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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
R
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2011
OR
o
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to ___________.
Commission File Number: 001-34811
Ameresco, Inc.
(Exact name of registrant as specified in its charter)
Delaware
 
04-3512838
(State or Other Jurisdiction of
Incorporation or Organization)
 
(I.R.S. Employer
Identification No.)
111 Speen Street, Suite 410
Framingham, Massachusetts
 
01701
(Address of Principal Executive Offices)
 
(Zip Code)
(508) 661-2200
(Registrant's Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Class A Common Stock,
par value $0.0001 per share
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o     No R
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 R
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 R     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 R     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 R
The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold on the New York Stock Exchange on June 30, 2011, the last business day of the registrant's most recently completed second fiscal quarter, was $261,384,520.
Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date.
Class
Shares outstanding as of February 29, 2012
Class A Common Stock, $0.0001 par value per share
26,119,303
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 2012 annual meeting of stockholders are incorporated by reference into Part III.
 
 


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AMERESCO, INC.
TABLE OF CONTENTS
 
 
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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, or the Exchange Act. All statements, other than statements of historical fact, including statements regarding our strategy, future operations, future financial position, future revenue, 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 are 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;
the expected future growth of the market for energy efficiency and renewable energy solutions;
our backlog, awarded projects and recurring revenue;
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.
PART I
Item 1. Business
Company Overview
Ameresco is a leading provider of energy efficiency solutions for facilities throughout North America. Our solutions enable customers to reduce their energy consumption, lower their operating and maintenance costs and realize environmental benefits. Our comprehensive set of services addresses almost all aspects of purchasing and using energy within a facility. Our services include upgrades to a facility's energy infrastructure and the construction and operation of small-scale renewable energy plants. As one of the few large, independent energy efficiency service providers, we are able to objectively select and provide the products and technologies best suited for a customer's needs. Having grown from four offices in three states in 2001 to 62 offices in 34 states and five Canadian provinces by year-end 2011, we now combine a North American footprint with strong local operations, which enable us to remain close to our customers and serve them effectively.
In addition to organic growth, strategic acquisitions of complementary businesses and assets have been an important part of our development. Since inception, we have completed fifteen acquisitions, which have enabled us to broaden our service offerings and expand our geographical reach. We made three acquisitions in 2011. Our acquisition of energy efficiency and demand side management consulting services provider Applied Energy Group, Inc., or AEG, expanded our service offerings 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. In late 2011, we acquired the xChangePoint® and energy projects businesses from Energy and Power Solutions, Inc., or EPS, to expand our service offerings to private sector commercial and industrial customers. These businesses offer energy efficiency solutions to customers across North America encompassing the food and beverage, meat, dairy, paper, aerospace, oil and gas and REIT industries.

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The market for energy efficiency services has grown significantly over the last 20 years, driven largely by rising and volatile energy prices, advances in energy efficiency and renewable energy technologies, aging facility infrastructure, governmental support for energy efficiency and renewable energy programs and growing customer awareness of energy costs and environmental issues. End users and governmental agencies are increasingly viewing energy efficiency measures as a cost-effective solution for saving energy, renewing aging facility infrastructure and reducing harmful emissions.
Our principal service is the development, design, engineering and installation of projects that reduce the energy and operations and maintenance, or 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, or LFG, to generate energy. During 2011, our largest renewable energy project for a customer completed construction and 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. We also sell and install photovoltaic, or PV, panels and integrated PV systems that convert solar energy to power. By enabling our customers to procure renewable sources of energy, we help them reduce or stabilize their energy costs, as well as realize environmental benefits.
We provide our services primarily to governmental, educational, utility, healthcare and other institutional, commercial and industrial entities. Since our inception in 2000, we have served more than 2,000 customers.
Our revenue has increased from $20.9 million in 2001, our first full year of operations, to $728.2 million in 2011. We achieved profitability in 2002 and have been profitable every year since then.
As of December 31, 2011, we had backlog of approximately $478 million in future revenue 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 revenue of an additional $741 million. As of December 31, 2010, we had backlog of approximately $651 million in future revenue 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 revenue of an additional $483 million. As of December 31, 2009, we had backlog of approximately $598 million in future revenue 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 revenue of an additional $706 million. The contracts reflected in our fully-contracted backlog typically have a construction period of 12 to 24 months; this is the period over which we expect to recognize revenue for customer contracts. 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. Historically, awarded projects typically have taken 6 to 12 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. Revenue generated from backlog was $507 million and $598 million in 2010 and 2011, respectively. See "We may not recognize all revenue from our backlog or receive all payments anticipated under awarded projects and customer contracts" in Item 1A, Risk Factors.
We also expect to realize recurring revenue both under long-term O&M contracts and under energy supply contracts for renewable energy plants that we own. In addition, we expect to generate revenue from solar and other product and service sales. Revenue generated from O&M, energy supply contracts and solar and other product and service sales was $111 million and $130 million in 2010 and 2011, respectively.

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Industry Overview
Energy efficiency companies, sometimes referred to as energy services companies, or ESCOs, develop, install and arrange financing for projects designed to improve the energy efficiency of buildings and other facilities. Typical products and services offered by energy efficiency companies include boiler and chiller replacement, HVAC upgrades, lighting retrofits, equipment installations, on-site cogeneration, renewable energy plants, load management, energy procurement, rate analysis, risk management and billing administration. Energy efficiency companies often offer their products and services through energy savings performance contracts, or ESPCs. Under these contracts, energy efficiency companies assume certain responsibilities for the performance of the installed measures, under assumed conditions, for a portion of the project's economic lifetime.
Ameresco’s Products and Services
We offer a comprehensive set of services that includes the design and installation of upgrades to a facility’s energy infrastructure, the design and construction of renewable energy plants and the arranging of financing for customer projects; we also sell renewable energy products.
Energy Efficiency Services
Our services typically includes the design, engineering and installation of, and the arranging of financing for, equipment to improve the 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.
At the commencement of a project, we typically evaluate the customer’s energy needs and opportunities to reduce costs. We start by reviewing and analyzing the customer’s utility and other energy bills. Our in-house personnel can, for example, analyze whether a customer is eligible for lower rates in a different utility rate class. Our experienced engineers then review and assess the customer’s current energy systems and determine how to optimize federal, state or local energy, utility and environmental based payments or credits available for usage reductions or renewable power generation. Upon customer approval of a project, our engineers, with the assistance in some cases of local or specialized engineers, design and engineer the project.
Energy Efficiency Measures
In designing a project for a customer, we typically include a combination of the following energy efficiency measures:
Boilers and Furnaces. We replace low efficiency boilers and furnaces with higher efficiency equipment. In addition, to reduce emissions, we can install emissions controls or either modify existing equipment or install new equipment to use cleaner fuels. We can also install biomass boilers for customers that have access to organic materials, such as wood, waste from agricultural or food processing activities or animal waste.
Chillers. Small buildings are cooled by air conditioners and large buildings are cooled by chillers. We replace older low efficiency chillers with new higher efficiency chillers capable of delivering the same cooling with less energy input, often eliminating the use of atmospheric ozone depleting chlorofluorocarbon based refrigerants in the process. We retrofit existing chillers with new, more sophisticated, automated controls, high efficiency motors and variable speed drives to improve efficiency in cases where complete equipment replacement is not necessary. If the customer has an on-site source of recoverable waste heat, we may replace an electric chiller with an absorption chiller that can utilize the waste heat to directly produce cooling with reduced need to purchase energy for chiller operation.
Central Plants. Customers that have multiple buildings in close proximity on a site may benefit from installation of a single central plant to provide power, heat or cooling to these buildings. The central plant typically contains multiple large boilers, chillers or combined heat and power, or CHP, systems to handle the combined requirements of all site buildings. Pipes are installed to distribute steam, hot water or chilled water from the central plant to the individual buildings. Any centrally generated power is delivered via interconnection with the existing site-wide electrical distribution system. A central plant allows the multiple smaller and less energy efficient individual building heating and cooling plants to be decommissioned. In addition to improved energy efficiency, centralization can create other scale benefits in operating labor, equipment maintenance and operating reliability. Where a customer already has a central plant, we can improve the efficiency of the plant by implementing improved equipment controls and by retrofit or replacement of existing equipment for enhanced energy efficiency.

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Cogeneration or Combined Heat and Power. CHP systems produce both heat and power simultaneously at a customer site, displacing power purchases from the utility grid and conventional sources of heat generation at the customer facility. When utilities produce power at large central station plants, the heat produced as a byproduct of the power generation process is typically wasted via disposal to the atmosphere or a nearby waterway. This wasted heat is generally a majority of the energy value of the input fuel to the power generation process. With on site power generation, the waste heat can be recovered from the power generation process and used as a substitute for heat that would otherwise be generated using site purchased fuels. Through use of heat driven chillers, also known as absorption chillers, this recovered heat can also be employed to provide building cooling. For facilities with large and relatively constant needs for power and heat or cooling, the cost of fuel for the cogeneration system operation can often be less than the cost of the purchased utility power and conventional heating fuel that is displaced. Installing a CHP that uses a lower cost fossil fuel or a renewable fuel source can create further economic benefits.
Energy Management Systems. Automating building system adjustments for optimum performance under changing building operating conditions is one of the most cost-effective energy saving strategies. We install energy management system, or EMS, projects consisting of small computers, wiring or wireless communication systems, and sensors and controllers located at energy using equipment and at locations that need monitoring for such conditions as temperature and flow. Equipment that may be controlled through an energy management system includes lights, boilers, chillers, and fans and pumps that move energy throughout a building. We program the computers to automatically turn the equipment on and off or to adjust equipment operating setpoints for lower energy use in response to monitored conditions. For example, when the outdoor air is cool and the building requires cooling, instead of turning on the chillers to cool the building, the EMS may turn on building fans to draw the cool outside air into the building and significantly reduce the energy use under that condition. Both we and the customer can access the EMS information through a personal computer and reprogram the energy saving strategies through secure, hardwired or web-based communications systems.
Lighting. We replace lighting system components with more efficient components in both indoor and outdoor lighting systems. We may alternatively redesign and install a new lighting system. Typical measures include replacing incandescent lighting with compact fluorescent lighting, metal halide lighting with fluorescent lighting and low efficiency fluorescent lighting with higher efficiency fluorescent lighting. Also, lighting controls may be installed to turn off lights when the lit space is unoccupied or if natural light through windows or skylights is adequate.
Retro-commissioning. Over time, the performance of building systems can degrade due to a variety of factors, such as a failure of dampers, actuators and switches to operate in accordance with the building control system or modifications to equipment without taking into account their interaction with other building systems. Cumulatively, these factors can lead to significant increased energy consumption and reduce the quality of the indoor environment. Through a retro-commissioning process, we systematically repair and restore building equipment and systems so that they function together in an optimal manner to enhance overall building performance.
Motors. The energy cost over the life of a motor is often many times the original cost of the motor. We replace older low efficiency motors with new higher efficiency motors. Often, motors are over sized for the application and additional savings can be attained by replacing an existing motor with an appropriately sized motor. We may also replace the sheave and belt drives associated with motors so that the motor output is transmitted to the driven device with reduced energy loss.
Variable Speed Drives or Variable Frequency Drives. Motors driving building equipment such as fans, pumps, chillers and elevators are typically selected and operated at the size and speed necessary to deliver services under worst case or peak load conditions. This causes inefficiencies when operating at less than peak load conditions. We install electronic devices called variable speed drives, or VSDs, that automatically adjust the characteristics of the power supplied to a motor so that the motor is operated at only the speed necessary to meet the load conditions at any time.
Electric Load Shaping. Many customers pay an energy charge per kWh of electricity used and a demand charge based on their highest or peak use of electricity in a 15 minute period during the month. By installing an EMS or an on-site generator and controlling the system using our monitoring and analysis of the customer’s electricity use, we can reduce the customer’s peak electricity use and thus its demand charge. We may also shift energy use from expensive on-peak (weekday) periods to less expensive off-peak periods (nights and weekends). For example, by adding chilled water storage tanks to a facility, cooling systems can be operated at night to generate stored chilled water and the chilled

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water can then be withdrawn to cool the building during the next day without operating the cooling equipment during daytime peak periods.
Utility Rate Reductions. A customer’s cost of gas and electricity is a function of how much energy is used and what rate the customer is charged for the energy. We analyze a customer’s energy use and the various utility rates that the customer is eligible to select. By switching a customer to the optimal rate, the customer can typically save energy costs. We may be able to switch a customer into a better rate by installing an EMS or an on-site generator.
Geothermal Heat Pumps. Heat pumps are designed to efficiently provide both heat and cooling to a facility. The geothermal heat pump system works to store and recapture energy from the ground on a seasonally advantageous basis. Beneath the surface, the earth is warmer than the air in winter and cooler than the air in summer. Using the heat pump, heat removed from a building to cool it during the summer can be stored in the ground. This stored heat can then be withdrawn by the heat pump in the winter to provide necessary building heating. We install piping loops in the ground and heat pumps in buildings. Water piped underground captures the stored geothermal energy and heat pumps deliver the energy efficiently to the building interior.
Window Replacement. Existing windows are often the most inefficient component of a building envelope. We may replace existing inefficient windows with new windows with features that more effectively control the sources of window heat transfer.
Roofs. An existing roof with inadequate insulation levels or with water damage compromising the effectiveness of insulation is a source of unnecessary energy waste. We replace existing roofs with new roofs with higher insulation levels to reduce heat losses in winter and heat gains in summer. We may employ membrane roof technology for better protection of the insulation against degradation.
Insulation. Insulating materials reduce unwanted transfer of heat that can increase energy usage. We apply additional insulation to building shell components, such as walls, ceilings, floors and foundations, to reduce heat loss in winter and heat gain in summer. We may add to or fully replace existing insulation on equipment such as piping, storage tanks and heat exchangers to reduce energy losses and the equipment inefficiency that results from these losses.
Asset Planning. Asset planning tools enable organizations to identify and prioritize current and future facility renewal requirements and associated capital investment needs. We have developed software that helps organizations measure the condition of their facilities, the costs necessary to improve the facilities and make them more energy efficient and the funding alternatives for any such improvements. Our asset planning tools enable customers to develop facility renewal plans that will effectively leverage their available sources of capital and meet their future needs.
Demand Response and Demand Side Management. Electric utilities and regional or independent system operators, or ISOs, are responsible for ensuring that power is available at all times throughout a region’s electrical transmission and distribution system. It is expensive to provide power during peak times such as a hot summer afternoon when customers are turning on their air conditioners and chillers. Utilities and ISOs seek to reduce the peak load demand and are willing to pay customers to reduce their power usage at these times, either during pre-arranged hours or in response to a call to reduce power. We help utilities and ISOs to attract customers to their programs and coordinate the customers’ participation in the programs.
Utility Data Management. We have developed proprietary software and systems that allow us to efficiently collect, optically scan, enter into a data base and perform analysis on information from customer utility bills. Using these systems, we can deliver a variety of services, including centralized and automated collection, processing and preparation for payment of utility billing information; identification of errors in utility metering or billings; aggregation of multiple location billings from a single utility to facilitate payment; modeling of available utility tariff rates against a database of historical energy use to identify the most economical rate; and analysis of utility use data in multiple ways to identify and report usage and cost trends, variances and performance relative to benchmarks.
Carbon Emissions Tracking. Our carbon management program provides greenhouse gas, or GHG, emissions accounting and reporting services to our customers. With an international, multi-tiered approach, we can support a wide variety of GHG accounting and reporting standards, including utility based GHG and full ISO 14064 compliance reporting. This service helps customers, for example, to develop corporate social responsibility reports and prepare for an audit of their GHG emissions.

