EnerNOC, Inc.
ENERNOC INC (Form: 10-K, Received: 03/16/2009 13:15:10)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)    

ý

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008

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 001-33471

EnerNOC, Inc.
(Exact Name of Registrant as Specified in its Charter)

Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
  87-0698303
(IRS Employer
Identification No.)

75 Federal Street
Suite 300

 

 
Boston, Massachusetts
(Address of Principal Executive Offices)
  02110
(Zip Code)

Registrant's telephone number, including area code: (617) 224-9900

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class   Name of Each Exchange on Which Registered
Common Stock, $0.001 par value   The NASDAQ Stock Market LLC
    (The NASDAQ Global Market)

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  ý

         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  ý

         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  ý     No  o

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

         Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one).

Large accelerated filer  o   Accelerated filer  ý   Non-accelerated filer  o
(Do not check if a smaller
reporting company)
  Smaller reporting company  o

         Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  o     No  ý

         The aggregate market value of the Registrant's common stock held by non-affiliates of the Registrant as of June 30, 2008, the last business day of the Registrant's second quarter of fiscal 2008, was approximately $221.9 million based upon the last sale price reported for such date on The NASDAQ Global Market.

         The number of shares of the Registrant's common stock (the Registrant's only outstanding class of stock) outstanding as of March 11, 2009 was 20,375,900.

DOCUMENTS INCORPORATED BY REFERENCE

         Portions of the Registrant's definitive proxy statement for its 2009 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than 120 days after the end of the Registrant's fiscal year ended December 31, 2008, are incorporated by reference into this Annual Report on Form 10-K.


Table of Contents


ENERNOC, INC.
ANNUAL REPORT ON FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008

Table of Contents

 
   
  Page  

PART I

       

Item 1.

 

Business

    1  

Item 1A.

 

Risk Factors

    23  

Item 1B.

 

Unresolved Staff Comments

    43  

Item 2.

 

Properties

    43  

Item 3.

 

Legal Proceedings

    43  

Item 4.

 

Submission of Matters to a Vote of Security Holders

    44  

Part II

       

Item 5.

 

Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

    45  

Item 6.

 

Selected Financial Data

    47  

Item 7.

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

    48  

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

    69  

Item 8.

 

Financial Statements and Supplementary Data

    69  

Item 9.

 

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

    69  

Item 9A.

 

Controls and Procedures

    70  

Item 9B.

 

Other Information

    72  

PART III

       

Item 10.

 

Directors, Executive Officers and Corporate Governance

    72  

Item 11.

 

Executive Compensation

    72  

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

    72  

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

    72  

Item 14.

 

Principal Accounting Fees and Services

    73  

PART IV

       

Item 15.

 

Exhibits, Financial Statement Schedules

    73  

Signatures

       

Appendix A

 

Consolidated Financial Statements

    F-1  

 

Report of Ernst & Young LLP, Independent Registered Public Accounting Firm

    F-2  

Exhibit Index

       

Table of Contents

        This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. For this purpose, any statements contained herein regarding our strategy, future operations, financial position, future revenues and gross margins, projected costs, market position, prospects, plans and objectives of management, other than statements of historical facts, are forward-looking statements. The words "anticipates," "believes," "estimates," "expects," "intends," "may," "plans," "projects," "will," "would" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. We cannot guarantee that we actually will achieve the plans, intentions or expectations expressed or implied in our forward-looking statements. Matters subject to forward-looking statements involve known and unknown risks and uncertainties, including economic, regulatory, competitive and other factors, which may cause actual results, levels of activity, performance or the timing of events to be materially different than those exposed or implied by forward-looking statements. Important factors that could cause or contribute to such differences include the factors set forth under the caption "Risk Factors" in Item 1A of Part I of this Annual Report on Form 10-K. Although we may elect to update forward-looking statements in the future, we specifically disclaim any obligation to do so, even if our estimates change, and readers should not rely on those forward-looking statements as representing our views as of any date subsequent to March 16, 2009.

        Our trademarks include: EnerNOC, ENERBLOG, Get More from Energy, Energy for Education, Capacity on Demand, PowerTrak, Celerity Energy, eNode, The Greenest Kilowatt-hour is the One Never Used, One-Click Curtailment, Clean Green California and CarbonTrak.

        Other trademarks or service marks appearing in this Annual Report on Form 10-K are the property of their respective holders.


Table of Contents


PART I

Item 1.    Business

         We use the terms "EnerNOC," the "Company," "we," "us" and "our" in this Annual Report on Form 10-K to refer to the business of EnerNOC, Inc. and its subsidiaries.

