Business Radar | Ameresco, Inc. | Annual Report of 2013

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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, 2013 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 (I.R.S. Employer Incorporation or Organization) 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, New York Stock Exchange par value $0.0001 per share 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 or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Large Accelerated Filer o Accelerated Filer þ Non-accelerated filer o Smaller reporting company o (Do not check if a smaller reporting company) 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 28, 2013, the last business day of the registrant’s most recently completed second fiscal quarter, was $191,266,010. 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 3, 2014 Class A Common Stock, $0.0001 par value per share 27,925,817 Class B Common Stock, $0.0001 par value per share 18,000,000 DOCUMENTS INCORPORATED BY REFERENCE Portions of the definitive proxy statement for our 2014 annual meeting of stockholders are incorporated by reference into Part III.

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AMERESCO, INC. TABLE OF CONTENTS Page PART I ITEM 1. BUSINESS 1 ITEM 1A. RISK FACTORS 6 ITEM 1B. UNRESOLVED STAFF COMMENTS 19 ITEM 2. PROPERTIES 19 ITEM 3. LEGAL PROCEEDINGS 19 ITEM 4. MINE SAFETY DISCLOSURES 19 PART II ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER 20 MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES ITEM 6. SELECTED FINANCIAL DATA 22 ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND 24 RESULTS OF OPERATIONS ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 45 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 47 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING 86 AND FINANCIAL DISCLOSURE ITEM 9A. CONTROLS AND PROCEDURES 86 ITEM 9B. OTHER INFORMATION 88 PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 88 ITEM 11. EXECUTIVE COMPENSATION 89 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 89 AND RELATED STOCKHOLDER MATTERS ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR 89 INDEPENDENCE ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES 89 PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 90 SIGNATURES 91 EXHIBIT INDEX 92

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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 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 uses of future earnings; • 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.

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Table of Contents PART I Item 1. Business Company Overview Founded in 2000, Ameresco, Inc. is a leading independent provider of comprehensive services, energy efficiency, infrastructure upgrades, asset sustainability and renewable energy solutions for facilities throughout North America. Ameresco’s services include upgrades to a facility’s energy infrastructure and the development, construction 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 provides local expertise through its 70 offices in 33 states, five Canadian provinces and the United Kingdom. Ameresco has more than 900 employees. 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. In 2013, our acquisition of Ennovate Corporation (“Ennovate”), in the first quarter increased our footprint and penetration in the Rocky Mountain area; and our acquisition of energy management consulting companies The Energy Services Partnership Limited and ESP Response Limited (together “ESP”), in the second quarter added a local presence in the United Kingdom, expertise and seasoned energy industry professionals to support multi-national customers of our enterprise energy management service offerings. 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 typically include a variety of measures customized for the facility and designed to improve the efficiency of major building systems, such as heating, ventilation, air conditioning and lighting systems. 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 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 have been constructed adjacent to landfills and use landfill gas (“LFG”) to generate energy. Our largest renewable energy project for a customer uses biomass as the primary source of energy. In the case of the plants that we own, the electricity, thermal energy or processed LFG 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. As of December 31, 2013, we had backlog of approximately $362 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, which we sometimes refer to as awarded projects, with estimated total future revenues of an additional $993 million. As of December 31, 2012, we had backlog of approximately $367 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 do not yet have signed customer contracts, with estimated total future revenues of an additional $1.1 billion. As of December 31, 2011, we had backlog of approximately $478 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 $741 million. The contracts reflected in our fully-contracted backlog typically have a construction period of 12 to 24 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 a customer contract has been signed and we treat the project as fully-contracted backlog. Recently, awarded projects typically have been taking 12 to 16 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 projects ultimately have resulted in a signed contract. 1

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Table of Contents 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 was $388 million, $457 million and $598 million in 2013, 2012 and 2011, respectively. We also expect to realize recurring revenues both from long-term O&M contracts and energy supply contracts for renewable energy plants that we own. In addition, we expect to generate revenues from solar products and services, consulting services and enterprise energy management services. Revenues generated from O&M, energy supply contracts, solar products and services, consulting services and enterprise energy management services were $186 million, $174 million and $130 million in 2013, 2012 and 2011, respectively. Ameresco’s Services and Products Our principle service is energy efficiency projects, which entails the design, engineering and installation of, and the arranging of financing for, equipment to improve the energy efficiency, and control the operation, of a building’s heating, ventilation, cooling and lighting systems. In certain projects, we also design and construct a central plant or cogeneration system providing power, heat and/or cooling to a building. 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. After an energy efficiency 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 plants. For larger projects, we often maintain staff on-site to perform these services. Our service offering also includes the development, construction and operation of, and the arrangement of financing for, small-scale renewable energy plants. Small-scale renewable energy projects can either be developed for the portfolio of assets that we own and operate or designed and built for customers. We have constructed and are currently designing and constructing a wide range of renewable energy plants using LFG, wastewater treatment biogas, solar, wind, biomass, other bio-derived fuels and hydro sources of energy. Most of our renewable energy projects to date have involved the generation of electricity from 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. As of December 31, 2013, we owned and operated 41 small-scale renewable energy plants and solar photovoltaic (“PV”) installations. Of the owned plants, 21 are renewable LFG plants, two are wastewater biogas plants, and 18 are solar PV installations. The 41 small-scale renewable energy plants and solar PV installations that we own have the capacity to generate electricity or deliver LFG producing an aggregate of more than 115 megawatt equivalents. 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. 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 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 2

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Table of Contents 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 an IDIQ agreement with the U.S. Department of Energy, expiring in 2019, with an aggregate maximum potential ordering amount of $5 billion. 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 40 months. We identify project opportunities through referrals, requests for proposals (“RFPs”), conferences, web searches, telemarketing and repeat business from existing customers. Our direct sales force develops and follows up on customer leads and, in some cases, works with customers to develop their RFPs. By working with customers prior to the issuance of an RFP, we can gain a deeper understanding of the customers’ needs and the scope of the potential project. As of December 31, 2013, we had 143 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 read and analyze the customer’s utility bill and other energy-related expenses. 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. Customers In 2013, we served more than 1,000 customers in 49 states in the United States, the District of Columbia, six Canadian provinces, and the United Kingdom. Historically, including for the years ended December 31, 2013, 2012 and 2011 more than 80% of 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 12.3%, 11.6% and 19.9% of our consolidated revenues for the years ended December 31, 2013, 2012 and 2011, respectively. For the year ended December 31, 2013 our largest 20 customers accounted for approximately 36% of our total revenues. 3

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Table of Contents Our 20 largest customers for the year ended December 31, 2013, by revenues, in alphabetical order, were: Alameda Municipal Power (Alameda, California) Arizona State University (Tempe, Arizona) British Columbia Housing Authority (Burnaby, British Columbia) Edmonton District School Board (Edmonton, Alberta) Fall River Housing Authority (Fall River, Massachusetts) Hamilton County (Cincinnati, Ohio) Hazelwood School District (Saint Louis, Missouri) Hoosier Energy (Bloomington, Indiana) North Carolina State University (Raleigh, North Carolina) Philadelphia Water Department (Philadelphia, Pennsylvania) Rainbow District School Board (Sudbury, Ontario) Town of Acton (Acton, Massachusetts) Town of Dartmouth (Dartmouth, Massachusetts) U.S. Architect of Capitol - U.S. Senate Building (Washington, D.C.) U.S. Army - Adelphi Laboratory Center (Adelphi, Maryland) U.S. Army - Tobyhanna Army Depot (Tobyhanna, Pennsylvania) U.S. Department of Energy - Savannah River Site (Aiken, South Carolina) U.S. General Services Administration (Washington, D.C.) University City School District (University City, Missouri) University of Illinois (Chicago, Illinois) 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 include Chevron Energy Solutions, Constellation Energy, Honeywell, Johnson Controls, NORESCO, Siemens Building Technologies, TAC Energy Solutions, and Trane. 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. For the sale of solar energy products and systems, we face numerous competitors ranging from small web-based companies that sell components to PV module manufacturers and other multi-national corporations that sell both products and systems. 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. 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. 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. 4

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Table of Contents 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, operation, and sale of power generation facilities may be subject to regulation under 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 by 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, 2013, we had a total of 976 employees in offices located in 33 states, five Canadian provinces and the United Kingdom. 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 Notes 13 and 17, respectively, of “Notes to Consolidated Financial Statements” included in Item 8 of this Annual Report on Form 10-K, which information is incorporated herein by reference. 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 5

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Table of Contents (“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 3, 2014 and their principal positions. Name Age Position (s) George P. Sakellaris 67 Chairman of the Board of Directors, President and Chief Executive Officer David J. Anderson 53 Executive Vice President, Business Development and Director Michael T. Bakas 45 Senior Vice President, Renewable Energy David J. Corrsin 55 Executive Vice President, General Counsel and Secretary and Director Joseph P. DeManche 57 Executive Vice President, Engineering and Operations Mario Iusi 55 President, Ameresco Canada Louis P. Maltezos 47 Executive Vice President and General Manager, Central Region Andrew B. Spence 57 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, business development, as well as a director, since 2000. Michael T. Bakas: Mr. Bakas has served as our senior vice president, renewable energy, since March 2010. From 2000 to February 2010, he was our vice president, renewable energy. David J. Corrsin: Mr. Corrsin has served as our executive vice president, general counsel and secretary, as well as a director, since 2000. Joseph P. DeManche: Mr. DeManche has served as our executive vice president, engineering and operations since 2002. Mario Iusi: Mr. Iusi has served as president of Ameresco Canada since 2002. Louis P. Maltezos: Mr. Maltezos has served as our executive vice president and general manager, central region, since April 2009. From 2004 until April 2009, Mr. Maltezos was our vice president and general manager, midwest region. Andrew B. Spence: Mr. Spence has served as our vice president, chief financial officer and treasurer since 2002. 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 6