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We typically purchase the equipment for our projects either from local vendors or, in certain cases, from vendors with whom we have a relationship across the company. Our large volume of equipment purchases enables us to achieve cost efficiencies with our significant vendors. In most cases, we use local subcontractors to install the purchased equipment in accordance with our design and under the supervision of our project manager.
Customer Arrangements
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 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 and not 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. From our inception to December 31, 2011, our total payments to customers and incurred costs under our energy reduction commitments, after customer acceptance of a project, have been less than $100,000 in the aggregate. 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, or 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.
Engineering and Installation Controls
Our engineering and construction quality, schedule and budget goals are managed through several control processes. We follow formal processes for the review and approval of the technical and economic content of all proposals by senior managers. Our engineers employ standardized, and in some cases proprietary, software tools for technical and economic analysis to establish a baseline for quality and accuracy during the development stage of our projects. We fully review final design, engineering and construction document preparation efforts at selected milestones, using internal or subcontracted specialized engineering resources. During the construction phase, a construction project management team utilizes a number of tools to

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manage quality, cost and schedule. We use agreement templates, customized to meet the specific technical requirements of each project, to ensure well defined procedures and responsibilities to be followed by our equipment suppliers and labor subcontractors. We use scheduling software to prepare, regularly update and communicate project schedules at a task specific level. Inspections of work progress and quality are conducted throughout the construction process at frequent intervals. Both project managers and senior management use a computerized project control system throughout the project delivery process to track actual project costs against project budgets on a real-time basis. In addition, we employ a full-time, dedicated safety director who is responsible for developing and promulgating best practices and training throughout the organization and working with our regional safety coordinators to ensure appropriate procedures are in place at all job sites.
Operations and Maintenance Services
After a 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.
Renewable Energy Projects and Products
Our services offering includes the development, construction and operation of, and the arrangement of financing for, small-scale renewable energy plants, as well as the sale and integration of solar energy products and systems.
We have constructed and are currently designing and constructing a wide range of renewable energy plants using LFG, wastewater treatment biogas, solar, wind, biomass, food waste, animal waste, 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. LFG is created by the action of micro-organisms within a landfill that generate methane gas as a byproduct of solid waste decay. Generally, landfills avoid the unsafe build up of methane-containing LFG by venting it into the atmosphere, or in most cases, by collecting and flaring it. As methane is suspected of contributing to global climate change and is regulated as a pollutant, landfill owners are generally required by environmental laws to collect and combust LFG, usually in a flare. We purchase the LFG that otherwise would be combusted or vented, process it, and either sell it or use it in our energy plants. Electricity that we sell is generally delivered to the customer at the interconnection of our plant with the electrical grid. The thermal energy that we sell is generally delivered to the customer at the inlet flange of the thermal piping located at the customer's facilities. The processed LFG we sell to industrial customers is generally delivered by us to the customer's facility through a pipeline transmission system that we design, construct and operate. Under our energy supply agreements, we typically provide all environmental attributes associated with the project, including those represented by renewable energy certificates, to the customer.
Depending on the customer's preference, we will either build, own and operate the completed plant or build it for the customer to own. We generally sell the electricity, gas, heat or cooling generated by small-scale plants that we own under long-term contracts, typically to utilities, industrial facilities or other large users of energy. For an LFG plant, the output will typically be sold under a sales agreement with a term covering ten to 20 years of plant operation. The right to use the site for the energy plant, and the purchase of the renewable energy needed to fuel the plant, are also obtained under long-term agreements with terms at least as long as that of the associated output sales agreement. Our projects are generally designed and permitted by our own engineers, although we often obtain additional engineering assistance from consulting engineers. We generally subcontract installation of project equipment, under the supervision of our construction manager. 
As part of our renewable energy offering, we also distribute and integrate solar energy products manufactured by several vendors. We are a distributor of PV panels, solar regulators, solar charge controllers, inverters, solar powered lighting systems, solar powered water pumps, solar panel mounting hardware and other system components. We also integrate our PV products and system components into solar solutions designed specifically for customers. We provide solar energy solutions for both on-grid applications where the solar power is used in a building connected to a utility distribution system, and for off-grid applications where the power is used directly in the device using the electricity, such as traffic signs. 
We also design and construct renewable energy plants based on wind power. In many parts of the country, available wind resources, utility net metering and local incentives can make on-site wind generation a viable solution for meeting a significant portion of customers' energy needs.
In addition, we have constructed, and are constructing, small-scale renewable energy plants based on biomass. Biomass is organic material such as wood, agricultural waste, animal waste and waste from food processors. Biomass is typically

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converted to energy by burning or gasifying it in a boiler to produce steam or gas. Our largest renewable energy project for a customer completed construction in 2011 and will use biomass and other bio-derived fuels as the primary source of energy. 
As of December 31, 2011, we had constructed more than 34 renewable energy projects, and owned and operated 22 small-scale renewable energy plants. Of the owned plants, 19 are renewable LFG plants, two are waste water biogas plants, and one is a solar PV installation. The 22 small-scale renewable energy plants that we own have the capacity to generate electricity or deliver LFG producing an aggregate of 107 megawatts (MW) or megawatt-equivalents (MWE). During 2011, we completed the biomass power and cogeneration plants at the Savannah River Site and four biomass boiler projects; signed contracts to design and construct four small-scale renewable energy plants for customers; and continued moving forward with designing, permitting and constructing six LFG plants that we will own and operate. If and when completed, we expect the four small-scale renewable energy plants being designed and constructed for customers to be capable of producing an aggregate of approximately 43 MW or MWE. These projects consist of two LFG plants, a waste water biogas plant and a coal bed methane to energy plant. If and when completed, we expect the six LFG plants that we will own and operate to be capable of producing an aggregate of approximately 27 MW or MWE.
Examples of Energy Efficiency and Renewable Energy Projects
The following are examples of energy efficiency and renewable energy projects we have designed and either have installed or are installing for customers. While most of our projects are less complex and smaller in scope than those shown below, these examples are intended to demonstrate how various different types of energy efficiency measures and renewable energy plants can be combined to create a customized solution addressing the multiple needs of a customer.
Elmendorf Air Force Base (Alaska). Elmendorf Air Force Base had an inefficient, costly-to-operate central heating and power plant and approximately 50 miles of aging steam and condensate distribution piping. We modernized the heating system by demolishing the central plant and installing over 200 boilers and 20 alternate heating systems in over 120 commercial facilities. We worked with the local gas utility to install approximately seven miles of gas pipeline to serve the new, decentralized boilers and negotiated a new gas and electric service for the Base with the local utilities. We also installed over 800 energy efficient steam traps and abated over 125 steam pits throughout the base. The $49 million project is designed to save approximately $4 million of energy and energy-related O&M costs per year. This work was completed in 2008. We provide a full-time staff of four people at the base and have contracted to perform approximately $22 million of fixed price O&M services throughout the 22-year performance period term of our agreement. 
BMW (South Carolina). BMW was seeking to lower and stabilize its energy costs, and Waste Management was seeking to monetize the value of the LFG produced at its Palmetto Landfill. To achieve these goals, in 2003, we completed the development, design, construction and financing for the $9.6 million project to process and deliver LFG to BMW's factory and refurbish BMW's boilers and turbines to be able to utilize the LFG fuel. BMW also uses the LFG to provide energy for its paint shop, incinerator and pollution control devices. This project involves buying LFG from Waste Management at its Palmetto Landfill, processing and compressing the LFG adjacent to the landfill and piping the LFG approximately 9.5 miles for delivery to BMW. Over the period from 2005 to 2009, the project has delivered from 0.88 to 1.17 million BTU annually. BMW pays for the LFG under a multi-year supply contract. Our delivery obligations are limited to those volumes of LFG supplied to us by Waste Management. In 2009, BMW announced that the project produces over 60% of the plant's total energy requirements, saving BMW an average of $5 million in energy costs annually while reducing carbon dioxide emissions by approximately 92,000 tons per year. 
U.S. Department of Energy Savannah River Site (South Carolina). The Savannah River Site, or SRS, previously utilized steam and power for process and heating loads currently generated from an aging and inefficient coal power plant. We completed construction of a 20.7 MW cogeneration plant to replace this coal power plant. The cogeneration plant uses fuel from forest residue, scrap tires, pallets and other clean wood and came on line in December 2011. We also installed two ten million BTU per hour wood-fired heating plants at other SRS locations to replace an old and inefficient fuel oil heating plant. This $183.4 million project is designed to save approximately $34 million of energy and energy related O&M costs per year. We will provide a full time staff of 20 to 25 people at the new plant and have contracted to perform approximately $17 million of O&M services annually, at escalating fixed rates, throughout the 19-year performance period of the agreement. 
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 typically takes from 12 to 36 months, with sales to federal governmental and housing authority

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customers tending to require the longest sales processes. We identify project opportunities through referrals, requests for proposals, or 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, 2011, we had 148 sales people.
In preparation for a proposal, we typically conduct a preliminary audit of the customer’s needs and the opportunity to reduce its energy costs. We start by reading and analyzing the customer’s utility and other energy bills. If the bills are complex or numerous, we employ our proprietary AXIS software for bill scanning and analysis. Our experienced engineers visit and assess the customer’s current energy systems. 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. If we are 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, such as a landfill or a site with high wind, 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 2011, we served more than 1,000 customers in 49 states in the United States and seven Canadian provinces. Our customers include government, education, utility, healthcare and other institutional, industrial and commercial customers. Outside North America, we have constructed projects for U.S. naval bases in Europe, and also sell our off-grid PV systems. During 2011, no single customer accounted for more than ten percent of total revenue and our largest 20 customers accounted for approximately 45% of our total revenue. Historically, including for 2010 and 2011, more than 80% of of our revenue has been derived from federal, state, provincial or local government entities, including public housing authorities and public universities. Our 20 largest customers in 2011, by revenue, in alphabetical order, were:
 
Arizona State University (Tempe, Arizona)
Boston Housing Authority (Boston, Massachusetts)
British Columbia Housing Authority (Burnaby, British Columbia)
City of Knoxville (Knoxville, Tennessee)
City of Lowell (Lowell, Massachusetts)  
 City of Miami Beach (Miami Beach, Florida)  
City of Portland (Portland, Maine)
Hazelwood School District (Saint Louis, Missouri)
North Carolina State University (Raleigh, North Carolina)
 Rainbow District School Board (Sudbury, Ontario)
 Riverview Gardens School District (Saint Louis, Missouri)
San Francisco Housing Authority (San Francisco, California)
South Huntington School District (Huntington Station, New York)
Toronto Community Housing (Toronto, Ontario)
U.S. Air Force - McGuire Air Force Base (New Jersey)
U.S. Architect of Capitol - U.S. Capitol Building (Washington, D.C.)  
U.S. Architect of Capitol - U.S. Senate Building (Washington, D.C.)
 U.S. Department of Energy - Savannah River Site (Aiken, South Carolina)
University of Kentucky (Lexington, Kentucky)
University City School District (University City, Missouri)

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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, Siemens Building Technologies and TAC Energy Solutions. 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.
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 energy efficiency and renewable energy projects 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.
Many of our competitors have longer operating histories and greater resources than we do, and we may be unable to continue to compete effectively against our current competitors or additional companies that may enter our markets.
Regulatory
Various regulations affect the conduct of our business. Federal and state legislation and regulations enable us to enter into ESPCs with government agencies in the United States. The applicable regulatory requirements for ESPCs differ in each state and between agencies of the federal government.
Our projects must conform to all applicable electric reliability, building and safety, and environmental regulations and codes, which vary from place to place and time to time. Various federal, state, provincial and local permits are required to construct an energy efficiency project or renewable energy plant.
Renewable energy projects are also subject to specific governmental safety and economic regulation. States and the federal government typically do not regulate the transportation or sale of LFG unless it is combined with and distributed with natural gas, but this is not uniform among states and may change from time to time. 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, or PUHCA, the Federal Power Act, or FPA, and Public Utility Regulatory Policies Act of 1978, or 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, PHUCA 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 MW, 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. Renewable energy projects may also be eligible for certain governmental or government-related incentives from time to time,

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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, 2011, we had a total of 947 employees in offices located in 39 states and five Canadian provinces.
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
We report four segments: U.S. federal, central U.S. region, other U.S. regions and Canada. Financial information about our domestic and international operations and about our segments may be found in Notes 15 and 20, respectively, of “Notes to Consolidated Financial Statements” included in Item 8 of this Annual Report, 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, or SEC, and through the SEC's website, www.sec.gov. We include our website address in this report only as an inactive textual reference and do not intend it to be an active link to our website. None of the material on our website is part of this Annual Report on Form 10-K.
Executive Officers
The following is a list of our executive officers, their ages as of March 1, 2012 and their principal positions.
Name
 
Age
 
Position (s)
George P. Sakellaris
 
65

 
Chairman of the Board of Directors, President and Chief Executive Officer
David J. Anderson
 
51

 
Executive Vice President, Business Development and Director
Michael T. Bakas
 
43

 
Senior Vice President, Renewable Energy
David J. Corrsin
 
53

 
Executive Vice President, General Counsel and Secretary and Director
William J. Cunningham
 
52

 
Senior Vice President, Corporate Government Relations
Joseph P. DeManche
 
55

 
Executive Vice President, Engineering and Operations
Keith A. Derrington
 
51

 
Executive Vice President and General Manager, Federal Operations
Mario Iusi
 
53

 
President, Ameresco Canada
Louis P. Maltezos
 
45

 
Executive Vice President and General Manager, Central Region
Andrew B. Spence
 
55

 
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.