Company Overview

        EnerNOC is a leading developer and provider of clean and intelligent energy solutions. We use our Network Operations Center, or NOC, to remotely manage and reduce electricity consumption across a network of commercial, institutional and industrial customer sites to enable a more information-based and responsive, or intelligent, electric power grid. Our customers are electric power grid operators and utilities, as well as commercial, institutional and industrial end-users of electricity. In order to avoid service disruptions, such as brownouts and blackouts, during periods of peak electricity demand, grid operators and utilities have traditionally increased supply-side capacity by building additional power plants and transmission lines. As an alternative, we offer demand response solutions, whereby we monitor electricity consumption and alert our end-use customers to reduce their usage during these same peak periods. This helps optimize the balance of electric supply and demand and creates a significantly lower cost and more environmentally sound, or clean, alternative to building additional power plants and transmission lines. Grid operators and utilities pay us a stream of recurring revenues for managing this demand response capacity. We make payments to commercial, institutional and industrial end-users of electricity for both contracting to reduce electricity usage and actually doing so when called upon.

        We build upon our position as a leading demand response solutions provider by using our NOC and scalable technology platform to also deliver a portfolio of additional energy management solutions to our customers, including our monitoring-based commissioning services, or MBCx solutions, energy procurement services, or EPS solutions, and emissions tracking and trading support. Our MBCx solutions combine advanced metering applications, and energy analytics and control to provide our commercial, institutional and industrial customers with the ability to identify energy efficiency opportunities through the continuous analysis of such customers' real-time energy data. Our EPS solutions provide our commercial, institutional and industrial customers located in restructured or deregulated markets throughout the United States with the ability to more effectively manage the energy supplier selection process, including energy supply product procurement and implementation.

        Since inception, our business has grown substantially. With over 1,650 commercial, institutional and industrial customers across approximately 4,000 customer sites in our demand response network and over 2,050 megawatts, or MW, of demand response capacity under our management as of December 31, 2008, we believe that we are the largest national demand response solutions provider focused on the commercial, institutional and industrial market. Our total revenues increased from $26.1 million to $60.8 million to $106.1 million for the years ended December 31, 2006, 2007 and 2008, respectively. Revenues derived from our energy management solutions increased from $0.4 million to $1.6 million to $6.8 million for the years ended December 31, 2006, 2007 and 2008, respectively.

Significant Developments in 2008

        In December 2008, our board of directors approved a one-time offer, which we refer to as the exchange offer, to our employees, including our executive officers, and directors to exchange option grants that had an exercise price per share that was equal to or greater than the higher of $12.00 or the closing price of our common stock as reported on The NASDAQ Global Market, or NASDAQ, on January 21, 2009. The exchange offer closed on January 21, 2009, and we exchanged options that had exercise prices equal to or greater than $12.00 per share. As a result, an aggregate of 744,401 options, with exercise prices ranging from $12.27 to $48.54 per share, were exchanged for an aggregate of

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612,554 options with exercise prices per share of $8.63 for employees who are not also executive officers of ours, $11.47 for executive officers who are not also directors of ours and $12.94 for our directors.

        In October 2008, James L. Turner was elected to serve as a member of our board of directors and was appointed to the nominating and governance committee of our board of directors.

        In August 2008, we and a subsidiary of ours entered into a $35.0 million secured revolving credit and term loan facility with Silicon Valley Bank, or SVB, which provides for, among other things, revolving credit and term loan advances and letters of credit for our account. Our obligations under this credit facility are secured by all of our assets and the assets of our subsidiaries, excluding any intellectual property. This credit facility replaced our credit facility with BlueCrest Capital Finance, L.P., or BlueCrest.

        In June 2008, Arthur W. Coviello, Jr. was elected to serve as a member of our board of directors and was appointed to the audit committee of our board of directors.

        In May 2008, we acquired 100% of the membership interests of South River Consulting, LLC, or SRC, an energy procurement and risk management services provider. The acquisition of SRC strengthens our position in a growing energy procurement services market and provides a local presence for us in the PJM Interconnection, or PJM, service region.

        In April 2008, we were notified by the Connecticut Department of Public Utility Control that the Agreement, dated as of February 29, 2008, between The Connecticut Light and Power Company, or CL&P, and EnerNOC for up to 170 MW of demand response capacity was denied regulatory approval. Also in April 2008, the Federal Energy Regulatory Commission, or FERC, issued an order accepting proposed changes to the market rules governing ISO New England Inc.'s day-ahead load response program, effective February 7, 2008, which changes resulted in less opportunity for demand response to participate in this program.

        In January 2008, Darren P. Brady commenced employment as our senior vice president and chief operating officer.

Other Significant Developments

        In November 2007, we successfully completed a follow-on public offering of 2,500,000 shares of our common stock at a price of $43.00 per share, of which we sold 500,000 shares and selling stockholders sold 2,000,000 shares. This transaction resulted in net proceeds to us of approximately $19.4 million.

