Anderson: Mr. Anderson has served as our executive vice president as well as a director, since 2000 and oversees business development, government relations, strategic marketing and communications, as well as several U.S. business units and U.K. operations.
Michael T. Bakas: Mr. Bakas has served as our executive vice president, distributed energy systems, since November 2017. Mr. Bakas previously served as our senior vice president, renewable energy, from March 2010 to September 2017 and our vice president, renewable energy from 2000 to February 2010.
David J. Corrsin: Mr. Corrsin has served as our executive vice president, general counsel and secretary, as well as a director, since 2000.
Nicole A. Bulgarino: Ms. Bulgarino has served as our executive vice president and general manager of federal solutions since May 2017. Ms. Bulgarino previously served as our senior vice president and general manager of federal solutions from May 2015 to May 2017; vice president and general manager of federal solutions from February 2014 to May 2015; vice president, federal group operations from December 2012 to February 2014; director, implementation from May 2010 to December 2012; and senior engineer from June 2004 to May 2010.
Joseph P. DeManche: Mr. DeManche has served as our executive vice president, engineering and operations since 2002.
Louis P. Maltezos: Mr. Maltezos has served as executive vice president since April 2009 and oversees Central and Northwest Regions and Canada operations. Mr. Maltezos has also served as the chief executive officer of Ameresco Canada since September 2015 and served as the president of Ameresco Canada from September 2014 to September 2015.
John R. Granara, III: Mr. Granara has served as our executive vice president since February 2017 and as our chief financial officer and treasurer since May 2015. Mr. Granara previously served as our vice president and chief accounting officer from September 2013 to May 2015. Prior to joining Ameresco, Mr. Granara served as Vice President Finance, Chief Accounting Officer and Corporate Controller for GT Advanced Technologies, Inc., a diversified technology company, from May 2011 through August 2013. Mr. Granara also served as interim chief financial officer of A123 Systems, Inc, a lithium-ion battery developer and manufacturer, from January 2011 through May 2011, and as vice president, finance, and corporate controller of A123 Systems, Inc. from November 2007 through December 2011. On October 16, 2012, A123 Systems, Inc. filed for voluntary reorganization under Chapter 11 of the U.S. Bankruptcy Code.

6

Table of Contents                            



Item 1A. Risk Factors
Our business is subject to numerous risks. We caution you that the following important factors, among others, could cause our actual results to differ materially from those expressed in forward-looking statements made by us or on our behalf in filings with the SEC, press releases, communications with investors and oral statements. Any or all of our forward-looking statements in this Annual Report on Form 10-K and in any other public statements we make may turn out to be wrong. They can be affected by inaccurate assumptions we might make or by known or unknown risks and uncertainties. Many factors mentioned in the discussion below will be important in determining future results. Consequently, no forward-looking statement can be guaranteed. Actual future results may differ materially from those anticipated in forward-looking statements. We undertake no obligation to update any forward-looking statements, whether as a result of new information, future events or otherwise, except to the extent required by applicable law. You should, however, consult any further disclosure we make in our reports filed with the SEC.
Risks Related to Our Business
If demand for our energy efficiency and renewable energy solutions does not develop as we expect, our revenues will suffer and our business will be harmed.
We believe, and our growth plans assume, that the market for energy efficiency and renewable energy solutions will continue to grow, that we will increase our penetration of this market and that our revenues from selling into this market will continue to increase over time. If our expectations as to the size of this market and our ability to sell our products and services in this market are not correct, our revenues will suffer and our business will be harmed.
In order to secure contracts for new projects, we typically face a long and variable selling cycle that requires significant resource commitments and requires a long lead time before we realize revenues.
The sales, design and construction process for energy efficiency and renewable energy projects recently has been taking from 18 to 54 months on average, with sales to federal government and housing authority customers tending to require the longest sales processes. Our existing and potential customers generally follow extended budgeting and procurement processes, and sometimes must engage in regulatory approval processes related to our services. Our customers often use outside consultants and advisors, which contributes to a longer sales cycle. Most of our potential customers issue an RFP, as part of their consideration of alternatives for their proposed project. In preparation for responding to an RFP, we typically conduct a preliminary audit of the customer’s needs and the opportunity to reduce its energy costs. For projects involving a renewable energy plant that is not located on a customer’s site or that uses sources of energy not within the customer’s control, the sales process also involves the identification of sites with attractive sources of renewable energy, such as a landfill or a favorable site for solar PV, and it may involve obtaining necessary rights and governmental permits to develop a project on that site. If we are awarded a project, we then perform a more detailed audit of the customer’s facilities, which serves as the basis for the final specifications of the project. We then must negotiate and execute a contract with the customer. In addition, we or the customer typically need to obtain financing for the project.
This extended sales process requires the dedication of significant time by our sales and management personnel and our use of significant financial resources, with no certainty of success or recovery of our related expenses. A potential customer may go through the entire sales process and not accept our proposal. All of these factors can contribute to fluctuations in our quarterly financial performance and increase the likelihood that our operating results in a particular quarter will fall below investor expectations. These factors could also adversely affect our business, financial condition and operating results due to increased spending by us that is not offset by increased revenues.

7

Table of Contents                            



We may not recognize all revenues from our backlog or receive all payments anticipated under awarded projects and customer contracts.
As of December 31, 2017, we had backlog of approximately $572.5 million in expected future revenues under signed customer contracts for the installation or construction of projects, which we sometimes refer to as fully-contracted backlog; and we also had been awarded projects for which we do not yet have signed customer contracts with estimated total future revenues of an additional $1,199.0 million. As of December 31, 2016, we had fully-contracted backlog of approximately $534.1 million; and we also had awarded projects for which we had not yet have signed customer contracts with estimated total future revenues of an additional $957.6 million. As of December 31, 2015, we had fully-contracted backlog of approximately $390.4 million; and we also had been awarded projects for which we had not yet signed customer contracts with estimated total future revenues of an additional $955.8 million.
Our customers have the right under some circumstances to terminate contracts or defer the timing of our services and their payments to us. In addition, our government contracts are subject to the risks described below under “Provisions in government contracts may harm our business, financial condition and operating results.” The payment estimates for projects that have been awarded to us but for which we have not yet signed contracts have been prepared by management and are based upon a number of assumptions, including that the size and scope of the awarded projects will not change prior to the signing of customer contracts, that we or our customers will be able to obtain any necessary third-party financing for the awarded projects, and that we and our customers will reach agreement on and execute contracts for the awarded projects. We are not always able to enter into a contract for an awarded project on the terms proposed. As a result, we may not receive all of the revenues that we include in the awarded projects component of our backlog or that we estimate we will receive under awarded projects. If we do not receive all of the revenue we currently expect to receive, our future operating results will be adversely affected. In addition, a delay in the receipt of revenues, even if such revenues are eventually received, may cause our operating results for a particular quarter to fall below our expectations.
Revenue recognition accounting pronouncements may materially adversely affect our reported results of operations.
We continuously review our compliance with all new and existing revenue recognition accounting pronouncements. In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which supersedes nearly all existing revenue recognition guidance. We adopted this guidance and its subsequent amendments effective as of January 1, 2018 using the modified retrospective transition approach beginning with our Quarterly Report on Form 10-Q for the first quarter of 2018. Under this approach, the new standard would apply to all new contracts initiated on or after January 1, 2018. For existing contracts that have remaining obligations as of January 1, 2018, any difference between the recognition criteria in these ASUs and the Company’s current revenue recognition practices would be recognized using a cumulative effect adjustment to the opening balance of retained earnings. Specifically we expect up to a 6 month delay in the timing of revenue recognition related to solar renewable energy credits (“SRECs”) or renewable energy attributes, as well as potential changes in timing of revenue recognition on contracts with uninstalled materials if a significant delay is anticipated between purchasing and installation. See Recent Accounting Pronouncements in Note 2, “Summary of Significant Accounting Policies” to the Consolidated Financial Statements for further information regarding ASU 2014-09.
Our business depends in part on federal, state, provincial and local government support for energy efficiency and renewable energy, and a decline in such support could harm our business.
We depend in part on legislation and government policies that support energy efficiency and renewable energy projects that enhance the economic feasibility of our energy efficiency services and small-scale renewable energy projects. This support includes legislation and regulations that authorize and regulate the manner in which certain governmental entities do business with us; encourage or subsidize governmental procurement of our services; encourage or in some cases require other customers to procure power from renewable or low-emission sources, to reduce their electricity use or otherwise to procure our services; and provide us with tax and other incentives that reduce our costs or increase our revenues. Without this support, on which projects frequently rely for economic feasibility, our ability to complete projects for existing customers and obtain project commitments from new customers could be adversely affected.


8

Table of Contents                            



A substantial portion of our earnings are derived from the sale of solar renewable energy certificates (“SRECs”) and other environmental attributes, and our failure to be able to sell such attributes could materially adversely affect our business, financial condition and results of operation.
    
A substantial portion of our earnings (approximately 25% for fiscal 2017) are attributable to our sale of RECs and other environmental attributes generated by our energy assets. These attributes are used as compliance purposes for state-specific or U.S. federal policy.
We own and operate solar PV installations which derive a significant portion of their revenues from the sale of SRECs, which are produced as a result of generating electricity. The value of these SRECs is determined by the supply and demand of SRECs in the states in which the solar PV installations are installed. Supply is driven by the amount of installations and demand is driven by state-specific laws relating to renewable portfolio standards.
 
We also own and operate renewable natural gas plants that may deliver biofuels into to the nation’s natural gas pipeline grid. Such biofuel may qualify for certain environmental attribute mechanisms, such as renewable identification numbers (“RINs”) which are used for compliance purposes under the Renewable Fuel Standard (“RFS”) program. The RFS is a U.S. federal policy that requires transportation fuel to contain a minimum volume of renewable fuel. The U.S. Environmental Protection Agency (“EPA”) administers the RFS program and may periodically undertake regulatory action involving the RFS, including annual volume standards for renewable fuel.
We sometimes seek to sell forward a portion of our SRECs and other environmental attributes under contracts to fix the revenues from those attributes for financing purposes or hedge against future declines in prices of such environmental attributes. If our renewable energy facilities do not generate the amount of renewable energy attributes sold under such forward contracts or if for any reason the renewable energy we generate does not produce SRECs or other environmental attributes for a particular state, we may be required to make up the shortfall of SRECs or other environmental attributes under such forward contracts through purchases on the open market or make payments of liquidated damages.
RECs are created through state law requirements for utilities to purchase a portion of their energy from renewable energy sources and changes in state laws or regulation relating to RECs may adversely affect the availability of RECs or other environmental attributes and the future prices for RECs or other environmental attributes, which could have an adverse effect on our business, financial condition and results of operations.

A significant decline in the fiscal health of federal, state, provincial and local governments could reduce demand for our energy efficiency and renewable energy projects.

Historically, including for the years ended December 31, 2017, 2016 and 2015, more than 77% of our revenues have been derived from sales to federal, state, provincial or local governmental entities, including public housing authorities and public universities. We expect revenues from this market sector to continue to comprise a significant percentage of our revenues for the foreseeable future. A significant decline in the fiscal health of these existing and potential customers may make it difficult for them to enter into contracts for our services or to obtain financing necessary to fund such contracts, or may cause them to seek to renegotiate or terminate existing agreements with us. In addition, if there is a partial shutdown of any federal, state, provincial or local governing body this may adversely impact our financial performance.
Provisions in our government contracts may harm our business, financial condition and operating results.
A significant majority of our fully-contracted backlog and awarded projects is attributable to customers that are government entities. Our contracts with the federal government and its agencies, and with state, provincial and local governments, customarily contain provisions that give the government substantial rights and remedies, many of which are not typically found in commercial contracts, including provisions that allow the government to:
terminate existing contracts, in whole or in part, for any reason or no reason;
reduce or modify contracts or subcontracts;
decline to award future contracts if actual or apparent organizational conflicts of interest are discovered, or to impose organizational conflict mitigation measures as a condition of eligibility for an award;
suspend or debar the contractor from doing business with the government or a specific government agency; and

9

Table of Contents                            



pursue criminal or civil remedies under the False Claims Act, False Statements Act and similar remedy provisions unique to government contracting.
Under general principles of government contracting law, if the government terminates a contract for convenience, the terminated company may recover only its incurred or committed costs, settlement expenses and profit on work completed prior to the termination. If the government terminates a contract for default, the defaulting company is entitled to recover costs incurred and associated profits on accepted items only and may be liable for excess costs incurred by the government in procuring undelivered items from another source. In most of our contracts with the federal government, the government has agreed to make a payment to us in the event that it terminates the agreement early. The termination payment is designed to compensate us for the cost of construction plus financing costs and profit on the work completed.
In ESPCs for governmental entities, the methodologies for computing energy savings may be less favorable than for non-governmental customers and may be modified during the contract period. We may be liable for price reductions if the projected savings cannot be substantiated.
In addition to the right of the federal government to terminate its contracts with us, federal government contracts are conditioned upon the continuing approval by Congress of the necessary spending to honor such contracts. Congress often appropriates funds for a program on a September 30 fiscal-year basis even though contract performance may take more than one year. Consequently, at the beginning of many major Governmental programs, contracts often may not be fully funded, and additional monies are then committed to the contract only if, as and when appropriations are made by Congress for future fiscal years. Similar practices are likely to also affect the availability of funding for our contracts with Canadian, as well as state, provincial and local government entities. If one or more of our government contracts were terminated or reduced, or if appropriations for the funding of one or more of our contracts is delayed or terminated, our business, financial condition and operating results could be adversely affected.
Our senior credit facility, project financing term loans and construction contain financial and operating restrictions that may limit our business activities and our access to credit.
Provisions in our senior credit facility, project financing term loans and construction loans impose customary restrictions on our and certain of our subsidiaries’ business activities and uses of cash and other collateral. These agreements also contain other customary covenants, including covenants that require us to meet specified financial ratios and financial tests.
We have a $75 million revolving senior secured credit facility that matures June 2020, subject to the quarter end ratio covenant described below. This facility may not be sufficient to meet our needs as our business grows, and we may be unable to extend or replace it on acceptable terms, or at all. Under the revolving credit facility we are required to maintain a maximum ratio of total funded debt to EBITDA (as defined in the agreement) of less than 2.75 to 1.0 as of the end of each fiscal quarter ending September 30, 2016 and thereafter. We are also required to maintain a debt service coverage ratio (as defined in the agreement) of at least 1.5 to 1.0. EBITDA for purposes of the facility excludes the results of certain renewable energy projects that we own and for which financing from others remains outstanding.
In addition, our project financing term loans and construction loans require us to comply with a variety of financial and operational covenants.
Although we do not consider it likely that we will fail to comply with any of these covenants for the next twelve months, we cannot assure that we will be able to do so. Our failure to comply with these covenants may result in the declaration of an event of default and cause us to be unable to borrow under our credit facility. In addition to preventing additional borrowings under this facility, an event of default, if not cured or waived, may result in the acceleration of the maturity of indebtedness outstanding under it or the applicable project financing term loan, which would require us to pay all amounts outstanding. If an event of default occurs, we may not be able to cure it within any applicable cure period, if at all. Certain of our debt agreements also contain subjective acceleration clauses based on a lender deeming that a “material adverse change” in our business has occurred. If these clauses are implicated, and the lender declares that an event of default has occurred, the outstanding indebtedness would likely be immediately due and owing. If the maturity of our indebtedness is accelerated, we may not have sufficient funds available for repayment or we may not have the ability to borrow or obtain sufficient funds to replace the accelerated indebtedness on terms acceptable to us or at all.

10

Table of Contents                            



The projects we undertake for our customers generally require significant capital, which our customers or we may finance through third parties, and such financing may not be available to our customers or to us on favorable terms, if at all.
Our projects for customers are typically financed by third parties. For small-scale renewable energy plants that we own, we typically rely on a combination of our working capital and debt to finance construction costs. If we or our customers are unable to raise funds on acceptable terms when needed, we may be unable to secure customer contracts, the size of contracts we do obtain may be smaller or we could be required to delay the development and construction of projects, reduce the scope of those projects or otherwise restrict our operations. Any inability by us or our customers to raise the funds necessary to finance our projects could materially harm our business, financial condition and operating results.
Project development or construction activities may not be successful, and we may make significant investments without first obtaining project financing, which could increase our costs and impair our ability to recover our investments.
The development and construction of small-scale renewable energy plants and other energy infrastructure projects involve numerous risks. We may be required to spend significant sums for preliminary engineering, permitting, legal and other expenses before we can determine whether a project is feasible, economically attractive or capable of being built. In addition, we will often choose to bear the costs of such efforts prior to obtaining project financing, prior to getting final regulatory approval and prior to our final sale to a customer, if any.
Successful completion of a particular project may be adversely affected by numerous factors, including: failures or delays in obtaining desired or necessary land rights, including ownership, leases and/or easements; failures or delays in obtaining necessary permits, licenses or other governmental support or approvals, or in overcoming objections from members of the public or adjoining land owners; uncertainties relating to land costs for projects; unforeseen engineering problems; access to available transmission for electricity generated by our small-scale renewable energy plants; construction delays and contractor performance shortfalls; work stoppages or labor disruptions and compliance with labor regulations; cost over-runs; availability of products and components from suppliers; adverse weather conditions; environmental, archaeological and geological conditions; and availability of construction and permanent financing.
If we are unable to complete the development of a small-scale renewable energy plants or fail to meet one or more agreed target construction milestone dates, we may be subject to liquidated damages and/or penalties under the Engineering Procurement and Construction agreement or other agreements relating to the power plant or project, and we typically will not be able to recover our investment in the project. We expect to invest a significant amount of capital to develop projects whether owned by us or by third parties. If we are unable to complete the development of a project, we may write-down or write-off some or all of these capitalized investments, which would have an adverse impact on our net income in the period in which the loss is recognized.
Our business is affected by seasonal trends and construction cycles, and these trends and cycles could have an adverse effect on our operating results.
We are subject to seasonal fluctuations and construction cycles, particularly in climates that experience colder weather during the winter months, such as the northern United States and Canada, or at educational institutions, where large projects are typically carried out during summer months when their facilities are unoccupied. In addition, government customers, many of which have fiscal years that do not coincide with ours, typically follow annual procurement cycles and appropriate funds on a fiscal-year basis even though contract performance may take more than one year. Further, government contracting cycles can be affected by the timing of, and delays in, the legislative process related to government programs and incentives that help drive demand for energy efficiency and renewable energy projects. As a result, our revenues and operating income in the third and fourth quarter are typically higher, and our revenues and operating income in the first quarter are typically lower, than in other quarters of the year. As a result of such fluctuations, we may occasionally experience declines in revenue or earnings as compared to the immediately preceding quarter, and comparisons of our operating results on a period-to-period basis may not be meaningful.
We may have exposure to additional tax liabilities and our effective tax rate may increase or fluctuate, which could increase our income tax expense and reduce our net income.
Our provision for income taxes is subject to volatility and could be adversely affected by changes in tax laws or regulations, particularly changes in tax incentives in support of energy efficiency. For example, certain deductions relating to energy efficiency have expiration dates which could significantly alter the existing tax code, including the removal of these credits prior to their scheduled expiration. The 30% investment tax credit (“ITC”) relating to the installation of solar power was