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David J. Corrsin: Mr. Corrsin has served as our executive vice president, general counsel and secretary, as well as a director, since 2000.
William J. Cunningham: Mr. Cunningham has served as our senior vice president, corporate government relations since January 2008. From April 2007 to January 2008, he was a vice president at Dutko Worldwide, a public affairs and lobbying firm. From 2004 to 2006, Mr. Cunningham was senior vice president, corporate government relations, at Conseco Services, which is a subsidiary of Conseco, Inc., an insurance company.
Joseph P. DeManche: Mr. DeManche has served as our executive vice president, engineering and operations since 2002.
Keith A. Derrington: Mr. Derrington has served as our executive vice president and general manager, federal operations since April 2009. From 2004 to April 2009, Mr. Derrington was our vice president and general manager, federal operations.
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 are advised, however, to 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 revenue will suffer and our business will be harmed.
Our revenue has increased significantly since January 1, 2005. We believe, and our growth expectations 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 revenue from selling into this market will continue to increase. 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 revenue will suffer and our business will be harmed.
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 are typically financed by third parties. The cost of these projects to our customers can reach up to $200 million. For our energy efficiency projects, we often assist our customers in arranging third-party financing. 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. The significant disruptions in the credit and capital markets in the last several years have made it more difficult for our customers and us to obtain financing on acceptable terms or, in some cases, at all. 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.
In 2011, we amended and restated our revolving senior secured credit facility. The new credit facility extended and expanded our prior credit facility, and consists of a $60 million revolving credit facility and a $40.0 million term loan, and it matures in June 2016. 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 of $40 million on a rolling four-quarter basis. This facility may

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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.
Any inability by us or our customers to raise the funds necessary to finance our projects, or any inability by us to expand our revolving credit facility if necessary, could materially harm our business, financial condition and operating results.
Our operating results may fluctuate significantly from quarter to quarter and may fall below expectations in any particular fiscal quarter.
Our operating results are difficult to predict and have historically fluctuated from quarter to quarter due to a variety of factors, many of which are outside of our control. As a result, comparing our operating results on a period-to-period basis may not be meaningful, and you should not rely on our past results as an indication of our future performance. If our revenue or operating results fall below the expectations of investors or any securities analysts that follow our company in any period, the trading price of our Class A common stock would likely decline.
Factors that may cause our operating results to fluctuate include:
our ability to arrange financing for projects;
changes in federal state and local government policies and programs related to, or a reduction in governmental support for, energy efficiency and renewable energy;
the timing of work we do on projects where we recognize revenue on a percentage of completion basis;
seasonality in construction and in demand for our products and services;
a customer’s decision to delay our work on, or other risks involved with, a particular project;
availability and costs of labor and equipment;
the addition of new customers or the loss of existing customers;
the size and scale of new customer projects;
the availability of bonding for our projects;
our ability to control costs, including operating expenses;
changes in the mix of our products and services;
the rates at which customers renew their O&M contracts with us;
the length of our sales cycle;
the productivity and growth of our sales force;
the timing of opening of new offices or making other significant investments in the growth of our business, as the revenue we hope to generate from those expenses often lags several quarters behind those expenses;
changes in pricing by us or our competitors, or the need to provide discounts to win business;
costs related to the acquisition and integration of companies or assets;
general economic trends, including changes in energy efficiency spending or geopolitical events such as war or incidents of terrorism; and
future accounting pronouncements and changes in accounting policies.
Our operating expenses do not always vary directly with revenue and may be difficult to adjust in the short term. As a result, if revenue for a particular quarter is below our expectations, we may not be able to proportionately reduce operating expenses for that quarter, and therefore such a revenue shortfall could have a disproportionate effect on our operating results for that quarter.
We may not be able to maintain or increase our profitability.
We have been profitable on an annual basis since the year ended December 31, 2002. However, we have incurred net losses in certain quarters since that time. We may not succeed in maintaining our profitability and could incur quarterly or annual

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losses in future periods. We intend to increase our expenses as we grow our business and expand into new geographic locations, and we expect to continue to incur additional accounting, legal and other expenses associated with being a public company. If our revenue does not increase sufficiently to offset these increases in costs, our operating results will be harmed. Our historical operating results should not be considered as necessarily indicative of future operating results and we can provide no assurance that we will be able to maintain or increase our profitability in the future.
We may not recognize all revenue from our backlog or receive all payments anticipated under awarded projects and customer contracts.
As of December 31, 2011, we had backlog of approximately $478 million in future revenue 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 revenue of an additional $741 million. As of December 31, 2010, we had fully contracted backlog of approximately $651 million; and we also had been awarded projects for which we had not yet signed customer contracts with estimated total future revenue of an additional $483 million. As of December 31, 2009, we had fully contracted backlog of approximately $598 million; and we also had been awarded projects for which we had not yet signed customer contracts with estimated total future revenue of an additional $706 million.
We also expect to realize recurring revenue both under long-term O&M contracts and under energy supply contracts for renewable energy plants that we own. In addition, we expect to generate revenue from solar and other product and service sales.
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 revenue 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 revenue, even if such revenue is eventually received, may cause our operating results for a particular quarter to fall below our expectations.
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 revenue and operating income in the third quarter are typically higher, and our revenue 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.
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 government legislation and policies that support energy efficiency and renewable energy projects and that enhance the economic feasibility of our energy efficiency services and small-scale renewable energy projects. The U.S. and Canadian federal governments and several of the states and provinces in which we operate support our existing and potential customers’ investments in energy efficiency and renewable energy through legislation and regulations that authorize and regulate the manner in which certain governmental entities do business with us, encourage or subsidize governmental

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procurement of our services, provide regulatory, tax and other incentives to others to procure our services and provide us with tax and other incentives that reduce our costs or increase our revenue.
For example, U.S. legislation authorizing federal agencies to enter into ESPCs, such as those we enter into with our customers, was enacted in 1992. In 2007, three years after the expiration of the original legislation, new ESPC legislation was enacted without an expiration provision, and in the same year, the President of the United States issued an executive order requiring federal agencies to set goals to reduce energy use and increase renewable energy sources and use. The Internal Revenue Code currently provides production tax credits for the generation of electricity from wind projects and from LFG-fueled power projects, and an investment tax credit or grant in lieu of such tax credits for investments in LFG, wind, biomass and solar power generation projects. Various state and local governments have also implemented similar programs and incentives, including legislation authorizing the procurement of ESPCs.
We and our customers and our prospective customers frequently depend on these programs to help justify the costs associated with, and to finance, energy efficiency and renewable energy projects. If any of these incentives are adversely amended, eliminated or not extended beyond their current expiration dates, or if funding for these incentives is reduced, it could adversely affect our ability to complete projects for existing customers and obtain project commitments from new customers. A delay or failure by government agencies to administer, or make procurements under, these programs in a timely and efficient manner could have a material adverse effect on our existing and potential customers’ willingness to enter into project commitments with us.
In addition, some of our customers purchase electricity, thermal energy or processed LFG from our renewable energy plants, or purchase other energy services from us, because tax, energy and environmental laws encourage or in some cases require these customers to procure power from renewable or low-emission sources, or to reduce their electricity use. Changes to these tax, energy and environmental laws could reduce our customers’ incentives and mandates to purchase the kinds of services that we supply, and could thereby adversely affect our business, financial condition and operating results.
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.
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 2010 and 2011, more than 80% of our revenue has been derived from sales to federal, state, provincial or local governmental entities, including public housing authorities and public universities. We expect revenue from this market sector to continue to comprise a significant percentage of our revenue 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.
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 services and products, such as boilers, chillers, cogeneration systems, PV panels, lighting and other complex components. 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 rely on subcontractors to perform substantially all of the construction and installation work related to our projects. We provide all design and engineering work related to, and act as the general contractor for, our projects. We have established relationships with subcontractors that we believe to be reliable and capable of producing satisfactory results, but we often need

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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.
The warranties provided by our third-party suppliers and subcontractors typically limit any direct harm we might experience as a result of our relying on their products and services. However, there can be no assurance that a supplier or subcontractor will be willing or able to fulfill its contractual obligations and make necessary repairs or replace equipment. In addition, these warranties generally expire within one to five years or may be of limited scope or provide limited remedies. If we are unable to avail ourselves of warranty protection, we may incur liability to our customers or additional costs related to the affected products and components, including replacement and installation costs, 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 — even if covered by warranties — could adversely affect the quality and performance of our solutions. This could cause us to experience difficulty retaining current customers and attracting new customers, and could harm our brand, reputation and growth. In addition, any significant interruption or delay by our suppliers in the manufacture or delivery of products or services on which we depend could require us to expend considerable time, effort and expense to establish alternate sources for such products and services.
We may have liability to our customers under our ESPCs if our projects fail to deliver the energy use reductions to which we are committed under the contract.
For our energy efficiency projects, we typically enter into ESPCs under which we commit that the projects will satisfy agreed-upon performance standards appropriate to the project. These commitments are typically structured as guarantees of increased energy efficiency that are based on the design, capacity, efficiency or operation of the specific equipment and systems we install. Our commitments generally fall into three categories: pre-agreed, equipment-level and whole building-level. Under a pre-agreed efficiency commitment, our customer reviews the project design in advance and agrees that, upon or shortly after completion of installation of the specified equipment comprising the project, the pre-agreed increase in energy efficiency will have been met. Under an equipment-level commitment, we commit to a level of increased energy efficiency based on the difference in use measured first with the existing equipment and then with the replacement equipment upon completion of installation. A whole building-level commitment requires 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. 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. From our inception to December 31, 2011, our total payments to customers and incurred equipment replacement and maintenance costs under our energy efficiency commitments, after customer acceptance of a project, have been less than $100,000 in the aggregate. 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.

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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, including a specified annual increase in the price our subsidiary charges the customer for biomass fuel, incentives for the customer to make on-site biomass available to the cogeneration facility, an escrow fund from which our subsidiary can withdraw funds should the price of biomass in a given year exceed that charged to the customer, the right to reduce the amount of steam generated by the use of biomass to a stipulated minimum level and the ability to use other fuels, such as used tires, to produce up to 30% of the facility’s total production. 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 depends in large part on the skill of our personnel. Accordingly, it is critical that we maintain, and continue to build, a highly experienced management team and specialized workforce, including engineers, project and construction management, and business development and sales professionals. In addition, our construction projects require a significant amount of trade labor resources, such as electricians, mechanics, carpenters, masons and other skilled workers, as well as certain specialty subcontractor skills.
Competition for personnel, particularly those with expertise in the energy services and renewable energy industries, is high, and identifying candidates with the appropriate qualifications can be costly and difficult. We may not be able to hire the necessary personnel to implement our business strategy given our anticipated hiring needs, or we may need to provide higher compensation or more training to our personnel than we currently anticipate.
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, which may have an adverse effect on our financial results, harm our reputation and cause us to curtail our pursuit of new projects. Further, any increase in demand for personnel and specialty subcontractors may result in higher costs, causing us to exceed the budget on a project, which in turn may have an adverse effect on our business, financial condition and operating results and harm our relationships with our customers.
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. Our sureties historically required that George P. Sakellaris, who is our founder, principal stockholder, president and chief executive officer, personally indemnify them for up to an aggregate of $50 million of losses associated with the bonds they have provided on our behalf. This indemnity terminated in December 2010. Nonetheless, in the event that Mr. Sakellaris no longer controls our company, our sureties may reevaluate the surety relationship. Our ability to

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obtain required bonds or letters of credit depends in large part upon our capitalization, working capital, past performance, management expertise and reputation, and external factors beyond our control, including the overall capacity of the surety market. Our ability to obtain letters of credit under our existing credit arrangements is limited. We are not permitted to have more than $10 million in letters of credit outstanding at any time (including letters of credit that have been drawn upon but not repaid on our behalf) under the terms of our senior secured credit facility. Moreover, our use of letters of credit limits our borrowing capability under the revolving portion of our senior secured credit facility as the aggregate amount of letters of credit we have outstanding at any time reduces our borrowing capacity under the facility by an equal amount. As of December 31, 2011, we had an immaterial amount of letters of credit outstanding.
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, revenue, 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 competing business model, develop products or services that are more attractive to potential customers than what we offer or convince our potential customers that they should require financing arrangements that would be impractical for smaller companies to offer. 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 revenue, 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;

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mishandling of hazardous substances and waste; and
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 may be unable to manage our growth effectively.
Our business and operations have expanded rapidly in the last several years, and we anticipate that further expansion of our organization and operations will be required to achieve our expectations for future growth. In order to manage our expanding operations, we will need to continue to improve our management, operational and financial controls and our reporting systems and procedures. All of these measures will require significant expenditures and will demand the attention of management. If we do not continue to enhance our management personnel and our operational and financial systems and controls in response to growth in our business, we could experience operating inefficiencies that could impair our competitive position and could increase our costs more than we had planned. If we are unable to manage growth effectively, our business, financial condition and operating results could be adversely affected.
We expect that some of our growth will be accomplished through the opening of new offices and the hiring of additional personnel to staff those offices. Even if an office is ultimately successful in generating additional revenue and profit for us, there is generally a lag of several years before we are able to recoup the expenses associated with opening that office.
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 revenue.
The sales, design and construction process for energy efficiency and renewable energy projects typically takes from 12 to 36 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 have extended budgeting and procurement processes, and sometimes must engage in regulatory approval processes, related to our services. 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 revenue.

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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.
Generally, government contracts contain provisions permitting unilateral termination or modification, in whole or in part, at the government’s convenience. Under general principles of government contracting law, if the government terminates a contract for convenience, the terminated company may recover only its incurred or committed costs, settlement expenses and profit on work completed prior to the termination. If the government terminates a contract for default, the defaulting company is entitled to recover costs incurred and associated profits on accepted items only and may be liable for excess costs incurred by the government in procuring undelivered items from another source. In most of our contracts with the federal government, the government has agreed to make a payment to us in the event that it terminates the agreement early. The termination payment is designed to compensate us for the cost of construction plus financing costs and profit on the work completed.
In ESPCs for governmental entities, the methodologies for computing energy savings may be less favorable than for non-governmental customers and may be modified during the contract period. We may be liable for price reductions if the projected savings cannot be substantiated.
In addition to the right of the federal government to terminate its contracts with us, federal government contracts are conditioned upon the continuing approval by Congress of the necessary spending to honor such contracts. Congress often appropriates funds for a program on a September 30 fiscal-year basis even though contract performance may take more than one year. Consequently, at the beginning of many major governmental programs, contracts often may not be fully funded, and additional monies are then committed to the contract only if, as and when appropriations are made by Congress for future fiscal years. Similar practices are likely to also affect the availability of funding for our contracts with Canadian, as well as state, provincial and local, government entities. If one or more of our government contracts were terminated or reduced, or if appropriations for the funding of one or more of our contracts is delayed or terminated, our business, financial condition and operating results could be adversely affected.
Government contracts normally contain additional terms and conditions that may increase our costs of doing business, reduce our profits and expose us to liability for failure to comply with these terms and conditions. These include, for example:
specialized accounting systems unique to government contracting, which may include mandatory compliance with federal Cost Accounting Standards;
mandatory financial audits and potential liability for adjustments in contract prices;
public disclosure of contracts, which may include pricing information;
mandatory socioeconomic compliance requirements, including small business promotion, labor, environmental and U.S. manufacturing requirements; and
requirements for maintaining current facility and/or personnel security clearances to access certain government facilities or to maintain certain records, and related industrial security compliance requirements.
Our contracts with Canadian governmental entities frequently involve similar risks. Any failure by us to comply with these governmental requirements could adversely affect our business.

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Our renewable energy projects, particularly our LFG projects, depend on locating and acquiring suitable operating sites, of which there are a limited number.
Our biogas renewable energy projects must be sited at locations where we can secure sufficient supplies of biogas and economical connections to provide power or biofuel to customers. Specifically, LFG projects must originate on or near one of the remaining approximately 500 U.S. landfills currently available and believed to be able to sustain economically viable LFG projects according to the EPA's Landfill Methane Outreach Program. Sites for our renewable energy plants must be suitable for construction and efficient operation, which, among other things, requires appropriate road access. Further, electric plants must be interconnected to electricity transmission or distribution networks. Once we have identified a suitable project site, obtaining the requisite LFG and/or lease or other land rights (including access rights, setbacks and other easements) requires us to negotiate with landowners and local government officials. These negotiations can take place over a long time, are not always successful and sometimes require economic concessions not in our original plans. The property rights necessary to construct and interconnect our plants must also be insurable and otherwise satisfactory to our financing counterparties. In addition, our ability to obtain adequate LFG and/or property rights is subject to competition. If a competitor or other party obtains LFG and/or land rights critical to our project development efforts and we are unable to reach agreement for their use, we could incur losses as a result of development costs for sites we do not develop, which we would have to write off. If we are unable to obtain adequate LFG and/or property or other rights for a renewable energy plant, including its interconnection, that plant may be smaller in size or potentially unfeasible. Failure to obtain insurable property rights for a project satisfactory to our financing sources would preclude our ability to obtain third-party financing and could prevent ongoing development and construction of that project.
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 assume or be held liable for risks and liabilities (including for environmental-related costs) as a result of our acquisitions, some of which we may not discover during our due diligence or adequately adjust for in our acquisition arrangements;
our ongoing business and management’s attention may be disrupted or diverted by transition or integration issues and the complexity of managing geographically or culturally diverse enterprises;
we may incur one-time write-offs or restructuring charges in connection with the acquisition;
we may acquire goodwill and other intangible assets that are subject to amortization or impairment tests, which could result in future charges to earnings; and

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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, or FERC, under the FPA, but certain of our projects that are under construction or development could become subject to such regulation in the future. Also, we may acquire interests in or develop generating projects that are not qualifying facilities. Non-qualifying facility projects would be fully subject to FERC corporate and rate regulation, and would be required to obtain FERC acceptance of their rate schedules for wholesale sales of energy, capacity and ancillary services, which requires substantial disclosures to and discretionary approvals from FERC. FERC may revoke or revise an entity’s authorization to make wholesale sales at negotiated, or market-based, rates if FERC determines that we can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions or market manipulation. In addition, many public utilities (including any non-qualifying facility generator in which we may invest) are subject to FERC reporting requirements that impose administrative burdens and that, if violated, can expose the company to civil penalties or other risks.