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Table of Contents 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 40 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. Beginning in 2012, we have observed increased use of outside consultants and advisors by our customers, which has resulted in a lengthening of the 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 site with high winds, 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. We may not recognize all revenues from our backlog or receive all payments anticipated under awarded projects and customer contracts. As of December 31, 2013, we had backlog of approximately $362 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, which we sometimes refer to as awarded projects, with estimated total future revenues of an additional $993 million. As of December 31, 2012, we had fully-contracted backlog of approximately $367 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 $1.1 billion. As of December 31, 2011, we had fully-contracted backlog of approximately $478 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 $741 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. 7

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Table of Contents 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. 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, 2013, 2012 and 2011, more than 80% 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 forseeable 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. 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 • 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 8

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Table of Contents 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 credit facilities and debt instruments contain financial and operating restrictions that may limit our business activities and our access to credit. Provisions in our credit facilities and debt instruments 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 $60 million revolving senior secured credit facility that matures in June 2016. This facility may not be sufficient to meet our needs as our business grows, and we may be unable to expand it if necessary on acceptable terms, or at all. Availability under the revolving credit facility has been based on 2.0 times our EBITDA for the preceding four quarters and we are required to maintain a minimum EBITDA. EBITDA for purposes of the facility excludes the results of renewable energy projects that we own and for which financing from others remains outstanding. In light of our recent 2013 results, we recently amended the facility to waive the minimum EBITDA requirement for 2013 and to modify that minimum amount as well as financial ratios related to EBITDA during 2014 to accommodate the lagged effect of 2013 results on those requirements. Principally, the amendment: • reduces the required minimum EBITDA amount to $16.5 million for the four consecutive fiscal quarters ended March 31, 2014, $22.0 million for the four consecutive fiscal quarters ended June 30, 2014, $24.0 million for the four consecutive fiscal quarters ended September 30, 2014, and $27.0 million for the four consecutive fiscal quarters ended December 31, 2014 and thereafter; and • increases the maximum ratio of total funded debt to EBITDA as of the end of each fiscal quarter to 2.5 to 1.0 for March 31, 2014 and 2.25 to 1.0 for June 30, 2014, returning to 2.0 to 1.0 for September 30, 2014 and thereafter. Although we do not consider it likely that we will fail to comply with 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 facilities and debt instruments. In addition to preventing additional borrowings under these agreements, an event of default, if not cured or waived, may result in the acceleration of the maturity of indebtedness outstanding under these agreements, 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. 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. 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. 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 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. 9

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Table of Contents 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 expired at the end of the year in 2013; and certain investment credits relating to energy efficiency are scheduled to expire at the end of the year in 2016. Further, there are increasing calls for “comprehensive tax reform,” which could significantly alter the existing tax code, including the removal of these credits prior to their scheduled expiration. If these deductions are not reinstated, or these credits expire without being extended, or otherwise are eliminated, our effective tax rate would increase, which could increase our income tax expense and reduce our net income. 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 2009 through 2011 are currently under audit. 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 10

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Table of Contents installation. A whole building-level commitment requires measurement and verification of increased energy efficiency 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. 11

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Table of Contents 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. 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 12

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Table of Contents • other events outside of our control. 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 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; • 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; 13

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Table of Contents • 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 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 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 an IDIQ agreement with the U.S. Department of Energy that expires in 2019. 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 ownership requirements) that are exempt from regulations under PUHCA, most provisions of the FPA and state rate 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 14

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Table of Contents 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’ 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 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 significant portion of our revenues from operations in Canada, 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; 15

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Table of Contents • 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; • 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. We have identified a material weakness in our internal control over financial reporting. If we fail to remediate this material weakness and maintain proper and effective internal controls, our ability to produce accurate and timely financial statements could be impaired, which could adversely affect our operating results, our ability to operate our business and investors’ and customers’ views of us. In connection with our fiscal 2013 audit, we concluded that we did not have adequate processes to ensure timely preparation and reviews necessary to provide reasonable assurance that financial statements and related disclosures could be prepared in accordance with generally accepted accounting principles and recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. For a discussion of the material weakness and our remediation efforts during 2013 as well as ongoing remediation efforts, see Item 9A, Controls and Procedures, of this Annual Report on Form 10-K. We cannot assure you that our efforts to fully remediate this internal control weakness will be successful or that a similar material weakness will not recur. If we fail to maintain our internal control over financial reporting, we may be unable to report our financial results timely and accurately, and we may be less likely to prevent fraud. In addition, such failure could increase our operating costs, materially impair our ability to operate our business, result in SEC investigations and penalties and lead to the delisting of our common stock from the New York Stock Exchange (“NYSE”). The resulting damage to our reputation in the marketplace and our financial credibility could significantly impair our sales and marketing efforts with customers. Further, investors’ perceptions that our internal controls are inadequate or that we are unable to produce accurate financial statements could adversely affect the market price of our Class A common stock. 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. 16

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Table of Contents 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. 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 significant portion of our total revenues are generated by our Canadian subsidiary, Ameresco Canada. Changes in exchange rates between the Canadian dollar and the U.S. dollar may adversely affect our operating results. We may be liable for duties on certain solar products imported from the People’s Republic of China (“PRC”). On October 10, 2012, the U.S. Department of Commerce, or Commerce, announced its final determination to impose anti-dumping and countervailing duties of 249.96%, as applied to us, and 15.24%, respectively, on the value of imports of solar cells manufactured in the PRC, including solar modules containing such cells. Under Commerce’s determination, the anti-dumping and countervailing duties both were to apply retroactively 90 days from the respective date each first was published to February 25, 2012 and December 21, 2011, respectively. We estimate that we have received shipments of solar modules subject to these duties with an aggregate value of approximately $3.4 million, comprising approximately $2.2 million relating to shipments 17

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Table of Contents received during the 90-day anti-dumping retroactive period and $1.2 million relating to shipments received since May 25, 2012. On November 7, 2012, the International Trade Commission announced its final determination upholding the duties, but eliminating the retroactive periods. There remain procedural avenues for seeking a separate and reduced anti-dumping duty rate, several of which have been granted at a rate of approximately 26%. As of July 2012, we have ceased imports of solar modules containing PRC solar cells, and have arranged for production of modules utilizing non-PRC cells, thus eliminating the imposition of these duties on further shipments. In addition, we are monitoring and evaluating our alternatives for obtaining a separate and reduced anti-dumping duty rate for solar modules previously imported, though we can provide no assurance that we will obtain such a reduced rate. Depending on whether the maximum anti-dumping duty rate of 249.96% or some lower rate applies, we may be liable for combined duties of up to approximately $3.3 million. 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 79% 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. 18

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Table of Contents Item 1B. Unresolved Staff Comments None. Item 2. Properties Our corporate headquarters is located in Framingham, Massachusetts, where we occupy approximately 23,000 square feet under a lease expiring on June 30, 2017. We occupy ten regional offices in Tempe, Arizona; Islandia, New York; Oak Brook, Illinois; Columbia, Maryland; Charlotte, North Carolina; Knoxville, Tennessee; Tomball, Texas; Spokane, Washington; North York, Ontario and Burlington, Ontario, each less than 25,000 square feet, under lease or sublease agreements. In addition, we lease space, typically less space, for 60 field offices throughout North America. We also own 41 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 12, 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. 19

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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. 2013 2012 High Low High Low First Quarter $ 9.98 $ 6.70 $ 14.73 $ 12.55 Second Quarter 9.65 7.04 13.95 10.51 Third Quarter 10.19 8.31 13.03 10.63 Fourth Quarter 10.76 8.46 12.12 8.29 The closing sale price of our Class A common stock was $9.99 on March 3, 2014, and according to the records of our transfer agent, there were 18 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, and the Ameresco 2010 Annuity Trust, 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. Stock Performance Graph The following performance graph and related information shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulations 14A or 14C, or to the liabilities of Section 18 of the Exchange Act, 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 Ameresco specifically requests that such information be treated as soliciting material or specifically incorporates it by reference into a filing under the Securities Act or the Exchange Act. The following graph compares the cumulative 41-month 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 July 22, 2010, and in each of the indexes on June 30, 2010 and its relative performance is tracked through December 31, 2013. 20

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Table of Contents COMPARISON OF 41 MONTH CUMULATIVE TOTAL RETURN* Among Ameresco, Inc., the Russell 2000 Index and the NASDAQ Clean Edge Green Energy Index *$100 invested on July 22, 2010 in our Class A common stock or June 30, 2010 in respective index, including reinvestment of dividends. Fiscal year ending December 31, 2013. 7/22/2010 12/31/2011 12/31/2012 12/31/2013 Ameresco, Inc. $100.00 $134.91 $96.46 $94.99 Russell 2000 Index $100.00 $123.98 $144.25 $200.24 NASDAQ Clean Edge $100.00 $79.56 $77.91 $145.27 Green Energy Index Shareholder returns over the indicated period should not be considered indicative of future shareholder returns. 21