11

Table of Contents                            



extended through 2019, after which it will fall to 26 percent in 2020, 22 percent in 2021, and 10 percent in 2022 and future years. If these or other deductions and credits expire without being extended, or otherwise are reduced or eliminated, our effective tax rate would increase, which could increase our income tax expense and reduce our net income.
Our tax rate has historically been significantly impacted by the IRC Section 179D deduction. This deduction is related to energy efficient improvements we provide under government contracts. Section 179D was extended through December 31, 2017 as part of the Bipartisan Budget Act which became law on February 9, 2018. There is no assurance that Section 179D will continue to be extended retroactively or otherwise and were the deduction not available it would significantly affect our tax rate.
In addition, like other companies, we may be subject to examination of our income tax returns by the U.S. Internal Revenue Service and other tax authorities; our U.S. federal tax returns for 2014 through 2016 are subject to audit by federal, state and foreign tax authorities. Though we regularly assess the likelihood of adverse outcomes from such examinations and the adequacy of our provision for income taxes, there can be no assurance that such provision is sufficient and that a determination by a tax authority will not have an adverse effect on our net income.
Changes in the laws and regulations governing the public procurement of ESPCs could have a material impact on our business.
We derive a significant amount of our revenue from ESPCs with our government customers. While federal, state and local government rules governing such contracts vary, such rules may, for example, permit the funding of such projects through long-term financing arrangements; permit long-term payback periods from the savings realized through such contracts; allow units of government to exclude debt related to such projects from the calculation of their statutory debt limitation; allow for award of contracts on a “best value” instead of “lowest cost” basis; and allow for the use of sole source providers. To the extent these rules become more restrictive in the future, our business could be harmed.
Failure of third parties to manufacture quality products or provide reliable services in a timely manner could cause delays in the delivery of our services and completion of our projects, which could damage our reputation, have a negative impact on our relationships with our customers and adversely affect our growth.
Our success depends on our ability to provide services and complete projects in a timely manner, which in part depends on the ability of third parties to provide us with timely and reliable products and services. In providing our services and completing our projects, we rely on products that meet our design specifications and components manufactured and supplied by third parties, as well as on services performed by subcontractors.We also rely on subcontractors to perform substantially all of the construction and installation work related to our projects; and we often need to engage subcontractors with whom we have no experience for our projects.
If any of our subcontractors are unable to provide services that meet or exceed our customers’ expectations or satisfy our contractual commitments, our reputation, business and operating results could be harmed. In addition, if we are unable to avail ourselves of warranty and other contractual protections with providers of products and services, we may incur liability to our customers or additional costs related to the affected products and components, which could have a material adverse effect on our business, financial condition and operating results. Moreover, any delays, malfunctions, inefficiencies or interruptions in these products or services could adversely affect the quality and performance of our solutions and require considerable expense to establish alternate sources for such products and services. This could cause us to experience difficulty retaining current customers and attracting new customers, and could harm our brand, reputation and growth.
We may have liability to our customers under our ESPCs if our projects fail to deliver the energy use reductions to which we are committed under the contract.
For our energy efficiency projects, we typically enter into ESPCs under which we commit that the projects will satisfy agreed-upon performance standards appropriate to the project. These commitments are typically structured as guarantees of increased energy efficiency that are based on the design, capacity, efficiency or operation of the specific equipment and systems we install. Our commitments generally fall into three categories: pre-agreed, equipment-level and whole building-level. Under a pre-agreed efficiency commitment, our customer reviews the project design in advance and agrees that, upon or shortly after completion of installation of the specified equipment comprising the project, the pre-agreed increase in energy efficiency will have been met. Under an equipment-level commitment, we commit to a level of increased energy efficiency based on the difference in use measured first with the existing equipment and then with the replacement equipment upon completion of installation. A whole building-level commitment requires future measurement and verification of increased energy efficiency

12

Table of Contents                            



for a whole building, often based on readings of the utility meter where usage is measured. Depending on the project, the measurement and verification may be required only once, upon installation, based on an analysis of one or more sample installations, or may be required to be repeated at agreed upon intervals generally over periods of up to 20 years.
Under our contracts, we typically do not take responsibility for a wide variety of factors outside our control and exclude or adjust for such factors in commitment calculations. These factors include variations in energy prices and utility rates, weather, facility occupancy schedules, the amount of energy-using equipment in a facility, and failure of the customer to operate or maintain the project properly. We rely in part on warranties from our equipment suppliers and subcontractors to back-stop the warranties we provide to our customers and, where appropriate, pass on the warranties to our customers. However, the warranties we provide to our customers are sometimes broader in scope or longer in duration than the corresponding warranties we receive from our suppliers and subcontractors, and we bear the risk for any differences, as well as the risk of warranty default by our suppliers and subcontractors.
Typically, our performance commitments apply to the aggregate overall performance of a project rather than to individual energy efficiency measures. Therefore, to the extent an individual measure underperforms, it may be offset by other measures that overperform during the same period. In the event that an energy efficiency project does not perform according to the agreed-upon specifications, our agreements typically allow us to satisfy our obligation by adjusting or modifying the installed equipment, installing additional measures to provide substitute energy savings, or paying the customer for lost energy savings based on the assumed conditions specified in the agreement. However, we may incur additional or increased liabilities or expenses under our ESPCs in the future. Such liabilities or expenses could be substantial, and they could materially harm our business, financial condition or operating results. In addition, any disputes with a customer over the extent to which we bear responsibility to improve performance or make payments to the customer may diminish our prospects for future business from that customer or damage our reputation in the marketplace.
We may assume responsibility under customer contracts for factors outside our control, including, in connection with some customer projects, the risk that fuel prices will increase.
We typically do not take responsibility under our contracts for a wide variety of factors outside our control. We have, however, in a limited number of contracts assumed some level of risk and responsibility for certain factors — sometimes only to the extent that variations exceed specified thresholds — and may also do so under certain contracts in the future, particularly in our contracts for renewable energy projects. For example, under a contract for the construction and operation of a cogeneration facility at the U.S. Department of Energy Savannah River Site in South Carolina, a subsidiary of ours is exposed to the risk that the price of the biomass that will be used to fuel the cogeneration facility may rise during the 19-year performance period of the contract. Several provisions in that contract mitigate the price risk. In addition, although we typically structure our contracts so that our obligation to supply a customer with LFG, electricity or steam, for example, does not exceed the quantity produced by the production facility, in some circumstances we may commit to supply a customer with specified minimum quantities based on our projections of the facility’s production capacity. In such circumstances, if we are unable to meet such commitments, we may be required to incur additional costs or face penalties. Despite the steps we have taken to mitigate risks under these and other contracts, such steps may not be sufficient to avoid the need to incur increased costs to satisfy our commitments, and such costs could be material. Increased costs that we are unable to pass through to our customers could have a material adverse effect on our operating results.
Our business depends on experienced and skilled personnel and substantial specialty subcontractor resources, and if we lose key personnel or if we are unable to attract and integrate additional skilled personnel, it will be more difficult for us to manage our business and complete projects.
The success of our business and construction projects depend in large part on the skill of our personnel and on trade labor resources, including with certain specialty subcontractor skills. Competition for personnel, particularly those with expertise in the energy services and renewable energy industries, is high. In the event we are unable to attract, hire and retain the requisite personnel and subcontractors, we may experience delays in completing projects in accordance with project schedules and budgets. Further, any increase in demand for personnel and specialty subcontractors may result in higher costs, causing us to exceed the budget on a project. Either of these circumstances may have an adverse effect on our business, financial condition and operating results, harm our reputation among and relationships with our customers and cause us to curtail our pursuit of new projects.
Our future success is particularly dependent on the vision, skills, experience and effort of our senior management team, including our executive officers and our founder, principal stockholder, president and chief executive officer, George P.

13

Table of Contents                            



Sakellaris. If we were to lose the services of any of our executive officers or key employees, our ability to effectively manage our operations and implement our strategy could be harmed and our business may suffer.
If we cannot obtain surety bonds and letters of credit, our ability to operate may be restricted.
Federal and state laws require us to secure the performance of certain long-term obligations through surety bonds and letters of credit. In addition, we are occasionally required to provide bid bonds or performance bonds to secure our performance under energy efficiency contracts. In the future, we may have difficulty procuring or maintaining surety bonds or letters of credit, and obtaining them may become more expensive, require us to post cash collateral or otherwise involve unfavorable terms. Because we are sometimes required to have performance bonds or letters of credit in place before projects can commence or continue, our failure to obtain or maintain those bonds and letters of credit would adversely affect our ability to begin and complete projects, and thus could have a material adverse effect on our business, financial condition and operating results.
We operate in a highly competitive industry, and our current or future competitors may be able to compete more effectively than we do, which could have a material adverse effect on our business, revenues, growth rates and market share.
Our industry is highly competitive, with many companies of varying size and business models, many of which have their own proprietary technologies, competing for the same business as we do. Many of our competitors have longer operating histories and greater resources than us, and could focus their substantial financial resources to develop a competitive advantage. Our competitors may also offer energy solutions at prices below cost, devote significant sales forces to competing with us or attempt to recruit our key personnel by increasing compensation, any of which could improve their competitive positions. Any of these competitive factors could make it more difficult for us to attract and retain customers, cause us to lower our prices in order to compete, and reduce our market share and revenues, any of which could have a material adverse effect on our financial condition and operating results. We can provide no assurance that we will continue to effectively compete against our current competitors or additional companies that may enter our markets.
In addition, we may also face competition based on technological developments that reduce demand for electricity, increase power supplies through existing infrastructure or that otherwise compete with our products and services. We also encounter competition in the form of potential customers electing to develop solutions or perform services internally rather than engaging an outside provider such as us.
We may be unable to complete or operate our projects on a profitable basis or as we have committed to our customers.
Development, installation and construction of our energy efficiency and renewable energy projects, and operation of our renewable energy projects, entails many risks, including:
failure to receive critical components and equipment that meet our design specifications and can be delivered on schedule;
failure to obtain all necessary rights to land access and use;
failure to receive quality and timely performance of third-party services;
increases in the cost of labor, equipment and commodities needed to construct or operate projects;
permitting and other regulatory issues, license revocation and changes in legal requirements;
shortages of equipment or skilled labor;
unforeseen engineering problems;
failure of a customer to accept or pay for renewable energy that we supply;
weather interferences, catastrophic events including fires, explosions, earthquakes, droughts and acts of terrorism; and accidents involving personal injury or the loss of life;
labor disputes and work stoppages;
mishandling of hazardous substances and waste; and
other events outside of our control.

14

Table of Contents                            



Any of these factors could give rise to construction delays and construction and other costs in excess of our expectations. This could prevent us from completing construction of our projects, cause defaults under our financing agreements or under contracts that require completion of project construction by a certain time, cause projects to be unprofitable for us, or otherwise impair our business, financial condition and operating results.
Our small-scale renewable energy plants may not generate expected levels of output.
The small-scale renewable energy plants that we construct and own are subject to various operating risks that may cause them to generate less than expected amounts of processed LFG, electricity or thermal energy. These risks include a failure or degradation of our, our customers’ or utilities’ equipment; an inability to find suitable replacement equipment or parts; less than expected supply of the plant’s source of renewable energy, such as LFG or biomass; or a faster than expected diminishment of such supply. Any extended interruption in the plant’s operation, or failure of the plant for any reason to generate the expected amount of output, could have a material adverse effect on our business and operating results. In addition, we have in the past, and could in the future, incur material asset impairment charges if any of our renewable energy plants incurs operational issues that indicate that our expected future cash flows from the plant are less than its carrying value. Any such impairment charge could have a material adverse effect on our operating results in the period in which the charge is recorded.
We have not entered into offtake agreements for certain of our small-scale renewable energy plants.

We have not entered into long-term offtake agreements for a minor portion of our small-scale renewable energy plants, particularly LFG plants, and we are required to sell the processed LFG or electricity produced by the facility at wholesale prices, which are exposed to market fluctuations and risks. The failure to sell such processed LFG or electricity at a favorable price could have a material adverse effect on our business and operating results.

We may not be able to replace expiring offtake agreements with contracts on similar terms. If we are unable to replace an expired offtake agreement with an acceptable new contract, we may be required to remove the small-scale renewable energy plant from the site or, alternatively, we may sell the assets to the customer.
We may not be able to replace an expiring offtake agreement with a contract on equivalent terms and conditions, including at prices that permit operation of the related facility on a profitable basis. If we are unable to replace an expiring offtake agreement with an acceptable new revenue contract, the affected site may temporarily or permanently cease operations or we may be required to sell the power produced by the facility at wholesale prices which are exposed to market fluctuations and risks. In the case of a solar photovoltaic installation that ceases operations, the offtake agreement terms generally require that we remove the assets, including fixing or reimbursing the site owner for any damages caused by the assets or the removal of such assets. Alternatively, we may agree to sell the assets to the site owner, but the terms and conditions, including price, that we would receive in any sale, and the sale price may not be sufficient to replace the revenue previously generated by the small-scale renewable energy plant.

We plan to expand our business in part through future acquisitions, but we may not be able to identify or complete suitable acquisitions.

Historically, acquisitions have been a significant part of our growth strategy. We plan to continue to use acquisitions of companies or assets to expand our project skill-sets and capabilities, expand our geographic markets, add experienced management and increase our product and service offerings. However, we may be unable to implement this growth strategy if we cannot identify suitable acquisition candidates, reach agreement with acquisition targets on acceptable terms or arrange required financing for acquisitions on acceptable terms. In addition, the time and effort involved in attempting to identify acquisition candidates and consummate acquisitions may divert members of our management from the operations of our company.
Any future acquisitions that we may make could disrupt our business, cause dilution to our stockholders and harm our business, financial condition or operating results.
If we are successful in consummating acquisitions, those acquisitions could subject us to a number of risks, including:
the purchase price we pay could significantly deplete our cash reserves or result in dilution to our existing stockholders;
we may find that the acquired company or assets do not improve our customer offerings or market position as planned;

15

Table of Contents                            



we may have difficulty integrating the operations and personnel of the acquired company;
key personnel and customers of the acquired company may terminate their relationships with the acquired company as a result of the acquisition;
we may experience additional financial and accounting challenges and complexities in areas such as tax planning and financial reporting;
we may incur additional costs and expenses related to complying with additional laws, rules or regulations in new jurisdictions;
we may assume or be held liable for risks and liabilities (including for environmental-related costs) as a result of our acquisitions, some of which we may not discover during our due diligence or adequately adjust for in our acquisition arrangements;
our ongoing business and management’s attention may be disrupted or diverted by transition or integration issues and the complexity of managing geographically or culturally diverse enterprises;
we may incur one-time write-offs or restructuring charges in connection with the acquisition;
we may acquire goodwill and other intangible assets that are subject to amortization or impairment tests, which could result in future charges to earnings; and
we may not be able to realize the cost savings or other financial benefits we anticipated.
These factors could have a material adverse effect on our business, financial condition and operating results.
We may be required to write-off or impair capitalized costs or intangible assets in the future or we may incur restructuring costs or other charges, each of which could harm our earnings.
In accordance with generally accepted accounting principles in the United States, we capitalize certain expenditures and advances relating to our acquisitions, pending acquisitions, project development costs, interest costs related to project financing and certain energy assets. In addition, we have considerable unamortized assets. From time to time in future periods, we may be required to incur a charge against earnings in an amount equal to any unamortized capitalized expenditures and advances, net of any portion thereof that we estimate will be recoverable, through sale or otherwise, relating to: (i) any operation or other asset that is being sold, permanently shut down, impaired or has not generated or is not expected to generate sufficient cash flow; (ii) any pending acquisition that is not consummated; (iii) any project that is not expected to be successfully completed; and (iv) any goodwill or other intangible assets that are determined to be impaired.
In response to such charges and costs and other market factors, we may be required to implement restructuring plans in an effort to reduce the size and cost of our operations and to better match our resources with our market opportunities. As a result of such actions, we would expect to incur restructuring expenses and accounting charges which may be material. Several factors could cause a restructuring to adversely affect our business, financial condition and results of operations. These include potential disruption of our operations, the development of our small-scale renewable energy projects and other aspects of our business. Employee morale and productivity could also suffer and result in unintended employee attrition. Any restructuring would require substantial management time and attention and may divert management from other important work. Moreover, we could encounter delays in executing any restructuring plans, which could cause further disruption and additional unanticipated expense.
See also Note 2, “Summary of Significant Accounting Policies” and Note 4, “Goodwill and Intangible Assets”, to our Consolidated Financial Statements appearing in Item 8 of this Annual Report on Form 10-K.
We need governmental approvals and permits, and we typically must meet specified qualifications, in order to undertake our energy efficiency projects and construct, own and operate our small-scale renewable energy projects, and any failure to do so would harm our business.
The design, construction and operation of our energy efficiency and small-scale renewable energy projects require various governmental approvals and permits, and may be subject to the imposition of related conditions that vary by jurisdiction. In some cases, these approvals and permits require periodic renewal. We cannot predict whether all permits required for a given project will be granted or whether the conditions associated with the permits will be achievable. The denial of a permit essential to a project or the imposition of impractical conditions would impair our ability to develop the project. In addition, we cannot

16

Table of Contents                            



predict whether the permits will attract significant opposition or whether the permitting process will be lengthened due to complexities and appeals. Delay in the review and permitting process for a project can impair or delay our ability to develop that project or increase the cost so substantially that the project is no longer attractive to us. We have experienced delays in developing our projects due to delays in obtaining permits and may experience delays in the future. If we were to commence construction in anticipation of obtaining the final, non-appealable permits needed for that project, we would be subject to the risk of being unable to complete the project if all the permits were not obtained. If this were to occur, we would likely lose a significant portion of our investment in the project and could incur a loss as a result. Further, the continued operations of our projects require continuous compliance with permit conditions. This compliance may require capital improvements or result in reduced operations. Any failure to procure, maintain and comply with necessary permits would adversely affect ongoing development, construction and continuing operation of our projects.
In addition, the projects we perform for governmental agencies are governed by particular qualification and contracting regimes. Certain states require qualification with an appropriate state agency as a precondition to performing work or appearing as a qualified energy service provider for state, county and local agencies within the state. For example, the Commonwealth of Massachusetts and the states of Colorado and Washington pre-qualify energy service providers and provide contract documents that serve as the starting point for negotiations with potential governmental clients. Most of the work that we perform for the federal government is performed under IDIQ agreements between a government agency and us or a subsidiary. These IDIQ agreements allow us to contract with the relevant agencies to implement energy projects, but no work may be performed unless we and the agency agree on a task order or delivery order governing the provision of a specific project. The government agencies enter into contracts for specific projects on a competitive basis. We and our subsidiaries and affiliates are currently party to two IDIQ agreements with the U.S. Department of Energy expiring in 2019 and in 2022, respectively. We are also party to similar agreements with other federal agencies, including the U.S. Army Corps of Engineers and the U.S. General Services Administration. If we are unable to maintain or renew our IDIQ qualification under the U.S. Department of Energy program for ESPCs, or similar federal or state qualification regimes, our business could be materially harmed. We are also party to similar agreements with other federal agencies, including the U.S. Army Corps of Engineers and the U.S. General Services Administration.
If we are unable to maintain or renew our IDIQ qualification under the U.S. Department of Energy program for ESPCs, or similar federal or state qualification regimes, our business could be materially harmed.
Many of our small-scale renewable energy projects are, and other future projects may be, subject to or affected by U.S. federal energy regulation or other regulations that govern the operation, ownership and sale of the facility, or the sale of electricity from the facility.
PUHCA and the FPA regulate public utility holding companies and their subsidiaries and place constraints on the conduct of their business. The FPA regulates wholesale sales of electricity and the transmission of electricity in interstate commerce by public utilities. Under PURPA, all of our current small-scale renewable energy projects are small power “qualifying facilities” (facilities meeting statutory size, fuel and filing requirements) that are exempt from regulations under PUHCA, most provisions of the FPA and state rate and financial regulation. None of our renewable energy projects are currently subject to rate regulation for wholesale power sales by the Federal Energy Regulatory Commission (“FERC”) under the FPA, but certain of our projects that are under construction or development could become subject to such regulation in the future. Also, we may acquire interests in or develop generating projects that are not qualifying facilities. Non-qualifying facility projects would be fully subject to FERC corporate and rate regulation, and would be required to obtain FERC acceptance of their rate schedules for wholesale sales of energy, capacity and ancillary services, which requires substantial disclosures to and discretionary approvals from FERC. FERC may revoke or revise an entity’s authorization to make wholesale sales at negotiated, or market-based, rates if FERC determines that we can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions or market manipulation. In addition, many public utilities (including any non-qualifying facility generator in which we may invest) are subject to FERC reporting requirements that impose administrative burdens and that, if violated, can expose the company to civil penalties or other risks.
All of our wholesale electric power sales are subject to certain market behavior rules. These rules change from time to time, by virtue of FERC rulemaking proceedings and FERC-ordered amendments to utilities’ or power pools’ FERC tariffs. If we are deemed to have violated these rules, we will be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of our market-based rate authority, as well as potential criminal and civil penalties. If we were to lose market-based rate authority for any non-qualifying facility project we may acquire or develop in the future, we would be required to obtain FERC’s acceptance of a cost-based rate schedule and could become subject to, among other things, the