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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. For example, in 2009, a customer for which we were performing an energy efficiency project initiated a legal proceeding against us as a result of project delays that we believe were attributable to the discovery of hazardous materials and need for remediation by the customer. An adverse outcome in this proceeding could have an adverse effect on our operating results in the period in which the outcome is determined.
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 revenue 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 revenue from outside of North America. However, international expansion is one of our growth strategies, and we expect our revenue 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;

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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.
Our insurance and contractual protections may not always cover lost revenue, increased expenses or liquidated damages payments.
Although we maintain insurance, obtain warranties from suppliers, obligate subcontractors to meet certain performance levels and attempt, where feasible, to pass risks we cannot control to our customers, the proceeds of such insurance, warranties, performance guarantees or risk sharing arrangements may not be adequate to cover lost revenue, increased expenses or liquidated damages payments that may be required in the future.
If the cost of energy generated by traditional sources does not increase, or if it decreases, demand for our services may decline.
Decreases in the costs associated with traditional sources of energy, such as prices for commodities like coal, oil and natural gas, may reduce demand for energy efficiency and renewable energy solutions. Technological progress in traditional forms of electricity generation or the discovery of large new deposits of traditional fuels could reduce the cost of electricity generated from those sources and as a consequence reduce the demand for our solutions. Any of these developments could have a material adverse effect on 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.
As previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2010, filed with the SEC on March 31, 2011, we identified a material weakness in our internal control over financial reporting. In 2009 and for most of 2010, we did not have personnel with an appropriate level of knowledge, experience and training in the selection, application and implementation of GAAP as it relates to certain complex accounting issues, income taxes and SEC financial reporting requirements; and further we did not have certain personnel in place for the appropriate amount of time and lacked certain other personnel to ensure adequate levels of review of accounting and financial reporting matters, which resulted in our closing process not identifying all required adjustments in a timely fashion. In connection with our fiscal 2011 audit, we concluded that we did not have sufficient personnel in place for an adequate amount of time or effectively operating internal control procedures to ensure timely and accurate reviews necessary to provide reasonable assurance that financial statements and related disclosures could be prepared in accordance with generally accepted accounting principles.
For a discussion of the material weakness and our remediation efforts during 2011 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 similar material weaknesses will not recur.

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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, or 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 of utilities. For example, utility companies are commonly allowed by regulatory authorities to charge fees to larger industrial 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 revenue. In addition, modifications to the pricing policies of utilities could require renewable energy systems to achieve lower prices in order to compete with the price of electricity from the electric grid and may reduce the economic attractiveness of certain energy efficiency measures.
Some of the demand-reduction services we provide for utilities and institutional clients are subject to regulatory tariffs imposed under federal and state utility laws. In addition, the operation of, and electrical interconnection for, our renewable energy projects are subject to federal, state or provincial interconnection and federal reliability standards that are also set forth in utility tariffs. These tariffs specify rules, business practices and economic terms to which we are subject. The tariffs are drafted by the utilities and approved by the utilities’ state and federal regulatory commissions. These tariffs change frequently and it is possible that future changes will increase our administrative burden or adversely affect the terms and conditions under which we render service to our customers.
Our activities and operations are subject to numerous health and safety laws and regulations, and if we violate such regulations, we could face penalties and fines.
We are subject to numerous health and safety laws and regulations in each of the jurisdictions in which we operate. These laws and regulations require us to obtain and maintain permits and approvals and implement health and safety programs and procedures to control risks associated with our projects. Compliance with those laws and regulations can require us to incur substantial costs. Moreover, if our compliance programs are not successful, we could be subject to penalties or to revocation of our permits, which may require us to curtail or cease operations of the affected projects. Violations of laws, regulations and permit requirements may also result in criminal sanctions or injunctions.
Health and safety laws, regulations and permit requirements may change or become more stringent. Any such changes could require us to incur materially higher costs than we currently have. Our costs of complying with current and future health and safety laws, regulations and permit requirements, and any liabilities, fines or other sanctions resulting from violations of them, could adversely affect our business, financial condition and operating results.
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 restrictions on our and certain of our subsidiaries’ ability to, among other things:
incur additional debt, or debt related to federal projects in excess of specified limits;
pay cash dividends and make distributions;
make certain investments and acquisitions;
guarantee the indebtedness of others or our subsidiaries;
redeem or repurchase capital stock;
create liens;

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enter into transactions with affiliates;
engage in new lines of business;
sell, lease or transfer certain parts of our business or property;
enter into sale-leaseback arrangements; and
merge or consolidate.
These agreements also contain other customary covenants, including covenants that require us to meet specified financial ratios and financial tests. We may not be able to comply with these covenants in the future. 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.
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 revenue 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 revenue is derived under multi-year or long-term contracts with our customers, and our revenue is therefore dependent to a large extent on the creditworthiness of our customers. During periods of economic downturn in the global economy, 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.
The use and enjoyment of real property rights for our small-scale renewable energy projects may be adversely affected by the rights of lienholders and leaseholders that are superior to those of the grantors of those real property rights to us.
Our small-scale renewable energy projects generally are, and are likely to continue to be, located on land we or our customers occupy pursuant to long-term easements and leases. The ownership interests in the land subject to these easements and leases may be subject to mortgages securing loans or other liens (such as tax liens) and other easement and lease rights of third parties (such as leases of oil or mineral rights) that were created prior to our or our customers’ easements and leases. As a result, the rights under these easements or leases may be subject, and subordinate, to the rights of those third parties. We typically perform title searches and obtain title insurance to protect ourselves or our customers against these risks. Such measures may, however, be inadequate to protect against all risk of loss of rights to use the land on which these projects are located, which could have a material adverse effect on our business, financial condition and operating results.
Fluctuations in foreign currency exchange rates can impact our results.
A significant portion of our total revenue is 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.

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Risks Related to Ownership of Our Class A Common Stock
The trading price of our Class A common stock is volatile.
We sold shares of our Class A common stock in our initial public offering in July 2010 at a price of $10.00 per share, and our Class A common stock has subsequently traded at a price per share as high as $17.46 and as low as $8.60. The trading price of our Class A common stock is likely to continue to be volatile and could be subject to wide fluctuations in response to various factors. In addition to the risks described in this section, factors that may cause the market price of our Class A common stock to fluctuate include:
fluctuations in our quarterly financial results or the quarterly financial results of companies perceived to be similar to us;
changes in estimates of our future financial results or recommendations by securities analysts;
investors’ general perception of us; and
changes in general economic, industry and market conditions.
In addition, if the stock market in general experiences a significant decline, the trading price of our Class A common stock could decline for reasons unrelated to our business, financial condition or operating results.
Some companies that have had volatile market prices for their securities have had securities class actions filed against them. If a suit were filed against us, regardless of its merits or outcome, it would likely result in substantial costs and divert management’s attention and resources. This could have a material adverse effect on our business, operating results and financial condition.
Holders of our Class A common stock are entitled to one vote per share, and holders of our Class B common stock are entitled to five votes per share. The lower voting power of our Class A common stock may negatively affect the attractiveness of our Class A common stock to investors and, as a result, its market value.
We have two classes of common stock: Class A common stock, which is listed on the NYSE and which is entitled to one vote per share, and Class B common stock, which is not listed on the any security exchange and is entitled to five votes per share. The difference in the voting power of our Class A and Class B common stock could diminish the market value of our Class A common stock because of the superior voting rights of our Class B common stock and the power those rights confer.
For the foreseeable future, Mr. Sakellaris or his affiliates will be able to control the selection of all members of our board of directors, as well as virtually every other matter that requires stockholder approval, which will severely limit the ability of other stockholders to influence corporate matters.
Except in certain limited circumstances required by applicable law, holders of Class A and Class B common stock vote together as a single class on all matters to be voted on by our stockholders. Mr. Sakellaris, our founder, principal stockholder, president and chief executive officer, owns all of our Class B common stock, which, together with his Class A common stock, represents approximately 80% of the combined voting power of our outstanding Class A and Class B common stock. Under our restated certificate of incorporation, holders of shares of Class B common stock may generally transfer those shares to family members, including spouses and descendents or the spouses of such descendents, 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 descendents 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 18.5% 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.
Future sales of shares by existing stockholders could cause our stock price to decline.
Sales by our existing stockholders of a substantial number of shares in the public market, or the threat that substantial sales might occur, could cause the market price of the Class A common stock to decrease significantly. These factors could also make it difficult for us to raise additional capital by selling our Class A common stock.

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If securities or industry analysts do not publish research or publish inaccurate or unfavorable research about our business, our stock price and trading volume could decline.
The trading market for our Class A common stock depends in part on any research reports that securities or industry analysts publish about us or our business. In the event one or more securities or industry analysts downgrade our stock or publish unfavorable reports about our business, our stock price would likely decline. In addition, if any securities or industry analysts cease coverage of our company or fail to publish reports on us regularly, demand for our Class A common stock could decrease, which could cause our stock price and trading volume to decline.
We do not anticipate paying any cash dividends on our capital stock in the foreseeable future.
We have never declared or paid any cash dividends on our capital stock and do not currently expect to pay any cash dividends for the foreseeable future. Our senior secured credit facility limits our ability to declare and pay cash dividends during the term of that agreement. We intend to use our future earnings, if any, in the operation and expansion of our business. Accordingly, you are not likely to receive any dividends on your Class A common stock for the foreseeable future, and your ability to achieve a return on your investment will therefore depend on appreciation in the market price of our Class A common stock.
Anti-takeover provisions in our charter documents and Delaware law could discourage, delay or prevent a change in control of our company and may affect the trading price of our Class A common stock.
We are a Delaware corporation and the anti-takeover provisions of the Delaware General Corporation Law may discourage, delay or prevent an acquisition of our company by prohibiting us from engaging in a business combination with an interested stockholder for a period of three years after the person becomes an interested stockholder, even if a change in control would be supported by our existing stockholders. In addition, our restated certificate of incorporation and by-laws may discourage, delay or prevent an acquisition or a change in our management that stockholders may consider favorable. Our restated certificate of incorporation and by-laws:
provide for a dual class capital structure that allows our founder, principal stockholder, president and chief executive officer, Mr. Sakellaris, 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;
authorize the issuance of “blank check” preferred stock that could be issued by our board of directors to thwart a takeover attempt;
establish a classified board of directors, as a result of which only approximately one-third of our directors are presented to a stockholder vote for re-election at any annual meeting of stockholders;
provide that directors may be removed from office only for cause and only upon a supermajority stockholder vote;
provide that vacancies on our board of directors, including newly created directorships, may be filled only by a majority vote of directors then in office;
do not permit stockholders to call special meetings of stockholders;
prohibit stockholder action by written consent, requiring all actions to be taken at a meeting of the stockholders;
establish advance notice requirements for nominations for election to our board of directors or for proposing matters that can be acted upon by stockholders at stockholder meetings; and
require a supermajority stockholder vote to effect certain amendments to our restated certificate of incorporation and by-laws.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Our corporate headquarters is located in Framingham, Massachusetts, where we occupy approximately 20,000 square feet under a lease expiring on June 30, 2016. We occupy ten regional offices in Temple, 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

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lease space, typically less space, for 62 field offices throughout North America. We also own 53 small-scale renewable energy and central 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 financial statements.
For additional information about certain proceedings, please refer to Note 14, 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.

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PART II

Item 5.
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our Class A common stock has been traded on the New York Stock Exchange under the symbol “AMRC” since our initial public offering on July 22, 2010. The following table sets forth, for the fiscal quarters indicated, the high and low sale prices per share of our Class A common stock.
 
 
2010
2011
 
 
High
Low
High
Low
First Quarter
 
$

$

$
17.46

$
12.65

Second Quarter
 


17.09

12.31

Third Quarter (beginning July 22, 2010)
 
14.17

9.34

15.12

9.52

Fourth Quarter
 
14.88

11.51

13.74

8.60

The closing sale price of our Class A common stock was $13.76 on March 1, 2012, and according to the records of our transfer agent, there were 23 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 with Bank of America 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 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 17-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, 2011.












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COMPARISON OF 17 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, 2011.
 
7/22/2010
12/31/2010
12/31/2011
Ameresco, Inc.
$100.00
$141.20
$134.91
Russell 2000 Index
$100.00
$129.38
$123.98
NASDAQ Clean Edge
   Green Energy Index
$100.00
$123.01
$69.12
Shareholder returns over the indicated period should not be considered indicative of future shareholder returns.

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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, 2009, 2010, and 2011 and the consolidated balance sheet data at December 31, 2010 and 2011 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, 2007 and 2008, and the consolidated balance sheet data at December 31, 2007, 2008, 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.
 
 
 
 
 
Years Ended December 31,
 
 
2007
 
2008
 
2009
 
2010
 
2011
 
 
(In thousands, except share and per share data)
Consolidated Statement of Income Data:
 
 

 
 

 
 

 
 

 
 

Revenue(1):
 
 

 
 

 
 

 
 

 
 

Energy efficiency revenue
 
$
345,936

 
$
325,032

 
$
340,635


$
455,329

 
$
551,324

Renewable energy revenue
 
32,541

 
70,822

 
87,882


162,897

 
176,876

 
 
378,477

 
395,854

 
428,517

 
618,226

 
728,200

Direct expenses:
 
 

 
 

 
 

 
 

 
 

Energy efficiency expenses
 
285,966

 
259,019

 
282,345


378,084


446,963

Renewable energy expenses
 
26,072

 
59,551

 
66,472


129,440


146,191

 
 
312,038

 
318,570

 
348,817

 
507,524

 
593,154

Gross profit
 
66,439

 
77,284

 
79,700

 
110,702

 
135,046

Operating expenses
 
47,042

 
52,608

 
54,406

 
64,710

 
84,360

Operating income
 
19,397

 
24,676

 
25,294

 
45,992

 
50,686

Other (expense) income, net
 
(3,138
)
 
(5,188
)
 
1,563

 
(5,080
)
 
(5,192
)
Income before provision for income taxes
 
16,259

 
19,488

 
26,857

 
40,912

 
45,494

Income tax provision
 
(5,714
)
 
(1,215
)
 
(6,950
)
 
(12,186
)
 
(10,767
)
Net income
 
$
10,545

 
$
18,273

 
$
19,907

 
$
28,726

 
$
34,727

Net income per share attributable to common shareholders:
 
 

 
 

 
 

 
 

 
 

Basic(2)
 
$
0.95

 
$
1.71

 
$
1.99

 
$
1.12

 
$
0.82

Diluted
 
$
0.28

 
$
0.54

 
$
0.61

 
$
0.69

 
$
0.78

Weighted-average number of common shares outstanding:
 
 

 
 

 
 

 
 

 
 

Basic(2)
 
11,121,022

 
10,678,110

 
9,991,912

 
25,728,314

 
42,587,818

Diluted
 
37,552,953

 
33,990,547

 
32,705,617

 
41,513,482

 
44,707,132

Other Operating Data:
 
 

 
 

 
 

 
 

 
 

Adjusted EBITDA(3)
 
$
27,974

 
$
29,045

 
$
35,097

 
$
59,910

 
$
67,560



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As of December 31,
 
 
2007
 
2008
 
2009
 
2010
 
2011
 
 
(In thousands)
Consolidated Balance Sheet Data:
 
 

 
 

 
 

 
 

 
 

Cash and cash equivalents
 
$
40,892

 
$
18,149

 
$
47,928

 
$
44,691

 
$
26,277

Current assets
 
154,036

 
131,432

 
171,772

 
211,710

 
283,062

Total assets
 
262,224

 
292,027

 
375,545

 
584,407

 
645,597

Current liabilities
 
108,011

 
90,967

 
132,330

 
142,587

 
148,268

Long-term debt, less current portion(4)
 
39,316

 
90,980

 
102,807

 
202,409

 
196,402

Subordinated debt
 
2,999

 
2,999

 
2,999

 

 

Total stockholders’ equity
 
70,776

 
74,086

 
102,770

 
195,052

 
236,421

(1)
"Revenue" 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 and impairment expenses, share-based compensation expense and a non-recurring, non-cash recovery of a contingency in 2008. 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.
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, our investors can evaluate our operating results without the additional variations of depreciation and amortization expense, stock-based compensation expense and the non-recurring non-cash recovery of a contingency in 2008.
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 our business;
to evaluate the effectiveness of our business strategies; and
in communications with our board of directors and investors concerning our financial performance.