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Table of Contents 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 derived the consolidated statements of income data for the years ended December 31, 2013, 2012, and 2011 and the consolidated balance sheet data at December 31, 2013 and 2012 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 data for the years ended December 31, 2010 and 2009, and the consolidated balance sheet data at December 31, 2011, 2010, and 2009, 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. Year Ended December 31, 2013 2012 2011 2010 2009 (In thousands, except share and per share data) Consolidated Statements of Income Data: Revenues(1) $ 574,171 $ 631,171 $ 728,200 $ 618,226 $ 428,517 Cost of revenues 470,846 503,024 593,154 507,524 348,817 Gross profit 103,325 128,147 135,046 110,702 79,700 Selling, general and administrative expenses 96,693 98,474 84,360 64,710 54,406 Goodwill impairment — 1,016 — — — Operating income 6,632 28,657 50,686 45,992 25,294 Other expenses (income), net 3,873 4,050 6,506 6,293 (1,563) Income before provision for income taxes 2,759 24,607 44,180 39,699 26,857 Income tax provision 345 6,247 10,767 12,186 6,950 Net income $ 2,414 $ 18,360 $ 33,413 $ 27,513 $ 19,907 Net income per share attributable to common shareholders: Basic(2) $ 0.05 $ 0.41 $ 0.78 $ 1.07 $ 1.99 Diluted $ 0.05 $ 0.40 $ 0.75 $ 0.66 $ 0.61 Weighted average common shares outstanding: Basic(2) 45,560,078 44,649,275 42,587,818 25,728,314 9,991,912 Diluted 46,419,199 45,995,463 44,707,132 41,513,482 32,705,617 Other Operating Data: Adjusted EBITDA(3) $ 29,906 $ 52,364 $ 67,560 $ 59,910 $ 35,097 22

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Table of Contents As of December 31, 2013 2012 2011 2010 2009 (In thousands) Consolidated Balance Sheet Data: Cash and cash equivalents $ 17,171 $ 63,348 $ 26,277 $ 44,691 $ 47,928 Current assets 249,832 297,843 283,062 211,710 171,772 Total assets 604,660 675,472 645,597 584,407 375,545 Current liabilities 131,201 148,889 148,268 142,587 132,330 Long-term debt, less current portion 103,222 109,079 86,754 43,417 69,396 Federal ESPC liabilities(4) 44,297 92,843 109,648 158,992 33,411 Subordinated debt — — — — 2,999 Total stockholders’ equity $ 276,805 $ 261,819 $ 236,421 $ 195,052 $ 102,770 (1) “Revenues” for 2011 reflects approximately $8.9 million and $27.8 million attributable to our acquisitions in the third quarter of 2011 of AEG and Ameresco Southwest, respectively. (2) “Net income per share attributable to common shareholders - basic” and “weighted average number of common shares outstanding - basic” for 2010 reflect (i) our issuance of 405,286 shares of Common Stock upon the June 2010 exercise of a warrant at an exercise price of $0.005 per share, (ii) the reclassification of all outstanding shares of our Common Stock as Class A common stock, (iii) the conversion of all shares of our Series A Preferred Stock, other than those held by Mr. Sakellaris, into shares of our Class A common stock, (iv) the conversion of all other outstanding shares of our Series A Preferred Stock into shares of our Class B common stock, (v) the issuance of 932,500 shares of our Class A common stock upon the exercise of vested stock options by certain selling stockholders in connection with our initial public offering in July 2010 at a weighted-average exercise price of $1.94, and (vi) the issuance of an aggregate of 6,342,889 shares of our Class A common stock in connection with our initial public offering in July 2010. (3) We define adjusted EBITDA as operating income before depreciation, amortization of intangible assets, impairment of goodwill and share-based compensation expense. Adjusted EBITDA is a non-GAAP financial measure and should not be considered as an alternative to operating income or any other measure of financial performance calculated and presented in accordance with GAAP. For additional information and a reconciliation to the most directly comparable financial measure prepared in accordance with GAAP, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations Overview — Non-GAAP Financial Measures” in Item 7. (4) 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 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 for the ESPC receivables transferred to the investor ceases upon final acceptance of the work by the government customer, we remain the primary obligor for financing received. 23

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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. 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 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. Our acquisition of the energy services business of Duke Energy in 2002 expanded our geographical reach into Canada and the southeastern United States and enabled us to penetrate the federal government market for energy efficiency projects. The acquisition of the energy services business of Exelon in 2004 expanded our geographical reach into the Midwest. Our acquisition of the energy services business of Northeast Utilities in 2006 substantially grew our capability to provide services for the federal market and in Europe. Our acquisition of Southwestern Photovoltaic in 2007 significantly expanded our offering of solar energy products and services. Our acquisition of energy services company Quantum in 2010 expanded our geographical reach into the northwest U.S. We made three acquisitions in 2011. Our acquisition of energy efficiency and demand side management consulting services provider Applied Energy Group, Inc. (“AEG”), expanded our service offering to utility customers. Our acquisition of APS Energy Services Company, Inc., which we renamed Ameresco Southwest, a company that provides a full range of integrated energy efficiency and renewable energy solutions, strengthened our geographical position in the southwest U.S. Our acquisition of the xChangePoint® and energy projects businesses from Energy and Power Solutions, Inc. (“EPS”), which we operate as Ameresco Intelligent Systems (“AIS”), expanded our service offerings to private sector commercial and industrial customers. AIS offers energy efficiency solutions to customers across North America encompassing the food and beverage, meat, dairy, paper, aerospace, oil and gas and REIT industries. Our acquisition of infrastructure asset management solutions provider FAME Facility Software Solutions Inc. (“FAME”) in 2012 expanded our asset planning consulting and software services offerings and our geographical position in western Canada. Our acquisition of the business of Ennovate in the first quarter of 2013 increased our footprint and penetration in the Rocky Mountain area. Our acquisition of energy management consultant ESP in the second quarter of 2013 added a local presence in the United Kingdom, expertise and seasoned energy industry professionals to support multi-national customers of our enterprise energy management service offerings. 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. 24

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Table of Contents 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 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 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 enter into long-term contracts to supply the electricity, processed landfill gas, or 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 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 project 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 project 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. 25

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Table of Contents 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 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 40 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 12 to 16 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 projects ultimately have resulted in a signed contract. After the customer and Ameresco agree to the terms of the contract and the contract for the project is executed, the project moves to fully-contracted backlog. The contracts reflected in our fully- contracted backlog typically have a construction period of 12 to 24 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, 2013, we had backlog of approximately $361.9 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 $993.0 million. As of December 31, 2012, we had fully-contracted backlog of approximately $367.0 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 $1.1 billion. Financial Operations Overview Revenues We derive revenues from energy efficiency and renewable energy products and services. Our energy efficiency products and services 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. Our renewable energy products and services include the construction of small-scale plants that produce electricity, gas, heat or cooling from renewable sources of energy, the sale of such electricity, processed LFG, heat or cooling from plants that we own, which, for those plants that we own and operate, we refer to collectively as small-scale infrastructure; and the sale and installation of photovoltaic solar energy products and systems (“integrated-PV”). 26

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Table of Contents Historically, including for the years ended December 31, 2013, 2012 and 2011, more than 80% of 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 preconstruction 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. Amortization expense for the years ended December 31, 2013 and 2012 related to customer contracts was $1.6 million and $2.5 million, respectively. 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, 2013 and 2012, we recorded amortization expense of $3.3 million and $2.8 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. For the year ended December 31, 2013 we recorded $1.1 million related to the release of a contingent liability associated with a prior year acquisition. For the year ended December 31, 2012, we recorded $0.8 million relating to a gain on sale of an asset. Goodwill Impairment We conducted our annual goodwill impairment test as of December 31, 2013, 2012 and 2011 for all reporting units and noted no impairment as of the 2013 and 2011 testing dates. The testing performed for the year ended December 31, 2012, which 27