17

Table of Contents                            



burdensome accounting, record keeping and reporting requirements that are imposed on public utilities with cost-based rate schedules. This could have an adverse effect on the rates we charge for power from our projects and our cost of regulatory compliance.
Wholesale electric power sales are subject to increasing regulation. The terms and conditions for power sales, and the right to enter and remain in the wholesale electric sector, are subject to FERC oversight. Due to major regulatory restructuring initiatives at the federal and state levels, the U.S. electric industry has undergone substantial changes over the past decade. We cannot predict the future design of wholesale power markets or the ultimate effect ongoing regulatory changes will have on our business. Other proposals to further regulate the sector may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the movement towards competitive markets.
If we become subject to additional regulation under PUHCA, FPA or other regulatory frameworks, if existing regulatory requirements become more onerous, or if other material changes to the regulation of the electric power markets take place, our business, financial condition and operating results could be adversely affected.
Compliance with environmental laws could adversely affect our operating results.
Costs of compliance with federal, state, provincial, local and other foreign existing and future environmental regulations could adversely affect our cash flow and profitability. We are required to comply with numerous environmental laws and regulations and to obtain numerous governmental permits in connection with energy efficiency and renewable energy projects, and we may incur significant additional costs to comply with these requirements. If we fail to comply with these requirements, we could be subject to civil or criminal liability, damages and fines. Existing environmental regulations could be revised or reinterpreted and new laws and regulations could be adopted or become applicable to us or our projects, and future changes in environmental laws and regulations could occur. These factors may materially increase the amount we must invest to bring our projects into compliance and impose additional expense on our operations.
In addition, private lawsuits or enforcement actions by federal, state, provincial and/or foreign regulatory agencies may materially increase our costs. Certain environmental laws make us potentially liable on a joint and several basis for the remediation of contamination at or emanating from properties or facilities we currently or formerly owned or operated or properties to which we arranged for the disposal of hazardous substances. Such liability is not limited to the cleanup of contamination we actually caused. Although we seek to obtain indemnities against liabilities relating to historical contamination at the facilities we own or operate, we cannot provide any assurance that we will not incur liability relating to the remediation of contamination, including contamination we did not cause.
We may not be able to obtain or maintain, from time to time, all required environmental regulatory approvals. A delay in obtaining any required environmental regulatory approvals or failure to obtain and comply with them could adversely affect our business and operating results.
International expansion is one of our growth strategies, and international operations will expose us to additional risks that we do not face in the United States, which could have an adverse effect on our operating results.
We generate a portion of our revenues from operations in Canada and the U.K., and although we are engaged in overseas projects for the U.S. Department of Defense, we currently derive a small amount of revenues from outside of North America. However, international expansion is one of our growth strategies, and we expect our revenues and operations outside of North America will expand in the future. These operations will be subject to a variety of risks that we do not face in the United States, and that we may face only to a limited degree in Canada, including:
building and managing highly experienced foreign workforces and overseeing and ensuring the performance of foreign subcontractors;
increased travel, infrastructure and legal and compliance costs associated with multiple international locations;
additional withholding taxes or other taxes on our foreign income, and tariffs or other restrictions on foreign trade or investment;
imposition of, or unexpected adverse changes in, foreign laws or regulatory requirements, many of which differ from those in the United States;
increased exposure to foreign currency exchange rate risk;

18

Table of Contents                            



longer payment cycles for sales in some foreign countries and potential difficulties in enforcing contracts and collecting accounts receivable;
difficulties in repatriating overseas earnings;
general economic conditions in the countries in which we operate; and
political unrest, war, incidents of terrorism, or responses to such events.
Our overall success in international markets will depend, in part, on our ability to succeed in differing legal, regulatory, economic, social and political conditions. We may not be successful in developing and implementing policies and strategies that will be effective in managing these risks in each country where we do business. Our failure to manage these risks successfully could harm our international operations, reduce our international sales and increase our costs, thus adversely affecting our business, financial condition and operating results.
Changes in utility regulation and tariffs could adversely affect our business.
Our business is affected by regulations and tariffs that govern the activities and rates of utilities. For example, utility companies are commonly allowed by regulatory authorities to charge fees to some business customers for disconnecting from the electric grid or for having the capacity to use power from the electric grid for back-up purposes. These fees could increase the cost to our customers of taking advantage of our services and make them less desirable, thereby harming our business, financial condition and operating results. Our current generating projects are all operated as qualifying facilities. FERC regulations under the FPA confer upon these facilities key rights to interconnection with local utilities, and can entitle qualifying facilities to enter into power purchase agreements with local utilities, from which the qualifying facilities benefit. Changes to these federal laws and regulations could increase our regulatory burdens and costs, and could reduce our revenues. State regulatory agencies could award renewable energy certificates or credits that our electric generation facilities produce to our power purchasers, thereby reducing the power sales revenues we otherwise would earn. In addition, modifications to the pricing policies of utilities could require renewable energy systems to charge lower prices in order to compete with the price of electricity from the electric grid and may reduce the economic attractiveness of certain energy efficiency measures.
Some of the demand-reduction services we provide for utilities and institutional clients are subject to regulatory tariffs imposed under federal and state utility laws. In addition, the operation of, and electrical interconnection for, our renewable energy projects are subject to federal, state or provincial interconnection and federal reliability standards that are also set forth in utility tariffs. These tariffs specify rules, business practices and economic terms to which we are subject. The tariffs are drafted by the utilities and approved by the utilities’ state and federal regulatory commissions. These tariffs change frequently and it is possible that future changes will increase our administrative burden or adversely affect the terms and conditions under which we render service to our customers.
Our activities and operations are subject to numerous health and safety laws and regulations, and if we violate such regulations, we could face penalties and fines.
We are subject to numerous health and safety laws and regulations in each of the jurisdictions in which we operate. These laws and regulations require us to obtain and maintain permits and approvals and implement health and safety programs and procedures to control risks associated with our projects. Compliance with those laws and regulations can require us to incur substantial costs. Moreover, if our compliance programs are not successful, we could be subject to penalties or to revocation of our permits, which may require us to curtail or cease operations of the affected projects. Violations of laws, regulations and permit requirements may also result in criminal sanctions or injunctions.
Health and safety laws, regulations and permit requirements may change or become more stringent. Any such changes could require us to incur materially higher costs than we currently have. Our costs of complying with current and future health and safety laws, regulations and permit requirements, and any liabilities, fines or other sanctions resulting from violations of them, could adversely affect our business, financial condition and operating results.
We are subject to various privacy and consumer protection laws.
Our privacy policy is posted on our website, and any failure by us or our vendor or other business partners to comply with it or with federal, state or international privacy, data protection or security laws or regulations could result in regulatory or litigation-related actions against us, legal liability, fines, damages and other costs. We may also incur substantial expenses and costs in connection with maintaining compliance with such laws. For example, commencing in May 2018, the General Data Protection Regulation (the “GDPR”) will fully apply to the processing of personal information collected from individuals

19

Table of Contents                            



located in the European Union. The GDPR will create new compliance obligations and will significantly increase fines for noncompliance. Although we take steps to protect the security of our customers’ personal information, we may be required to expend significant resources to comply with data breach requirements if third parties improperly obtain and use the personal information of our customers or we otherwise experience a data loss with respect to customers’ personal information. A major breach of our network security and systems could have negative consequences for our business and future prospects, including possible fines, penalties and damages, reduced customer demand for our vehicles, and harm to our reputation and brand.
If our subsidiaries default on their obligations under their debt instruments, we may need to make payments to lenders to prevent foreclosure on the collateral securing the debt.
We typically set up subsidiaries to own and finance our renewable energy projects. These subsidiaries incur various types of debt which can be used to finance one or more projects. This debt is typically structured as non-recourse debt, which means it is repayable solely from the revenues from the projects financed by the debt and is secured by such projects’ physical assets, major contracts and cash accounts and a pledge of our equity interests in the subsidiaries involved in the projects. Although our subsidiary debt is typically non-recourse to Ameresco, if a subsidiary of ours defaults on such obligations, or if one project out of several financed by a particular subsidiary’s indebtedness encounters difficulties or is terminated, then we may from time to time determine to provide financial support to the subsidiary in order to maintain rights to the project or otherwise avoid the adverse consequences of a default. In the event a subsidiary defaults on its indebtedness, its creditors may foreclose on the collateral securing the indebtedness, which may result in our losing our ownership interest in some or all of the subsidiary’s assets. The loss of our ownership interest in a subsidiary or some or all of a subsidiary’s assets could have a material adverse effect on our business, financial condition and operating results.
We are exposed to the credit risk of some of our customers.
Most of our revenues are derived under multi-year or long-term contracts with our customers, and our revenues are therefore dependent to a large extent on the creditworthiness of our customers. During periods of economic downturn, our exposure to credit risks from our customers increases, and our efforts to monitor and mitigate the associated risks may not be effective in reducing our credit risks. In the event of non-payment by one or more of our customers, our business, financial condition and operating results could be adversely affected.
Fluctuations in foreign currency exchange rates can impact our results.
A portion of our total revenues are generated by our Canadian and U.K. subsidiaries. Changes in exchange rates between the Canadian dollar and the U.S. dollar, as well as the British pound sterling and the U.S. dollar, may adversely affect our operating results.
A failure of our information technology (“IT”) and data security infrastructure could adversely impact our business and operations.
We rely upon the capacity, reliability and security of our IT and data security infrastructure and our ability to expand and continually update this infrastructure in response to the changing needs of our business. As we implement new systems, they may not perform as expected. We also face the challenge of supporting our older systems and implementing necessary upgrades. If we experience a problem with the functioning of an important IT system or a security breach of our IT systems, including during system upgrades and/or new system implementations, the resulting disruptions could have an adverse effect on our business.
We and certain of our third-party vendors receive and store personal information in connection with our human resources operations and other aspects of our business. Despite our implementation of security measures, our IT systems, like those of other companies, are vulnerable to damages from computer viruses, natural disasters, unauthorized access, cyber attack and other similar disruptions, and we have experienced such incidents in the past. Any system failure, accident or security breach could result in disruptions to our operations. A material network breach in the security of our IT systems could include the theft of our intellectual property, trade secrets, customer information, human resources information or other confidential matter. Although past incidents have not had a material impact on our business operations or financial performance, to the extent that any disruptions or security breach results in a loss or damage to our data, or an inappropriate disclosure of confidential, proprietary or customer information, it could cause significant damage to our reputation, affect our relationships with our customers, lead to claims against the Company and ultimately harm our business. In addition, we may be required to incur significant costs to protect against damage caused by these disruptions or security breaches in the future.

20

Table of Contents                            



Risks Related to Ownership of Our Class A Common Stock
The trading price of our Class A common stock is volatile.
The trading price of our Class A common stock is volatile and could be subject to wide fluctuations. In addition, if the stock market in general experiences a significant decline, the trading price of our Class A common stock could decline for reasons unrelated to our business, financial condition or operating results. Some companies that have had volatile market prices for their securities have had securities class actions filed against them. If a suit were filed against us, regardless of its merits or outcome, it would likely result in substantial costs and divert management’s attention and resources. This could have a material adverse effect on our business, operating results and financial condition.
Holders of our Class A common stock are entitled to one vote per share, and holders of our Class B common stock are entitled to five votes per share. The lower voting power of our Class A common stock may negatively affect the attractiveness of our Class A common stock to investors and, as a result, its market value.
We have two classes of common stock: Class A common stock, which is listed on the NYSE and which is entitled to one vote per share, and Class B common stock, which is not listed on the any security exchange and is entitled to five votes per share. The difference in the voting power of our Class A and Class B common stock could diminish the market value of our Class A common stock because of the superior voting rights of our Class B common stock and the power those rights confer.
For the foreseeable future, Mr. Sakellaris or his affiliates will be able to control the selection of all members of our board of directors, as well as virtually every other matter that requires stockholder approval, which will severely limit the ability of other stockholders to influence corporate matters.
Except in certain limited circumstances required by applicable law, holders of Class A and Class B common stock vote together as a single class on all matters to be voted on by our stockholders. Mr. Sakellaris, our founder, principal stockholder, president and chief executive officer, owns all of our Class B common stock, which, together with his Class A common stock, represents approximately 80% of the combined voting power of our outstanding Class A and Class B common stock. Under our restated certificate of incorporation, holders of shares of Class B common stock may generally transfer those shares to family members, including spouses and descendants or the spouses of such descendants, as well as to affiliated entities, without having the shares automatically convert into shares of Class A common stock. Therefore, Mr. Sakellaris, his affiliates, and his family members and descendants will, for the foreseeable future, be able to control the outcome of the voting on virtually all matters requiring stockholder approval, including the election of directors and significant corporate transactions such as an acquisition of our company, even if they come to own, in the aggregate, as little as 20% of the economic interest of the outstanding shares of our Class A and Class B common stock. Moreover, these persons may take actions in their own interests that you or our other stockholders do not view as beneficial.
Though we may repurchase shares of our Class A common stock pursuant to our recently announced share repurchase program, we are not obligated to do so and if we do, we may purchase only a limited number of shares of Class A common stock.
On May 5, 2016, we announced a stock repurchase program under which the Company is currently authorized to repurchase, in the aggregate, up to $15.0 million of our outstanding Class A common stock. However, we are not obligated to acquire any shares of our Class A common stock, and holders of our Class A common stock should not rely on the share repurchase program to increase their liquidity. The amount and timing of any share repurchases will depend upon a variety of factors, including the trading price of our Class A common stock, liquidity, securities laws restrictions, other regulatory restrictions, potential alternative uses of capital, and market and economic conditions. We intend to purchase through open market transactions or in privately negotiated transactions, in accordance with applicable securities laws and regulatory limitations. We may reduce or eliminate our share repurchase program in the future. The reduction or elimination of our share repurchase program, particularly if we do not repurchase the full number of shares authorized under the program, could adversely affect the market price of our common stock.


21

Table of Contents                            



Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Our corporate headquarters is located in Framingham, Massachusetts, where we occupy approximately 26,000 square feet under a lease expiring on June 30, 2025. We occupy nine regional offices in Tempe, Arizona; Islandia, New York; Oak Brook, Illinois; Columbia, Maryland; Charlotte, North Carolina; Knoxville, Tennessee; Tomball, Texas; Spokane, Washington and North York, Ontario, each less than 25,000 square feet, under lease or sublease agreements. In addition, we lease space, typically less space, for 67 field offices throughout North America and the U.K. We also own 73 small-scale renewable energy plants throughout North America, which are located on leased sites or sites provided by customers. We expect to add new facilities and expand existing facilities as we continue to add employees and expand our business into new geographic areas.
Item 3. Legal Proceedings
In the ordinary conduct of our business we are subject to periodic lawsuits, investigations and claims. Although we cannot predict with certainty the ultimate resolution of such lawsuits, investigations and claims against us, we do not believe that any currently pending or threatened legal proceedings to which we are a party will have a material adverse effect on our business, results of operations or financial condition.
For additional information about certain proceedings, please refer to Note 13, “Commitments and Contingencies”, to our Consolidated Financial Statements included in this report, which is incorporated into this item by reference.
Item 4. Mine Safety Disclosures
Not applicable.

22

Table of Contents                            





PART II
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our Class A common stock trades on the New York Stock Exchange under the symbol “AMRC”. The following table sets forth, for the fiscal quarters indicated, the high and low sale prices per share of our Class A common stock.
 
2017
 
2016
 
High
 
Low
 
High
 
Low
First Quarter
$
6.55

 
$
4.85

 
$
6.23

 
$
4.14

Second Quarter
7.70

 
6.20

 
5.01

 
3.91

Third Quarter
7.80

 
7.55

 
5.34

 
4.35

Fourth Quarter
8.90

 
7.65

 
6.30

 
4.60

The closing sale price of our Class A common stock was $8.35 on March 5, 2018, and according to the records of our transfer agent, there were 14 shareholders of record of our Class A common stock on that date. A substantially greater number of holders of our Class A common stock are “street name” or beneficial holders, whose shares are held of record by banks, brokers, and other financial institutions.
Our Class B common stock is not publicly traded and is held of record by George P. Sakellaris, our founder, principal stockholder, president and chief executive officer, as well as the Ameresco 2015 Annuity Trust and the Ameresco 2017 Annuity Trust, each of which Mr. Sakellaris is trustee and the sole beneficiary.
Dividend Policy
We have never declared or paid any cash dividends on our capital stock. We currently intend to retain earnings, if any, to finance the growth and development of our business and do not expect to pay any cash dividends for the foreseeable future. Our revolving senior secured credit facility contains provisions that limit our ability to declare and pay cash dividends during the term of that agreement. Payment of future dividends, if any, will be at the discretion of our board of directors and will depend on our financial condition, results of operations, capital requirements, restrictions contained in current or future financing instruments, provisions of applicable law and other factors our board of directors deems relevant.


















23

Table of Contents                            



Stock Performance Graph
The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 (the “Securities Act”) or the Exchange Act, except to the extent that we specifically incorporate it by reference into such filing.
The following graph compares the cumulative total return attained by shareholders on our Class A common stock relative to the cumulative total returns of the Russell 2000 index and the NASDAQ Clean Edge Green Energy index. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our Class A common stock on December 31, 2012, and in each of the indexes on December 31, 2012 and its relative performance is tracked through December 31, 2017.
COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN*
Among Ameresco, Inc., the Russell 2000 Index
and the NASDAQ Clean Edge Green Energy Index
*$100 invested on December 31, 2012 in our Class A common stock or December 31, 2012 in respective index, including reinvestment of dividends. Fiscal year ending December 31, 2017.
totalreturncharta01.jpg
 
12/31/2012
 
12/31/2013
 
12/31/2014
 
12/31/2015
 
12/31/2016
 
12/31/2017
Ameresco, Inc.
$100.00
 
$98.47
 
$71.36
 
$63.71
 
$56.07
 
$87.67
Russell 2000 Index
$100.00
 
$138.82
 
$145.62
 
$139.19
 
$168.85
 
$193.58
NASDAQ Clean Edge Green Energy Index
$100.00
 
$196.27
 
$208.69
 
$232.98
 
$222.42
 
$295.91
Shareholder returns over the indicated period should not be considered indicative of future shareholder returns.