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We understand that, although measures similar to adjusted EBITDA are frequently used by investors and securities analysts in their evaluation of companies, adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation or as a substitute for GAAP operating income or an analysis of our results of operations as reported under GAAP. Some of these limitations are:
adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or other contractual commitments;
adjusted EBITDA does not reflect changes in, or cash requirements for, our working capital needs;
adjusted EBITDA does not reflect stock-based compensation expense;
adjusted EBITDA does not reflect cash requirements for income taxes;
adjusted EBITDA does not reflect net interest income (expense);
although depreciation, amortization and impairment are non-cash charges, the assets being depreciated, amortized or impaired will often have to be replaced in the future, and adjusted EBITDA does not reflect any cash requirements for these replacements; and
other companies in our industry may calculate adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure.
To properly and prudently evaluate our business, we encourage you to review the GAAP financial statements included elsewhere in this report, and not to rely on any single financial measure to evaluate our business.
The following table presents a reconciliation of adjusted EBITDA to operating income, the most comparable GAAP measure:
 
 
Years Ended December 31,
 
 
2007
 
2008
 
2009
 
2010
 
2011
 
 
(In thousands)
Operating income
 
$
19,397

 
$
24,676

 
$
25,294

 
$
45,992

 
$
50,686

Depreciation, amortization and impairment
 
5,898

 
7,278

 
6,634

 
11,419

 
14,008

Stock-based compensation
 
2,679

 
2,941

 
3,169

 
2,499

 
2,866

Recovery of contingency
 

 
(5,850
)
 

 

 

Adjusted EBITDA
 
$
27,974

 
$
29,045

 
$
35,097

 
$
59,910

 
$
67,560


(4)
Long-term debt, less current portion as of December 31, 2011 reflects a $49.6 million reduction in Federal ESPC receivable financing attributable primarily to acceptance of the Savannah River Site project in December 2011 and includes approximately $37.1 million outstanding with respect to the term loan portion of our senior secured credit facility.

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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.
We report results under ASC 280, Segment Reporting, for four segments: U.S. federal, central U.S. region, other U.S. regions and Canada. Each segment provides customers with energy efficiency and renewable energy solutions. These segments do not include results of other activities, such as operations and maintenance, or O&M, and sales of renewable energy and certain other renewable energy products, that are managed centrally at our corporate headquarters, or corporate operating expenses not specifically allocated to the segments. See Note 20 to our consolidated financial statements appearing in Item 8 of this Annual Report on Form 10-K.
The audited balance sheet, income statement and statement of cash flow included in our consolidated financial statements appearing in Item 8 of this report reflect certain reclassifications from our previously reported unaudited December 31, 2011 balance sheet, income statement and cash flow information. The net effects of these reclassifications are:  (1) to increase total assets, total liabilities and total stockholders' equity by $9.2 million, $7.3 million and $1.9 million from the respective amounts previously reported; (2) to decrease general, administrative and other expenses and increase both operating income and other income (expenses), net by $0.5 million from the respective amounts previously reported; and (3) to increase net cash provided by financing activities by $9.2 million from the amount previously reported.
Our revenue has increased from $20.9 million in 2001, our first full year of operations, to $728.2 million in 2011. We achieved profitability in 2002, and we have been profitable every year since.
In addition to organic growth, strategic acquisitions of complementary businesses and assets have been an important part of our development. Since inception, we have completed fifteen 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 Engineering and Development, Inc., or Quantum, in 2010 expanded our geographical reach into the Northwest. We made three acquisitions in 2011. Our acquisition of energy efficiency and demand side management consulting services provider 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. In late 2011 we acquired the xChangePoint® and energy projects businesses from EPS to expand our service offering to private sector commercial and industrial customers. These businesses offer energy efficiency solutions to customers across North America encompassing the food and beverage, meat, dairy, paper, aerospace, oil and gas and REIT industries.
Energy Savings Performance and Energy Supply Contracts
For our energy efficiency projects, we typically enter into energy savings performance contracts, or 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

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categories: pre-agreed, equipment-level and whole building-level. Under a pre-agreed energy reduction commitment, our customer reviews the project design in advance and agrees that, upon or shortly after completion of installation of the specified equipment comprising the project, the commitment will have been met. Under an equipment-level commitment, we commit to a level of energy use reduction based on the difference in use measured first with the existing equipment and then with the replacement equipment. A whole building-level commitment requires demonstration of energy usage reduction for a whole building, often based on readings of the utility meter where usage is measured. Depending on the project, the measurement and demonstration may be required only once, upon installation, based on an analysis of one or more sample installations, or may be required to be repeated at agreed upon intervals generally over up to 20 years.
Under our contracts, we typically do not take responsibility for a wide variety of factors outside 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 over perform. 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. From our inception to December 31, 2011, our total payments to customers and incurred equipment replacement and maintenance costs under our energy reduction commitments, after customer acceptance of a project, have been less than $100,000 in the aggregate. 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 the 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 debt 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

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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.
In addition to project-related debt, we currently maintain a $100 million senior secured credit facility with a group of commercial banks to finance our working capital needs. See "—Senior Secured Credit Facility—Revolver and Term Loan" below.
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 revenue and operating income in the third quarter are typically higher, and our revenue 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.
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. Historically, our sales cycle typically has averaged 12 to 36 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. Historically, awarded projects typically have taken 6 to 12 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. After the customer and Ameresco agree to the terms of the contract and the contract becomes executed, the project moves to fully-contracted backlog. The contracts reflected in our fully-contracted backlog typically have a construction period of 12 to 24 months; this is the period over which we expect to recognize revenue for customer contracts. Fully-contracted backlog begins converting into revenue generated from backlog on a percentage-of-completion basis once construction has commenced. See "We may not recognize all revenue from our backlog or receive all payments anticipated under awarded projects and customer contracts" in Item 1A, Risk Factors in this Annual Report on Form 10-K.
As of December 31, 2011, we had backlog of approximately $478 million in future revenue 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 revenue of an additional $741 million. As of December 31, 2010, we had fully-contracted backlog of approximately $651 million in future revenue 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 revenue of an additional $483 million.

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Financial Operations Overview
Revenue
We derive revenue 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, and the sale and installation of solar energy products and systems.
While in any particular quarter a single customer may account for more than ten percent of revenue, for the years ended December 31, 2009 and 2011, no customer accounted for more than ten percent of our revenue. During the year ended December 31, 2010, one customer, the U.S. Department of Energy, Savannah River Site, accounted for 11.5% of our total revenue.
Direct Expenses and Gross Margin
Direct expenses 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 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.
Direct expenses also include O&M 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 our acquisitions in 2011, we now 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 a direct expense.
Gross margin, which is gross profit as a percent of revenue, is affected by a number of factors, including the type of services performed and the geographic region in which the sale is made. 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.
Operating Expenses
Operating expenses consist of salaries and benefits, project development costs, and general, administrative and other expenses.
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. We expect salaries and benefits to continue to increase as we continue to incur additional costs related to operating as a publicly-traded company, including accounting, compliance and legal, as well as related to executing our growth plans.
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. We intend to hire additional sales personnel and initiate additional marketing programs as we expand into new regions or complement existing development resources. Accordingly, we expect that our project development costs will continue to increase, but will moderate as a percentage of revenue over time.
General, administrative and other 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. We expect general and administrative expenses to continue to increase as we continue to incur additional costs related to operating as a publicly-traded company, including increased audit and legal fees, costs of compliance with securities, corporate governance and other regulations, investor relations expenses and higher insurance premiums, particularly those related to director and officer insurance, as well as related to executing our growth plans.

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Other Income (Expenses), Net
Other income (expenses), net consists primarily of interest income on cash balances, interest expense on borrowings and amortization of deferred financing costs, unrealized gains and losses on derivatives not accounted for as hedges, and realized gains on derivatives not 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.
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, revenue, 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 photovoltaic, or PV, equipment and other renewable energy products for which we are a distributor, whether under our own brand name or for others; and
O&M services provided under long-term O&M agreements, as well as consulting services.
Often, we will sell a combination of these services and products in a bundled arrangement. We divide bundled arrangements into separate deliverables and revenue is allocated to each deliverable based on the relative selling price. The relative selling price is determined using vendor specific objective evidence, third party evidence or management's best estimate of selling price.
We recognize revenue 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 revenue associated with contract change orders only when the authorization for the change order has been properly executed and the work has been performed and accepted by the customer.
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

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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 revenue 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 revenue from O&M contracts and consulting 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 revenue 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, 2009, 2010 and 2011 was $1.4 million, $0.3 million and $0.4 million, respectively.
Routine maintenance costs are expensed in the current year’s consolidated statements of income and comprehensive 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 general and administrative expenses in the consolidated statements of income and comprehensive 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 ASC Topic 350 in accounting for the valuation of goodwill and identifiable intangible assets. During our annual goodwill impairment tests at December 31, 2009, 2010 and 2011, we determined that the fair value of equity exceeded the carrying value of equity, and therefore that goodwill and intangible assets were not impaired.
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.
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, 2009, 2010 and 2011 annual testing dates and determined that the fair value of equity exceeded the carrying value of equity, and therefore that goodwill was not impaired.

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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.
In addition, we periodically review the estimated useful lives of our identifiable intangible assets, taking into consideration any events or circumstances that might result in either a diminished fair value or revised useful life. If the Step 1 test concludes an impairment is indicated, we will employ a second step to measure the impairment. 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 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.
Impairment of Long-Lived Assets
We periodically evaluate long-lived assets for events and circumstances that indicate a potential impairment. A review of long-lived assets for impairment is performed whenever events or changes in business 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. Each impairment test is based on a comparison of the estimated undiscounted cash flows of the asset as compared to the recorded value of the asset. If these estimates or their related assumptions change in the future, an impairment charge may be required against these assets in the reporting period in which the impairment is determined.
Derivative Financial Instruments
We account for our interest rate swaps as derivative financial instruments in accordance with the related guidance. Under this guidance, derivatives are carried on our consolidated balance sheet 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.
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 three projects 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. We entered into the interest rate swap contracts as an economic hedge. In July 2011, we entered into a five-year interest rate swap contract under which we agreed to pay an

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amount equal to a specified fixed rate of interest times a notional amount, and to in turn receive an amount equal to a specified variable rate of interest times the same notional principal amount. The swap covers a notional amount of $38.6 million variable rate note at a fixed interest rate of 1.965% and expires in June 2016.
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 income (expense) in our consolidated statements of income and comprehensive income at fair value, and in the consolidated statements of comprehensive income thereafter. Cash flows from these derivative instruments are reported as operating activities on the consolidated statements of cash flows.
The interest rate swaps that we entered into during 2010 and 2011 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).
With respect to our interest rate swaps, we recorded the unrealized gain (loss) in earnings in 2009 and 2010 of $2.3 million and $(0.1) million, respectively, as other income (expense) in our consolidated statements of income and comprehensive income. No unrealized gain (loss) was recorded in earnings for the year ended December 31, 2011.
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.
Business Segments
We report four segments: U.S. federal, central U.S. region, other U.S. regions and Canada. Each segment provides customers with energy efficiency and renewable energy solutions. The other U.S. regions segment is an aggregation of four regions: northeast U.S., southeast U.S., southwest U.S. and northwest U.S. These regions have similar economic characteristics — in particular, expected and actual gross profit margins. In addition, they sell products and services of a similar nature, serve similar types of customers and use similar methods to distribute their products and services. Accordingly, these four regions meet the aggregation criteria set forth in ASC 280. The “all other” category includes activities, such as O&M and sales of renewable energy and certain other renewable energy products, that are managed centrally at our corporate headquarters. It also includes all corporate operating expenses — salaries and benefits, project development costs, and general, administrative and other — not specifically allocated to the segments. We do not allocate any indirect expenses to the segments.
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.

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Grants of Restricted Shares
On October 25, 2006, we issued 2,000,000 shares of restricted stock to George P. Sakellaris, our founder, principal shareholder, president and chief executive officer under the 2000 stock plan in consideration for his personal indemnity of surety arrangements required for certain projects. The shares vested in full upon the date three years from the date of grant. At the time the shares were issued, the fair value was determined to be $3.41 per share. The shares vested in October 2009. We recorded an expense of $1.9 million in 2009 related to this award. No expense was recorded in 2010 and 2011 related to this award. This expense is included in salaries and benefits in our consolidated statements of income and comprehensive income.
Issuance of Warrants
As part of a financing agreement, we issued warrants to acquire 2,000,000 and 1,600,000 shares of common stock in 2001 and 2002, respectively. The warrants initially had a per share exercise price of $0.005 and $0.30, respectively; however, the $0.30 per share exercise price was subsequently reduced to $0.005. During 2008, we repurchased 3,194,714 of these warrants at an average price of $2.505 per share, for a total price of $8.0 million. We recorded this transaction in additional paid-in capital and it is reflected in our consolidated balance sheets for 2008 and 2009. In June 2010, we issued 405,286 shares of Common Stock upon the exercise of a warrant at an exercise price of $0.005 per share, and no warrants to purchase shares of our Common Stock remain outstanding.
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, 2011, 9,742,500 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 and comprehensive income based on their fair values, using the prospective-transition method.
Effective with the adoption of ASC 718, we elected to use the Black-Scholes option pricing model to determine the weighted-average fair value of options granted.
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 2009, 2010 and 2011:
 
 
Years Ended December 31,
 
 
2009
 
2010
 
2011
Future dividends
 
$ -
 
$ -
 
$ -
Risk-free interest rate
 
2.00-2.94%
 
2.59-3.11%
 
1.35-2.58%
Expected volatility
 
57%-59%
 
57%-59%
 
32%-33%
Expected life
 
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

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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 direct expenses, project development and marketing expenses, and salaries and benefits expense.
As of December 31, 2011, we had $7.1 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 3.24 years after December 31, 2011. The allocation of this expense between direct expenses, project development and marketing expenses, and salaries and benefits expense will depend on the salaries and work assignments of the personnel holding these options.
Determination of Fair Value
We believe we have used reasonable methodologies and assumptions in determining the fair value of our common stock for financial reporting purposes. Prior to our initial public offering in July 2010, our board of directors had historically estimated the fair value of our common stock. Because there was then no public market for our shares, our board of directors historically determined the fair value of our common stock based primarily on the market approach, together with a number of objective and subjective factors, including:
our results of operations and financial condition during the most recently completed period;
forecasts of our financial results and market conditions affecting our business; and
developments in our business.
The market approach estimates the fair value of a company by applying market multiples of publicly-traded, or recently-acquired, firms in the same or similar lines of business to the results and projected results of the company being valued. In establishing exercise prices for our options, we followed a methodology designed to result in exercise prices that were not lower than, but could be higher than, the then fair value of our common stock. When choosing companies for use in the market approach, we focused on companies that provide energy efficiency services and have high rates of growth. To determine our enterprise value, we reviewed the multiple of market valuations of the comparable companies to their adjusted EBITDA for the prior fiscal year (based on publicly-available data), as well as the multiples of adjusted EBITDA for the prior fiscal year paid by us for our acquisitions. Based on this review, we established a market multiple which was generally higher than that of our comparable companies, and which we then applied to our own adjusted EBITDA for the prior fiscal year. To determine equity value, we added cash on hand at the end of the period and the cash from the pro forma exercise of stock options, and then subtracted senior corporate debt. The resulting value was divided by the number of common shares outstanding on a fully diluted basis to obtain the fair value per share of common stock. Typically, we performed a new valuation annually after completing our audited consolidated financial statements.
We used adjusted EBITDA in determining our enterprise value under the market approach because we believe that metric provides greater comparability than other metrics for the companies included in the analysis. We considered using net income, book value and cash flow; however, we found those metrics less meaningful than adjusted EBITDA due to varying levels of non-cash and non-operating income and expenses, and the effects of leverage, in the other companies’ financial statements. We believe adjusted EBITDA was the most meaningful financial metric for purposes of estimating the fair value of our common stock for financial statement reporting purposes because it is an unlevered measure of operating earnings potential before financing and certain other accounting decisions are considered. In addition to the use of the market approach to determine the enterprise value, we considered the discounted cash flow methodology to estimate the equity value in the goodwill impairment analysis discussed in Note 1. The resulting equity values obtained from the discounted cash flow methodology corroborated the results of the market approach used in our contemporaneous common stock valuations.