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Table of Contents was based on our most recent cash flow forecast, indicated that the goodwill of our Canada reporting unit related to our 2009 acquisition of Byrne Engineering, Inc. (“Byrne”), was likely impaired as the carrying value of the reporting unit exceeded its estimated fair value. Accordingly, we recorded a non-cash, non-tax deductible goodwill impairment charge of $1.0 million during the year ended December 31, 2012. Other Expenses, Net Other expenses, net consists primarily of interest income on cash balances, interest expense on borrowings and amortization of deferred financing costs, and unrealized gains and losses on derivatives not accounted for as hedges or the ineffective portion of those that are accounted for as hedges. 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 for Income Taxes The provision 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. Non-GAAP Financial Measures We use the non-GAAP financial measures defined and discussed below to provide investors and others with useful supplemental information to our financial results prepared in accordance with GAAP. These non-GAAP financial measures should not be considered as an alternative to any measure of financial performance calculated and presented in accordance with GAAP. The tables below provide a reconciliation of these non-GAAP measures to the most directly comparable financial measures prepared in accordance with GAAP. We understand that, although measures similar to these non-GAAP financial measures are frequently used by investors and securities analysts in their evaluation of companies, they have limitations as analytical tools, and investors should not consider them in isolation or as a substitute for the most directly comparable GAAP financial measures or an analysis of our results of operations as reported under GAAP. To properly and prudently evaluate our business, we encourage investors to review our GAAP financial statements included above, and not to rely on any single financial measure to evaluate our business. Adjusted EBITDA We define adjusted EBITDA as operating income before depreciation, amortization of intangible assets, impairment of goodwill and share-based compensation expense. We believe adjusted EBITDA is useful to investors in evaluating our operating performance for the following reasons: adjusted EBITDA and similar non-GAAP measures are widely used by investors to measure a company's operating performance without regard to items that can vary substantially from company to company depending upon financing and accounting methods, book values of assets, capital structures and the methods by which assets were acquired; securities analysts often use adjusted EBITDA and similar non-GAAP measures as supplemental measures to evaluate the overall operating performance of companies; and by comparing our adjusted EBITDA in different historical periods, investors can evaluate our operating results without the additional variations of depreciation and amortization expense, goodwill impairment and share-based compensation expense. Our management uses adjusted EBITDA: as a measure of operating performance, because it does not include the impact of items that we do not consider indicative of our core operating performance; for planning purposes, including the preparation of our annual operating budget; to allocate resources to enhance the financial performance of the business; to evaluate the effectiveness of our business strategies; and in communications with the board of directors and investors concerning our financial performance. Adjusted Free Cash Flow We define adjusted free cash flow as net cash (used in) provided by operating activities, less purchases of property and equipment, plus proceeds from Federal ESPC projects. Cash received in payment of Federal ESPC projects is treated as a financing cash flow under GAAP due to the unusual financing structure for these projects. These cash flows, however, correspond to the revenue generated by these projects. Thus we believe that adjusting operating cash flow to include the cash generated by our Federal ESPC projects and to give effect for purchases of property and equipment provides investors with a useful measure for evaluating the cash generating ability of our core operating business. Our management uses adjusted free cash flow as a measure of liquidity because it captures all sources of cash associated with our revenue generated by operations. 28

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Table of Contents Reconciliations The following table presents a reconciliation of adjusted EBITDA to operating income, the most comparable GAAP measure: Year Ended December 31, 2013 2012 2011 (In thousands) Operating income $ 6,632 $ 28,657 $ 50,686 Depreciation, amortization of intangible assets and impairment 20,475 20,356 14,008 Stock-based compensation 2,799 3,351 2,866 Adjusted EBITDA $ 29,906 $ 52,364 $ 67,560 The following table presents a reconciliation of adjusted free cash flow to cash (used in) provided by operating activities, the most comparable GAAP measure: Year Ended December 31, 2013 2012 2011 (In thousands) Cash (used in) provided by operating activities $ (60,609) $ 42,209 $ (108,767) Less: purchases of property and equipment (2,331) (5,061) (3,450) Plus: proceeds from federal ESPC projects 40,010 30,203 133,776 Adjusted free cash flow $ (22,930) $ 67,351 $ 21,559 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 contract profit in accordance with long-term contracts, project development costs, project assets, impairment of goodwill, impairment of long-lived assets, fair value of derivative financial instruments, income taxes and stock-based compensation expense. 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; • 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; • O&M services provided under long-term O&M agreements, as well as consulting services; and • enterprise energy management services. 29

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Table of Contents 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 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. 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. Project 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, 2013, 2012 and 2011 was $1.8 million, $2.1 million and $0.4 million, respectively. Routine maintenance costs are expensed in the current year’s consolidated statements of income 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. 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. 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 apply accounting standards codification (“ASC”) 350, Intangibles-Goodwill and Other, in accounting for the valuation of goodwill and identifiable intangible assets. We have selected December 31 as our annual goodwill impairment review date. During our annual goodwill impairment tests at December 31, 2013 and 2011, we determined that the fair value of the 30

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Table of Contents enterprise value (equity value plus debt less cash) exceeded the carrying value of the enterprise value for all reporting units, and therefore goodwill and intangible assets were not impaired. During our annual goodwill impairment test at December 31, 2012, we determined that the fair value of our Canada reporting unit did not exceed the carrying value of its enterprise value, and therefore goodwill was impaired and an impairment charge of $1.0 million was recorded against the goodwill of our Canada reporting unit on December 31, 2012; we also determined that the remainder of our goodwill and intangible assets were not impaired as of December 31, 2012. Based on our goodwill impairment assessment, all of our reporting units with goodwill had estimated fair values as of December 31, 2013 that exceeded their carrying values by greater than 39% except for our Canada and Solar reporting units which had estimated fair values in excess of their carrying values of 11% and 18%, respectively. The carrying value of goodwill assigned to the Canada and Solar reporting units were $4.1 million and $7.6 million, respectively. Goodwill represents the excess of cost over the fair value of net tangible and identifiable intangible assets of businesses acquired. We assess the impairment of goodwill and intangible assets with indefinite lives on an annual basis and whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable. We would record an impairment charge if such an assessment were to indicate that, more likely than not, the fair value of such assets was less than their carrying values. Judgment is required in determining whether an event has occurred that may impair the value of goodwill or identifiable intangible assets. Factors that could indicate that an impairment may exist include significant underperformance relative to plan or long-term projections, significant changes in business strategy, significant negative industry or economic trends or a significant decline in the base stock price of our public competitors for a sustained period of time. When changes occur in the composition of one or more reporting units, the goodwill is reassigned to the reporting units affected based on their relative fair values. The first step, or Step 1, of the goodwill impairment test, used to identify potential impairment, compares the fair value of the equity with its carrying amount, including goodwill. If the fair value of the equity exceeds its carrying amount, goodwill of the reporting unit is considered not impaired, thus the second step of the impairment test is unnecessary. If the carrying amount of a reporting unit exceeds its fair value, the second step of the goodwill impairment test shall be performed to measure the amount of impairment loss, if any. We performed a Step 1 test at our December 31, 2013, 2012 and 2011 annual testing dates and determined, with the exception of our Canada reporting unit as of December 31, 2012, that the fair value of the enterprise value exceeded the carrying value of the enterprise value, and therefore that goodwill was not impaired. We completed the Step 1 test using both an income approach and a market approach. The discounted cash flow method was used to measure the fair value of our equity under the income approach. A terminal value utilizing a constant growth rate of cash flows was used to calculate a terminal value after the explicit projection period. Determining the fair value using a discounted cash flow method requires that we make significant estimates and assumptions, including long-term projections of cash flows, market conditions and appropriate discount rates. Our judgments are based upon historical experience, current market trends, pipeline for future sales and other information. While we believe that the estimates and assumptions underlying the valuation methodology are reasonable, different estimates and assumptions could result in a different outcome. In estimating future cash flows, we rely on internally generated projections for a defined time period for sales and operating profits, including capital expenditures, changes in net working capital and adjustments for non-cash items to arrive at the free cash flow available to invested capital. Under the market approach, we estimate the fair value based on market multiples of revenue and earnings of comparable publicly traded companies and comparable transactions of similar companies. 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 flows. These estimates are based on historical experiences, our projections of future operating activity and our weighted-average cost of capital. Separable intangible assets that are not deemed to have indefinite lives are amortized over their useful lives. We annually assess whether a change in the life over which our intangible assets are amortized is necessary or more frequently if events or circumstances warrant. We review all amortizable intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount of such assets may not be recoverable. Recoverability of these assets is determined by comparing the forecasted undiscounted net cash flows of the operation to which the assets relate to their carrying amount. If the operation is determined to be unable to recover the carrying amount of its assets, then intangible assets are written down first, followed by the other long-lived assets of the operation, to fair value. Fair value is determined based on discounted cash flows or appraised values, depending upon the nature of the assets. If we determine that an impairment has occurred, we will record a write-down of the carrying value and charge the impairment as an operating expense in the period the determination is made. Although we believe goodwill and intangible 31

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Table of Contents assets are appropriately stated in our consolidated financial statements, changes in strategy or market conditions could significantly impact these judgments and require an adjustment to the recorded balance. As previously described, for the year ended December 31, 2012, during the course of our valuation analysis it was determined that the fair value of our Canada segment was less than the carrying amount of this segment. This determination prompted the performance of the Step 2 test as prescribed under ASC 350, recognizing and measuring the amount of the impairment loss, if any. Step 2 of the goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with carrying amount of the goodwill. The fair value of this goodwill can only be measured as a residual after the entity assigns the fair value of the reporting unit to all the assets and liabilities of that reporting unit, including any unrecognized intangible assets as if the reporting unit had been acquired in a business combination. The carrying amount of the goodwill of our Canada segment exceeded the implied fair value of that goodwill and an impairment charge of $1.0 million was recorded against this goodwill in the fourth quarter of 2012. 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. During the twelve months ended December 31, 2013, no asset group was identified as being potentially impaired. 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 in accordance with the related guidance. Under this guidance, 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 five credit facilities, both project related and corporate, that utilize a variable rate swap instrument. • Prior to December 31, 2009, we entered into two 15-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. • During the year ended December 31, 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. 32