        In September 2007, we acquired all of the outstanding membership interests of Mdenergy, LLC, or MDE, an energy procurement service provider, for a total purchase price of approximately $11.6 million, of which approximately $6.5 million was paid in cash and the remainder of which was paid by the issuance of 139,056 shares of our common stock. The acquisition of MDE enables us to apply leading energy market intelligence as well as an online reverse auction technology platform, now called EnerNOC Exchange, to help commercial, institutional, and industrial customers make more informed commodity purchasing decisions.

        In May 2007, we completed our initial public offering, or IPO, of 4,312,500 shares of common stock at a price of $26.00 per share, which included the exercise of the underwriters' over-allotment option to purchase 562,500 shares and the sale of 225,000 shares by certain of our stockholders. Net proceeds to us from the offering were approximately $95.2 million.

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Industry Background

The Electric Power Industry

        Historically, electric utility companies were formed in North America as regulated monopolies to manage the capital intensive, mission critical service of delivering electricity to end-use customers. Each local utility was vertically integrated, with responsibility for owning, managing and delivering all components of the electric power industry: generation, transmission, distribution and retail sales. Each utility was also responsible for maintaining reliability standards based on avoiding service disruptions, commonly known as blackouts. In about half of North America, the industry continues to operate in this vertically integrated fashion.

        In the rest of North America, including New England, New York, the Mid-Atlantic, the Midwest, Texas, California and Ontario, Canada, the electric power industry has been restructured to foster a competitive environment. In these restructured markets, utilities continue to operate and maintain transmission and distribution lines, delivering electricity to consumers as they had before, but power generators and electricity suppliers are now allowed to openly compete for business. Independent system operators, referred to as ISOs, or regional transmission organizations, referred to as RTOs, have been formed in these restructured markets to take control of the operation of the regional power system, coordinate the supply of electricity, and establish fair and efficient markets. ISOs and RTOs are collectively referred to as grid operators. These grid operators are responsible for maintaining Federal reliability standards designed to avoid service disruptions.

        Increasingly, grid operators and utilities in both restructured markets and in traditionally regulated markets are challenged to reliably provide electricity during periods of peak demand. Clean and intelligent energy solutions can provide a lower cost, reliable and environmentally sound alternative to building additional supply infrastructure in both traditionally regulated and restructured markets.

Challenges Facing the Electric Power Industry

        The electric power industry in North America faces enormous challenges to keep pace with the expected increase in demand for electricity and to manage the increased amount of intermittent renewable energy resources that are expected to be connected to the power grid in the future. Because electricity cannot be economically stored using commercially available technology today, it must be generated, delivered and consumed at the moment that it is needed by end-use customers. Maintaining a reliable electric power system therefore requires real-time balancing between supply and demand. Power generation, transmission and distribution facilities are built to capacity levels that can service the maximum amount of anticipated demand plus a reserve margin intended to serve as a buffer to protect the system in critical periods of peak demand or unexpected events such as failure of a power plant or major transmission line. However, under-investment in generation, transmission and distribution infrastructure in recent years in key regions, coupled with a dramatic growth in electricity consumption over that same time period, has led to an increased frequency of voltage reductions—commonly known as brownouts—and blackouts, which are collectively estimated to cost the United States $80 billion per year, primarily in lost productivity, according to a United States Department of Energy 2005 study. These challenges are exacerbated by environmental concerns and stringent regulatory environments that make it increasingly difficult to find suitable sites, obtain permits, and construct generation, transmission and distribution facilities where they are needed most, often in densely populated areas. Although the economic slowdown in the United States in late 2008 and early 2009 has resulted in declining industrial demand for electricity, mid-range and longer-term expectations of capacity shortfalls continue. In addition, existing power generation facility construction has slowed.

        According to the North American Electric Reliability Council, demand for electricity is expected to increase over the next 10 years by approximately 18% in the United States, but generation capacity is expected to increase by only approximately 6% in the United States during that same period. As a

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result, in North America, the margin between electric supply and demand is projected to drop below minimum target levels in parts of the Midwest, the Southeast, the West and the Southwest in the next two to three years, with other portions of the Northeast, the Mid-Atlantic, the Midwest, the South and the West falling below minimum target levels in the next 10 years. According to the International Energy Agency, North America is expected to add 695,000 MW of additional capacity at a cost of $2.65 trillion between 2007 and 2030 to reliably meet expected annual growth in demand. This presents enormous economic, environmental and logistical challenges.

        In addition to the challenges arising from the need to build additional generation capacity in North America, under-investment in the transmission and distribution infrastructure required to deliver power from centralized power plants to end-use customers has resulted in an overburdened electric power grid. This periodically prevents the transport of power to constrained areas during periods of peak demand, which can affect reliability and cause significant economic impacts. Whereas demand for electricity is expected to increase over the next 10 years by approximately 18% in the United States, total transmission miles in the United States are projected to increase by less than 10% during that same period.