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Since the beginning of 2007, we have granted stock options with exercise prices as follows:
 
 
Number of Shares of
 
 
 
 
Common Stock
 
 
 
 
Subject to Option
 
Exercise Price
Grant Date or Period
 
Grants
 
per Share
January 24, 2007
 
500,000

 
$
3.410

July 25, 2007 to January 30, 2008
 
982,000

 
4.220

April 30, 2008 to January 28, 2009
 
248,000

 
6.055

July 22, 2009 to September 30, 2009
 
842,000

 
6.055

April 26, 2010 to May 28, 2010
 
856,000

 
13.045

The analysis undertaken in determining the exercise prices for all option grants between January 24, 2007 and July 22, 2010, the date of our initial public offering. are summarized below.
Grants on January 24, 2007. On October 25, 2006, our board of directors established the exercise price per share of common stock at $3.41 per share. The market approach resulted in an enterprise value of $144.6 million, determined by applying the market multiple to our adjusted EBITDA for the year ended December 31, 2005. That value was increased by cash on hand totaling $11.8 million and reduced by debt of $10.5 million, for an equity value of $145.9 million. The equity value was divided by 42.8 million fully diluted shares outstanding to arrive at the estimated fair value per share.
Grants from July 25, 2007 to January 30, 2008. On July 25, 2007, our board of directors established the exercise price per share of common stock at $4.22 per share. The market approach resulted in an enterprise value of $157.9 million, determined by applying the market multiple to our adjusted EBITDA for the year ended December 31, 2006. That value was increased by cash on hand totaling $45.5 million and reduced by debt of $8.0 million, for an equity value of $195.3 million. The equity value was divided by 46.2 million fully diluted shares outstanding to arrive at the estimated fair value per share.
Grants from April 30, 2008 to January 28, 2009. On April 30, 2008, our board of directors established the exercise price per share of common stock at $6.055 per share. The market approach resulted in an enterprise value of $223.6 million, determined by applying the market multiple to our adjusted EBITDA for the year ended December 31, 2007. That value was increased by cash on hand totaling $45.5 million and reduced by debt of $8.0 million. In view of the increase in the number of options outstanding, we added the pro forma exercise cash value of the options, at a weighted-average exercise price of $1.995 per share, totaling $21.7 million. This resulted in an equity value of $280.7 million, which was divided by 46.4 million fully diluted shares outstanding to arrive at the estimated fair value per share.
Grants from July 22, 2009 to September 30, 2009. On July 22, 2009, our board of directors established the exercise price per share of common stock at $6.055 per share. Based on the methodology described above, our board would have decreased the value of a share of our common stock (from $6.055 to $5.66). However, the decrease was due primarily to higher corporate debt levels and a lower cash balance, which in our board’s view were the result primarily of the unprecedented economic conditions prevailing at that time. Our board, therefore, determined not to reduce its estimate of the fair value of the common stock and to maintain the value at $6.055 per share.
In March 2010, in connection with the preparation of our consolidated financial statements for the year ended December 31, 2009 and in preparing for our initial public offering, our board of directors decided to undertake a reassessment of the fair value of our common stock in 2007, 2008 and 2009. As a part of that reassessment, our board of directors took into account not only the factors it originally considered in determining fair value, but it also considered as of such dates:
the liquidation preferences of our preferred stock, including any financing and repurchase activities that may have occurred in the relevant period;
the illiquid nature of our common stock, including the opportunity and timing for any expected liquidity events;
our size and historical operating and financial performance, including our recent operating and financial projections as of each grant date;
our existing backlog;

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important events in the development of our business; and
the market performance of a peer group comprised of selected publicly-traded companies we identified as being guidelines for us.
In performing this retrospective analysis, we reexamined and reapplied the market approach and also applied the current value method to allocate the equity to the various share classes as outlined in the American Institute of Certified Public Accountants Technical Practice Aid, Valuation of Privately-Held Company Equity Securities Issued as Compensation, which we refer to as the practice aid. We believe that the valuation methodologies used in the retrospective analysis are reasonable and consistent with the practice aid.
In applying the current value method, we considered the rights of our Series A convertible preferred stock, which we refer to as our Series A preferred stock, and which will be converted into shares of Class B common stock upon the closing of this offering. The calculated enterprise value as of each of the valuation dates was significantly higher than the cumulative liquidation preference of our Series A preferred stock of $3.2 million. We also determined that in each valuation date, the Series A preferred stock would receive a substantially higher per share value on an “as if” converted to common stock basis than by retaining its liquidation preference. Thus for the purposes of these valuations the total equity value was divided by the fully diluted shares outstanding in order to calculate the per share value of our common stock.
In connection with this retrospective analysis, in determining our enterprise value, our analysis also considered the calculated multiple of market valuations of the comparable companies to their next 12 months adjusted EBITDA, and applied this multiple to our own next 12 months projected adjusted EBITDA, in addition to considering the enterprise value to trailing 12 months adjusted EBITDA, with more weight placed on our projected EBITDA analysis than the historical adjusted EBITDA analysis. To determine equity value, we added cash on hand at the end of the period and the cash from the assumed pro forma exercise of in-the-money stock options, and then subtracted senior corporate debt. To allocate the equity, we considered the option pricing method from the practice aid. In connection with applying the option pricing method to value our common stock for these valuation dates, we determined that allocating the equity based on applying the option pricing method instead of the current value method in the contemporaneous valuations resulted in immaterial differences from the per share value calculated using the current value method.
Following this retrospective analysis, our board of directors determined that the fair value of our common stock remained as previously determined in 2007, 2008 and on January 28, 2009, and that the fair value was $9.00 per share on July 22, 2009 and $11.00 per share on September 25, 2009, as described below.
January 28, 2009 Fair Value Calculation. The fair value of our common stock as of January 28, 2009 was retrospectively determined to be $6.055 per share. In applying the market approach, our next 12 months projected adjusted EBITDA was primarily affected by the following factors:
continued challenges during 2008 in the U.S. economy and decreased valuations of comparable companies; and
concerns about liquidity during the upcoming fiscal quarters.
July 22, 2009 Fair Value Calculation. The fair value of our common stock as of July 22, 2009 was retrospectively determined to be $9.00 per share. The primary reason for the significant increase in the valuation of our common stock between January 28, 2009 and July 22, 2009 was the 11% increase in our next 12 months projected adjusted EBITDA between those two dates. Our projected adjusted EBITDA in July 2009 had increased significantly for the following reasons:
we were notified in March 2009 that the U.S. Department of Energy had lifted restrictions on its ability to enter into ESPCs, which permitted us to proceed with the execution of larger federal contracts;
in May 2009, we executed a contract for our large U.S. Department of Energy Savannah River Site renewable energy project; however, we had not yet secured the financing necessary to complete this project; and
improvement in general economic and market conditions in the first half of 2009.
The valuation of our common stock in July 2009 was also significantly affected by an increase, between January 2009 and July 2009, in the multiple of market valuations of comparable companies that we applied to our next 12 months projected adjusted EBITDA. The multiple we applied in this analysis in January 2009, derived from publicly available data on the comparable companies we used in the market approach, was eight. We increased the multiple we applied to ten in July 2009, due primarily to the improvement in the public equity markets during this period. In addition, this determination took into

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account our expectation that we would undertake an initial public offering within one year.
September 25, 2009 Fair Value Calculation. The fair value of our common stock as of September 25, 2009 was retrospectively determined to be $11.00 per share. The primary reason for the increase in the valuation of our common stock between July 22, 2009 and September 25, 2009 was the 17% increase in our next 12 months projected adjusted EBITDA between those two dates. Our next 12 months projected adjusted EBITDA in September 2009 had increased from our next 12 months projected adjusted EBITDA in July 2009, for the following reasons:
our backlog under signed customer contracts increased from July 2009 to September 2009;
in August 2009, we secured the financing necessary to complete our large U.S. Department of Energy Savannah River Site renewable energy project, the contract for which had been executed in May 2009 but was subject to our securing that financing. Securing this financing represented a significant milestone for us, particularly in light of its size and the significant disruptions in the credit and capital markets in the preceding several years; and
improvement in general economic and market conditions in the third quarter of 2009.
The valuation of our common stock in September 2009 was also affected by an increase, between July 2009 and September 2009, in the multiple of market valuations of comparable companies that we applied to our next 12 months projected adjusted EBITDA. The multiple we applied in this analysis in July 2009, derived from publicly available data on the comparable companies we used in the market approach, was 10. We increased the multiple we applied to 11 in September 2009, due primarily to the improvement in the public equity markets during this period.
Our determination of fair market value in September 2009 also took into account our expectation that we would undertake an initial public offering within nine months.
We have incorporated the fair values calculated in the retrospective valuations into the Black-Scholes option pricing model when calculating the stock-based compensation expense to be recognized for the stock options granted during the period from July through September 2009. The retrospective valuations generated per share fair values of common stock of $9.00 and $11.00, respectively, at July 22, 2009 and September 25, 2009. This resulted in intrinsic values of $2.945 and $4.945 per share, respectively, at each grant date.
April 26, 2010 Fair Value Calculation.  The fair value of our common stock as of April 26, 2010 and May 28, 2010 was determined contemporaneously to be $13.045 per share. In determining this value, we employed the same methods and approaches used in the retrospective analysis described above. The primary reasons for the increase in the valuation of our common stock from September 25, 2009 to April 26, 2010 and May 28, 2010 were:
a 30% increase in our next 12 months projected adjusted EBITDA between September 25, 2009 and the two relevant dates in 2010, due to growth in our backlog and several, previously-contracted, large efficiency and renewable energy projects entering major construction phases;
our expectation that we would conduct an initial public offering within the next three months; and
our preliminary estimates of our valuation for purposes of this offering.
Valuation models require the input of highly subjective assumptions. There are significant judgments and estimates inherent in the determination of these valuations. These judgments and estimates include assumptions regarding our future performance, the time to undertaking and completing an initial public offering or other liquidity event, as well as determinations of the appropriate valuation methods. If we had made different assumptions, our stock-based compensation expense, net income and net income per share could have been significantly different. Additionally, because our capital stock prior to this offering had characteristics significantly different from that which will apply upon the closing of this offering, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management’s opinion, the existing models do not necessarily provide a reliable, single measure of fair value. The foregoing valuation methodologies are not the only valuation methodologies available and will not be used to value our Class A or Class B common stock once this offering is complete. We cannot make assurances regarding any particular valuation of our shares.

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Results of Operations
The following table sets forth certain financial data from the consolidated statements of income and comprehensive Income expressed as a percentage of revenue for the periods indicated:
 
Years Ended December 31,
 
2009
 
2010
 
2011
Revenue:
 
 
 
 
 
Energy efficiency revenue
79.5
 %
 
73.7
 %
 
75.7
 %
Renewable energy revenue
20.5
 %
 
26.3
 %
 
24.3
 %
 
100.0
 %
 
100.0
 %
 
100.0
 %
Direct expenses:
 
 
 
 
 
Energy efficiency expenses
65.9
 %
 
61.2
 %
 
61.4
 %
Renewable energy expenses
15.5
 %
 
20.9
 %
 
20.1
 %
 
81.4
 %
 
82.1
 %
 
81.5
 %
Gross profit
18.6
 %
 
17.9
 %
 
18.5
 %
Total operating expenses
12.7
 %
 
10.5
 %
 
11.6
 %
Operating income
5.9
 %
 
7.4
 %
 
6.9
 %
Other income (expenses), net
0.4
 %
 
(0.8
)%
 
(0.7
)%
Income before provision for income taxes
6.3
 %
 
6.6
 %
 
6.2
 %
Income tax provision
(1.6
)%
 
(2.0
)%
 
(1.5
)%
Net income
4.7
 %
 
4.6
 %
 
4.7
 %
Revenue
The following table sets forth a comparison of our revenue by mix for the periods indicated:
 
Years Ended December 31,
 
2009
 
2010
 
% change
 
2011
 
% change
(in $'000s)
(a)
 
(b)
 
((b-a)/a)
 
(c)
 
((c-b)/b)
Revenue:
 
 
 
 
 
 
 
 
 
Energy efficiency revenue
$
340,635

 
$
455,329

 
33.7
%
 
$
551,324

 
21.1
%
Renewable energy revenue
87,882

 
162,897

 
85.4
%
 
176,876

 
8.6
%
 
$
428,517

 
$
618,226

 
44.3
%
 
$
728,200

 
17.8
%

Total revenue.  We derive our revenue primarily from energy efficiency products and services, which accounted for approximately 79.5%, 73.7% and 75.7% of total revenue in 2009, 2010 and 2011, respectively. Total revenue increased by $110.0 million, or 17.8%, from 2010 to 2011 primarily due to higher energy efficiency revenue. Total revenue increased by $189.7 million, or 44.3%, from 2009 to 2010 primarily due to an increase in energy efficiency projects and, to a lesser extent, an increase in renewable energy projects.
Energy efficiency revenue. Energy efficiency revenue increased by $96.0 million, or 21.1%, from 2010 to 2011 due to increased energy efficiency installation activity across the other U.S. regions segment, such as northeast U.S., southeast U.S., southwest U.S., and northwest U.S., as well as Canada, which reflects both ongoing and new projects. Energy efficiency revenue for 2011 includes approximately $24.8 million attributable to our acquisitions of AEG and Ameresco Southwest in the third quarter of 2011. Energy efficiency revenue increased by $114.7 million, or 33.7%, from 2009 to 2010, due to an increase in the number of new projects being installed for our municipal and other institutional customers in all regions.
Renewable energy revenue. Renewable energy revenue increased by $14.0 million, or 8.6%, from 2010 to 2011 primarily due to increases from integrated-PV, developing renewable energy plants for our customers and small scale infrastructure, as well as approximately $11.9 million from renewable energy installation activity attributable to our acquisition of Ameresco Southwest in the third quarter of 2011, partially offset by a $16.9 million decline in revenue from renewable energy installation