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Table of Contents • 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 amount, and to in turn receive an amount equal to a specified variable rate of interest times the same notional principal amount. The 2011 swap covers an initial notional amount of $38.6 million variable rate note at a fixed interest rate of 1.965% and expires in June 2016. • 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 1.71%, and expires in March 2020. • In October 2012, we also entered into two eight-year forward starting interest rate swap contracts under which the Company 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 3.70%, with an effective date of March 31, 2020, and expires in June 2028. 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 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. Effective March 29, 2013, we have designated this interest rate swap as a cash flow hedge using the “long-haul” method. The interest rate swaps that we entered into during 2011 and 2012 qualify, and have been designated, 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). 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. 33

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Table of Contents 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 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, 2013, 2012 and 2011, we recorded stock-based compensation expense of approximately $2.8 million, $3.4 million, and $2.9 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 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 2000 stock incentive plan; however, we will grant no further stock options or restricted stock awards under that plan. We have also granted stock options to certain employees and directors under our 2010 stock incentive plan. At December 31, 2013, 8,535,127 shares were available for grant under that plan. Under the terms of our 2000 and 2010 stock incentive plans, all options expire if not exercised within ten years after the grant date. Historically, options generally provided for vesting over five years, with 20% vesting at the end of the first year and five percent vesting every three months beginning one year after the grant date. During 2011, we began awarding options generally providing for vesting over five years, with 20% vesting on each of the first five anniversaries of the grant date. 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. 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 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 2013, 2012 and 2011: Year Ended December 31, 2013 2012 2011 Expected dividend yield —% —% —% Risk-free interest rate 1.03%-2.18% 0.82%-1.25% 1.35%-2.58% Expected volatility 34%-52% 32% 32%-33% Expected life 6.0-6.5 years 6.5 years 6.0-6.5 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. In addition, any changes in the estimated forfeiture rate can have a significant effect on reported stock-based compensation expense, as the cumulative effect of adjusting the rate for all expense amortization is recognized in the period that the forfeiture estimate is changed. If a revised forfeiture rate is higher than the previously estimated forfeiture rate, an adjustment is made that will result in a decrease to the stock-based compensation expense recognized in our consolidated financial statements. If a revised forfeiture rate is lower than the previously estimated rate, an adjustment is made that will result in an increase to the stock-based compensation expense recognized in our consolidated financial statements. These expenses will affect our cost of revenues as well as our selling, general and administrative expenses. As of December 31, 2013, we had $6.0 million of total unrecognized stock-based compensation cost related to employee and director stock options. We expect to recognize this cost over a weighted-average period of 2.9 years after December 31, 34

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Table of Contents 2013. 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 In July 2013, the FASB issued Accounting Standards Update 2013-11, Presentation of an Unrecognized Tax Benefit when a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (a consensus of the FASB Emerging Issues Task Force) (“ASU” 2013-11). The amendments in this ASU provide guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. An unrecognized tax benefit should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward with certain exceptions, in which case such an unrecognized tax benefit should be presented in the financial statements as a liability. The amendments in this ASU do not require new recurring disclosures and are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. We are currently assessing the impact of this ASU on our consolidated financial statements. Results of Operations The following table sets forth certain financial data from the consolidated statements of income expressed as a percentage of revenues for the periods indicated: Year Ended December 31, 2013 2012 2011 Dollar % of Dollar % of Dollar % of (in $’000s) Amount Revenues Amount Revenues Amount Revenues Revenues $ 574,171 100.0% $ 631,171 100.0% $ 728,200 100.0% Cost of revenues 470,846 82.0% 503,024 79.7% 593,154 81.5% Gross profit 103,325 18.0% 128,147 20.3% 135,046 18.5% Selling, general and administrative expenses 96,693 16.8% 98,474 15.6% 84,360 11.6% Goodwill impairment — —% 1,016 0.2% — —% Operating income 6,632 1.2% 28,657 4.5% 50,686 7.0% Other expenses, net 3,873 0.7% 4,050 0.6% 6,506 0.9% Income before provision for income taxes 2,759 0.5% 24,607 3.9% 44,180 6.1% Income tax provision 345 0.1% 6,247 1.0% 10,767 1.5% Net income $ 2,414 0.4% $ 18,360 2.9% $ 33,413 4.6% Revenues The following table sets forth a comparison of our revenues for the periods indicated: Year Ended December 31, Dollar Percentage (in $’000s) 2013 2012 Change Change Revenues $ 574,171 $ 631,171 $ (57,000) (9.0)% Year Ended December 31, Dollar Percentage (in $’000s) 2012 2011 Change Change Revenues $ 631,171 $ 728,200 $ (97,029) (13.3)% We derive our revenues primarily from energy efficiency products and services, which accounted for approximately 64.4%, 71.1% and 75.7% of total revenues in 2013, 2012 and 2011, respectively. Total revenues decreased by $57.0 million, or 9.0%, from 2012 to 2013 primarily due to an $81.3 million decrease in energy efficiency revenues, partially offset by a $14.1 million increase in renewable energy revenues, a $5.7 million increase in O&M revenue and a $4.5 million increase in other revenues. The decrease in energy efficiency revenues was primarily due to the lagged effect of delays in converting awarded projects to signed contracts, a trend continued from 2012 and that we expect to continue into 2014. 35

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Table of Contents Total revenues decreased by $97.0 million, or 13.3%, from 2011 to 2012 due to lower energy efficiency revenues, partly offset by higher renewable energy revenues. Total revenues were down from 2011 to 2012 as we experienced a sustained lengthening of conversion times from awarded projects to signed contracts. Continued U.S. federal fiscal uncertainty not only contributed to a lengthening of our sales cycle for U.S. federal projects, but also adversely affected both municipal and commercial customers across most geographic regions. We observed among our existing and prospective customer base increased scrutiny of decisions about spending and about incurring debt to finance projects. For example, we observed increased use of outside consultants and advisors, as well as adoption of additional approval steps, by many of our customers, which resulted in a lengthening of the sales cycle. As a result, during 2012 we experienced a sustained market disruption that affected all geographic regions and all levels of government. 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: Year Ended December 31, Dollar Percentage (in $’000s) 2013 2012 Change Change Cost of revenues $ 470,846 $ 503,024 $ (32,178) (6.4)% Gross margin % 18.0% 20.3% Year Ended December 31, Dollar Percentage (in $’000s) 2012 2011 Change Change Cost of revenues $ 503,024 $ 593,154 $ (90,130) (15.2)% Gross margin % 20.3% 18.5% Cost of revenues. The majority of our expenses are incurred in connection with energy efficiency projects for which expenses represented approximately 81.3%, 79.0%, and 81.1% of energy efficiency revenue in 2013, 2012 and 2011, respectively. Total cost of revenues decreased by $32.2 million, or 6.4%, from 2012 to 2013 due primarily to the decrease in revenues year-over-year. Total cost of revenues decreased by $90.1 million, or 15.2%, from 2011 to 2012 due primarily to the decrease in energy efficiency revenues, partially offset by improved gross margin for both energy efficiency and renewable energy. Gross margin. Gross margin decreased from 20.3% in 2012 to 18.0% in 2013. The decrease was driven primarily by a proportional increase in lower margin projects as a percentage of total revenues as well as fewer project closeout adjustments in 2013. Gross margin increased from 18.5% in 2011 to 20.3% in 2012. The increase was driven by higher margin projects across a number of U.S. regions, project closeouts, which contribute revenues for which all related cost of revenues previously have been incurred, renewable energy gross margin increases primarily related to small-scale infrastructure and integrated-PV and contributions from our higher gross margin offerings attributable to our acquisitions of AEG and AIS in the second half of 2011. Selling, General and Administrative Expenses The following table sets forth a comparison of our selling, general and administrative expenses for the periods indicated: Year Ended December 31, Dollar Percentage (in $’000s) 2013 2012 Change Change Selling, general and administrative expenses $ 96,693 $ 98,474 $ (1,781) (1.8)% Year Ended December 31, Dollar Percentage (in $’000s) 2012 2011 Change Change Selling, general and administrative expenses $ 98,474 $ 84,360 $ 14,114 16.7 % Selling, general and administrative expenses decreased $1.8 million, or 1.8%, from 2012 to 2013 to $96.7 million primarily due to a decrease in salaries and benefits of $6.7 million, resulting from improved utilization rates (that is, an increase in employee time spent on specific project or revenue generating activity) partially offset by a $2.3 million increase in professional fees, a $1.1 million increase in information technology expenses, a $0.5 million increase in insurance expense and a $0.7 million increase in depreciation and amortization expense. 36