        As the electric power industry confronts these challenges, demand response has emerged as an important solution to help address the imbalance in electric supply and demand. For example, the Energy Policy Act of 2005 declared it the official policy of the United States to encourage demand response and the adoption of devices that enable it. In addition, as more renewable energy sources come on line, we believe that our demand side management offerings to grid operators and utilities will provide additional value as grid operators and utilities seek additional means to manage fluctuations in the amount of power generated by intermittent power generation sources, such as wind and solar.

Our Market Opportunity

        According to the International Energy Agency, electric power infrastructure expenditures in North America are expected to exceed $2.65 trillion between 2007 and 2030. We estimate that over 10% of the electric power infrastructure in North America has been constructed in order to meet peaks in electricity demand that occur less than 1% of the time, or approximately 88 hours per year. Based on these estimates, we believe that the market in North America for reducing demand during these critical peak hours, in place of building supply infrastructure, is $11.5 billion per year, if the need to build-out infrastructure occurs on an equal annual basis. Using the same assumptions, we estimate that the market for eliminating the top 1% of peak demand for electricity worldwide during this same period could be over $59.2 billion per year.

        We are a pioneer in the development, implementation and broader adoption of technology-enabled demand response solutions. Our technology enables us to send control signals to, and receive bi-directional communications from, an Internet-enabled network of broadly dispersed end-use customer sites in order to initiate, monitor and terminate demand response activity. Our robust and scalable technology and proprietary operational processes automate demand response and simplify end-use customer participation. These solutions are designed for the commercial, institutional and industrial market, which represents approximately 60% of the United States electricity consumption. We provide demand response capacity by contracting with these end-use customers of grid operators and utilities to reduce their electricity usage on demand. We receive most of our revenues from grid operators and utilities and we make payments to end-users of electricity for both contracting to reduce electricity usage and actually doing so when called upon.

        Our technology enables us to remotely reduce electricity usage in a matter of minutes, or send curtailment instructions to our end-use customers to be implemented on site. We believe that our solutions address extreme peaks in demand for electricity more efficiently than building additional electric generation, transmission and distribution infrastructure because over 10% of this supply-side

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infrastructure is typically built to meet peaks in demand that occur less than 1% of the time. We are well positioned as a market leader to address this substantial market opportunity for demand response. In addition, our PowerTrak enterprise energy management software platform enables us to deliver to our end-use customer base an expanding portfolio of additional energy management solutions, including our MBCx and EPS solutions and emissions tracking and trading support. We believe that the market opportunity for our MBCx and EPS solutions is significant and will remain so as operational efficiency and energy savings are given increased priority by commercial, institutional and industrial end-users of electricity, and as energy market prices remain volatile.

        We provide our demand response solutions to grid operators and utilities under long-term contracts and pursuant to open market bidding programs. Our long-term contracts generally have terms of three to 10 years and predetermined capacity commitment and payment levels. In open market programs, grid operators and utilities generally seek bids from companies such as ours to provide demand response capacity based on prices offered in competitive bidding. These opportunities are generally characterized by energy and capacity obligations with shorter commitment periods and prices that may vary by hour, by day, by month, by bidding period or by supplemental, new or modified demand response programs. We began providing demand response solutions in one state in 2003 and expanded nationally to 22 states and the District of Columbia in eight regions, as well as internationally in Ontario, Canada, by December 31, 2008. From our start in one open market in 2003 to our current 22 contracts and open market programs with grid operators and utilities, we have increased our demand response capacity under management with commercial, institutional and industrial customers to over 2,050 MW as of December 31, 2008.

        As indicated in the table below, we have substantial opportunities to continue expanding our MW under management in the regions in which we already provide our demand response solutions, as well as in other regions. The table depicts, as of December 31, 2008, each of our geographic markets currently served, the length of time we have operated in that region, the contracts and programs in each region under which we generate revenues, the demand response capacity in MW that we currently manage in the region, and our estimate of the market potential in MW for our demand response solutions. We expect to increase over time our MW under management, and thereby increase our revenues, in each of the geographic regions we serve.