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within the U.S. federal segment beginning in the second quarter of 2011 as projects neared completion. Renewable energy revenue increased by $75.0 million, or 85.4%, from 2009 to 2010, due mainly to an increase in the number of LFG and biomass facilities being built by us for our customers. Construction volume of such plants increased by $56.9 million from 2009 to 2010. Additionally, in 2010, we placed in service three new plants owned by us that sell and deliver LFG, or electricity generated by LFG, to customers. In 2010, we also saw an increase in revenue from sales of PV systems and components, primarily due to an increase in our market presence.
Revenue from customers outside the United States, principally Canada, was $112.6 million in 2011, compared with $103.9 million in 2010 and $86.9 million in 2009.
Business Segment Revenue
The following table sets forth a comparison of our business segment revenue for the periods indicated:
 
Years Ended December 31,
 
2009
 
2010
 
% change
 
2011
 
% change
(in $'000s)
(a)
 
(b)
 
((b-a)/a)
 
(c)
 
((c-b)/b)
U.S. Federal
$
87,580

 
$
177,522

 
102.7
%
 
$
145,199

 
(18.2
)%
Central U.S. Region
88,068

 
100,327

 
13.9
%
 
86,376

 
(13.9
)%
Other U.S. Regions
77,828

 
142,457

 
83.0
%
 
268,211

 
88.3
 %
Canada
83,633

 
101,408

 
21.3
%
 
106,531

 
5.1
 %
All Other
91,408

 
96,512

 
5.6
%
 
121,883

 
26.3
 %
Total
$
428,517

 
$
618,226

 
44.3
%
 
$
728,200

 
17.8
 %
Total revenue for the U.S. federal segment decreased from 2010 to 2011 by $32.3 million, or 18.2%, to $145.2 million primarily due to decreases in revenues from installation activity on ongoing projects, as a number of projects began nearing completion, combined with a decline in the velocity of converting awarded projects to signed contracts beginning in late 2010 through the first half of 2011. Total revenue for the U.S. federal segment increased from 2009 to 2010 by $89.9 million, or 102.7%, to $177.5 million, primarily due to an increase in the number of projects being installed primarily for the U.S. federal government. During 2010, revenue recognized on the continued installation of a large renewable energy project for the U.S. Department of Energy, Savannah River Site, accounted for a significant portion of our revenue for this segment.
Total revenue for the central U.S. region segment decreased from 2010 to 2011 by $14.0 million, or 13.9%, to $86.4 million primarily due to a lengthening of the sales cycle, which has resulted in fewer signed contracts to replace installation activity as projects are completed. Total revenue for the central U.S. region segment increased from 2009 to 2010 by $12.3 million, or 13.9%, to $100.3 million, primarily due to an increase in the number of energy efficiency projects in construction.
Total revenue for the other U.S. regions segment increased from 2010 to 2011 by $125.8 million, or 88.3%, to $268.2 million primarily due to an increase in the size and number of projects under construction in the northeast, southeast and northwest; total revenue for this segment in 2011 includes $27.8 million attributable to our acquisition of Ameresco Southwest in the third quarter of 2011. Total revenue for the other U.S. regions segment increased from 2009 to 2010 by $64.6 million, or 83.0%, to $142.5 million, primarily due to an increase in the size, and to some degree due to the number, of projects under construction.
Total revenue for the Canada segment increased from 2010 to 2011 by $5.1 million, or 5.1%, to $106.5 million primarily due to a larger volume of construction activity related to the installation of energy efficiency measures. Total revenue for the Canada segment increased from 2009 to 2010 by $17.8 million, or 21.3%, to $101.4 million, primarily due to a larger volume of construction activity related to the installation of energy efficiency measures, particularly two large projects for housing authorities, and, to a lesser extent, revenues generated from an acquisition in 2009.
Total revenue not allocated to segments and presented as all other, increased from 2010 to 2011 by $25.4 million, or 26.3%, to $121.9 million due primarily to our recent acquisition of AEG, as well as to increases in revenue from small scale infrastructure, developing renewable energy plants for our customers and integrated-PV. Total revenue not allocated to segments and presented as all other, increased from 2009 to 2010 by $5.1 million, or 5.6%, to $96.5

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million, due to increases in O&M revenues and sales of integrated-PV.
Direct Expenses and Gross Profit
The following table sets forth a comparison of our direct expenses and gross profit for the periods indicated:
 
Years ended December 31,
(in $'000s)
2009
 
2010
 
2011
Revenue:
 
 
 
 
 
Energy efficiency revenue
$
340,635

 
$
455,329

 
$
551,324

Renewable energy revenue
87,882

 
162,897

 
176,876

 
428,517

 
618,226

 
728,200

Direct expenses:
 
 
 
 
 
Energy efficiency expenses
282,345

 
378,084

 
446,963

Renewable energy expenses
66,472

 
129,440

 
146,191

 
348,817

 
507,524

 
593,154

Gross profit:
$
79,700

 
$
110,702

 
$
135,046

Energy efficiency gross margin
17.1
%
 
17.0
%
 
18.9
%
Renewable energy gross margin
24.4
%
 
20.5
%
 
17.3
%
Gross profit %
18.6
%
 
17.9
%
 
18.5
%
Total direct expenses. The majority of our expenses are incurred in connection with energy efficiency projects for which expenses represented approximately 82.9%, 83.0% and 81.1% of energy efficiency revenue in 2009, 2010 and 2011, respectively. Total direct expenses increased by $85.6 million, or 16.9%, from 2010 to 2011 due primarily to increases associated with increased installation activity and, to a lesser extent, an increase in amortization of intangible assets resulting from our two acquisitions during the third quarter of 2011, partially offset by higher energy efficiency gross profit margin as discussed below. Total direct expenses increased by $158.7 million, or 45.5%, from 2009 to 2010, due to increased installation activity combined with lower profit margins recognized in 2010, causing total direct expenses to increase at a greater rate than revenue.
Energy efficiency gross margin. Energy efficiency gross margin increased from 17.0% in 2010 to 18.9% in 2011 primarily due to higher gross margins related to several project closeouts and positive margin contribution form AEG and Ameresco Southwest. Energy efficiency gross margin decreased slightly from 17.1% in 2009 to 17.0% in 2010, as large projects continued through the year end, deferring recognition of project costs contingencies
Renewable energy gross margin. Renewable energy gross margin decreased from 20.5% in 2010 to 17.3% in 2011 primarily due to maintenance expenses at several of our renewable energy plants, approximately $1.8 million in start-up costs for Savannah River O&M incurred during the fourth quarter of 2011 for which we will not recognize corresponding revenue until the first quarter of 2012; and integrated-PV inventory adjustments of $0.8 million. Renewable energy gross margin decreased from 24.4% in 2009 to 20.5% in 2010 due primarily to a shift in revenue mix toward implementation projects, which generally have lower gross margins than small scale infrastructure and integrated-PV sales.

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Operating Expenses
The following table sets forth a comparison of our operating expenses and operating expenses as a percentage of revenue for the periods indicated:
 
Years Ended December 31,
 
2009
 
% of
 
2010
 
% of
 
2011
 
% of
(in $'000s)
 
 
Revenue
 
 
 
Revenue
 
 
 
Revenue
Revenue
$
428,517

 
 
 
$
618.226

 
 
 
$
728,200

 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Salaries and benefits
$
28,274

 
6.6
%
 
$
30,721

 
5.0
%
 
40,746

 
5.6
%
Project development costs
9,600

 
2.2
%
 
13,677

 
2.2
%
 
18,282

 
2.5
%
General, administrative and other
16,532

 
3.9
%
 
20,312

 
3.3
%
 
25,332

 
3.5
%
 
$
54,406

 
12.7
%
 
$
64,710

 
10.5
%
 
$
84,360

 
11.6
%
Salaries and benefits. Salaries and benefits increased by $10.0 million, or 32.6%, from 2010 to 2011 primarily due to increased headcount both as a result of the three acquisitions in 2011 and to support expanded sales and development activity, including continued expansion in the northwest and southeast regions of the U.S. Salaries and benefits increased $2.4 million, or 8.7%, from 2009 to 2010. This was primarily due to the increased headcount necessary to manage our expectation of a continued increase in our business activity in 2010 and beyond.
Project development costs. Project development costs increased by $4.6 million, or 33.7%, from 2010 to 2011 reflecting continued efforts relating to increased proposal activities and efforts to convert awarded projects to fully-contracted backlog. We experienced a lengthening of the conversion time from awarded projects to fully-contracted backlog in the second and third quarters and as a result have been incurring additional expenses in support of conversion, representing, we believe, an investment in future growth. We expect this trend to carry into 2012 as we continue to focus on converting awarded projects to fully-contracted backlog. Project development expenses increased $4.1 million, or 42.5%, from 2009 to 2010, reflecting a significant increase in the volume of our business development activity during 2010
General, administrative and other. General, administrative and other expenses increased by $5.0 million, or 24.7%, from 2010 to 2011. During the second quarter of 2010 we recorded an unexpected prepayment of a long-term receivable from one of our customers, resulting in a $2.1 million non-cash charge. The net increase of $7.1 million for 2011 is due primarily to our growth and the costs necessary to support our continued growth, including a significant increase in general, administrative and other expenses attributable to being a public company, such as auditing, compliance and insurance costs, as well as acquisition integration expenses. General, administrative and other expenses in 2011 include approximately $1.0 million in acquisition-related expenses. General, administrative and other expenses increased $3.8 million, or 22.9%, from 2009 to 2010. This increase was primarily a result of the $2.1 million non-cash charge described above. Additionally, the increase was due to the higher costs incurred to support our expanding headcount and business growth.
Other Income (Expenses), Net
The following table shows the activity in other income (expenses), net for the periods indicated:
 
Years Ended December 31,
(in $'000s)
2009
 
2010
 
2011
Gain realized from derivative
$
2,494

 
$

 
$

Unrealized gain (loss) from derivatives
2,264

 
(134
)
 

Interest expense, net of interest income
(2,993
)
 
(4,380
)
 
(4,130
)
Amortization of deferred financing costs
(202
)
 
(567
)
 
(1,062
)
 
$
1,563

 
$
(5,081
)
 
$
(5,192
)
Other income (expenses), net decreased from 2010 to 2011 by $0.1 million. In 2010 we recorded a termination charge and a write-off of deferred financing fees totaling $0.7 million in connection with terminating and paying off a term loan of one of our project subsidiaries. The effect of these payments on the period-over-period change was partially offset by higher average balances on our outstanding borrowings, resulting in higher interest expense. Other income (expense), net decreased from 2009

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to 2010 by $6.6 million, from a net income of $1.6 million to a net expense of $5.1 million, due primarily to realized and unrealized gains from derivatives in 2009 of $4.7 million, $0.7 million due to an early termination at a subsidiary level project financing, increased interest expenses of $0.7 million incurred in 2010 on renewable energy financing agreements and $0.2 million in deferred financing fees relating to the aforementioned early termination of debt.
Income Before Taxes
The following table sets forth a comparison of our income before taxes for the periods indicated:
 

 
2009
 
2010
 
% change
 
2011
 
% change
(in $'000s)
(a)
 
(b)
 
((b-a)/a
 
(c)
 
((b-a)/a)
U.S. Federal
$
11,276

 
$
21,444

 
90.2
 %
 
$
19,252

 
(10.2
)%
Central U.S. Region
10,121

 
10,379

 
2.5
 %
 
5,643

 
(45.6
)%
Other U.S. Regions
5,077

 
25,583

 
403.9
 %
 
47,074

 
84.0
 %
Canada
4,155

 
4,352

 
4.7
 %
 
1,976

 
(54.6
)%
All Other
(3,772
)
 
(20,846
)
 
(452.7
)%
 
(28,451
)
 
(36.5
)%
Total
$
26,857

 
$
40,912

 
52.3
 %
 
$
45,494

 
11.2
 %
Income before taxes increased from 2010 to 2011 by $4.6 million, or 11.2%, primarily due to higher gross profit, which was partially offset by an increase in operating expenses, both as described above. Income before taxes increased from 2009 to 2010 by $14.1 million, or 52.3%, due to higher revenues and improved operating leverage.
Business Segment Income Before Taxes
Income before taxes for the U.S. federal segment decreased from 2010 to 2011 by $2.2 million, or 10.2%, to $19.3 million. The decrease was primarily due to the decline in revenue described above.  Income before taxes for the U.S. federal segment increased from 2009 to 2010 by $10.2 million, or 90.2%, to $21.4 million. The increase was primarily due to increased revenue and higher margins recognized on project installations.
Income before taxes for the central U.S. region segment decreased from 2010 to 2011 by $4.7 million, or 45.6%, to $5.6 million due primarily to decreased revenue as described above and a greater portion of lower margin projects within the segments revenue mix. Income before taxes for the central U.S. region segment increased from 2009 to 2010 by $0.3 million, or 2.5%, to $10.4 million. The increase was primarily due to higher revenue.
Income before taxes for the other U.S. regions segment increased from 2010 to 2011 by 84.0%, or $21.5 million, to $47.1 million due primarily to increased revenue as described above, but also reflecting improved operating leverage. Income before taxes for the other U.S. regions segment increased from 2009 to 2010 by $20.5 million, or 403.9%, to $25.6 million, primarily due to increased revenue and higher margins.
Income before taxes for the Canada segment decreased from 2010 to 2011 by $2.4 million, or 54.6%, to $2.0 million due to a greater portion of lower gross margin projects in its revenue mix and to higher operating expenses. Income before taxes for the Canada segment increased from 2009 to 2010 by $0.2 million, or 4.7%, to $4.4 million. The increase was primarily due to higher revenue.
The loss before taxes not allocated to segments and presented as all other, increased from 2010 to 2011 by $7.6 million, or 36.5%, to $28.5 million primarily due to increases in corporate overhead partially offset by higher revenue. The changes in the expense allocation to all other increased from 2009 to 2010 by $17.1 million, or 452.7%, to $20.8 million were consistent with the overall change in consolidated expenses discussed 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 39.7%. During 2011, we recognized income taxes of $10.8 million, or 23.7% of pretax income. The tax rate for 2011 included a net tax benefit of $0.9 million relating to accrued interest on a tax position that was resolved during the third quarter of 2011. In addition to this net tax benefit, a one-time item, the principal difference between the statutory rate and the effective rate was due to deductions permitted under Section 179D of the

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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 $6.2 million reduction in the 2011 provision, or a reduction of 13.7 percentage points in the effective rate. We expect the effective tax rate for 2012 to be higher than for 2011.
During 2010, we recognized income taxes of $12.2 million, or 29.8% 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 $4.2 million reduction in the 2010 provision, or a reduction of 10.4 percentage points in the effective rate.
In 2009, we recognized income taxes of $6.9 million, or 25.8% 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 $3.0 million reduction in the 2009 provision, or a reduction of 11.1 percentage points in the effective rate.
Net Income
Net income increased in 2011 by $6.0 million, or 20.9%, due to higher pre-tax income and a lower effective tax rate. Earnings per share in 2011 was $0.82 per basic share, representing a decrease of $0.30, or 26.8%, and $0.78 per diluted share, representing an increase of $0.09, or 13.0%. 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.
Net income increased in 2010 by $8.8 million, or 44.3%, due to higher pre-tax income, partially offset by an increase in the tax provision. Earnings per share in 2010 was $1.12 per basic share, representing a decrease of $(0.87), or 43.7%, and $0.69 per diluted share, representing an increase of $0.08, or 13.1%. The weighted-average number of basic and diluted shares increased by 157.5% and 26.9%, respectively, primarily as a result of the issuance of shares in our initial public offering.
Net income increased in 2009 by $1.6 million, or 8.9%, due to higher pre-tax income, partially offset by an increase in the provision for income taxes. Earnings per share in 2009 were $1.99 per basic share, and $0.61 per diluted share, representing an increase from 2008 of $0.28, or 16.4%, and $0.07, or 13.1%, respectively. The weighted-average number of basic and diluted shares decreased from 2008 by 6.4% and 3.8%, respectively, as a result of share repurchases.
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 for the years ended December 31, 2009, 2010 and 2011:
 
Fiscal Years Ended December 31,
(in $'000s)
2009
 
2010
 
2011
Cash and cash equivalents
$
47,928

 
$
44,691

 
$
26,277

Book overdraft

 

 
(7,297
)
Net cash available
$
47,928

 
$
44,691

 
$
18,980

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.