24

Table of Contents                            





Item 5C. Unregistered Sales of Equity and Use of Proceeds
Stock Repurchase Program

The following table provides information as of and for the quarter ended December 31, 2017 regarding shares of our Class A common stock that were repurchased under our stock repurchase program authorized by the Board of Directors on April 27, 2016 (the “Repurchase Program”):
Period
Total Number of Shares Purchased
 
Average Price Paid per Share
 
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 
Approximate
Dollar Value of
Shares that May
Yet Be Purchased
Under the Plans
or Programs
October 1, 2017 - October 31, 2017

 
$

 

 
$
5,658,528

November 1, 2017 - November 30, 2017

 

 

 
5,658,528

December 1, 2017 - December 31, 2017
45,053

 
8.47

 
45,053

 
5,276,719

Total
45,053

 
$
8.47

 
45,053

 
$
5,276,719


Under the Repurchase Program, we are authorized to repurchase up to $15.0 million of our Class A common stock, as increased by the Board of Directors in February 2017. Stock repurchases may be made from time to time through the open market and privately negotiated transactions. The amount and timing of any share repurchases will depend upon a variety of factors, including the trading price of our Class A common stock, liquidity, securities laws restrictions, other regulatory restrictions, potential alternative uses of capital, and market and economic conditions.  The Repurchase Program may be suspended or terminated at any time without prior notice, and has no expiration date.
Item 6. Selected Financial Data
You should read the following selected consolidated financial data in conjunction with Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the related notes appearing in Item 8 “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K. We prepare our financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”).
We derived the consolidated statements of income (loss) data for the years ended December 31, 2017, 2016, and 2015 and the consolidated balance sheet data at December 31, 2017 and 2016 from our audited consolidated financial statements appearing in Item 8 of this Annual Report on Form 10-K. We derived the consolidated statements of income (loss) data for the years ended December 31, 2014 and 2013, and the consolidated balance sheet data at December 31, 2015, 2014, and 2013, from our audited consolidated financial statements that are not included in this Annual Report on Form 10-K. Our historical results are not necessarily indicative of the results to be expected in any future period.

25

Table of Contents                            



 
Year Ended December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
 
(in thousands, except share and per share data)
Consolidated Statements of Income (Loss) Data:
 

 
 

 
 

 
 

 
 

Revenues
$
717,152

 
$
651,227

 
$
630,832

 
$
593,241

 
$
574,171

Cost of revenues
572,994

 
516,883

 
513,768

 
476,309

 
470,846

Gross profit
144,158

 
134,344

 
117,064

 
116,932

 
103,325

Selling, general and administrative expenses
107,570

 
110,568

 
110,007

 
103,781

 
96,693

Operating income
36,588

 
23,776

 
7,057

 
13,151

 
6,632

Other expenses, net
7,871

 
7,409

 
6,765

 
6,859

 
3,873

Income before provision for income taxes
28,717

 
16,367

 
292

 
6,292

 
2,759

Income tax provision (benefit)
(4,791
)
 
4,370

 
4,976

 
(4,091
)
 
345

Net income (loss)
33,508

 
11,997

 
(4,684
)
 
10,383

 
2,414

Net loss attributable to redeemable non-controlling interest
3,983

 
35

 
5,528

 

 

Net income attributable to common shareholders
$
37,491

 
$
12,032

 
$
844

 
$
10,383

 
$
2,414

Net income per share attributable to common shareholders:
 

 
 

 
 

 
 

 
 

Basic
$
0.82

 
$
0.26

 
$
0.02

 
$
0.22

 
$
0.05

Diluted
$
0.82

 
$
0.26

 
$
0.02

 
$
0.22

 
$
0.05

Weighted average common shares outstanding:
 

 
 

 
 

 
 

 
 

Basic
45,509,000

 
46,409,000

 
46,494,000

 
46,162,000

 
45,560,000

Diluted
45,748,000

 
46,493,000

 
47,665,000

 
47,028,000

 
46,685,000


 
As of December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
 
(in thousands)
Consolidated Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
24,262

 
$
20,607

 
$
21,645

 
$
23,762

 
$
17,171

Current assets
287,078

 
226,061

 
263,698

 
215,795

 
247,009

Federal ESPC receivable(1)
248,917

 
158,209

 
125,804

 
79,167

 
44,297

Energy assets, net
356,443

 
319,758

 
244,309

 
217,772

 
210,744

Total assets
983,951

 
797,281

 
723,440

 
617,550

 
600,983

Current liabilities
202,142

 
190,602

 
179,723

 
142,934

 
133,288

Long-term debt, less current portion
173,237

 
140,593

 
100,490

 
85,724

 
97,902

Federal ESPC liabilities(1)
235,088

 
133,003

 
122,040

 
70,875

 
44,297

Total stockholders’ equity
$
336,620

 
$
294,306

 
$
287,409

 
$
286,306

 
$
276,806


(1)
Federal ESPC receivable represents the amount to be paid by various federal government agencies for work performed and earned by the Company under specific ESPCs. The Company assigns certain of its rights to receive those payments to third-party investors that provide construction and permanent financing for such contracts. Federal ESPC liabilities represent the advances received from third-party investors under agreements to finance certain energy savings performance contract projects with various federal government agencies. Upon completion and acceptance of the project by the government, typically within 24 - 36 months of construction commencement, the ESPC receivable from the Government and corresponding related ESPC liability is eliminated from our consolidated balance sheet. Until recourse to us ceases for the ESPC receivables transferred to the investor, upon final acceptance of the work by the Government customer, we remain the primary obligor for financing received.

26

Table of Contents                            




Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion and analysis of our financial condition and results of operations together with our consolidated financial statements and the related notes and other financial information included in Item 8 of this Annual Report on Form 10-K. Some of the information contained in this discussion and analysis or set forth elsewhere in this Report, including information with respect to our plans and strategy for our business and related financing, includes forward-looking statements that involve risks and uncertainties. You should review the “Risk Factors” included in Item 1A of this Annual Report on Form 10-K for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.
Overview
Ameresco is a leading provider of energy efficiency solutions for facilities throughout North America and Europe. We provide solutions that enable customers to reduce their energy consumption, lower their operating and maintenance costs and realize environmental benefits. Our comprehensive set of services includes upgrades to a facility’s energy infrastructure and the construction and operation of small-scale renewable energy plants.
In September 2015, we entered into an agreement with a third party investor which granted the investor ownership interests in the net assets of certain of our renewable energy project subsidiaries. In June 2017, we entered into a separate agreement with a third party investor which granted the investor ownership interests in the net assets of certain of our renewable energy project subsidiaries. We entered into these agreements in order to finance the costs of constructing certain energy assets which are under long-term customer contracts. We have determined that we are the primary beneficiary in the operational partnerships for accounting purposes. Accordingly, we consolidate the assets and liabilities and operating results of the entities in our consolidated financial statements. We recognize the investors’ share of the net assets of the investors’ funds as redeemable non-controlling interests in our consolidated balance sheets. These income or loss allocations, which are reflected on our consolidated statements of income (loss), may create significant volatility in our reported results of operations, including potentially changing net income available (loss attributable) to common stockholders from income to loss, or vice versa, from quarter to quarter.
In addition to organic growth, strategic acquisitions of complementary businesses and assets have been an important part of our historical development. Since inception, we have completed numerous acquisitions, which have enabled us to broaden our service offerings and expand our geographical reach.
From time to time we also acquire solar photovoltaic (“solar PV”) projects under construction. Our acquisition of a solar PV asset under construction in the fourth quarter of 2016, as well as two solar PV assets under construction in the first quarter of 2017, expanded our portfolio of small-scale renewable energy plants.
Energy Savings Performance and Energy Supply Contracts
For our energy efficiency projects, we typically enter into ESPCs, under which we agree to develop, design, engineer and construct a project and also commit that the project will satisfy agreed-upon performance standards that vary from project to project. These performance commitments are typically based on the design, capacity, efficiency or operation of the specific equipment and systems we install. Our commitments generally fall into three categories: pre-agreed, equipment-level and whole building-level. Under a pre-agreed energy reduction commitment, our customer reviews the project design in advance and agrees that, upon or shortly after completion of installation of the specified equipment comprising the project, the commitment will have been met. Under an equipment-level commitment, we commit to a level of energy use reduction based on the difference in use measured first with the existing equipment and then with the replacement equipment. A whole building-level commitment requires demonstration of energy usage reduction for a whole building, often based on readings of the utility meter where usage is measured. Depending on the project, the measurement and demonstration may be required only once, upon installation, based on an analysis of one or more sample installations, or may be required to be repeated at agreed upon intervals generally over up to 20 years.
Under our contracts, we typically do not take responsibility for a wide variety of factors outside of our control and exclude or adjust for such factors in commitment calculations. These factors include variations in energy prices and utility rates, weather, facility occupancy schedules, the amount of energy-using equipment in a facility and the failure of the customer to operate or maintain the project properly. Typically, our performance commitments apply to the aggregate overall performance of a project rather than to individual energy efficiency measures. Therefore, to the extent an individual measure underperforms,

27

Table of Contents                            



it may be offset by other measures that overperform during the same period. In the event that an energy efficiency project does not perform according to the agreed-upon specifications, our agreements typically allow us to satisfy our obligation by adjusting or modifying the installed equipment, installing additional measures to provide substitute energy savings or paying the customer for lost energy savings based on the assumed conditions specified in the agreement. Many of our equipment supply, local design and installation subcontracts contain provisions that enable us to seek recourse against our vendors or subcontractors if there is a deficiency in our energy reduction commitment. See “We may have liability to our customers under our ESPCs if our projects fail to deliver the energy use reductions to which we are committed under the contract” in Item 1A, Risk Factors in this Annual Report on Form 10-K.
Payments by the federal government for energy efficiency measures are based on the services provided and the products installed, but are limited to the savings derived from such measures, calculated in accordance with federal regulatory guidelines and the specific contract’s terms. The savings are typically determined by comparing energy use and other costs before and after the installation of the energy efficiency measures, adjusted for changes that affect energy use and other costs but are not caused by the energy efficiency measures.
For projects involving the construction of a small-scale renewable energy plant that we own and operate, we generally enter into long-term contracts to supply the electricity, processed LFG, heat or cooling generated by the plant to the customer, which is typically a utility, municipality, industrial facility or other large purchaser of energy. The rights to use the site for the plant and purchase of renewable fuel for the plant are also obtained by us under long-term agreements with terms at least as long as the associated output supply agreement. Our supply agreements typically provide for fixed prices or prices that escalate at a fixed rate or vary based on a market benchmark. See “We may assume responsibility under customer contracts for factors outside our control, including, in connection with some customer projects, the risk that fuel prices will increase” in reference Item 1A, Risk Factors in this Annual Report on Form 10-K.
Project Financing
To finance projects with federal governmental agencies, we typically sell to third-party lenders our right to receive a portion of the long-term payments from the customer arising out of the project for a purchase price reflecting a discount to the aggregate amount due from the customer. The purchase price is generally advanced to us over the implementation period based on completed work or a schedule predetermined to coincide with the construction of the project. Under the terms of these financing arrangements, we are required to complete the construction or installation of the project in accordance with the contract with our customer, and the liability remains on our consolidated balance sheet until the completed project is accepted by the customer. Once the completed project is accepted by the customer, the financing is treated as a true sale and the related receivable and financing liability are removed from our consolidated balance sheet.
Institutional customers, such as state, provincial and local governments, schools and public housing authorities, typically finance their energy efficiency and renewable energy projects through either tax-exempt leases or issuances of municipal bonds. We assist in the structuring of such third-party financing.
In some instances, customers prefer that we retain ownership of the renewable energy plants and related energy assets that we construct for them. In these projects, we typically enter into a long-term supply agreement to furnish electricity, gas, heat or cooling to the customer’s facility. To finance the significant upfront capital costs required to develop and construct the plant, we rely either on our internal cash flow or, in some cases, third-party debt. For project financing by third-party lenders, we typically establish a separate subsidiary, usually a limited liability company, to own the energy assets and related contracts. The subsidiary contracts with us for construction and operation of the project and enters into a financing agreement directly with the lenders. Additionally, we will provide assurance to the lender that the project will achieve commercial operation. Although the financing is secured by the assets of the subsidiary and a pledge of our equity interests in the subsidiary, and is non-recourse to Ameresco, Inc., we may from time to time determine to provide financial support to the subsidiary in order to maintain rights to the project or otherwise avoid the adverse consequences of a default. The amount of such financing is included on our consolidated balance sheet.
Effects of Seasonality
We are subject to seasonal fluctuations and construction cycles, particularly in climates that experience colder weather during the winter months, such as the northern United States and Canada, or at educational institutions, where large projects are typically carried out during summer months when their facilities are unoccupied. In addition, government customers, many of which have fiscal years that do not coincide with ours, typically follow annual procurement cycles and appropriate funds on a fiscal-year basis even though contract performance may take more than one year. Further, government contracting cycles can be

28

Table of Contents                            



affected by the timing of, and delays in, the legislative process related to government programs and incentives that help drive demand for energy efficiency and renewable energy projects. As a result, our revenues and operating income in the third and fourth quarter are typically higher, and our revenues and operating income in the first quarter are typically lower, than in other quarters of the year. As a result of such fluctuations, we may occasionally experience declines in revenues or earnings as compared to the immediately preceding quarter, and comparisons of our operating results on a period-to-period basis may not be meaningful.
Our annual and quarterly financial results are also subject to significant fluctuations as a result of other factors, many of which are outside our control. See “Our operating results may fluctuate significantly from quarter to quarter and may fall below expectations in any particular fiscal quarter” in Item 1A, Risk Factors in this Annual Report on Form 10-K.
Backlog and Awarded Projects
Total construction backlog represents projects that are active within our ESPC sales cycle. Our sales cycle begins with the initial contact with the customer and ends, when successful, with a signed contract, also referred to as fully-contracted backlog. Our sales cycle recently has been averaging 18 to 42 months. Awarded backlog is created when a potential customer awards a project to Ameresco following a request for proposal. Once a project is awarded but not yet contracted, we typically conduct a detailed energy audit to determine the scope of the project as well as identify the savings that may be expected to be generated from upgrading the customer’s energy infrastructure. At this point, we also determine the sub-contractor, what equipment will be used, and assist in arranging for third party financing, as applicable. Recently, awarded projects have been taking an average of 12 to 24 months to result in a signed contract and thus convert to fully-contracted backlog. It may take longer, however, depending upon the size and complexity of the project. Historically, approximately 90% of our awarded backlog projects ultimately have resulted in a signed contract. After the customer and Ameresco agree to the terms of the contract and the contract becomes executed, the project moves to fully-contracted backlog. The contracts reflected in our fully-contracted backlog typically have a construction period of 12 to 36 months and we typically expect to recognize revenue for such contracts over the same period. Fully-contracted backlog begins converting into revenues generated from backlog on a percentage-of-completion basis once construction has commenced. See “We may not recognize all revenues from our backlog or receive all payments anticipated under awarded projects and customer contracts” and “In order to secure contracts for new projects, we typically face a long and variable selling cycle that requires significant resource commitments and requires a long lead time before we realize revenues” in Item 1A, Risk Factors in this Annual Report on Form 10-K.
As of December 31, 2017, we had backlog of approximately $572.5 million in expected future revenues under signed customer contracts for the installation or construction of projects; and we also had been awarded projects for which we had not yet signed customer contracts with estimated total future revenues of an additional $1,199.0 million. As of December 31, 2016, we had fully-contracted backlog of approximately $534.1 million in future revenues under signed customer contracts for the installation or construction of projects; and we also had been awarded projects for which we had not yet signed customer contracts with estimated total future revenues of an additional $957.6 million. As of December 31, 2015, we had backlog of approximately $390.4 million in expected future revenues under signed customer contracts for the installation or construction of projects; and we also had been awarded projects for which we had not yet signed customer contracts with estimated total future revenues of an additional $955.8 million.
We define our 12-month backlog as the estimated amount of revenues that we expect to recognize in the next twelve months from our fully-contracted backlog. As of December 31, 2017 and 2016, our 12-month backlog was $348.0 million and $309.6 million, respectively.
Assets in development, which represents the potential design/build project value of small-scale renewable energy plants that have been awarded or for which we have secured development rights, was $165.8 million and $228.3 million as of December 31, 2017 and 2016, respectively.
Financial Operations Overview
Revenues
We derive revenues principally from energy efficiency projects, which entails the design, engineering and installation of equipment and other measures that incorporate a range of innovative technology and techniques to improve the efficiency and control the operation of a facility’s energy infrastructure; this can include designing and constructing for a customer a central plant or cogeneration system providing power, heat and/or cooling to a building, or other small-scale plant that produces electricity, gas, heat or cooling from renewable sources of energy. We also derive revenue from: long-term O&M contracts;

29

Table of Contents                            



energy supply contracts for renewable energy operating assets that we own; integrated-PV; and consulting and enterprise energy management services.
Historically, including for the years ended December 31, 2017, 2016 and 2015, approximately 77% of our revenues have been derived from federal, state, provincial or local government entities, including public housing authorities and public universities.
Cost of Revenues and Gross Margin
Cost of revenues include the cost of labor, materials, equipment, subcontracting and outside engineering that are required for the development and installation of our projects, as well as pre-construction costs, sales incentives, associated travel, inventory obsolescence charges, amortization of intangible assets related to customer contracts, and, if applicable, costs of procuring financing. A majority of our contracts have fixed price terms; however, in some cases we negotiate protections, such as a cost-plus structure, to mitigate the risk of rising prices for materials, services and equipment.
Cost of revenues also include costs for the small-scale renewable energy plants that we own, including the cost of fuel (if any) and depreciation charges.
As a result of certain acquisitions, we have intangible assets related to customer contracts; these are amortized over a period of approximately one to five years from the respective date of acquisition. This amortization is recorded as a cost of revenues in the consolidated statements of income (loss). Amortization expense for the year ended December 31, 2016 related to customer contracts was $0.2 million. Customer contract intangible assets were fully amortized as of December 31, 2017.
Gross margin, which is gross profit as a percent of revenues, is affected by a number of factors, including the type of services performed. Renewable energy projects that we own and operate typically have higher margins than energy efficiency projects, and sales in the United States typically have higher margins than in Canada due to the typical mix of products and services that we sell there.
In addition, gross margin frequently varies across the construction period of a project. Our expected gross margin on, and expected revenues for, a project are based on budgeted costs. From time to time, a portion of the contingencies reflected in budgeted costs are not incurred due to strong execution performance. In that case, and generally at project completion, we recognize revenues for which there is no further corresponding cost of revenues. As a result, gross margin tends to be back-loaded for projects with strong execution performance; this explains the gross margin improvement that occurs from time to time at project closeout. We refer to this gross margin improvement at the time of project completion as a project closeout.
Selling, General and Administrative Expenses
Selling, general and administrative expenses include salaries and benefits, project development costs, and general and administrative expenses not directly related to the development or installation of projects.
Salaries and benefits. Salaries and benefits consist primarily of expenses for personnel not directly engaged in specific project or revenue generating activity. These expenses include the time of executive management, legal, finance, accounting, human resources, information technology and other staff not utilized in a particular project. We employ a comprehensive time card system which creates a contemporaneous record of the actual time by employees on project activity.
Project development costs. Project development costs consist primarily of sales, engineering, legal, finance and third-party expenses directly related to the development of a specific customer opportunity. This also includes associated travel and marketing expenses.
General and administrative expenses. These expenses consist primarily of rents and occupancy, professional services, insurance, unallocated travel expenses, telecommunications, office expenses and amortization of intangible assets not related to customer contracts. Professional services consist principally of recruiting costs, external legal, audit, tax and other consulting services. For the years ended December 31, 2017 and 2016, we recorded amortization expense of $1.4 million and $2.2 million, respectively, related to customer relationships, non-compete agreements, technology and trade names. Amortization expense related to these intangible assets is included in selling, general and administrative expenses in the consolidated statements of income (loss). For the year ended December 31, 2016, we recorded $6.2 million in restructuring charges which consisted primarily of bad debt expense in our Canada segment, and a reserve for certain amounts receivable from a customer who declared bankruptcy.