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Our Geographic Regions, Contracts and Markets
As of December 31, 2008

Region(1)
(Years of Operation In Region)
  Type of
Contract/Open
Market Program
(OMP)
  Date of
Contract/
Initial
Enrollment
IN OMP
  Contract/OMP
Expiration
Date
  Demand
Response
Capacity
Under
Management
12/31/08
(MW)
  Regional
All-Time
Peak
Demand
(MW)(1)
  Demand
Response
Potential
Market
Opportunity
(MW)(2)
 
New England   Reliability-Based OMP   Mar 2003   May 2010                    
(6 Years)   Price-Based OMP   Jul 2003   May 2010                    
    Price-Based OMP   Jul 2006   May 2010     854     28,130     2,813  
    Reliability-Based Contract   Jun 2008   Dec 2012                    
    Reliability-Based OMP   Jun 2010   Open-Ended                    
   
 
 
New York   Reliability-Based OMP   Aug 2004   Open-Ended                    
(4.5 Years)   Reliability-Based OMP   Aug 2007   Open-Ended     207     33,939     3,394  
    Reliability-Based Contract   Oct 2006   Mar 2012                    
   
 
 
California   Reliability-Based Contract   May 2006   Dec 2017                    
(4 Years)   Reliability-Based OMP   Mar 2007   Open-Ended                    
    Reliability-Based OMP   May 2007   Open-Ended     164     50,270     5,027  
    Reliability-Based Contract   Feb 2007   Dec 2011                    
    Reliability-Based Contract   Feb 2007   Jun 2009                    
   
 
 
PJM   Ancillary Services OMP   Aug 2006   Open-Ended                    
(2.5 Years)   Price-Based OMP   Aug 2006   Open-Ended     698     144,644     14,464  
    Reliability-Based OMP   Jun 2007   Open-Ended                    
   
 
 
Southwest
(2 Years)
  Reliability-Based Contract   Feb 2007   Dec 2017     20     36,519     3,652  
   
 
 
Southeast   Reliability-Based Contract   Aug 2007   Dec 2011     59     237,100     23,710  
(1.5 Years)   Reliability-Based Contract   Jun 2008   Sept 2011                    
   
 
 
Northwest
(1 Year)
  Reliability-Based Pilot Contract   Nov 2007   Dec 2009     4     40,298     4,030  
   
 
 
Texas
(1 Year)
  Reliability-Based OMP   Feb 2008   Open-Ended     47     62,500     6,250  
   
 
 
Ontario
(1 Year)
  Reliability-Based Contract   Mar 2008   May 2013     4     27,005     2,701  
                           
  Total                 2,057     660,405     66,041  
                           

(1)
US Regions and Regional All-Time Peak Demands based on FERC Electric Power Market Classifications and Data.

(2)
Calculated as 10% of regional peak demand, estimated to occur during 1% of annual hours.

        The column above labeled Demand Response Capacity Under Management reflects demand response capacity under contract with commercial, institutional and industrial customers.

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        The column above labeled Type of Contract/Open Market Program (OMP) describes, on a region by region basis, how we provide our demand response solutions to electric power grid operators and utilities under long-term contracts and in open market programs. Our long-term contracts generally have terms of three to 10 years and predetermined capacity commitment and payment levels. Our open market program opportunities are generally characterized by flexible capacity commitments and prices that vary by hour, by day, by month, by bidding period or by supplemental, new or modified demand response programs. Within these contracts and open market programs we offer the following solutions to serve the needs of grid operators and utilities:

    reliability-based demand response, which requires a level of demand response capacity to be available for dispatch on call by grid operators and utilities;

    price-based demand response, which enables commercial, institutional and industrial customers to monitor and respond to electricity market price signals by reducing electricity usage; and

    ancillary services, which include resources utilized as a reserve pool of quick-start resources to provide short-term support for grid operators and utilities, including operating reserves, called upon by grid operators and utilities during short-term events such as the loss of a transmission line or a power plant.

The EnerNOC Solution

        We have developed a proprietary suite of technology applications and operational processes that enable us to make demand response capacity and energy available to grid operators and utilities on demand and remotely manage electricity consumption at commercial, institutional and industrial customer sites. Our solution provides the following benefits:

        Compelling Value Proposition to Grid Operators and Utilities.     On the supply side, grid operators and utilities deploy our technology-enabled demand response solutions to supplement, avoid or defer costly investments in generation, transmission and distribution facilities and to enhance the reliability of the electric power system. Our demand response solutions help grid operators and utilities achieve their capacity and capacity reserve margin goals quickly and economically and allow them to diversify their portfolio of resources, without requiring the installation of any hardware or software at their facilities. Whereas it typically takes years to site, permit and construct a power plant and the associated transmission and distribution infrastructure, demand response capacity can generally be enabled within months, in densely populated, constrained areas, exactly where the new capacity is needed most and with no need for new transmission or distribution infrastructure. We either enter into long-term contracts to sell our demand response capacity to grid operators and utilities, or participate in the open market opportunities for demand response that they establish. Together with these demand response solutions, our energy management solutions enhance the reliability of regional electric power grids by providing grid operators and utilities the ability to measure, manage, shift and reduce energy consumption in specific distribution areas within minutes.