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There were no book overdrafts as of December 31, 2009 or 2010.
We presented the book overdraft as a financing activity in the consolidated statements of cash flows.
The changes in cash and cash equivalents for the years ended December 31, 2009, 2010 and 2011 were as follows:
 
Fiscal Years Ended December 31,
(in $'000s)
2009
 
2010
 
2011
Net cash provided by operating activities
$
45,296

 
$
20,850

 
$
30,146

Net cash used in investing activities
(22,314
)
 
(45,930
)
 
(105,601
)
Net cash provided by financing activities
4,129

 
20,505

 
58,076

Effect of exchange rate changes on cash
2,667

 
1,338

 
(1,035
)
Net increase (decrease) in cash and cash equivalents
$
29,778

 
$
(3,237
)
 
$
(18,414
)
We believe that cash and cash equivalents, net of the book overdraft, 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 2013 and thereafter.
Capital expenditures. Our total capital expenditures were $21.6 million in 2009, $39.6 million in 2010 and $45.2 million in 2011. The 2009, 2010 and 2011 capital expenditures were net of Section 1603 rebates received of $12.9 million, $0.8 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 forego such tax credits in exchange for the payment made under Section 1603. Additionally, in 2009, 2010 and 2011 we invested $0.7 million, $6.3 million and $66.2 million in acquisitions, respectively. We currently plan to make capital expenditures of approximately $30.0 million in 2012, principally for new renewable energy plants.
Cash flows from operating activities. Operating activities provided $30.1 million of net cash during the 2011. In 2011, we had net income of $34.7 million, which is net of non-cash compensation, depreciation, amortization, gains on sales of assets, deferred income taxes and other non-cash items totaling $34.6 million. Net increases in restricted cash draws (net of Federal ESPC financing), project development costs and other assets provided $41.1 million. However, net decreases in accounts receivable including retainage, inventory, net costs and estimated earnings in excess of billings, prepaid expenses and other current assets, accounts payable and accrued expenses, other liabilities and income taxes payable used $80.2 million in cash.
Operating activities provided $20.8 million of net cash during 2010. In 2010, we had net income of $28.7 million, which is adjusted for certain non-cash items such as stock-based compensation, depreciation, amortization, unrealized losses and deferred income taxes totaling $14.5 million, and which is net of $2.1 million relating to a write down on a long-term receivable. Offsetting these adjustments was another non-cash item, excess tax benefits from stock-based compensation arrangements of $2.0 million. Net increases in accounts payable and other liabilities contributed $10.9 million in cash. However, net increases in accounts receivable and other assets used $33.3 million of cash. Included in the $33.3 million of cash used is net activity from our investments in U.S. federal projects. In 2010, investments in U.S. federal projects used $160.5 million. We also drew a total of $151.0 million in cash from restricted cash accounts maintained in connection with our U.S. federal ESPC and our renewable energy projects, which increased cash from operating activities. We reflect restricted cash as an operating asset on our consolidated balance sheet and withdrawals from existing restricted cash accounts as cash flow from operations on our consolidated statements of cash flows. The creation of new restricted cash accounts is reflected as a decrease to cash flows from financing activities on our consolidated statements of cash flows. Certain of the cash generated from our U.S. federal ESPC receivable financing is held in restricted cash accounts to be used to pay for the cost of construction under our U.S. federal ESPCs. We withdrew $144.7 million in cash from these accounts during 2010. In addition, under the terms of our term loan agreements used to finance certain of our renewable energy projects, we are required to maintain restricted cash accounts to provide for operation and maintenance expenses incurred. We withdrew $6.4 million in cash from these accounts during 2010.
Operating activities provided $45.3 million of net cash during 2009. In 2009, we had net income of $19.9 million, which is net of non-cash compensation, depreciation and amortization totaling $10.1 million, partially offset by a $2.3 million unrealized gain on derivatives. Increases in accounts payable and other liabilities contributed $36.7 million to cash from operating activities, and investment in U.S. federal projects used $52.9 million in cash. We also drew a total of $33.0 million in cash from restricted cash accounts maintained in connection with our U.S. federal ESPC and our renewable energy projects. Certain of the

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cash generated from our U.S. federal ESPC receivable financing is held in restricted cash accounts to be used to pay for the cost of construction under our U.S. federal ESPCs. We withdrew $31.5 million in cash from these accounts during 2009. In addition, under the terms of our term loan agreements used to finance certain of our renewable energy projects, we are required to maintain restricted cash accounts to provide for operation and maintenance expenses incurred. We withdrew $1.5 million in cash from these accounts during 2009. Other changes in net assets and liabilities provided the balance of net cash during the year.
Cash flows from investing activities. 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 used in investing activities totaled $45.9 million during 2010 and consisted of capital expenditures of $39.6 million, primarily related to the development of renewable energy plants. This amount was net of $0.8 million of Section 1603 rebates received during the year. Also, $6.3 million of cash was used for the Quantum acquisition.
Cash used in investing activities totaled $22.3 million during 2009 and consisted of capital expenditures of $21.6 million, primarily related to the development of renewable energy plants. This amount was net of $12.9 million of Section 1603 rebates received during the year. Also, $0.7 million of cash was used for an acquisition.
Cash flows from financing activities. Net cash provided by financing activities totaled $58.1 million during 2011. Most of this was due to the draw down of $42.1 million from the revolving portion of the renewed senior secured credit facility (see Note 8 and the discussion below), 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 also provided $6.4 million. These were partially offset by reductions in restricted cash of $7.8 million.
 Cash flows provided by financing activities totaled $20.5 million during 2010 and included proceeds of $60.1 million primarily from the issuance of stock, but also from the exercise of stock options and warrants, and the $2.0 million recognition of excess tax benefits from stock-based compensation arrangements. These proceeds and benefits were offset by repayments of $19.9 million on our revolving senior secured credit facility, repayment of $3.0 million on our subordinated debt, repayments of $11.0 million on other long-term debt, payments of $1.4 million relating to financing fees and payments of $6.3 million into restricted cash accounts, which we are required to maintain under the stipulations of certain term loan agreements related to our renewable energy projects. These accounts provide for operation and maintenance expenses incurred in connection with such projects.
Cash flows provided by financing activities totaled $4.1 million during 2009 and included proceeds, net of financing costs, of $25.4 million from a construction and term loan facility provided by a bank. These proceeds were offset by repayments of $14.6 million on our revolving senior secured credit facility, repayments of $3.6 million on other long-term debt and payments of $3.1 million into restricted cash accounts which we are required to maintain under the terms of our term loan agreements used to finance certain of our renewable energy projects to provide for operation and maintenance expenses incurred in connection with such projects.
Subordinated Note
In connection with the organization of Ameresco, on May 17, 2000, we issued a subordinated note to our principal stockholder in the amount of $3.0 million. The subordinated note bore interest at the rate of 10.00% per annum, payable monthly in arrears, and was subordinate to our revolving senior secured credit facility. The subordinated note was payable upon demand. We incurred $0.3 million of interest related to the subordinated note during 2009, and $0.2 million in 2010 when the note was settled in full in connection with our initial public offering.
Senior Secured Credit Facility — Revolver and Term Loan
In 2008, we entered into a credit and security agreement with Bank of America, consisting of a $50.0 million revolving facility. The agreement required us to pay monthly interest at various rates in arrears, based on the amount outstanding. This facility had a maturity date of June 30, 2011. The facility was secured by a lien on all of our assets other than renewable energy projects that we own that were financed by others, and limited our ability to enter into other financing arrangements. Availability under the facility was based on two times our EBITDA for the preceding four quarters, and we were required to maintain a minimum EBITDA of $20.0 million on a rolling four-quarter basis and a minimum level of tangible net worth.

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On June 30, 2011, we again amended and restated the credit and security agreement with Bank of America, adding Webster Bank as an additional lender. The new credit facility extended and expanded our prior existing credit facility, and consists of a $60.0 million revolving credit facility and a $40.0 million term loan. At December 31, 2011, $5.0 million was outstanding under the revolving credit facility and $37.1 million was outstanding under the term loan. The revolving credit facility may be increased by up to an additional $25.0 million at our option, if the lenders agree. The term loan requires quarterly principal payments of $1.4 million, with the balance due at maturity. Ameresco, Inc. remains the sole borrower under the credit facility. The new credit facility is secured by a lien on all of our assets other than renewable energy projects that we own that were financed by others, 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 of $40.0 million on a rolling four-quarter basis. The new credit facility matures on June 30, 2016, when all amounts will be due and payable in full.
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, 2011, we had outstanding $56.2 million in aggregate principal amount under these loans, bearing interest at rates ranging from 6.1% to 8.9% and maturing at various dates from 2013 to 2024. One loan totaling $5.2 million, does require Ameresco, Inc. to provide assurance to the lender of the project performance. As of December 31, 2010, we had outstanding $46.8 million in aggregate principal amount under these loans, bearing interest at rates ranging from 5.3% to 8.7% and maturing at various dates from 2013 to 2024. As of December 31, 2009, we had outstanding $58.4 million in aggregate principal amount under these loans, bearing interest at rates ranging from 6.9% to 8.7% and maturing at various dates from 2014 to 2021. As of December 31, 2009, a term loan in the amount of $5.4 million was in default as a result of the bankruptcy of the customer for the energy output of the plant financed by the loan. The bankruptcy filing by the customer had constituted an event of default under the credit agreement; however, the customer emerged from bankruptcy in 2010 and continued operations. To cure the default we decided to pay the loan in full during the third quarter of 2010.
Federal ESPC Receivable Financing. 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 $109.6 million and $159.0 million in principal amounts at December 31, 2011 and 2010, 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.
Our revolving senior secured credit facility and construction and term loan agreements require us to comply with a variety of financial and operational covenants. As of December 31, 2011 we were in compliance with all of our 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.

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Contractual Obligations
The following table summarizes our significant contractual obligations and commitments as of December 31, 2011:
 
 
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(1)
 
$
5,000

 
$

 
$

 
$
5,000

 
$

Term Loan
 
37,143

 
5,714

 
17,143

 
14,286

 

Project Financing:
 
 
 
 
 
 
 
 
 
 
Construction and term loans
 
56,175

 
5,850

 
9,843

 
8,698

 
31,784

Federal ESPC receivable financing(2)
 
109,648

 

 
109,648

 

 

Interest obligations(3)
 
28,673

 
4,955

 
8,383

 
6,186

 
9,149

Operating leases
 
9,220

 
3,235

 
3,597

 
2,124

 
264

Total
 
$
245,859

 
$
19,754

 
$
148,614

 
$
36,294

 
$
41,197

(1
)
 
For our revolving senior secured credit facility, the table above assumes that the variable interest rate in effect as of December 31, 2011 remains constant for the term of the facility.
 
 
 
(2
)
 
Federal ESPC receivable financing arrangements relate to the installation and construction of projects for certain customers, typically federal governmental entities, where we assign to the lenders our right to customer receivables. We are relieved of the financing liability when the project is completed and accepted by the customer. We typically expect to be relieved of the financing liability between one and three years from the date of project construction commencement. The table does not include, for our federal ESPC receivable financing 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.
 
 
 
(3
)
 
For the term loan portion of our senior secured credit facility, the table above assumes that the variable interest rate in effect at December 31, 2011 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.
Recent Accounting Pronouncements
In May 2011, the Financial Accounting Standards Board issued Accounting Standards Update No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs”, (ASU 2011-04). This update changes certain fair value measurement principles and enhances the disclosure requirements particularly for Level 3 fair value measurements. This update is effective for reporting periods beginning on or after December 15, 2011, with early adoption prohibited, and requires prospective application. We are evaluating the effect, if any, that the adoption of ASU 2011-04 will have on our consolidated financial statements.
In June 2011, the FASB issued an amendment to the accounting guidance for presentation of comprehensive income. Under the amended guidance, a company may present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In either case, a company is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. The amendment originally required the company to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement(s) where the components of net income and the components of other comprehensive income are presented; however, this provision was deferred under amended accounting guidance issued by the FASB in December 2011. For public companies,

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the amendment to the accounting guidance for presentation of comprehensive income is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, and shall be applied retrospectively. The Company adopted this amendment on January 1, 2012. Other than a change in presentation, the adoption of this guidance is not expected to have a material impact on the Company's consolidated financial statements.
In September 2011, the FASB issued ASU No. 2011-08, Intangibles - Goodwill and Other (Topic 350) - Testing Goodwill for Impairment, which allows an entity to use a qualitative approach to test goodwill for impairment. ASU 2011-08 permits an entity to first perform a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value. If it is concluded that this is the case, it is necessary to perform the currently prescribed two-step goodwill impairment test. Otherwise, the two-step goodwill impairment test is not required. ASU 2011-08 is effective for our fiscal year beginning January 1, 2012 and earlier adoption is permitted. We are currently evaluating the impact of the adoption of ASU 2011-08 on our consolidated financial statements.
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 $26.3 million as of December 31, 2011 and $44.7 million as of December 31, 2010. 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.
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
As a result of our operations in Canada, we have significant expenses, assets and liabilities that are denominated in a foreign currency. Also, a significant number of employees are located in Canada and we transact a significant amount of business in Canadian currency. Consequently, we have determined that Canadian currency is the functional currency for our Canadian operations. When we consolidate the operations of our Canadian subsidiary 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 Canadian subsidiary from Canadian currency into U.S. dollars. We translate the revenues, expenses, gains, and losses from our Canadian subsidiary into U.S. dollars using a weighted average exchange rate for the applicable fiscal period. We translate the assets and liabilities of our Canadian subsidiary 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 Canadian 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

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income (loss). For the year ended December 31, 2010, 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 $1.7 million which we recorded as an increase in accumulated other comprehensive income. For the years ended December 31, 2011, due to changes in the U.S.-Canadian exchange rate that were unfavorable to the value of the Canadian dollar versus the U.S. dollar, our foreign currency translation resulted in a loss of $1.0 million, respectively, which we recorded as a decrease 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. We have not repatriated earnings from our Canadian subsidiary, but have elected to invest in new business opportunities there. We do not hedge our exposure to foreign currency exchange risk.

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Item 8. Financial Statements and Supplementary Data
AMERESCO, INC.
CONSOLIDATED BALANCE SHEETS
 
December 31,
 
2010
 
2011
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
44,691,021

 
$
26,277,366

Restricted cash
9,197,447

 
12,372,356

Accounts receivable, net
68,584,304

 
109,296,773

Accounts receivable retainage
18,452,777

 
26,089,216

Costs and estimated earnings in excess of billings
35,556,425

 
69,251,022

Inventory, net
6,780,092

 
8,635,633

Prepaid expenses and other current assets
8,471,628

 
8,992,963