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Table of Contents Selling, general and administrative expenses increased $14.1 million or 16.7% to $98.5 million from 2011 to 2012 primarily due to an increase in salaries and benefits of $10.5 million, resulting from increased headcount due to the full year effect of acquisitions during 2011 and from opening six new offices during 2012, an increase of $2.8 million due primarily to the costs necessary to support our continued growth, including expenses attributable to being a public company, such as auditing, compliance and insurance costs, and $2.4 million of incremental intangible asset amortization expense attributable to our acquisitions in the second half of 2011 and in 2012. Goodwill Impairment We conducted our annual goodwill impairment test as of December 31, 2013, 2012 and 2011 for all reporting units and noted no impairment of goodwill as of the 2013 and 2011 test dates. The 2012 test, which was based on our then most recent cash flow forecast, indicated that the goodwill of our Canada reporting unit related to our 2009 Byrne acquisition was impaired, as the carrying value exceeded its estimated fair value. Accordingly, we recorded a non-cash, non-tax deductible goodwill impairment charge of $1.0 million during the year ended December 31, 2012. Other Expenses, Net The following table shows the activity in other expenses, net for the periods indicated: Year Ended December 31, (in $’000s) 2013 2012 2011 Unrealized (gain) loss from derivatives $ (1,459) $ 98 $ 1,314 Interest expense, net of interest income 4,600 3,496 4,130 Amortization of deferred financing costs, net 732 456 1,062 Other expenses, net $ 3,873 $ 4,050 $ 6,506 Other expenses, net decreased from 2012 to 2013 by $0.2 million primarily due to the unrealized gain from derivatives. Other expenses, net decreased from 2011 to 2012 by $2.5 million primarily due to a decrease in unrealized loss from derivatives of $1.3 million which was market related, a decrease in interest expense, net of $0.6 million reflecting lower net borrowings and higher capitalization of interest for 2012, and the remainder relates to a decrease in amortization of deferred financing costs of $0.3 million. Income Before Taxes Income before taxes decreased from 2012 to 2013 by $21.8 million, or 88.8%, primarily due to lower revenues and a decrease in gross margin, both as described above. Income before taxes decreased from 2011 to 2012 by $19.6 million, or 44.3%, primarily due to lower revenues and an increase in operating expenses, both as described above. Provision for Income Taxes The provision 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. Our statutory rate, which is a combined federal and state rate, has ranged between 38.1% and 39.8%. During 2013, we recognized income taxes of $0.3 million, or 12.5% of pretax income. The principal difference between the statutory rate and the effective rate was due to deductions permitted under Section 179D of the Code, which relate to the installation of certain energy efficiency equipment in federal, state, provincial and local government-owned buildings, as well as production tax credits to which we are entitled from the electricity generated by certain plants that we own. These energy efficiency tax benefits accounted for a $3.6 million reduction in the 2013 provision, or a reduction of 128.9 percentage points in the effective rate. During 2012, we recognized income taxes of $6.2 million, or 25.4% of pretax income. The principal difference between the statutory rate and the effective rate was due to deductions permitted under Section 179D of the Code, which relate to the installation of certain energy efficiency equipment in federal, state, provincial and local government-owned buildings, as well as production tax credits to which we are entitled from the electricity generated by certain plants that we own. These energy efficiency tax benefits accounted for a $7.0 million reduction in the 2012 provision, or a reduction of 28.6 percentage points in the effective rate. During 2011, we recognized income taxes of $10.8 million, or 24.4% of pretax income. The principal difference between the statutory rate and the effective rate was due to deductions permitted under Section 179D of the Code, which relate to the 37

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Table of Contents installation of certain energy efficiency equipment in federal, state, provincial and local government-owned buildings, as well as production tax credits to which we are entitled from the electricity generated by certain plants that we own. These energy efficiency tax benefits accounted for a $6.2 million reduction in the 2011 provision, or a reduction of 14.1 percentage points in the effective rate. Net Income As a result of the 2013 outcomes discussed above net income decreased in 2013 by $15.9 million, or 86.9%. Earnings per share in 2013 was $0.05 per basic share, representing a decrease of $0.36, or 87.8%, and $0.05 per diluted share, representing a decrease of $0.35, or 87.5%. The weighted-average number of basic and diluted shares increased in 2013 by 2.0% and 0.9%, respectively. The exercise of incentive stock options accounted for the increase in basic shares, while the awarding of new stock options contributed to an increase in diluted shares. As a result of the 2012 outcomes discussed above net income decreased in 2012 by $15.1 million, or 45.1%. Earnings per share in 2012 was $0.41 per basic share, representing a decrease of $0.37, or 47.4%, and $0.40 per diluted share, representing a decrease of $0.35, or 46.7%. The weighted-average number of basic and diluted shares increased in 2012 by 4.8% and 2.9%, respectively. The exercise of incentive stock options accounted for the increase in basic shares, while the awarding of new stock options contributed to an increase in diluted shares. As a result of the 2011 outcomes discussed above net income increased in 2011 by $5.9 million, or 21.4%. Earnings per share in 2011 was $0.78 per basic share, representing a decrease of $0.29, or 27.1%, and $0.75 per diluted share, representing an increase of $0.09, or 13.6%. The weighted-average number of basic and diluted shares increased in 2011 by 65.5% and 7.7%, respectively. The increase in our basic shares was due mainly to the conversion of 3.2 million shares of Series A preferred stock into 1.3 million shares of Class A common stock and 18.0 million shares of Class B common stock in connection with our initial public offering and the exercise of 2.2 million options and warrants for shares of Class A common stock. The issuance and sale of 6.3 million shares of Class A common stock in our initial public offering contributed to the increase in both. The increase in the weighted-average number of diluted shares outstanding also was the result of the grant of new stock options and the increase in the market price of our stock. Business Segment Analysis We report results under ASC 280, Segment Reporting. Our reportable segments for the year ended December 31, 2013 are U.S. Regions, Federal, Canada and Small-Scale Infrastructure. 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 products and services, which include the construction of small-scale plants for customers that produce electricity, gas, heat or cooling from renewable sources of energy; and O&M services. Our Small-Scale Infrastructure segment sells electricity, processed LFG, heat or cooling, produced from renewable sources of energy and generated by small-scale plants that we own. 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 (in $’000s) Year Ended December 31, Dollar Percentage 2013 2012 Change Change Revenues $ 314,339 $ 382,118 $ (67,779) (17.7)% Income before taxes $ 22,408 $ 44,361 $ (21,953) (49.5)% (in $’000s) Year Ended December 31, Dollar Percentage 2012 2011 Change Change Revenues $ 382,118 $ 379,529 $ 2,589 0.7 % Income before taxes $ 44,361 $ 42,029 $ 2,332 5.5 % Total revenues for the U.S. Regions segment decreased from 2012 to 2013 by $67.8 million, or 17.7%, to $314.3 million primarily due to an $81.8 million decrease in energy efficiency revenues, partially offset by a $14.3 million increase in renewable energy revenues and a $3.3 million increase in O&M revenue. The decrease in energy efficiency revenues was 38

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Table of Contents primarily due to the lagged effect of delays in converting awarded projects to signed contracts, a trend continued from 2012 and that we expect to continue into 2014. Total revenues for the U.S. Regions segment increased from 2011 to 2012 by $0.3 million, or 0.1%, to $382.1 million primarily due to a $4.1 million increase in O&M revenue, partially offset by decreases in revenues across the segment primarily due to a lengthening of conversion times from awarded projects to signed contracts. Income before taxes for the U.S. Regions segment decreased from 2012 to 2013 by $22.0 million, or 49.5%, to $22.4 million. The decrease was primarily due to the decrease in revenues, a proportional increase in lower margin projects as a percentage of total revenues as well as fewer project closeout adjustments in 2013. Income before taxes for the U.S. Regions segment increased from 2011 to 2012 by $2.3 million, or 5.5%, to $44.4 million. The increase was primarily due to higher margin projects across a number of U.S. regions and project closeouts, which contribute revenues for which all related cost of revenues previously have been incurred. U.S. Federal (in $’000s) Year Ended December 31, Dollar Percentage 2013 2012 Change Change Revenues $ 70,452 $ 73,469 $ (3,017) (4.1)% Income before taxes $ 6,430 $ 2,263 $ 4,167 184.1 % (in $’000s) Year Ended December 31, Dollar Percentage 2012 2011 Change Change Revenues $ 73,469 $ 145,199 $ (71,730) (49.4)% Income before taxes $ 2,263 $ 19,252 $ (16,989) (88.2)% Total revenues for the U.S. Federal segment decreased from 2012 to 2013 by $3.0 million, or 4.1%, to $70.5 million primarily due to the U.S. federal government sequestration during 2013 resulting in a delay in the conversion of project backlog to revenues. Total revenues for the U.S. Federal segment decreased from 2011 to 2012 by $71.7 million, or 49.4%, to $73.5 million primarily due to a $42.5 million decline in revenues from the Savannah River project, which was completed in the fourth quarter of 2011 and transitioned to its O&M phase, and the effects of fewer projects entering the construction phase during 2011 and the first half of 2012. We experienced delays during 2011 and continuing through 2012 in converting awarded projects to signed contracts, arising, we believe, initially from implementation and adoption of new enhanced competition rules for federal ESPCs released in the second quarter of 2011, and, beginning in 2012, from additional diligence steps in response to pressure from respective committees responsible for approving energy efficiency projects. Income before taxes for the U.S. Federal segment increased from 2012 to 2013 by $4.2 million, or 184.1%, to $6.4 million. The increase was primarily due to an improvement in profit margins due to project mix and a $1.3 million decrease in selling, general and administrative expenses as a result of improved utilization rates. Income before taxes for the U.S. Federal segment decreased from 2011 to 2012 by $17.0 million, or 88.2%, to $2.3 million. The decrease was primarily due to decreased revenues as described above and a greater portion of lower margin projects within the segment’s revenue mix. 39