        Compelling Value Proposition To End-Use Customers.     On the demand side, our turnkey, outsourced demand response and energy management solutions create new streams of recurring cash flows, reduce energy costs and simplify energy management for participating commercial, institutional and industrial customers. Our offerings typically involve no up-front capital investment on the part of the participating customer. We share demand response payments, called capacity payments, that we receive from grid operators and utilities with our end-use customers for giving us the ability to reduce their electrical consumption whether or not we are actually called upon to do so. We also generally make additional payments, called energy payments, when they actually reduce their consumption from the electric power grid.

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        Energy Management Solutions for End-Use Customers.     Our demand response solutions position us to deliver additional energy management solutions to our commercial, institutional and industrial customers. These end-use customers are increasingly focused on efficiently managing their energy consumption and reducing costs. The real-time energy consumption data that we gather in our PowerTrak enterprise energy management software platform empowers our MBCx solutions to identify savings opportunities in our end-use customers' energy costs across departments and throughout such customers' operations on an enterprise-wide basis. The devices that we have installed in connection with our demand response solutions enable us to implement our MBCx solutions. By delivering a recurring cash stream for our end-use customers, we are often viewed by them as a trusted partner who can help address their increasingly complex energy challenges.

        Open, Scalable and Secure Architecture.     Our NOC is supported by our PowerTrak enterprise energy management software platform, which is built on an open and scalable Web services architecture. PowerTrak is able to interface with energy management and building automation systems at commercial, institutional and industrial customer sites, thereby enabling us to cost-effectively leverage existing technology for remote monitoring and control from our NOC. PowerTrak's analytical tools enable a single NOC operator to supervise hundreds of end-use metering and control points and simultaneously optimize demand response performance and energy savings measures across numerous customer sites and geographic regions. We have built a comprehensive security infrastructure, including firewalls, intrusion detection systems and data encryption, and have established fail-over redundancy for our information technology systems.

        Reduced Environmental Impact.     By reducing electricity consumption during periods of peak demand and other system emergencies, our demand response solutions can displace older, inefficiently-used power plants, and defer new generation, transmission and distribution development, resulting in reduced emissions and land use benefits. These environmental benefits are particularly clear when demand response capacity qualifies under regional regulations as operating reserves. In these areas, grid operators and utilities call on demand response when contingencies such as power plant or transmission outages occur, which can offset the need to keep centralized peaking power plants running on idle for thousands of hours per year. Dispatchable demand response capacity therefore allows grid operators and utilities to meet reserve requirements with significantly less environmental impact than conventional supply-side alternatives. In addition, we believe that growing participation in demand response by commercial, institutional and industrial organizations will lead to an increased focus on energy management efforts, including energy efficiency and conservation, through which end-use customers can significantly reduce air emissions.

        Management of Intermittent Renewable Power Source Shortfalls.     We expect that the electric power industry in North America will face challenges in managing an increased amount of intermittent renewable energy resources that are expected to be connected to the power grid in the future. Although these numbers will be smaller initially, as grid operators and utilities move to meet increased regulatory requirements for renewable energy sources at the state level and look ahead to possible Federal renewable energy portfolio standards, we believe our demand response solutions will offer additional value to grid operators and utilities trying to address some of the risks inherent in renewable energy sources that are less predictable than traditional baseload energy generation sources. Some of the primary current candidates for large-scale renewable energy sources such as wind and solar power provide fluctuating amounts of power based on external factors such as weather and atmospheric conditions. Accordingly, grid operators and utilities must plan for the risk that these kinds of renewable resources will not be available on a consistent basis. This means that reserve margins, or excess capacity available during normal operations, must be higher. We believe that our demand response solutions offer a more cost-effective solution for providing a wide variety of reserve capacity than traditional peaking power plants, which require significant infrastructure expenditures for capacity that is

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infrequently used, and that this cost benefit gives us an additional competitive advantage when pursuing demand response opportunities from grid operators and utilities.

Competitive Strengths

        Our competitive strengths position us for continued leadership and rapid expansion in the clean and intelligent energy solutions sector.

        First-Mover Advantage with National Presence.     We are a pioneer in the development, implementation and broader adoption of technology-enabled demand response solutions to commercial, institutional and industrial customers on a national scale. With approximately 4,000 customer sites in our demand response network across multiple electric power grids as of December 31, 2008, we believe that we are the largest national demand response service provider for commercial, institutional and industrial customers. We reliably delivered our demand response capacity over 50 times in 2006 and over 100 times in each of 2007 and 2008 when called upon by grid operators and utilities. Specifically, in 2008, we delivered performance that averaged over 100% during the year, based on nominated versus delivered capacity. As a result, we have developed a substantial base of operating experience in delivering demand response solutions.