30

Table of Contents                            



Other Expenses, Net
Other expenses, net, includes gains and losses from derivatives, interest income and expenses, amortization of deferred financing costs, net, and foreign currency transaction gains and losses. Interest expense will vary periodically depending on the amounts drawn on our revolving senior secured credit facility and the prevailing short-term interest rates.
Provision or Benefit for Income Taxes
The provision or benefit for income taxes is based on various rates set by federal and local authorities and is affected by permanent and temporary differences between financial accounting and tax reporting requirements.
Critical Accounting Policies and Estimates
This discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expense and related disclosures. The most significant estimates with regard to these consolidated financial statements relate to estimates of final construction contract profit in accordance with accounting for long-term contracts, allowance for doubtful accounts, inventory reserves, realization of project development costs, fair value of derivative financial instruments, accounting for business acquisitions, stock-based awards, impairment of long-lived assets, income taxes, self insurance reserves and potential liability in conjunction with certain commitments and contingencies. Such estimates and assumptions are based on historical experience and on various other factors that management believes to be reasonable under the circumstances. Estimates and assumptions are made on an ongoing basis, and accordingly, the actual results may differ from these estimates under different assumptions or conditions.
The following are critical accounting policies that, among others, affect our more significant judgments and estimates used in the preparation of our consolidated financial statements.
Revenue Recognition
For each arrangement we have with a customer, we typically provide a combination of one or more of the following services or products:
installation or construction of energy efficiency measures, facility upgrades and/or a renewable energy plant to be owned by the customer;
sale and delivery, under long-term agreements, of electricity, gas, heat, chilled water or other output of a renewable energy or central plant that we own and operate;
O&M services provided under long-term O&M agreements;
sale and delivery of PV equipment and other renewable energy products for which we are a distributor, whether under our own brand name or for others; and
enterprise energy management and consulting services.
Often, we will sell a combination of these services and products in a bundled arrangement. We divide bundled arrangements into separate deliverables and revenue is allocated to each deliverable based on the relative selling price. The relative selling price is determined using third party evidence or management’s best estimate of selling price.
We recognize revenues from the installation or construction of a project on a percentage-of-completion basis. The percentage-of-completion for each project is determined on an actual cost-to-estimated final cost basis. In accordance with industry practice, we include in current assets and liabilities the amounts of receivables related to construction projects that are payable over a period in excess of one year. We recognize revenues associated with contract change orders only when the authorization for the change order has been properly executed and the work has been performed.
When the estimate on a contract indicates a loss, or claims against costs incurred reduce the likelihood of recoverability of such costs, our policy is to record the entire expected loss immediately, regardless of the percentage of completion.
Deferred revenue represents circumstances where (i) there has been a receipt of cash from the customer for work or services that have yet to be performed, (ii) receipt of cash where the product or service may not have been accepted by the customer or (iii) when all other revenue recognition criteria have been met, but an estimate of the final total cost cannot be

31

Table of Contents                            



determined. Deferred revenue will vary depending on the timing and amount of cash receipts from customers and can vary significantly depending on specific contractual terms. As a result, deferred revenue is likely to fluctuate from period to period. Unbilled revenue, presented as costs and estimated earnings in excess of billings, represent amounts earned and billable that were not invoiced at the end of the fiscal period.
We recognize revenues from the sale and delivery of products, including the output of our renewable energy plants, when produced and delivered to the customer, in accordance with the specific contract terms, provided that persuasive evidence of an arrangement exists, our price to the customer is fixed or determinable and collectability is reasonably assured.
We recognize revenues from O&M contracts, consulting services and enterprise energy management services as the related services are performed.
For a limited number of contracts under which we receive additional revenue based on a share of energy savings, we recognize such additional revenue as energy savings are generated.
For information regarding our adoption of ASC 606, Revenue Recognition, see “Note 2 - Summary of Significant Accounting Policies” included in our Notes to the Consolidated Financial Statements.
Project Development Costs
We capitalize as project development costs only those costs incurred in connection with the development of energy efficiency and renewable energy projects, primarily direct labor, interest costs, outside contractor services, consulting fees, legal fees and associated travel, if incurred after a point in time when the realization of related revenue becomes probable. Project development costs incurred prior to the probable realization of revenues are expensed as incurred.
Energy Assets
We capitalize interest costs relating to construction financing during the period of construction. The interest capitalized is included in the total cost of the project at completion. The amount of interest capitalized for the years ended December 31, 2017, 2016 and 2015 was $4.3 million, $1.3 million and $0.9 million, respectively.
Routine maintenance costs are expensed in the current year’s consolidated statements of income (loss) to the extent that they do not extend the life of the asset. Major maintenance, upgrades and overhauls are required for certain components of our assets. In these instances, the costs associated with these upgrades are capitalized and are depreciated over the shorter of the life of the asset or until the next required major maintenance or overhaul period. Gains or losses on disposal of property and equipment are reflected in selling, general and administrative expenses in the consolidated statements of income (loss).
We evaluate our long-lived assets for impairment as events or changes in circumstances indicate the carrying value of these assets may not be fully recoverable. Should an assessment be performed or triggering event identified, we evaluate recoverability of long-lived assets to be held and used by estimating the undiscounted future cash flows before interest associated with the expected uses and eventual disposition of those assets. When these comparisons indicate that the carrying value of those assets is greater than the undiscounted cash flows, we recognize an impairment loss for the amount that the carrying value exceeds the fair value.
Impairment of Goodwill and Intangible Assets
We have classified as goodwill the amounts paid in excess of fair value of the net assets (including tax attributes) of companies acquired in purchase transactions. We have recorded intangible assets related to customer contracts, customer relationships, non-compete agreements, trade names and technology, each with defined useful lives. We assess the impairment of goodwill and intangible assets that have indefinite lives on an annual basis (December 31st) and whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable.

Goodwill is reviewed for impairment annually and whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. The process of evaluating the potential impairment of goodwill requires significant judgment. We regularly monitor current business conditions and other factors including, but not limited to, adverse industry or economic trends, restructuring actions and projections of future results. We estimate the reporting units fair value and compares it with the carrying value of the reporting unit, including goodwill. If the fair value is greater than the carrying value of its reporting unit, no impairment is recorded. Fair value is determined using both an income approach and a market approach. The estimates and assumptions used in our calculations include revenue growth rates, expense growth rates, expected capital expenditures to determine projected cash flows, expected tax rates and an estimated discount rate to determine present value of expected cash

32

Table of Contents                            



flows. These estimates are based on historical experiences, our projections of future operating activity and our weighted-average cost of capital.
 
Acquired intangible assets other than goodwill that are subject to amortization include customer contracts and customer relationships, as well as software/technology, trade names and non-compete agreements. The intangible assets are amortized over periods ranging from one to fifteen years from their respective acquisition dates. We evaluate the intangible assets for impairment consistent with, and part of, their long-lived assets evaluation, as discussed in Energy Assets above.

Impairment of Long-Lived Assets

We use the guidance prescribed in ASC 360, Property, Plant and Equipment, for the proper testing and valuation methodology to ensure we record any impairment when the carrying amount of a long-lived asset is not recoverable equivalent to an amount equal to its fair market value.

We review long-lived asset groups for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be fully recoverable or that the useful lives of these assets are no longer appropriate. Examples of such triggering events applicable to our asset groups include a significant decrease in the market price of a long-lived asset group or a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset group.

Should an asset group be identified as potentially impaired based on the defined criteria, an impairment test is performed that includes a comparison of the estimated undiscounted cash flows of the asset as compared to the recorded value of the asset. If these estimates or their related assumptions change in the future, an impairment charge may be required against these assets in the reporting period in which the impairment is determined.

Derivative Financial Instruments

We account for our interest rate swaps as derivative financial instruments. As required under GAAP, derivatives are carried on our consolidated balance sheets at fair value. The fair value of our interest rate swaps is determined based on observable market data in combination with expected cash flows for each instrument.
We follow the guidance which expands the disclosure requirements for derivative instruments and hedging activities.
In the normal course of business, we utilize derivative contracts as part of our risk management strategy to manage exposure to market fluctuations in interest rates. These instruments are subject to various credit and market risks. Controls and monitoring procedures for these instruments have been established and are routinely reevaluated. Credit risk represents the potential loss that may occur because a party to a transaction fails to perform according to the terms of the contract. The measure of credit exposure is the replacement cost of contracts with a positive fair value. We seek to manage credit risk by entering into financial instrument transactions only through counterparties that we believe to be creditworthy. Market risk represents the potential loss due to the decrease in the value of a financial instrument caused primarily by changes in interest rates. We seek to manage market risk by establishing and monitoring limits on the types and degree of risk that may be undertaken. As a matter of policy, we do not use derivatives for speculative purposes.
We are exposed to interest rate risk through our borrowing activities. A portion of our project financing includes four credit facilities, both project related and corporate, that utilize a variable rate swap instrument.
Prior to December 31, 2009, we entered into two interest rate swap contracts under which we agreed to pay an amount equal to a specified fixed rate of interest times a notional principal amount, and to, in turn, receive an amount equal to a specified variable rate of interest times the same notional principal amount. The first swap covers an initial notional amount of $3.3 million variable rate note at a fixed interest rate of 5.3%, with an effective date of February 28, 2006, and expires in February 2021. The second swap covers an initial notional amount of $13.1 million variable rate note at a fixed interest rate of 5.4%, with an effective date of September 30, 2008, and expires in March 2024.
In March 2010, we entered into a 14-year interest rate swap contract under which we agreed to pay an amount equal to a specified fixed rate of interest times a notional principal amount, and to in turn receive an amount equal to a specified variable rate of interest times the same notional principal amount. The swap covers an initial notional amount

33

Table of Contents                            



of $27.9 million variable rate note at a fixed interest rate of 3.7%, with an effective date of March 11, 2010, and expires in December 2024.
In July 2011, we entered into a five-year interest rate swap contract under which we agreed to pay an amount equal to a specified fixed rate of interest times a notional principal amount, and to in turn receive an amount equal to a specified variable rate of interest times the same notional principal amount. The swap covered an initial notional amount of $38.6 million variable rate note at a fixed interest rate of 2.0% and expired in June 2016. This interest rate swap was designated as a hedge since inception.
In October 2012, and in connection with a construction and term loan, we entered into two eight-year interest rate swap contracts under which we agreed to pay an amount equal to a specified fixed rate of interest times a notional principal amount, and to in turn receive an amount equal to a specified variable rate of interest times the same notional principal amount. The swaps have an initial notional amount of $16.8 million, which increased to $42.2 million on September 30, 2013, at a fixed rate of 1.7%, and expires in March 2020.

In October 2012, we also entered into two eight-year forward starting interest rate swap contracts under which we agreed to pay an amount equal to specified fixed rate of interest times a notional amount, and to in turn receive an amount equal to a specified variable rate of interest times the same notional principal amount. The swaps cover an initial notional amount of $25.4 million variable rate note at a fixed interest rate of 3.7%, with an effective date of March 31, 2020, and expires in June 2028.
In September 2015, we entered into a seven-year forward starting interest rate swap contract under which we agreed to pay an amount equal to a specified fixed rate of interest times a notional amount, and to in turn receive an amount equal to a specified variable rate of interest times the same notional principal amount. The swap covers an initial notional amount of $20.7 million variable rate note at a fixed interest rate of 2.2%, with an effective date of February 29, 2016, and expires in February 2023. This interest rate swap has been designated as a hedge since inception.
In September 2015, we also also entered into a fifteen-year forward starting interest rate swap contract under which we agreed to pay an amount equal to a specified fixed rate of interest times a notional amount, and to in turn receive an amount equal to a specified variable rate of interest times the same notional principal amount. The swap covers an initial notional amount of $14.1 million variable rate note at a fixed interest rate of 3.3%, with an effective date of February 28, 2023, and expires in December 2038. This interest rate swap has been designated as a hedge since inception.
In June 2017, we entered into a ten-year interest rate swap contract under which we agreed to pay an amount equal to a specified fixed rate of interest times a notional amount, and to in turn receive an amount equal to a specified variable rate of interest times the same notional principal amount. The swap covers an initial notional amount of $14.1 million variable rate note at a fixed interest rate of 2.3%, with an effective date of June 27, 2017, and expires in December 2027. This interest rate swap has been designated as a hedge since inception. As of December 31, 2017 this hedge was operating ineffectively, which resulted in recognizing an immaterial amount of fair value loss in the consolidated statements of income (loss).
We entered into each of the interest rate swap contracts as an economic hedge.
We recognize all derivatives in our consolidated financial statements at fair value.
The interest rate swaps that we entered into prior to December 31, 2009 qualified, but were not designated as cash flow hedges until April 1, 2010. Accordingly, any changes in fair value through March 31, 2010 were reported in other expenses, net in our consolidated statements of income (loss) at fair value, and in the consolidated statements of comprehensive income (loss) thereafter. Cash flows from these derivative instruments are reported as operating activities on the consolidated statements of cash flows.
The interest rate swap that we entered into in March 2010 was a floating-to-fixed interest rate swap. This swap was designated as a hedge in March 2013. During the second quarter of 2014, this swap was de-designated and re-designated as a hedge as a result of a partial pay down of the associated hedged debt principal. As a result $566 was reclassified from accumulated other comprehensive loss and recorded as a reduction to other expenses, net in our consolidated statements of income (loss) during the second quarter of 2014.

34

Table of Contents                            



The interest rate swaps that we entered into during 2011, 2012, 2015 and 2017 qualify, and were designated at inception, as cash flow hedges.
We recognize the fair value of derivative instruments designated as hedges in our consolidated balance sheets and any changes in the fair value are recorded as adjustments to other comprehensive income (loss) if the hedges operate effectively.
Income Taxes
We provide for income taxes based on the liability method. We provide for deferred income taxes based on the expected future tax consequences of differences between the financial statement basis and the tax basis of assets and liabilities calculated using the enacted tax rates in effect for the year in which the differences are expected to be reflected in the tax return.
We account for uncertain tax positions using a “more-likely-than-not” threshold for recognizing and resolving uncertain tax positions. The evaluation of uncertain tax positions is based on factors that include, but are not limited to, changes in tax law, the measurement of tax positions taken or expected to be taken in tax returns, the effective settlement of matters subject to audit, new audit activity and changes in facts or circumstances related to a tax position. We evaluate uncertain tax positions on a quarterly basis and adjust the level of the liability to reflect any subsequent changes in the relevant facts surrounding the uncertain positions. Our liabilities for an uncertain tax position can be relieved only if the contingency becomes legally extinguished through either payment to the taxing authority or the expiration of the statute of limitations, the recognition of the benefits associated with the position meet the “more-likely-than-not” threshold or the liability becomes effectively settled through the examination process. We consider matters to be effectively settled once: the taxing authority has completed all of its required or expected examination procedures, including all appeals and administrative reviews; we have no plans to appeal or litigate any aspect of the tax position and we believe that it is highly unlikely that the taxing authority would examine or re-examine the related tax position. We also accrue for potential interest and penalties, related to unrecognized tax benefits in income tax expense.
We have presented all deferred tax assets and liabilities as noncurrent on our consolidated balance sheet as of December 31, 2017, 2016 and 2015, respectively.
The 2017 Tax Cuts and Jobs Act (the “2017 Tax Act”) was signed into law on December 22, 2017. The 2017 Tax Act significantly revises the U.S. corporate income tax by, among other things, lowering the statutory corporate tax rate from 35% to 21%, eliminating certain deductions, imposing a mandatory one-time tax on accumulated earnings of foreign subsidiaries as of 2017, introducing new tax regimes, and changing how foreign earnings are subject to U.S. tax. The 2017 Tax Act also enhanced and extended through 2026 the option to claim accelerated depreciation deductions on qualified property. We recorded a tax benefit for the impact of the 2017 Tax Act of approximately $13.9 million in our consolidated financial statements as of December 31, 2017. This amount is primarily comprised of the remeasurement of federal net deferred tax liabilities resulting from the permanent reduction in the U.S. statutory corporate tax rate from 35% to 21%, after taking into account the mandatory one-time tax on the accumulated earnings of our foreign subsidiaries.
The Tax Legislation provided for a one-time deemed mandatory repatriation for post-1986 undistributed foreign subsidiary earnings and profits (“E&P”) through the year ended December 31, 2017.  Our initial estimate shows a deficit in foreign E&P and significant foreign taxes paid, which may be creditable against any tax resulting from the deemed mandatory repatriation. We will continue to refine our calculations of foreign E&P during the measurement period, however we do not expect the deemed mandatory repatriation to result in material tax assessment.
On December 22, 2017, the SEC staff issued Staff Accounting Bulletin No. 118 to address the application of U.S. GAAP in situations when a registrant does not have the necessary information available, prepared, or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Tax Legislation. We have recognized the provisional tax impacts related to the revaluation of deferred tax assets and liabilities and included these amounts in its consolidated financial statements for the year ended December 31, 2017. As of December 31, 2017, we have substantially completed our accounting for the tax effects of the 2017 Tax Act.  If revisions are needed as new information becomes available, the final determination of the deemed re-measurement of our deferred assets and liabilities, the deemed mandatory repatriation or other applicable provisions of The Legislation will be completed as additional information becomes available, but no later than one year from the enactment of the 2017 Tax Act.
Stock-Based Compensation Expense
Our stock-based compensation expense results from the issuances of shares of restricted common stock and grants of stock options to employees, directors, outside consultants and others. We recognize the costs associated with option grants

35

Table of Contents                            



using the fair value recognition provisions of ASC 718, Compensation — Stock Compensation. Generally, ASC 718 requires the value of all stock-based payments to be recognized in the statement of operations based on their estimated fair value at date of grant amortized over the grants’ respective vesting periods. For the years ended December 31, 2017, 2016 and 2015, we recorded stock-based compensation expense of approximately $1.3 million, $1.5 million, and $1.8 million, respectively, in connection with stock-based payment awards. The compensation expense is allocated between cost of revenues and selling, general and administrative expenses in the accompanying consolidated statements of income (loss) based on the salaries and work assignments of the employees holding the options.
Stock Option Grants
We have granted stock options to certain employees and directors under our 2010 stock incentive plan and at December 31, 2017, 7,100,394 shares were available for grant under that plan. We have also granted stock options to certain employees and directors under our 2000 stock incentive plan; however, we will grant no further stock options or restricted stock awards under that plan.

Stock options issued under our 2000 stock incentive plan generally expire if not exercised within ten years after the grant date. Under the terms of our 2010 stock incentive plan, all options expire if not exercised within ten years after the grant date. During 2011, we began awarding options which typically vest over a five year period on an annual ratable basis. If the employee ceases to be employed for any reason before vested options have been exercised, the employee generally has three months to exercise vested options or they are forfeited. Certain option grants have performance conditions that must be achieved prior to vesting and are expensed based on the expected achievement at each reporting period.

We follow the fair value recognition provisions of ASC 718 requiring that all stock-based payments to employees, including grants of employee stock options and modifications to existing stock options, be recognized in the consolidated statements of income (loss) based on their fair values, using the prospective-transition method.
We use the Black-Scholes option pricing model to determine the weighted-average fair value of options granted and record stock-based compensation expense utilizing the straight-line method.
The determination of the fair value of stock-based payment awards utilizing the Black-Scholes model is affected by the stock price and a number of assumptions, including expected volatility, expected life, risk-free interest rate and expected dividends. The following table sets forth the significant assumptions used in the model during 2017, 2016 and 2015:
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Expected dividend yield
 
—%
 
—%
 
—%
Risk-free interest rate
 
1.96%-2.36%
 
1.16%-1.77%
 
1.53%-2.01%
Expected volatility
 
46%
 
46%-49%
 
44%-49%
Expected life
 
6.5 years
 
6.5-10 years
 
5.0-6.5 years
We will continue to use our judgment in evaluating the expected term, volatility and forfeiture rate related to our own stock-based compensation on a prospective basis, and incorporating these factors into the Black-Scholes pricing model. Higher volatility and longer expected lives result in an increase to stock-based compensation expense determined at the date of grant. These expenses will affect our cost of revenues as well as our selling, general and administrative expenses.
As of December 31, 2017, we had $2.8 million of total unrecognized stock-based compensation expense related to employee and director stock options. We expect to recognize this cost over a weighted-average period of 2.3 years after December 31, 2017. The allocation of this expense between cost of revenues and selling, general and administrative expenses will depend on the salaries and work assignments of the personnel holding these options.
Recent Accounting Pronouncements
Revenue from Contracts with Customers
In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers, as amended (Topic 606) (commonly referred to as ASC 606), which will change the way we recognize revenue and costs related to customer contract and significantly expand the disclosure requirements for

36

Table of Contents                            



revenue arrangements. The new standard is effective for annual reporting periods beginning after December 15, 2017. The standard allows for two transition methods - retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with the cumulative effect of initially applying the standard recognized at the date of initial adoption (modified retrospective method).
We adopted the requirements of the new standard, including additional accounting standard updates issued during 2016 which provide clarification and expanded guidance on ASU 2014-09 topics, on January 1, 2018 using the modified retrospective method, whereby ASC 606 would apply to all new contracts initiated on or after January 1, 2018. For existing contracts that have remaining obligations as of January 1, 2018, any difference between the recognition criteria in connection with the new standard and the Company’s current revenue recognition practices would be recognized using a cumulative effect adjustment to the opening balance of retained earnings. Accordingly, we have elected to retroactively adjust only those contracts that do not meet the definition of a complete contract at the date of the initial application. As ASC 606 supersedes substantially all existing revenue guidance affecting the Company under current GAAP, it will impact revenue and cost recognition across all of the Company’s business segments, as well as its business processes and information technology systems.