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Table of Contents Canada (in $’000s) Year Ended December 31, Dollar Percentage 2013 2012 Change Change Revenues $ 68,797 $ 60,564 $ 8,233 13.6 % Loss before taxes $ (3,043) $ (4,179) $ 1,136 27.2 % (in $’000s) Year Ended December 31, Dollar Percentage 2012 2011 Change Change Revenues $ 60,564 $ 110,211 $ (49,647) (45.0)% (Loss) income before taxes $ (4,179) $ 1,976 $ (6,155) (311.5)% Total revenues for the Canada segment increased from 2012 to 2013 by $8.2 million, or 13.6%, to $68.8 million, primarily due to an increase in new customer contracts and the full year impact of the 2012 FAME acquisition. Total revenues for the Canada segment decreased from 2011 to 2012 by $49.6 million, or 45.0%, to $60.6 million primarily due to the effects of fewer projects entering the construction phase and delays in converting both proposals to awarded projects and awarded projects to signed contracts arising from what we believe was continued government and municipal customer uncertainty related to the consequences of election outcomes. Loss before taxes for the Canada segment decreased from 2012 to 2013 by $1.1 million, or 27.2%, to a loss of $3.0 million. The improvement is primarily due to an increase in gross profit and a decrease in selling, general and administrative expenses related to improved operating efficiencies. Income (loss) before taxes for the Canada segment decreased from 2011 to 2012 by $6.2 million, or 311.5%, to a loss of $4.2 million. The decrease is primarily due to decreased revenues as described above. Small-Scale Infrastructure (in $’000s) Year Ended December 31, Dollar Percentage 2013 2012 Change Change Revenues $ 40,388 $ 37,979 $ 2,409 6.3% Income before taxes $ 4,365 $ 2,031 $ 2,334 114.9% (in $’000s) Year Ended December 31, Dollar Percentage 2012 2011 Change Change Revenues $ 37,979 $ 35,441 $ 2,538 7.2% Income before taxes $ 2,031 $ 424 $ 1,607 379.0% Total revenues for the Small-Scale Infrastructure segment increased from 2012 to 2013 by $2.4 million, or 6.3%, to $40.4 million primarily due to an increase in the number of plants fully operational during 2013, as well as a $0.8 million increase in revenue recognized from the sale of renewable energy certificates. Total revenues for the Small-Scale Infrastructure segment increased from 2011 to 2012 by $2.5 million, or 7.2%, to $38.0 million primarily due to an increase in the number of plants fully operational during 2012, as well as a $1.7 million increase in revenue recognized from the sale of renewable energy certificates. Income before taxes for the Small-Scale Infrastructure segment increased from 2012 to 2013 by $2.3 million, or 114.9%, to $4.4 million. The increase was primarily due to the increase in revenues described above, a decrease in maintenance expense and a $1.4 million gain on the ineffective portion of our interest rate swaps, partially offset by an increase in depreciation expense. Income before taxes for the Small-Scale Infrastructure segment increased from 2011 to 2012 by $1.6 million, or 379.0%, to $2.0 million. The increase was primarily due to the increase in revenues described above and a $1.3 million loss on the ineffective portion of our interest rate swaps for the year ended December 31, 2011. 40

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Table of Contents All Other & Unallocated Corporate Activity (in $’000s) Year Ended December 31, Dollar Percentage 2013 2012 Change Change Revenues $ 80,195 $ 77,041 $ 3,154 4.1 % (Loss) income before taxes $ (1,282) $ 1,321 $ (2,603) (197.0)% Unallocated corporate activity $ (26,120) $ (21,191) $ (4,929) 23.3 % (in $’000s) Year Ended December 31, Dollar Percentage 2012 2011 Change Change Revenues $ 77,041 $ 57,822 $ 19,219 33.2 % Income (loss) before taxes $ 1,321 $ (713) $ 2,034 285.3 % Unallocated corporate activity $ (21,191) $ (18,788) $ (2,403) 12.8 % Total revenues not allocated to segments and presented as all other, increased from 2012 to 2013 by $3.2 million, or 4.1%, to $80.2 million primarily due to a $3.6 million increase in integrated-PV sales. Total revenues not allocated to segments and presented as all other, increased from 2011 to 2012 by $19.2 million, or 33.2%, to $77.0 million primarily due to incremental revenues from our acquisitions of AEG and AIS in 2011, which contributed $17.7 million. Income (loss) before taxes not allocated to segments and presented as all other, decreased from 2012 to 2013 by $2.6 million, or 197.0%, to a loss of $1.3 million primarily due to investments made in new products and service offerings that are not yet generating meaningful revenues, partially offset by the increase in revenues described above. Income (loss) before taxes not allocated to segments and presented as all other, increased from 2011 to 2012 by $2.0 million, or 285.3%, to $1.3 million primarily due to the increase in revenues as described above. Unallocated 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. Unallocated corporate activity increased from 2012 to 2013 by $4.9 million, or 23.3%, to $26.1million primarily due to an increase in salary and benefit expenses related to an increase in headcount and increased professional fees. Unallocated corporate activity not allocated to segments increased from 2011 to 2012 by $2.4 million, or 12.8%, to $21.2 million primarily due to the costs necessary to support our continued growth, including expenses attributable to being a public company, such as auditing, compliance and insurance costs. Liquidity and Capital Resources Sources of liquidity. Since inception, we have funded operations primarily through existing net cash available, cash flow from operations and various forms of debt. We consider the difference between cash and cash equivalents and the book overdraft to represent the net cash available to meet our liquidity requirements. Those amounts were as follows as of December 31, 2013, 2012 and 2011: As of December 31, (in $’000s) 2013 2012 2011 Cash and cash equivalents $ 17,171 $ 63,348 $ 44,691 Book overdraft — — (7,297) Net cash available $ 17,171 $ 63,348 $ 37,394 At December 31, 2011, we recorded a book overdraft which represents certain checks issued on a disbursement bank account but not yet paid by that bank. Accounting conventions require that the book overdraft be presented as a current liability. There were no book overdrafts as of December 31, 2013 or 2012. We presented the book overdraft as a financing activity in the consolidated statements of cash flows. 41

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Table of Contents The changes in cash and cash equivalents for the years ended December 31, 2013, 2012 and 2011 were as follows: Year Ended December 31, (in $’000s) 2013 2012 2011 (Revised) (Revised) Net cash (used in) provided by operating activities $ (60,609) $ 42,209 $ (108,767) Net cash used in investing activities (29,937) (48,953) (105,601) Net cash provided by financing activities 43,190 43,486 196,989 Effect of exchange rate changes on cash 1,179 328 (1,035) Net (decrease) increase in cash and cash equivalents $ (46,177) $ 37,070 $ (18,414) 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 2014 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 for the ESPC receivables transferred to the investor ceases 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 are recorded as financing cash inflows. The use of the cash received under these arrangements to pay project costs is classified as operating cash flows. 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 transaction. See Note 2 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 project 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 $23.6 million in 2013, $44.9 million in 2012, and $45.2 million in 2011. The 2013, 2012 and 2011 capital expenditures were net of Section 1603 rebates received of $3.3 million, $7.3 million, and $6.7 million, respectively. Section 1603 of the American Recovery and Reinvestment Tax Act of 2009 authorized the U.S. Department of the Treasury to make payments to eligible persons who place in service specified energy property. This property would have been eligible for production tax credits under the Code, but we elected to forgo such tax credits in exchange for the payment made under Section 1603. Additionally, in 2013, 2012 and 2011 we invested $9.8 million, $4.0 million and $66.2 million in acquisitions, respectively. We currently plan to make capital expenditures of approximately $15.0 million in 2014, principally for new renewable energy plants. Cash flows from operating activities. Operating activities used $60.6 million of net cash during 2013. In 2013, we had net income of $2.4 million, which is net of non-cash compensation, depreciation, amortization, gains on contingent liabilities and sales of assets, deferred income taxes and other non-cash items totaling $1.2 million. Net increases in accounts receivable including retainage, inventory, net costs and estimated earnings in excess of billings, project development costs, other assets, and decreases in accounts payable and accrued expenses and income taxes payable used $28.9 million, partially offset by decreases in prepaid expenses and increases in other liabilities which provided $5.7 million. Federal ESPC receivables used $41.0 million. As described above, Federal ESPC operating cash flows only reflect the ESPC contract 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 provided $42.2 million of net cash during 2012. In 2012, we had net income of $18.4 million, which is net of non- cash compensation, depreciation, amortization, gains on sales of assets, deferred income taxes and other non-cash items totaling $19.5 million. Net decreases in accounts receivable including retainage, net costs and estimated earnings in excess of billings, and increases in accounts payable and accrued expenses, other liabilities and income taxes payable provided 42