        Highly Scalable Business Model Focused on Commercial, Institutional and Industrial Customers.     The large size of our target customers, along with our PowerTrak enterprise energy management software platform, enables us to rapidly scale our business in existing and new geographies. Once a demand response market is established in a region, the marginal cost of acquiring and servicing commercial, institutional and industrial customers is relatively low compared to traditional supply-side capacity resources. In addition, the large size of our target end-use customers significantly lowers our acquisition cost per unit of capacity compared to the acquisition cost of residential customers. Commercial, institutional and industrial customers also often have one decision maker who controls multiple sites, thereby accelerating our acquisition of new capacity under management, lowering our cost to expand our network of managed sites and providing more opportunities to sell our additional energy management solutions.

        Recurring Revenues.     We engage in long-term contracts and participate in open market programs with grid operators and utilities through which we are paid recurring payments, typically on a monthly basis, for the capacity that we make available, whether or not we are called upon to reduce our end-use customers' electricity consumption from the electric power grid. These long-term contracts generally range between three and 10 years in duration. These recurring payments significantly increase the visibility and predictability of our future revenues. In addition, we enter into long-term agreements that generally range between three and five years in duration with commercial, institutional and industrial customers that provide us with demand response capacity.

        Comprehensive Technology Platform.     Our scalable, proprietary technology platform, in addition to our operational experience, creates significant barriers to entry. We communicate via the Internet using advanced metering applications and automation equipment that we or third parties install at end-use customer sites to make demand response participation viable for a wide range of commercial, institutional and industrial organizations. The open design architecture of our proprietary technology platform enables us to interface with existing and new energy management and building automation systems which use a variety of protocol languages. Once an end-use customer is enabled in our network, we collect real-time energy consumption data. This data enables our software to perform demand response measurement and verification, and also provides the underlying information to conduct further energy management analysis and provide decision-making support. In addition, rather than being limited to curtailing electricity used by a specific type of equipment, such as air-conditioning units, our platform enables us to manage a wide array of equipment and systems to implement appropriate demand response solutions on an end-user by end-user basis.

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        Growing Customer Base.     We have rapidly and significantly grown our base of grid operator and utility customers since inception. As of December 31, 2008, our grid operator and utility customer base included ISO New England Inc., or ISO-NE, New York ISO, PJM, Pacific Gas and Electric Company, Southern California Edison Company, San Diego Gas and Electric Company, or SDG&E, Public Service Company of New Mexico, Tampa Electric Company, and Tennessee Valley Authority, among others. As of December 31, 2008, we had over 1,650 end-use commercial, institutional, and industrial customers for our demand response solutions, including Adobe Systems, Albertsons, AT&T, California State University, General Electric, Level 3 Communications, Pfizer, and Stop & Shop, among others. In addition, because we have a national presence, we are able to offer a single platform for national chains to participate in our solutions across different geographic regions with different market rules and conditions.

Strategy

        Our strategy is to capitalize on our scalable and proprietary technology platform as well as our leading market position to continue providing clean and intelligent energy solutions to commercial, institutional and industrial customers, grid operators, and utilities. Ultimately, our aim is to become the leading outsourced energy management solutions provider for commercial, institutional and industrial customers worldwide. Key elements of our strategy include:

        Target Aggressive Expansion in Existing Territories.     We will continue to pursue opportunities to provide demand response capacity to grid operators and utilities in markets where we currently operate through additional long-term contracts and open market opportunities for demand response capacity. To provide this demand response capacity, we will enter into contracts with commercial, institutional and industrial customers. We will also seek to provide additional energy management solutions, such as our MBCx and EPS solutions, to these end-use customers. Our sales force will primarily focus their efforts on the six following vertical markets: technology, education, food sales and storage, government, healthcare and manufacturing/industrial. We believe that our full-service demand response and energy management solutions, the recurring payments that we provide and our national presence will enable us to continue to pursue rapid growth of our end-use customer base.

        Strengthen Presence by Entering New Geographic Regions.     We will also continue to expand our addressable market by pursuing new demand response and energy management opportunities in new geographic regions in North America and beyond. We intend to accomplish this and capitalize on the trend toward a more responsive and distributed electricity grid by (i) educating and marketing to existing and prospective customers, consumer advocates, consultants, industry experts, and policy makers; (ii) designing and developing demand response programs and goals in cooperation with grid operators, utilities, regulators, and governmental agencies; and (iii) continually enhancing our demand response and energy management solutions.

        Expand Sales of our Growing Portfolio of Technology-Enabled Energy Management Solutions.     We believe that our demand response solutions have uniquely positioned us to deliver additional energy management solutions to our growing network of commercial, institutional and industrial customers. We will continue to develop our technology, including our PowerTrak enterprise energy management software platform. This platform enables us to measure, manage, benchmark and optimize end-use customers' energy consumption and facility operations. We will continue through our MBCx solutions to use real-time and historical energy data to help end-use customers analyze and control their consumption of electricity, forecast demand, continuously monitor building management equipment to optimize system operation, model rates and tariffs and create energy scorecards to benchmark similar facilities. In addition, we offer our EPS solutions and emissions tracking solutions to our customers, which enable our end-use customers to mitigate risk through competitive energy supply contracts and achieve energy cost savings. We believe that our end-use customers will become increasingly aware of

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their energy costs and consumption and will look to advanced analytics and trusted third-party providers to help them better manage their overall energy expenditures.