We commenced our evaluation of the impact of ASC 606 in mid-2016, by evaluating its impact on existing contracts for each of our lines of business at each of our business segments. With this baseline understanding, we developed a project plan to evaluate numerous contracts across our business segments, develop processes and tools to dual report financial results under both current GAAP and ASC 606 and assess the internal control structure in order to adopt ASC 606 on January 1, 2018. We have substantially completed our evaluation and implementation of system updates and changes to internal controls over financial reporting to allow us to timely compile the information needed to account for transactions under this new guidance and to adjust our consolidated financial statements. We have periodically briefed our Audit Committee on our progress made towards adoption.

During the fourth quarter of 2017 we finalized our assessments over the impact that these new standards will have on our consolidated results of operations, financial position and disclosures. In adopting the previously mentioned ASUs, we expect the following significant changes in accounting principles:

(i)
Timing of revenue recognition for uninstalled materials - We currently recognize the majority of our revenue from the installation or construction of projects using the percentage-of-completion method of accounting, whereby revenue is recognized as we progress on the contract. The percentage-of-completion for each project is determined on an actual cost-to-estimated final cost basis. Under ASC 606, revenue will be recognized as the customer obtains control of the goods and services promised in the contract (i.e., performance obligations). The cost of uninstalled materials or equipment will generally be excluded from our measure of progress, unless specifically produced or manufactured for a project, because such costs are not considered to be a measure of progress, unless the materials or equipment are delivered and expected to be installed by the Company in 90 days or less.

(ii)
Deferral of incremental direct costs to obtaining a contract with a customer - We currently record certain incremental compensation (i.e., sales commissions) payable to our sales force as an expense when earned which is included in the measure of progress towards completion. Under ASC 606, we will continue to capitalize these costs and subsequently amortize the capitalized costs over a period of time that is consistent with the transfer of the related good or service to the customer. Capitalized costs, net of accumulated amortization, will be included in “Prepaid expenses and other current assets” and “Other assets”on our consolidated balance sheets. If the incremental cost incurred exceeds payments made, the accrued cost will be included in “Accrued expenses and other liabilities”.

(iii)
Timing of revenue recognition from renewable energy incentives - Under current accounting policies, we recognize revenue for SRECs and other renewable energy incentives when generated if we have a signed contract to sell those SRECs or renewable energy incentives to a third party (thus making the sale price fixed and determinable). Under ASC 606, we will recognize SREC and other renewable energy incentive revenues when the rights are transferred to a third party, which can be up to six months after generation.


37

Table of Contents                            



Revenue of approximately $9.1 million, that is reflected in the consolidated statement of income (loss) in 2017, will be recorded as a reduction in equity as an adjustment under the modified retrospective method. Additionally costs of approximately $2.7 million, that are reflected in the consolidate statement of income (loss) in 2017, will be recorded as an increase in equity in connection with the modified retrospective adjustment. In connection with the change in accounting treatment we estimate that we will record a net deferred tax asset of approximately $1.7 million. This is the result of timing differences in the recognition of revenue items and their associated costs for financial statement purposes versus the Tax Code. The cumulative impact of adopting the new accounting standard will result in a decrease in stockholders’ equity, net of tax, of approximately $4.7 million.
Intangibles-Goodwill and Other

In January 2017, the FASB issued ASU No. 2017-04, Intangibles-Goodwill and Other (Topic 350), which eliminates the requirement to compare the implied fair value of reporting unit goodwill with the carrying amount of that goodwill (commonly referred to as Step 2) from the goodwill impairment test. The new standard does not change how a goodwill impairment is identified. We will continue to perform our quantitative and qualitative goodwill impairment test by comparing the fair value of each reporting unit to its carrying amount, but if we are required to recognize a goodwill impairment charge, under the new standard the amount of the charge will be calculated by subtracting the reporting unit’s fair value from its carrying amount. Under the prior standard, if we were required to recognize a goodwill impairment charge, Step 2 required us to calculate the implied value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination and the amount of the charge was calculated by subtracting the reporting unit’s implied fair value of goodwill from its actual goodwill balance. The new standard is effective for interim and annual reporting periods beginning after December 15, 2019, with early adoption permitted, and should be applied prospectively from the date of adoption. We elected to adopt the new standard for future goodwill impairment tests at the beginning of the fourth quarter of 2017, because it significantly simplifies the evaluation of goodwill for impairment. See Note 3 to the consolidated financial statements for further details.

Derivatives and Hedging

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities, which improves the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities in its financial statements. ASU 2017-12 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within those annual reporting periods. Early adoption is permitted. We are currently evaluating the impact ASU 2017-12 will have on our consolidated financial statements.

Leases
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The guidance in this ASU supersedes the leasing guidance in Topic 840, Leases. Under the new guidance, lessees are required to recognize lease assets and lease liabilities on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We are currently evaluating the impact of adopting the new standard on its consolidated financial statements.
Stock Based Compensation Expense
In May 2017, the FASB issued ASU No. 2017-09, Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting. This new guidance amends the scope of modification accounting for share-based payment awards. ASU 2017-09 provide guidance on the types of changes to the terms or conditions of share-based payment awards to which an entity would be required to apply modification accounting under ASC 718. ASU 2017-09 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact of ASU 2017-09, but does not expect that the adoption of this guidance will have a significant impact on its consolidated financial statements.
In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation-Improvements to Employee Share-Based Payment Accounting. The guidance in this ASU involves several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and

38

Table of Contents                            



classification on the consolidated statement of cash flows. Under ASU 2016-09, income tax benefits and deficiencies are to be recognized as income tax expense or benefit in the consolidated statement of income (loss) and the tax effects of exercised or vested awards should be treated as discrete items in the reporting period in which they occur. Additionally, under ASU 2016-09, excess tax benefits should be classified along with other income tax cash flows as an operating activity. We adopted this guidance in the first quarter of fiscal 2017, and as a result of this adoption recorded a $4.0 million deferred tax asset and corresponding credit to retained earnings for excess tax benefits that had not previously been recognized because the related tax deductions had not reduced taxes payable. We have not changed our accounting policy in regards to forfeitures as a result of the adoption of this guidance. Our adoption of the new standard also resulted in the prospective classification of excess tax benefits as cash flows from operating activities in the same manner as other cash flows related to income taxes within the consolidated statements of cash flows. Based on the prospective method of adoption chosen, the classification of excess tax benefits within the consolidated statements of cash flows for prior periods presented has not been adjusted to reflect the change.
Consolidated Statements of Cash Flow
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. ASU 2016-15 eliminates diversity in practice in how certain cash receipts and cash payments are presented and classified in the consolidated statements of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact of ASU 2016-15, but do not expect that the adoption of this guidance will have a significant impact on our consolidated financial statements.
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 23), Restricted Cash. ASU 2016-18 requires restricted cash and cash equivalents to be included with cash and cash equivalents on the statement of cash flows. ASU 2016-18 is effective for annual reporting periods beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted. The guidance should be applied using a retrospective transition method for each period presented. We expect to adopt this guidance when effective. We are currently evaluating the impact ASU 2016-18 will have on our consolidated financial statements, and expect the ASU will modify the presentation of the consolidated statements of cash flows, but will not have a material impact on the consolidated statements of income, consolidated statements of comprehensive income (loss), consolidated statement of changes in redeemable non-controlling interests and stockholders’ equity and the consolidated balance sheets.

Results of Operations
The following table sets forth certain financial data from the consolidated statements of income (loss) expressed as a percentage of revenues for the periods indicated (in thousands):
 
Year Ended December 31,
 
2017
 
2016
 
2015
 
Dollar
 
% of
 
Dollar
 
% of
 
Dollar
 
% of
 
Amount
 
Revenues
 
Amount
 
Revenues
 
Amount
 
Revenues
Revenues
$
717,152

 
100.0
 %
 
$
651,227

 
100.0
%
 
$
630,832

 
100.0
 %
Cost of revenues
572,994

 
79.9
 %
 
516,883

 
79.4
%
 
513,768

 
81.4
 %
Gross profit
144,158

 
20.1
 %
 
134,344

 
20.6
%
 
117,064

 
18.6
 %
Selling, general and administrative expenses
107,570

 
15.0
 %
 
110,568

 
17.0
%
 
110,007

 
17.4
 %
Operating income
36,588

 
5.1
 %
 
23,776

 
3.7
%
 
7,057

 
1.1
 %
Other expenses, net
7,871

 
1.1
 %
 
7,409

 
1.1
%
 
6,765

 
1.1
 %
Income before provision (benefit) for income taxes
28,717

 
4.0
 %
 
16,367

 
2.5
%
 
292

 
 %
Income tax (benefit) provision
(4,791
)
 
(0.7
)%
 
4,370

 
0.7
%
 
4,976

 
0.8
 %
Net income (loss)
$
33,508

 
4.7
 %
 
$
11,997

 
1.8
%
 
$
(4,684
)
 
(0.7
)%
Net loss attributable to redeemable non-controlling interest
$
3,983

 
0.6
 %
 
$
35

 
%
 
$
5,528

 
0.9
 %
Net income attributable to common shareholders
$
37,491

 
5.2
 %
 
$
12,032

 
1.8
%
 
$
844

 
0.1
 %

39

Table of Contents                            



Revenues
The following table sets forth a comparison of our revenues for the periods indicated (in thousands):
 
Year Ended December 31,
 
Dollar
 
Percentage
 
2017
 
2016
 
Change
 
Change
Revenues
$
717,152

 
$
651,227

 
$
65,925

 
10.1
%
 
 
 
 
 
 
 
 
 
Year Ended December 31,
 
Dollar
 
Percentage
 
2016
 
2015
 
Change
 
Change
Revenues
$
651,227

 
$
630,832

 
$
20,395

 
3.2
%
Total revenues increased by $65.9 million, or 10.1%, from 2016 to 2017 primarily due to a $51.1 million increase in revenues from our U.S. Federal segment, a $4.8 million increase in revenues from our Non-solar Distributed Generation (“DG”) segment, a $13.4 million increase in revenues from our U.S. Regions segment and a $3.2 million from All Other. These increases were partially offset by a $6.6 million decrease in revenues from our Canada segment.
Total revenues increased by $20.4 million, or 3.2%, from 2015 to 2016 primarily due to a $50.4 million increase in revenues from our U.S. Federal segment, a $12.8 million increase in revenues from our Non-solar DG segment and a $1.2 million increase in revenues from our Canada segment. These increases were partially offset by a $29.3 million decrease in revenues from our U.S. Regions segment and a $14.7 million decrease in revenues from All Other.
Cost of Revenues and Gross Margin
The following table sets forth a comparison of our cost of revenues and gross profit for the periods indicated (in thousands):
 
Year Ended December 31,
 
Dollar
 
Percentage
 
2017
 
2016
 
Change
 
Change
Cost of revenues
$
572,994

 
$
516,883

 
$
56,111

 
10.9
%
Gross margin %
20.1
%
 
20.6
%
 

 


 
 
 
 
 
 
 
 
 
Year Ended December 31,
 
Dollar
 
Percentage
 
2016
 
2015
 
Change
 
Change
Cost of revenues
$
516,883

 
$
513,768

 
$
3,115

 
0.6
%
Gross margin %
20.6
%
 
18.6
%
 
 
 
 
Cost of revenues. Total cost of revenues increased $56.1 million, or 10.9%, from 2016 to 2017 due primarily to an increase in revenues from our U.S. Federal segment. Total cost of revenues increased by $3.1 million, or 0.6%, from 2015 to 2016 due primarily to the increase in revenues described above, partially offset by cost budget revisions and a reserve for potential future losses totaling $6.6 million on the significant project in our Canada segment recorded during 2015.
Gross margin. Gross margin decreased from 20.6% in 2016 to 20.1% in 2017. The decrease was due primarily to a mix of lower margin projects in our U.S. Regions segment. Gross margin increased from 18.6% in 2015 to 20.6% in 2016. The increase was due primarily to cost budget revisions on a significant project in our Canada segment during 2015, which resulted in a reduction in project to date revenues recognized and a reserve for potential future losses on the project recorded during 2015.

40

Table of Contents                            



Selling, General and Administrative Expenses
The following table sets forth a comparison of our selling, general and administrative expenses for the periods indicated (in thousands):
 
Year Ended December 31,
 
Dollar
 
Percentage
 
2017
 
2016
 
Change
 
Change
Selling, general and administrative expenses
$
107,570

 
$
110,568

 
$
(2,998
)
 
(2.7
)%
 
 
 
 
 
 
 
 
 
Year Ended December 31,
 
Dollar
 
Percentage
 
2016
 
2015
 
Change
 
Change
Selling, general and administrative expenses
$
110,568

 
$
110,007

 
$
561

 
0.5
 %
Selling, general and administrative expenses decreased $3.0 million or 2.7% to $107.6 million from 2016 to 2017 primarily due to $2.1 million in restructuring charges incurred during 2016, which included $1.9 million in bad debt expense in our Canada segment related to our restructuring efforts, and $2.9 million in write-downs, primarily in accounts receivable related to a customer that declared bankruptcy during 2016, offset by higher project development costs incurred during 2017.
Selling, general and administrative expenses were relatively flat at $110.6 million and $110.0 million in 2016 and 2015, respectively, with higher recurring expenses in 2016 offset by restructuring charges of $6.6 million in 2015.
Other Expenses, Net
Other expenses, net, includes gains and losses from derivatives and foreign currency transactions, interest income and expenses and amortization of deferred financing costs, net. Other expenses, net, increased from 2016 to 2017 by $0.5 million primarily due to an increase in interest expense offset by favorable foreign exchange rate fluctuations realized in 2017. Other expenses, net, increased from 2015 to 2016 by $0.6 million primarily due to an increase in interest expense and a decrease in interest income partially offset by favorable foreign exchange rate fluctuations realized in 2016.
Income Before Taxes
Income before taxes increased from 2016 to 2017 by $12.4 million, or 75.5% and increased from 2015 to 2016 by $16.1 million, or 5,505.1%, primarily due to the reasons described above.
Provision for Income Taxes
The provision (benefit) for income taxes is based on various rates set by federal, state, provincial and local authorities and is affected by permanent and temporary differences between financial accounting and tax reporting requirements. During 2017, we recognized an income tax benefit of $4.8 million, equivalent to an effective tax rate of (16.7)%. The effective tax rate decreased significantly primarily due to the change in the U.S. tax law. Specifically, on December 22, 2017, the U.S. federal government enacted comprehensive tax legislation (defined as the “Tax Act” above), which significantly revises the U.S. corporate income tax law by, among other things, lowering the U.S. federal corporate income tax rate from 35% to 21%, implementing a territorial tax system, imposing a one-time transition tax on foreign unremitted earnings, and setting limitations on deductibility of certain costs (e.g., interest expense).
Due to the complexities involved in accounting for the recently enacted 2017 Tax Act, the U.S. Securities and Exchange Commission’s SAB 118 requires that we include in our consolidated financial statements a reasonable estimate of the impact of the Tax Act on earnings to the extent such reasonable estimate has been determined. Accordingly, the U.S. provision for income tax for 2017 is based on the reasonable estimate guidance provided by SAB 118. We are continuing to assess the impact from the Tax Act and will record adjustments in 2018 if deemed necessary.
We recorded a deferred U.S. income tax benefit in 2017 of approximately $13.9 million, relating to the revaluation of deferred tax assets and liabilities resulting from the reduced federal tax rate in the recently enacted 2017 Tax Act. We also had a $6.3 million tax benefit resulting from investment tax credits associated with new renewable energy plants we placed in service in 2017. The investment tax credits to which we are entitled fluctuate from year to year based on the cost of the renewable energy plants that we place or expect to place in service in that year.
During 2016, we recognized an income tax provision of $4.4 million, or 26.7% of pretax income. The principal reasons for the difference between the statutory rate and the estimated annual effective rate for 2016 relate to the effects of the tax deduction under Internal Revenue Code Section 179D and production tax credits to which we are entitled from plants we own.

41

Table of Contents                            



The investment tax credits to which we are entitled fluctuate from year to year based on the cost of the renewable energy plants that we place or expect to place in service in that year. There were no owned renewable energy plants placed in service during the year and therefore no investment tax credits included in the rate for the year.
In addition, the tax deduction under Internal Revenue Code Section 179D was retroactively extended in the fourth quarter of 2015 and expired on December 31, 2016. The amount of the deduction to which we are entitled would vary in accordance with the number of qualifying projects completed during the year and any impact on our effective tax rate would further depend on the magnitude of the available deduction.
During 2015, we recognized an income tax provision of $5.0 million, or 1,704.1% of pretax income. The principal reason for the difference between the statutory rate and the annual effective rate were the effects of the valuation allowance required for the Canada losses and the effects of the net loss attributable to redeemable non-controlling interest partially offset by energy efficiency tax benefits.
Net Income (Loss)
Net income increased $21.5 million to a net income of $33.5 million for the twelve months ended December 31, 2017 compared to a net income of $12.0 million for the same period of 2016 for the reasons discussed above. Basic and diluted loss per share for the twelve months ended December 31, 2017 were $0.82 per share, an increase of $0.56 per share, compared to the same period of 2016.
Net income increased $16.7 million to a net income of $12.0 million for the twelve months ended December 31, 2016 compared to a net loss of $4.7 million for the same period of 2015 for the reasons discussed above. Basic and diluted loss per share for the twelve months ended December 31, 2016 were $0.26 per share, an increase of $0.24 per share, compared to the same period of 2015.
Business Segment Analysis (in thousands)
We report results under ASC 280, Segment Reporting. Our reportable segments for the year ended December 31, 2017 are U.S. Regions, U.S. Federal, Canada and Non-Solar Distributed Generation “DG”. Our U.S. Regions, U.S. Federal and Canada segments offer energy efficiency products and services, which include: the design, engineering and installation of equipment and other measures to improve the efficiency and control the operation of a facility’s energy infrastructure; renewable energy solutions and services, which include the construction of small-scale plants that we own or develop for customers that produce electricity, gas, heat or cooling from renewable sources of energy; and O&M services. Our Non-Solar DG segment sells electricity, processed renewable gas fuel, heat or cooling, produced from renewable sources of energy, other than solar, and generated by small-scale plants that we own; and O&M services for customer owned small-scale plants. The Company’s U.S. Regions segment also now includes certain small-scale solar grid-tie plants developed for customers previously included in our Non-Solar DG segment. Previously reported amounts have been restated for comparative purposes. The “All Other” category offers enterprise energy management services, consulting services and integrated-PV. These segments do not include results of other activities, such as corporate operating expenses not specifically allocated to the segments.
U.S. Regions
 
Year Ended December 31,
 
Dollar
 
Percentage
 
2017
 
2016
 
Change
 
Change
Revenues
$
290,196

 
$
276,766

 
$
13,430

 
4.9
 %
Income before taxes
$
13,865

 
$
19,802

 
$
(5,937
)
 
(30.0
)%
 
 
 
 
 

 
 
 
Year Ended December 31,
 
Dollar
 
Percentage
 
2016
 
2015
 
Change
 
Change
Revenues
$
276,766

 
$
306,086

 
$
(29,320
)
 
(9.6
)%
Income before taxes
$
19,802

 
$
25,856

 
$
(6,054
)
 
(23.4
)%
Revenues for the U.S. Regions segment increased by $13.4 million, or 4.9%, to $290.2 million for the twelve months ended December 31, 2017 compared to the same period of 2016 primarily due to an increase in project revenues attributed to an increase in the average project size of projects versus the prior year. Project revenues for the year ending December 31, 2017 were negatively impacted by unanticipated delays caused by Hurricane Harvey. These delays resulted in a shortfall in expected revenue of $12.5 million.