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Table of Contents $54.1 million. However, increases in restricted cash, project development costs, inventory, prepaid expenses and other current assets used $21.1 million. Federal ESPC receivables used $28.7 million. Operating activities used $108.8 million of net cash during 2011. In 2011, we had net income of $33.4 million, which is net of non- cash compensation, depreciation, amortization, gains on sales of assets, deferred income taxes and other non-cash items totaling $35.9 million. Net increases in restricted cash, accounts receivable including retainage, inventory, net costs and estimated earnings in excess of billings, prepaid expenses and other current assets and decreases in accounts payable and accrued expenses, other liabilities and income taxes payable used $80.7 million. However, net decreases in project development costs and other assets provided $2.4 million in cash. Federal ESPC receivables used $99.8 million. Cash flows from investing activities. Cash used for investing activities totaled $29.9 million during 2013 and consisted of capital investments of $24.5 million related to the development of renewable energy plants; $2.3 million related to purchases of other property and equipment; and $9.8 million for the acquisitions of Ennovate and ESP. Offsetting these amounts were, the sale of assets of $3.5 million and $3.3 million of Section 1603 and other rebates received during the period. Cash used for investing activities totaled $49.0 million during 2012 and consisted of capital investments of $47.2 million related to the development of renewable energy plants; $5.1 million related to purchases of other property and equipment; and $4.0 million primarily for the acquisition of FAME. Offsetting these amounts were $7.3 million of Section 1603 and other rebates received during the period. Cash used for investing activities totaled $105.6 million during 2011 and consisted of capital investments of $48.5 million related to the development of renewable energy plants; $3.4 million related to purchases of other property and equipment; $66.2 million for the acquisitions of AEG, Ameresco Southwest and two businesses of EPS; and $2.0 million for acquisition related costs for the 2010 acquisition of Quantum. Offsetting these amounts were $6.7 million of Section 1603 rebates received during the period and proceeds from sales of assets of $7.8 million. Cash flows from financing activities. Net cash used in financing activities totaled $43.2 million during 2013 and included repayments of $14.7 million on long-term debt and payments of $0.5 million relating to financing fees. These uses of financing cash were offset by the release of $1.6 million from restricted cash accounts, proceeds from long-term debt financing of $9.4 million and exercises of options provided $2.1 million. Proceeds from Federal ESPC projects provided $40.0 million in cash. Net cash used in financing activities totaled $43.5 million during 2012 and included repayments of $9.3 million on our senior secured credit facility, repayments of $5.6 million on other long-term debt, payments of $3.2 million relating to financing fees, payments of $2.7 million into restricted cash accounts, and the book overdraft of $7.3 million. These were offset by proceeds from long-term debt financing of $37.7 million and exercises of options which provided $3.5 million. Proceeds from Federal ESPC projects provided $30.2 million in cash. Net cash provided by financing activities totaled $197.0 million during 2011. Most of this was due to the $40.0 million term loan portion of our senior secured credit facility, book overdraft of $7.3 million as well as proceeds from long-term debt financing of $7.9 million net of payments. Exercises of options provided $6.4 million. These were partially offset by reductions in restricted cash of $2.7 million. Proceeds from Federal ESPC projects provided $133.8 million in cash. Senior Secured Credit Facility — Revolver and Term Loan We have a credit and security agreement with two banks. The credit facility consists of a $60.0 million revolving credit facility and an initial $40.0 million term loan. At December 31, 2013, no amounts were outstanding under the revolving credit facility and $25.7 million was outstanding under the term loan. The term loan requires quarterly principal payments of $1.4 million, with the balance due at maturity. Ameresco, Inc. is the sole borrower under the credit facility. The credit facility is secured by a lien on all of our assets other than renewable energy projects that we own and for which financing from others remains outstanding, and limits our ability to enter into other financing arrangements. Availability under the revolving credit facility is based on two times our EBITDA for the preceding four quarters, and we are required to maintain a minimum EBITDA amount on a rolling four-quarter basis. EBITDA for purposes of the facility excludes the results of renewable energy projects that we own and for which financing from others remains outstanding. The credit facility matures on June 30, 2016, when all amounts will be due and payable in full. We recently amended the senior credit facility to: • increase the margins over the applicable benchmark rate in determining the interest rate by 25 basis points; • waive compliance with the minimum EBITDA covenant for the four consecutive fiscal quarters ended December 31, 2013; 43

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Table of Contents • reduce the required minimum EBITDA amount to $16.5 million for the four consecutive fiscal quarters ended March 31, 2014, $22.0 million for the four consecutive fiscal quarters ended June 30, 2014, $24.0 million for the four consecutive fiscal quarters ended September 30, 2014, and $27.0 million for the four consecutive fiscal quarters ended December 31, 2014 and thereafter; • increase the maximum ratio of total funded debt to EBITDA as of the end of each fiscal quarter to 2.5 to 1.0 for March 31, 2014 and 2.25 to 1.0 for June 30, 2014, returning to 2.0 to 1.0 for September 30, 2014 and thereafter; and • reduce the minimum ratio of cash flow to debt service to 1.25 to 1.0 for the four fiscal quarters ended March 31, 2014, returning to 1.5 to 1.0 for the four fiscal quarters ended June 30, 2014 and thereafter. As of December 31, 2013 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 generally accepted accounting principles to reflect these loans as liabilities on our consolidated balance sheet, they are generally nonrecourse and not direct obligations of Ameresco, Inc. As of December 31, 2013, we had outstanding $90.5 million in aggregate principal amount under these loans, bearing interest at rates ranging from 6.1% to 8.7% and maturing at various dates from 2015 to 2028. One loan, with an outstanding balance as of December 31, 2013 of $4.3 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, 2013 of $45.3 million, requires Ameresco, Inc. to provide assurance to the lender of construction completion with respect to those projects still in construction and of reimbursement upon any recapture of certain renewable energy government cash grants upon the occurrence of events that cause the recapture of such grants. As of December 31, 2012, we had outstanding $88.6 million in aggregate principal amount under these loans, bearing interest at rates ranging from 6.1% to 8.7% and maturing at various dates from 2013 to 2028. As of December 31, 2011, we had outstanding $56.2 million in aggregate principal amount under these loans, bearing interest at rates ranging from 6.1% to 8.7% and maturing at various dates from 2013 to 2024. 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 $44.3 million and $92.8 million in principal amounts at December 31, 2013 and 2012, 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. These construction and term loan agreements require us to comply with a variety of financial and operational covenants. As of December 31, 2013 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. 44

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Table of Contents Contractual Obligations The following table summarizes our significant contractual obligations and commitments as of December 31, 2013: Payments due by Period Less than One to Three to More than (in $’000s) Total One Year Three Years Five Years Five Years Senior Secured Credit Facility: Revolver $ — $ — $ — $ — $ — Term Loan 25,714 5,714 20,000 — — Project Financing: Construction and term loans 90,481 7,259 14,734 13,645 54,843 Federal ESPC liabilities(1) 44,297 — 44,297 — — Interest obligations(2) 38,200 5,402 9,212 7,032 16,554 Operating leases 10,954 3,049 4,829 2,647 429 Total $ 209,646 $ 21,424 $ 93,072 $ 23,324 $ 71,826 (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 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, 2013 remains constant for the term of the facility. 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. 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. 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 $17.2 million as of December 31, 2013 and $63.3 million as of December 31, 2012. 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). 45

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Table of Contents 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 beginning in June of 2013 in British pounds (“GBP”). Also, a significant number of employees are located in Canada and the United Kingdom (“U.K.”), and the companies 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 income. For the year ended December 31, 2013, due to the strengthening of the U.S. dollar versus both the Canadian dollar and the GBP, our foreign currency translation resulted in a loss of $1.0 million which we recorded as a decrease in accumulated other comprehensive income. For the year ended December 31, 2012, due to changes in the U.S.- Canadian exchange rate that were favorable to the value 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. 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 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. 46

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Table of Contents Item 8. Financial ASSETS Current assets: Cash and cash equivalents Restricted cash Accounts receivable, net Accounts receivable retainage Costs and estimated Inventory, net Prepaid expenses Income tax receivable Deferred income taxes Project development costs Total current assets Federal ESPC receivable Property and equipment, net Project assets, net Deferred financing fees, net Goodwill Intangible assets, net Other assets Total assets LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities: Current portion of long-term debt Accounts payable Accrued expenses Billings in excess Income taxes payable Total current liabilities Long-term debt, less current portion Federal ESPC liabilities Deferred income taxes Deferred grant income Other liabilities Commitments and contingencies (Note 12) Statements and Supplementary Data AMERESCO, INC. CONSOLIDATED BALANCE SHEETS December 31, 2013 2012 $ 17,170,736 $ 63,347,645 15,496,829 26,358,908 86,008,308 84,124,627 21,018,816 23,197,784 earnings in excess of billings 71,204,421 62,096,284 10,256,415 9,502,289 and other current assets 10,176,880 9,600,619 3,970,726 5,385,242 4,842,635 5,190,718 9,686,354 9,038,725 249,832,120 297,842,841 44,297,275 91,854,808 8,699,048 9,387,218 210,744,176 207,274,982 5,319,642 5,746,177 53,074,362 48,968,390 10,253,181 9,742,878 22,439,759 4,654,709 $ 604,659,563 $ 675,472,003 $ 12,973,591 $ 12,452,678 88,733,043 101,007,455 and other current liabilities 11,947,022 13,157,024 of cost and estimated earnings 16,932,639 22,271,655 615,063 — 131,201,358 148,888,812 103,221,845 109,079,009 44,297,304 92,843,163 11,318,406 24,888,229 8,163,368 7,590,730 29,652,488 30,362,869 The accompanying notes are an integral part of these consolidated financial statements. 47

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