42

Table of Contents                            



Revenues for the U.S. Regions segment decreased by $29.3 million, or 9.6%, to $276.8 million for the twelve months ended December 31, 2016 compared to the same period of 2015 primarily due to a decrease in the number of projects.
Income before taxes for the U.S. Regions segment decreased by $5.9 million, or 30.0%, for the twelve months ended December 31, 2017 compared to the same period of 2016 primarily due to a decrease in gross profit attributed to the mix of lower margin projects. Results for the year ending December 31, 2017 were negatively impacted by unanticipated delays caused by Hurricane Harvey. These delays resulted in a shortfall in expected earnings of $5.5 million.
Income before taxes for the U.S. Regions segment decreased by $6.1 million, or 23.4%, for the twelve months ended December 31, 2016 compared to the same period of 2015 primarily due to the decrease in revenues described above, which resulted in decreased operating leverage.
U.S. Federal
 
Year Ended December 31,
 
Dollar
 
Percentage
 
2017
 
2016
 
Change
 
Change
Revenues
$
229,146

 
$
178,005

 
$
51,141

 
28.7
%
Income before taxes
$
29,261

 
$
22,246

 
$
7,015

 
31.5
%
 
 
 
 
 
 
 
 
 
Year Ended December 31,
 
Dollar
 
Percentage
 
2016
 
2015
 
Change
 
Change
Revenues
$
178,005

 
$
127,620

 
$
50,385

 
39.5
%
Income before taxes
$
22,246

 
$
16,676

 
$
5,570

 
33.4
%
Revenues for the U.S. Federal segment increased by $51.1 million, or 28.7%, to $229.1 million for the twelve months ended December 31, 2017 compared to the same period of 2016 primarily due to an increase in project revenues related to the increase in average project size of projects versus the prior year. This increase is primarily attributed to larger comprehensive projects which integrate multiple technologies.
Revenues for the U.S. Federal segment increased from 2015 to 2016 by $50.4 million, or 39.5%, to $178.0 million primarily due to an increase in the contract value of projects and the timing of revenue recognized as a result of the phase of projects.
Income before taxes for the U.S. Federal segment increased by $7.0 million, or 31.5%, to $29.3 million for the twelve months ended December 31, 2017 compared to the same period of 2016 primarily due to the increase in revenues described above partially offset by higher project development costs during 2017.
Income before taxes for the U.S. Federal segment increased from 2015 to 2016 by $5.6 million, or 33.4%, to $22.2 million. The increase was primarily due to the increase in revenues described above partially offset by a budget revision on a large project in the second quarter of 2016.
Canada
 
Year Ended December 31,
 
Dollar
 
Percentage
 
2017
 
2016
 
Change
 
Change
Revenues
$
43,803

 
$
50,448

 
$
(6,645
)
 
(13.2
)%
Income before taxes
$
1,751

 
$
(2,330
)
 
$
4,081

 
175.2
 %
 
 
 
 
 
 
 
 
 
Year Ended December 31,
 
Dollar
 
Percentage
 
2016
 
2015
 
Change
 
Change
Revenues
$
50,448

 
$
49,235

 
$
1,213

 
2.5
 %
Loss before taxes
$
(2,330
)
 
$
(15,449
)
 
$
13,119

 
84.9
 %
Revenues for the Canada segment decreased $6.6 million, or 13.2%, to $43.8 million for the twelve months ended December 31, 2017 compared to the same period of 2016 primarily due to a decrease in project revenues related to a significant low margin project which was completed during the third quarter of 2017.

43

Table of Contents                            



Revenues for the Canada segment increased from 2015 to 2016 by $1.2 million, or 2.5%, to $50.4 million, primarily due to cost budget revisions, during the first quarter of 2015, on a significant project which resulted in a reduction in project to date revenues recognized in 2015, as well as an increase in the size of active projects in 2016.
Income before taxes for the Canada segment increased $4.1 million, or 175.2%, to income of $1.8 million for the twelve months ended December 31, 2017 compared to a loss of $2.3 million for the same period of 2016 primarily due to the decrease in project revenues related to the significant low margin project described above, $1.9 million of bad debt expense related to our previously disclosed restructuring efforts in Canada recorded during 2016, and favorable foreign currency exchange rate fluctuations realized during 2017.
Loss before taxes for the Canada segment decreased from 2015 to 2016 by $13.1 million, or 84.9%, to a loss of $2.3 million primarily due to a reserve in 2015 for potential future losses on the significant project described above as well as improved gross margin on active projects in 2016, partially offset by $1.9 million of bad debt expense recorded during the second quarter of 2016.
Non-Solar DG
 
Year Ended December 31,
 
Dollar
 
Percentage
 
2017
 
2016
 
Change
 
Change
Revenues
$
79,220

 
$
74,395

 
$
4,825

 
6.5
 %
Income before taxes
$
8,115

 
$
9,301

 
$
(1,186
)
 
(12.8
)%
 
 
 
 
 
 
 
 
 
Year Ended December 31,
 
Dollar
 
Percentage
 
2016
 
2015
 
Change
 
Change
Revenues
$
74,395

 
$
61,626

 
$
12,769

 
20.7
 %
Income before taxes
$
9,301

 
$
7,609

 
$
1,692

 
22.2
 %
Revenues for the Non-solar DG segment increased $4.8 million, or 6.5%, to $79.2 million for the twelve months ended December 31, 2017 primarily due to an increase in project revenues from the development of small-scale plants we are constructing for customers and energy and incentive revenue from renewable gas assets the Company owns.
Revenues for the Non-solar DG segment increased from 2015 to 2016 by $12.8 million, or 20.7%, to $74.4 million primarily due to project revenues for the active development of small-scale plants we are constructing for customers during 2016, as compared to 2015 where no similar projects were in development.
Income before taxes for the Non-solar DG segment was relatively flat at $8.1 million for the twelve months ended December 31, 2017 compared to the same period of 2016 primarily due to the increase in revenues described above offset by increased interest expense attributed to an increase in project financing activity in 2017 for assets placed in service.
Income before taxes for the Non-solar DG segment increased by $1.7 million, or 22.2%, to $9.3 million     for the twelve months ended December 31, 2016 compared to the same period of 2015 primarily due to the increase in revenues described above.
All Other
 
Year Ended December 31,
 
Dollar
 
Percentage
 
2017
 
2016
 
Change
 
Change
Revenues
$
74,787

 
$
71,613

 
$
3,174

 
4.4
 %
Income (loss) before taxes
$
2,920

 
$
(427
)
 
$
3,347

 
783.8
 %
Unallocated corporate activity
$
(27,195
)
 
$
(32,225
)
 
$
5,030

 
15.6
 %
 
 
 
 
 
 
 
 
 
Year Ended December 31,
 
Dollar
 
Percentage
 
2016
 
2015
 
Change
 
Change
Revenues
$
71,613

 
$
86,265

 
$
(14,652
)
 
(17.0
)%
Loss before taxes
$
(427
)
 
$
(8,323
)
 
$
7,896

 
94.9
 %
Unallocated corporate activity
$
(32,225
)
 
$
(26,077
)
 
$
(6,148
)
 
(23.6
)%

44

Table of Contents                            



Revenues from all other segments increased $3.2 million, or 4.4%, to $74.8 million for the twelve months ended December 31, 2017 compared to the same period of 2016 primarily due to an increase in integrated-PV revenues attributed to sales to customers for oilfield microgrid applications, which rebounded in 2017, partially offset by a decrease in revenues from business assets sold during the first quarter of 2017.
Revenues from all other segments decreased from 2015 to 2016 by $14.7 million, or 17.0%, to $71.6 million primarily due to our anticipated decrease in integrated-PV sales as a result of a weakening of sales to customers for oilfield microgrid applications.
Income (loss) before taxes from all other segments increased $3.3 million to income of $2.9 million for the twelve months ended December 31, 2017 compared to a loss of $0.4 million for the same period of 2016 primarily due to to increased integrated-PV revenues as described above as well as improved profitability following the sale of business assets described above.
Loss before taxes from all other segments improved from 2015 to 2016 by $7.9 million from a loss of $8.3 million to a loss of $0.4 million primarily due to the positive impact of our 2015 restructuring efforts, including cost savings realized in our software group from a lower headcount.
Corporate activity includes all corporate level selling, general and administrative expenses and other expenses not allocated to the segments. We do not allocate any indirect expenses to the segments.
Corporate activity decreased by $5.0 million, or 15.6%, to $27.2 million primarily due to $3.2 million in reserves for certain amounts receivable from a customer who declared bankruptcy during 2016.
Corporate activity increased from 2015 to 2016 by $6.1 million, or 23.6%, to $32.2 million primarily due to $3.2 million in reserves for certain amounts receivable from a customer who declared bankruptcy.
Liquidity and Capital Resources
Sources of liquidity. Since inception, we have funded operations primarily through cash flow from operations, advances from Federal ESPC projects and various forms of debt.
The changes in cash and cash equivalents for the years ended December 31, 2017, 2016 and 2015 were as follows:
 
Year Ended December 31,
 
2017
 
2016
 
2015
Cash flows used in operating activities
$
(136,559
)
 
$
(58,073
)
 
$
(49,538
)
Cash flows used in investing activities
(88,042
)
 
(79,616
)
 
(51,829
)
Cash flows provided by financing activities
228,088

 
137,301

 
100,705

Effect of exchange rate changes on cash
168

 
(650
)
 
(1,455
)
Net increase (decrease) in cash and cash equivalents
$
3,655

 
$
(1,038
)
 
$
(2,117
)
We believe that cash and cash equivalents, and availability under our revolving senior secured credit facility, combined with our access to the credit markets, will be sufficient to fund our operations through at least March 6, 2019 and thereafter.
Proceeds from our Federal ESPC projects are generally received through agreements to sell the ESPC receivables related to certain ESPC contracts to third-party investors. We use the advances from the investors under these agreements to finance the projects. Until recourse to us ceases for the ESPC receivables transferred to the investor, upon final acceptance of the work by the government customer, we are the primary obligor for financing received. The transfers of receivables under these agreements do not qualify for sales accounting until final customer acceptance of the work, so the advances from the investors are not classified as operating cash flows. Cash draws that we receive under these ESPC agreements, $165.0 million, as of year ended December 31, 2017, are recorded as financing cash inflows. The use of the cash received under these arrangements is to pay project costs classified as operating cash flows $(157.5) million as of the year ending December 31, 2017. Due to the manner in which the ESPC contracts with the third-party investors are structured, our reported operating cash flows are materially impacted by the fact that operating cash flows only reflect the ESPC contract expenditure outflows and do not reflect any inflows from the corresponding contract revenues. Upon acceptance of the project by the federal customer the ESPC receivable and corresponding ESPC liability are removed from our consolidated balance sheet as a non-cash settlement. See

45

Table of Contents                            



Note 2, “Summary of Significant Accounting Policies”, to our Consolidated Financial Statements appearing in Item 8 of this Annual Report on Form 10-K.
Our service offering also includes the development, construction and operation of small-scale renewable energy plants. Small-scale renewable energy projects, or energy assets, can either be developed for the portfolio of assets that we own and operate or designed and built for customers. Expenditures related to projects that we own are recorded as cash outflows from investing activities. Expenditures related to projects that we build for customers are recorded as cash outflows from operating activities as cost of revenues.
Capital expenditures. Our total capital expenditures were $88.4 million, $76.0 million, and $52.7 million for the twelve months ended December 31, 2017, 2016 and 2015, respectively. Additionally, we invested $2.4 million in acquisitions of renewable energy plants, net of debt assumed, for the twelve months ended December 31, 2017, and $3.6 million in acquisitions for the twelve months ended December 31, 2016. We currently plan to invest approximately $60.0 million to $85.0 million in capital expenditures in 2018, principally for the development or acquisition of new renewable energy plants.
Cash flows from operating activities. Operating activities used $136.6 million of net cash during 2017. In 2017, we had net income of $33.5 million, which is net of non-cash compensation, depreciation, amortization, deferred income taxes and other non-cash items totaling $22.2 million. Net increases in restricted cash, costs and estimated earnings in excess of billings, prepaid expenses and other current assets, project development costs, and other assets and decreases in billings in excess of cost and estimated earnings, other liabilities and income taxes payable used $61.5 million. These uses of cash were partially offset by a decrease in accounts receivable including retainage, inventory, and increase in accounts payable and accrued expenses which provided $26.8 million. Federal ESPC receivables used $157.5 million. As described above, Federal ESPC operating cash flows only reflect the ESPC expenditure outflows and do not reflect any inflows from the corresponding contract revenues, which are recorded as cash inflows from financing activities due to the timing of the receipt of cash related to the assignment of the ESPC receivables to the third-party investors.
Operating activities used $58.1 million of net cash during 2016. In 2016, we had a net income of $12.0 million, which is net of non-cash compensation, depreciation, amortization, deferred income taxes and other non-cash items totaling $35.8 million. Net increases in restricted cash, prepaid expenses and other current assets, accounts receivable including retainage and other assets and decreases in accounts payable and accrued expenses and other current liabilities and other liabilities used $20.5 million. These uses of cash were partially offset by a decrease in inventory, costs and estimated earnings in excess of billings and billings in excess of cost and estimated earnings and project development costs and increases in income taxes payable which provided $31.5 million. Federal ESPC receivables used $116.8 million.
Operating activities provided $49.5 million of net cash during 2015. In 2015, we had a net loss of $4.7 million, which is net of non-cash compensation, depreciation, amortization, gains on sales of assets, deferred income taxes and other non-cash items totaling $37.2 million. Increases in restricted cash and increases in accounts payable and accrued expenses and other current liabilities and incomes taxes payable provided $30.6 million. However, net increases in accounts receivable including retainage, inventory, costs and estimated earnings in excess of billings and billings in excess of cost and estimated earnings, prepaid expenses and other current assets, project development costs and other assets and decreases in other liabilities used $39.3 million. Federal ESPC receivables used $73.2 million.
Cash flows from investing activities. Cash used for investing activities totaled $88.0 million during 2017 and consisted of capital investments of $88.0 million related to the development and acquisition of renewable energy plants and $2.9 million related to purchases of other property and equipment. Offsetting these amounts was $2.8 million in proceeds from the sale of assets from a business.
Cash used for investing activities totaled $79.6 million during 2016 and consisted of capital investments of $73.2 million related to the development of renewable energy plants, $2.8 million related to purchases of other property and equipment and $3.6 million related to acquisitions of renewable energy plants.
Cash used for investing activities totaled $51.8 million during 2015 and consisted of capital investments of $51.3 million related to the development of renewable energy plants and $1.3 million related to purchases of other property and equipment Offsetting these amounts was $0.9 million in proceeds from the sale of a project asset in Canada.
Cash flows from financing activities. Net cash provided by financing activities totaled $228.1 million during 2017 and included repayments of $54.2 million on long-term debt, payments of $2.9 million relating to financing fees, $3.4 million for the repurchase of stock and placed $2.1 million into restricted cash accounts. These uses of financing cash were offset by proceeds from long-term debt financing of $48.5 million, proceeds from sale-leaseback financings of $51.2 million, proceeds

46

Table of Contents                            



from redeemable non-controlling interest of $7.5 million, proceeds from our senior secured credit facility of $12.5 million, and exercises of options which provided $2.0 million. Proceeds from Federal ESPC projects and energy assets provided $169.0 million in cash.
Net cash provided by financing activities totaled $137.3 million during 2016 and included repayments of $14.0 million on long-term debt, payments of $1.9 million relating to financing fees and $6.4 million for the repurchase of stock. These uses of financing cash were offset by proceeds from long-term debt financing of $38.0 million, proceeds from sale-leaseback financings of $17.0 million, proceeds from redeemable non-controlling interest of $6.4 million, proceeds from our senior secured credit facility of $3.8 million, releases of restricted cash of $3.2 million and exercises of options, which provided $1.1 million. Proceeds from Federal ESPC projects provided $90.0 million in cash.
Net cash provided by financing activities totaled $100.7 million during 2015 and included repayments of $12.4 million on long-term debt, $5.7 million placed into restricted cash accounts and payments of $2.7 million relating to financing fees. These uses of financing cash were offset by proceeds from our senior secured credit facility of $6.3 million, exercises of options, which provided $1.2 million, proceeds from sale-leaseback financings of $12.5 million, proceeds from long-term debt financing of $17.7 million and proceeds from redeemable non-controlling interest of $6.0 million. Proceeds from Federal ESPC projects provided $78.0 million in cash.
We currently plan additional financings of $100.0 million to $110.0 million in 2018.
Senior Secured Credit Facility — Revolver and Term Loan
On June 30, 2015, we entered into a third amended and restated bank credit facility with two banks. The new credit facility replaces and extends our existing credit facility, which was scheduled to expire in accordance with its terms on June 30, 2016. The revolving credit and term loan facility mature on June 30, 2020, when all amounts will be due and payable in full. We expect to use the new credit facility for our general corporate purposes, including permitted acquisitions, refinancing of existing indebtedness and working capital. In July 2016, we entered into an amendment to the third amended and restated bank credit facility that amended the requirement of the total funded debt to EBITDA ratio. In November 2016, we entered into an additional amendment to the third amended and restated bank credit facility that increased the amount of the term loan under the credit facility by approximately $20.0 million to an aggregate of $30.0 million and extended the maturity date of the term loan from June 30, 2018 to June 30, 2020. In June 2017, we entered into an additional amendment to the third amended and restated bank credit facility that increased the amount available to be drawn on the revolving credit facility from $60.0 million to $75.0 million. This amendment also amended the requirement of the total funded debt to EBITDA ratio as described below.
The credit facility consists of a $75.0 million revolving credit facility and a $30.0 million term loan. The revolving credit facility may be increased by up to an additional $25.0 million at our option if lenders are willing to provide such increased commitments, subject to certain conditions. Up to $20.0 million of the revolving credit facility may be borrowed in Canadian dollars, Euros and Pounds Sterling. We are the sole borrower under the credit facility. The obligations under the credit facility are guaranteed by certain of our direct and indirect wholly owned domestic subsidiaries and are secured by a pledge of all of our and such of our subsidiary guarantors’ assets, other than the equity interests of certain subsidiaries and assets held in non-core subsidiaries (as defined in the agreement). At December 31, 2017 and 2016, $22.5 million and $28.5 million, was outstanding under the term loan, respectively. At December 31, 2017 and 2016, $27.6 million and $15.0 million was outstanding under the revolving credit facility, respectively. At December 31, 2017 funds of $38.9 million was available for the revolving credit facility.
The interest rate for borrowings under the credit facility is based on, at our option, either (1) a base rate equal to a margin of 0.5% or 0.25%, depending on our ratio of Total Funded Debt to EBITDA (each as defined in the agreement), over the highest of (a) the federal funds effective rate, plus 0.50% , (b) Bank of America’s prime rate and (c) a rate based on the London interbank deposit rate (“LIBOR”) plus 1.50%, or (2) the one-, two- three- or six-month LIBOR plus a margin of 2.00% or 1.75%, depending on our ratio of Total Funded Debt to EBITDA. A commitment fee of 0.375% is payable quarterly on the undrawn portion of the revolving credit facility. At December 31, 2017, the interest rate for borrowings under the revolving credit facility was 5.00% and the weighted average interest rate for borrowings under the term loan was 3.45%.
The revolving credit facility does not require amortization of principal. The term loan requires quarterly principal payments of $1.5 million, with the balance due at maturity. All borrowings may be paid before maturity in whole or in part at our option without penalty or premium, other than reimbursement of any breakage and deployment costs in the case of LIBOR borrowings.

47

Table of Contents                            



The credit facility limits our ability to, among other things: incur additional indebtedness; incur liens or guarantee obligations; merge, liquidate or dispose of assets; make acquisitions or other investments; enter into hedging agreements; pay dividends and make other distributions and engage in transactions with affiliates, except in the ordinary course of business on an arms’ length basis.
Under the credit facility, we may not invest cash or property in, or loan to, our non-core subsidiaries in aggregate amounts exceeding 49% of our consolidated stockholders’ equity. In addition, under the credit facility, we and our core subsidiaries must maintain the following financial covenants:
 
 
a ratio of total funded debt to EBITDA of less than 2.75 to 1.0 as of the end of each fiscal quarter ending September 30, 2016 and thereafter; and
 
 
a debt service coverage ratio (as defined in the agreement) of at least 1.5 to 1.0.
Any failure to comply with the financial or other covenants of the credit facility would not only prevent us from being able to borrow additional funds, but would constitute a default, permitting the lenders to, among other things, accelerate the amounts outstanding, including all accrued interest and unpaid fees, under the credit facility, to terminate the credit facility, and enforce liens against the collateral.
The credit facility also includes several other customary events of default, including a change in control, permitting the lenders to accelerate the indebtedness, terminate the credit facility, and enforce liens against the collateral.
As of December 31, 2017, we were in compliance with all of the financial and operational covenants in the senior credit facility. In addition, we do not consider it likely that we will fail to comply with these covenants for the next twelve months.
Project Financing
Construction and Term Loans. We have entered into a number of construction and term loan agreements for the purpose of constructing and owning certain renewable energy plants. The physical assets and the operating agreements related to the renewable energy plants are owned by wholly owned, single member special purpose subsidiaries. These construction and term loans are structured as project financings made directly to a subsidiary, and upon acceptance of a project, the related construction loan converts into a term loan. While we are required under GAAP to reflect these loans as liabilities on our consolidated balance sheet, they are generally non-recourse and not direct obligations of Ameresco, Inc. As of December 31, 2017, we had outstanding $117.8 million in aggregate principal amount under these loans with maturities at various dates from 2017 to 2034. Effective interest rates, after consideration for our interest rate swap contracts, ranged from 3.4% to 7.3%. As of December 31, 2016, we had outstanding $108.0 million in aggregate principal amount under these loans, bearing interest at rates ranging from 4.7% to 13.0% and maturing at various dates from 2017 to 2031. As of December 31, 2015, we had outstanding $87.5 million in aggregate principal amount under these loans, bearing interest at rates ranging from 4.7% to 7.3% and maturing at various dates from 2017 to 2028.
In September 2015, we entered into a credit and guaranty agreement for use in providing non-recourse financing for certain of its solar PV projects currently under construction. The credit and guaranty agreement provides for a $20.7 million construction-to-term loan credit facility and bears interest at a variable rate. On March 30, 2016, the construction loan was converted to a term loan. At December 31, 2017, $18.3 million was outstanding under the term loan. The variable rate for this loan at December 31, 2017 was 4.2%.
In August 2016, we entered into a credit and guaranty agreement with two banks for use in providing limited recourse financing for certain of its solar PV projects in operation. The credit and guaranty agreement provided for a term loan credit facility with an original principal balance of $4.8 million and bears interest at a fixed rate of 5.0%. At December 31, 2017, $4.6 million was outstanding under the term loan.
In November 2016, we entered into a construction loan agreement with a bank for use in providing non-recourse financing for certain solar PV projects currently under construction. The construction loan agreement provides for a $35.0 million construction facility that bears interest at a variable rate. The facility matures on June 30, 2018, and all remaining unpaid amounts outstanding under the facility will be due at that time. At December 31, 2017, $1.7 million was outstanding under the construction loan. The variable rate for this loan at December 31, 2017 was 6.75%. We have classified this debt as non-current as of December 31, 2017, due to our intention to refinance the variable rate construction loan to sale-leasebacks prior to the maturity date.

48

Table of Contents                            



In November 2016, we entered into a construction loan agreement with a bank for use in providing non-recourse financing for a certain natural gas to energy project currently under construction. The construction loan agreement provides for a $9.5 million construction facility. The facility matures on March 1, 2018, and all remaining unpaid amounts outstanding under the facility will be due at that time. The construction loan was paid in full during the year ended December 31, 2017, thus at December 31, 2017, no amount was outstanding under the construction loan.
In December 2016, we acquired a solar PV project currently under construction as well as an associated construction loan agreement with a bank for use in providing non-recourse financing for this acquired solar PV project currently under construction. The construction loan agreement provided for a $10.7 million construction facility and bore interest at a fixed rate of 13.0%. The facility matured on May 30, 2017, and all remaining unpaid amounts outstanding under the facility were paid at that time. We had previously classified this debt as non-current due to our intention to refinance the construction loan to a term loan prior to the maturity date. We did refinance the construction loan to a term loan during the year ended December 31, 2017. This construction loan contained a subjective acceleration clause that allowed the bank to call the debt, if a material adverse change occured. If exercised, the subjective acceleration clause provides for a 60-day notice period to repay the construction loan balance. The bank did not exercise the subjective acceleration clause during the term of the loan agreement.
In January 2017, we acquired two solar PV projects currently under construction as well as associated construction loan agreements with a bank for use in providing non-recourse financing for these acquired solar PV projects currently under construction. The construction loans agreements provided for construction facilities of $3.8 million and $4.0 million and both facilities bore interest at a fixed rate of 13.0%. These facilities matured on May 30, 2017 and May 26, 2017, respectively, and all remaining unpaid amounts outstanding under each respective facility were paid at those times. We had classified both construction loans as non-current due to the our intention to refinance the construction loans to term loans prior to the maturity dates. We did refinance the construction loans to a term loan during the year ended December 31, 2017. Each construction loan contained a subjective acceleration clause that allowed the bank to call the debt, if a material adverse change occurred. If exercised, the subjective acceleration clause provided for a 60-day notice period to repay the respective construction loan balance. The bank did not exercise the subjective acceleration clauses during the term of the loan agreement.
In March 2017, we entered into a credit agreement with a bank for use in providing non-recourse financing for a certain solar PV project in operation. The credit agreement provides for a $4.3 million construction-to-term-loan credit facility and bears interest at a fixed rate of 5.5% during the construction phase and 5.0% during the term loan phase, with interest payments due monthly. The construction loan automatically converts to a term loan on March 24, 2018 and matures on March 24, 2028, and all remaining unpaid amounts outstanding under the agreement will be due at that time. At December 31, 2017, $4.3 million was outstanding under the construction loan.
In April 2017, we entered into a non-recourse construction-to-term loan agreement with a municipal corporation to finance construction costs on a certain Biogas Facility project in development. The construction-to-term loan agreement provides for a $24.8 million facility and bears interest at a fixed rate of 4.5% during both the construction and term loan phases, with interest payments due monthly. The construction loan converts to a term loan upon completion of the Biogas Facility and matures ten years after the conversion date, with all remaining unpaid amounts outstanding under the agreement due at that time. At December 31, 2017, $13.3 million was outstanding under the construction loan.
In April 2017, we entered into a credit and guaranty agreement with a bank for use in providing limited recourse financing for certain of our solar PV projects in operation. The credit and guaranty agreement provided for a term loan credit facility with an original principal balance of $3.2 million and bears interest at a fixed rate of 5.6% with interest payments due in quarterly installments. The term loan matures on February 28, 2034, and all remaining unpaid amounts outstanding under the credit and guaranty agreement will be due at that time. At December 31, 2017, $3.2 million was outstanding under the term loan.
In June 2017, we entered into a loan agreement for use in providing non-recourse financing for certain of our solar PV projects currently in operation. The loan agreement provides for a $14 million term loan credit facility and bears interest at a variable rate, with interest payments due in quarterly installments. The term loan matures on December 15, 2027, and all remaining unpaid amounts outstanding under the facility will be due at that time. At December 31, 2017, $14.1 million was outstanding under the term loan. The variable rate for this loan at December 31, 2017 was 4.04%.
One loan, with an outstanding balance as of December 31, 2017 of $2.2 million, does require Ameresco, Inc. to provide assurance to the lender of the project performance. A second loan, entered into during 2012, with an outstanding balance at December 31, 2017 of $32.7 million, requires Ameresco, Inc. to provide assurance to the lender of reimbursement upon any recapture of certain renewable energy government cash grants upon the occurrence of events that cause the recapture of such grants.

49

Table of Contents                            



These construction and term loan agreements require us to comply with a variety of financial and operational covenants. As of December 31, 2017, we were in compliance with all of these financial and operational covenants. In addition, we do not consider it likely that we will fail to comply with these covenants during the term of these agreements.
Federal ESPC liabilities. We have arrangements with certain lenders to provide advances to us during the construction or installation of projects for certain customers, typically federal governmental entities, in exchange for our assignment to the lenders of our rights to the long-term receivables arising from the ESPCs related to such projects. These financings totaled $235.1 million and $133.0 million in principal amounts at December 31, 2017 and 2016, respectively. Under the terms of these financing arrangements, we are required to complete the construction or installation of the project in accordance with the contract with our customer, and the debt remains on our consolidated balance sheet until the completed project is accepted by the customer.
Sale-Leaseback. During the first quarter of 2015, we entered into an agreement with an investor which gives us the option to sell and contemporaneously lease back solar PV projects. In September 2016, we amended our agreement with the investor whereas the investor has committed up to a maximum combined funding amount of $100.0 million through June 30, 2017 on certain projects. In May 2017, we amended our agreement with the investor to extend the end date of the agreement to June 30, 2018. As of December 31, 2017, $23.3 million remained available under the lending commitment all though this amount is not expected to be used. During the year ended December 31, 2017, we sold twelve solar PV projects and in return received $47.2 million as part of this arrangement. Additionally, we had a second sale-lease back project which sold for $2.0 million. During the year ended December 31, 2016, we sold six solar PV projects and in return received $17.0 million as part of this arrangement. While we are required under GAAP to reflect these lease payments as liabilities on our consolidated balance sheet, they are generally non-recourse and not direct obligations of Ameresco, Inc., except that Ameresco, Inc. has guaranteed certain obligations relating to taxes and project warranties, operation and maintenance.
Contractual Obligations
The following table summarizes our significant contractual obligations and commitments as of December 31, 2017 (in thousands):
 
 
Payments due by Period
 
 
 
 
Less than
 
One to
 
Three to
 
More than
 
 
Total
 
One Year
 
Three Years
 
Five Years
 
Five Years
Senior Secured Credit Facility:
 
 
 
 
 
 
 
 
 
 
Revolver
 
$
27,580

 
$

 
$
27,580

 
$

 
$

Term Loan
 
22,500

 
6,000

 
16,500

 

 

Project Financing:
 
 
 
 
 
 
 
 
 
 
Construction and term loans
 
117,771

 
12,074

 
54,402

 
27,862

 
23,433

Federal ESPC liabilities(1)
 
235,088

 

 
235,088

 

 

Interest obligations(2)
 
71,973

 
10,749

 
17,568

 
13,307

 
30,349

Capital lease liabilities
 
35,013

 
4,300

 
13,623

 
4,009

 
13,081

Operating leases
 
26,886

 
5,549

 
8,540

 
5,630

 
7,166

Total
 
$
536,811

 
$
38,672

 
$
373,301

 
$
50,808

 
$
74,029

(1
)
 
Federal ESPC arrangements relate to the installation and construction of projects for certain customers, typically federal governmental entities, where we assign to third-party lenders our right to customer receivables. We are relieved of the liability, without making a payment, when the project is completed and accepted by the customer. We typically expect to be relieved of the liability between one and three years from the date of project construction commencement. The table does not include, for our Federal ESPC liability arrangements, the difference between the aggregate amount of the long-term customer receivables sold by us to the lender and the amount received by us from the lender for such sale.
 
 
 
(2
)
 
For both the revolving and term loan portions of our senior secured credit facility, the table above assumes that the variable interest rate in effect at December 31, 2017 remains constant for the term of the facility. Excludes interest on construction loans payable and lines of credit due to no stated payment terms.

50

Table of Contents                            



Off-Balance Sheet Arrangements
We did not have during the periods presented, and we do not currently have, any off-balance sheet arrangements, as defined under SEC rules, such as relationships with unconsolidated entities or financial partnerships, which are often referred to as structured finance or special purpose entities, established for the purpose of facilitating financing transactions that are not required to be reflected on our balance sheet. The Company from time to time issues letters of credit and performance bonds, with their third-party lenders, to provide collateral.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to changes in interest rates and foreign currency exchange rates because we finance certain operations through fixed and variable rate debt instruments and denominate our transactions in U.S. and Canadian dollars and British pounds sterling (“GBP”). Changes in these rates may have an impact on future cash flows and earnings. We manage these risks through normal operating and financing activities and, when deemed appropriate, through the use of derivative financial instruments.
Interest Rate Risk
We had cash and cash equivalents totaling $24.3 million as of December 31, 2017 and $20.6 million as of December 31, 2016. Our exposure to interest rate risk primarily relates to the interest expense paid on our senior secured credit facility.
Derivative Instruments
We do not enter into financial instruments for trading or speculative purposes. However, through our subsidiaries we do enter into derivative instruments for purposes other than trading purposes. Certain of the term loans that we use to finance our renewable energy projects bear variable interest rates that are indexed to short-term market rates. We have entered into interest rate swaps in connection with these term loans in order to seek to hedge our exposure to adverse changes in the applicable short-term market rate. In some instances, the conditions of our renewable energy project term loans require us to enter into interest rate swap agreements in order to mitigate our exposure to adverse movements in market interest rates. The interest rate swaps that we have entered into qualify and have been designated as fair value hedges. See Note 2 of “Notes to Consolidated Financial Statements” included in Item 8 of this Annual Report on Form 10-K.
By using derivative instruments, we are subject to credit and market risk. The fair market value of the derivative instruments is determined by using valuation models whose inputs are derived using market observable inputs, including interest rate yield curves, and reflects the asset or liability position as of the end of each reporting period. When the fair value of a derivative contract is positive, the counterparty owes us, thus creating a receivable risk for us. We are exposed to counterparty credit risk in the event of non-performance by counterparties to our derivative agreements. We minimize counterparty credit (or repayment) risk by entering into transactions with major financial institutions of investment grade credit rating.
Our exposure to market interest rate risk is not hedged in a manner that completely eliminates the effects of changing market conditions on earnings or cash flow.
Foreign Currency Risk
We have revenues, expenses, assets and liabilities that are denominated in foreign currencies, principally the Canadian dollar and British pound sterling (“GBP”). Also, a significant number of employees are located in Canada and the U.K., and our subsidiaries in those countries transact business in those respective currencies. As a result, we have designated the Canadian dollar as the functional currency for Canadian operations. Similarly, the GBP has been designated as the functional currency for our operations in the U.K. When we consolidate the operations of these foreign subsidiaries into our financial results, because we report our results in U.S. dollars, we are required to translate the financial results and position of our foreign subsidiaries from their respective functional currencies into U.S. dollars. We translate the revenues, expenses, gains, and losses from our Canadian and U.K. subsidiaries into U.S. dollars using a weighted average exchange rate for the applicable fiscal period. We translate the assets and liabilities of our Canadian and U.K. subsidiaries into U.S. dollars at the exchange rate in effect at the applicable balance sheet date. Translation adjustments are not included in determining net income for the period but are disclosed and accumulated in a separate component of consolidated equity until sale or until a complete or substantially complete liquidation of the net investment in our foreign subsidiary takes place. Changes in the values of these items from one period to the next which result from exchange rate fluctuations are recorded in our consolidated statements of changes in stockholders’ equity as accumulated other comprehensive loss. For the year ended December 31, 2017, due to the strengthening

51

Table of Contents                            



of the Canadian dollar versus the U.S. dollar, our foreign currency translation resulted in a gain of $0.7 million which we recorded as a increase in accumulated other comprehensive income. For the year ended December 31, 2016, due to the strengthening of the U.S. dollar versus the GBP, our foreign currency translation resulted in a loss of $1.9 million, which we recorded as a decrease in accumulated other comprehensive loss.
As a consequence, gross profit, operating results, profitability and cash flows are impacted by relative changes in the value of the Canadian dollar and GBP. We have not repatriated earnings from our foreign subsidiaries, but have elected to invest in new business opportunities there. See Note 8, “Income Taxes” to our consolidated financial statements appearing in Item 8 of this Annual Report on Form 10-K. We do not hedge our exposure to foreign currency exchange risk.

52

Table of Contents                            




Item 8. Financial Statements and Supplementary Data
AMERESCO, INC.
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share amounts)
 
December 31,
 
2017
 
2016
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
24,262

 
$
20,607

Restricted cash
15,751

 
12,299

Accounts receivable, net
85,121

 
85,354

Accounts receivable retainage, net
17,484

 
17,465

Costs and estimated earnings in excess of billings
104,852

 
56,914

Inventory, net
8,139

 
12,104

Prepaid expenses and other current assets
14,037

 
11,732

Income tax receivable
6,053

 
406

Project development costs
11,379

 
9,180

Total current assets
287,078

 
226,061

Federal ESPC receivable
248,917

 
158,209

Property and equipment, net
5,303

 
5,018

Energy assets, net
356,443

 
319,758

Goodwill
56,135

 
57,976

Intangible assets, net
2,440

 
3,931

Other assets
27,635

 
26,328

Total assets
$
983,951

 
$
797,281

 
 
 
 
LIABILITIES, REDEEMABLE NON-CONTROLLING INTERESTS AND STOCKHOLDERS’ EQUITY
Current liabilities:
 
 
 
Current portions of long-term debt and capital lease liabilities
$
22,375

 
$
19,292

Accounts payable
135,881

 
126,583

Accrued expenses and other current liabilities
23,260

 
22,763

Billings in excess of cost and estimated earnings
19,871

 
21,189

Income taxes payable
755

 
775

Total current liabilities
202,142

 
190,602

Long-term debt and capital lease liabilities, less current portions and net of deferred financing fees
173,237

 
140,593

Federal ESPC liabilities
235,088

 
133,003

Deferred income taxes, net
584

 
9,037

Deferred grant income
7,188

 
7,739

Other liabilities
18,754

 
15,154

Commitments and contingencies (Note 13)

 

Redeemable non-controlling interests
10,338

 
6,847

The accompanying notes are an integral part of these consolidated financial statements.

53

Table of Contents                            



AMERESCO, INC.
CONSOLIDATED BALANCE SHEETS — (Continued)
(in thousands, except share and per share amounts)
 
December 31,
 
2017
 
2016
Stockholders’ equity:
 
 
 
Preferred stock, $0.0001 par value, 5,000,000 shares authorized, no shares issued and outstanding at December 31, 2017 and 2016
$

 
$

Class A common stock, $0.0001 par value, 500,000,000 shares authorized, 29,406,315 shares issued and 27,533,049 shares outstanding at December 31, 2017, 29,005,284 shares issued and 27,706,866 shares outstanding at December 31, 2016
3

 
3

Class B common stock, $0.0001 par value, 144,000,000 shares authorized, 18,000,000 shares issued and outstanding at December 31, 2017 and 2016
2

 
2

Additional paid-in capital
116,196

 
112,926

Retained earnings
235,844

 
194,353

Accumulated other comprehensive loss, net
(5,626
)
 
(6,591