        Pursue Targeted Strategic Acquisitions.     We intend to pursue selective acquisitions to reinforce our leadership position in the expanding clean and intelligent energy solutions sector. This sector consists of a number of companies with offerings or customer relationships that present attractive acquisition opportunities. Our track record includes successfully integrating acquired companies to increase our customer base, enter new geographic regions and enhance our technology. In May 2008, we acquired SRC, an energy procurement and risk management services provider, to strengthen our position in a growing energy procurement services market and provide a local presence for us in the PJM service region.

Our Clean and Intelligent Energy Solutions

Demand Response Solutions

        Demand response is achieved when end-use customers reduce their consumption of electricity from the electric power grid in response to a market signal. End-use customers can reduce their consumption of electricity by reducing demand (for example, by dimming lights, resetting air conditioning set-points or shutting down production lines) or they can self-generate electricity with onsite generation (for example, by means of a back-up generator or onsite cogeneration). Our demand response capacity provides a more timely, cost-effective and environmentally sound alternative to building conventional supply-side resources, such as natural gas-fired peaking power plants, to meet infrequent periods of peak demand.

        Although electric power utilities have offered less technology-enabled forms of demand response to their largest electricity consumers for decades in the form of interruptible tariffs—a mechanism that allows utilities to call on customers to reduce consumption during periods of peak demand in exchange for lower rates—these programs typically lack an affordable means of real-time data communication and adequate automation technologies to make demand response participation viable for most commercial, institutional and industrial organizations. We believe that the widespread adoption of the Internet, as well as cost-effective and robust metering and control technologies, have created a new opportunity for technology-enabled demand response solutions to drive significant benefits for all stakeholders.

        We have pursued this opportunity by building our own proprietary technologies and operational processes that make demand response participation possible for a wider range of electricity consumers. The devices that we install at our commercial, institutional and industrial customer sites transmit to us via the Internet electrical consumption data on a 1-minute, 5-minute, 15-minute and hourly basis, which is referred to in the electric power industry as near real-time data. Our proprietary software applications analyze the data from individual sites and aggregate data for specific regions. When a demand response event occurs, our NOC automatically processes the notification coming from the grid operator or utility. Our NOC operators then begin activating procedures to curtail demand from the grid at our commercial, institutional and industrial customer sites. Our one-click curtailment activation sends signals to all registered sites in the targeted geography where the event is occurring. Upon activation of remote demand reduction, our technology, which is receiving near real-time data from each site, is able to determine on a near real-time basis whether the location is performing as expected. Signals are relayed to our NOC operators when further steps are needed to achieve demand reductions at any given location. Each customer site is monitored for the duration of the demand response event and operations are automatically restored to normal when the event ends.

        We offer the following three distinct demand response solutions to serve the needs of grid operators and utilities: (i) reliability-based demand response, (ii) price-based demand response, and (iii) short-term reserve resources referred to in the electric power industry as ancillary services.

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        Reliability-Based Demand Response.     We receive recurring capacity payments from grid operators and utilities for being on call, which means having available previously registered demand response capacity that we have aggregated from our commercial, institutional and industrial customers, regardless of whether we receive a signal to reduce consumption. When we receive a signal from a grid operator or utility customer, which we refer to as a dispatch signal, our proprietary software applications automatically notify our end-use customers that a demand reduction is needed and initiate processes that reduce electrical consumption by our commercial, institutional and industrial customers in the targeted area. When we are called to implement a demand reduction, we typically receive an additional payment for the energy that we reduce. Our commercial, institutional and industrial customers will then receive a payment from us. We are called upon to perform by grid operators and utilities during periods of high demand or supply shortfalls, otherwise known as capacity deficiency events. By aggregating a large number of end-use customers to participate in these reliability-based programs, we believe that we have played a significant role over the past four years in helping to prevent brownouts and blackouts in some of the most capacity constrained regions in the United States. We currently provide reliability-based demand response solutions to ISO-NE, PJM, the New York Independent System Operator, SDG&E, Southern California Edison Company and Pacific Gas and Electric Company, among others.

        Price-Based Demand Response.     Our price-based demand response solutions enable commercial, institutional and industrial customers to monitor and respond to wholesale electricity market price signals when it is cost-effective for them to do so. We register a "strike price" with respect to each customer using this solution, above which it may be economical for that end-use customer to reduce its consumption of electricity. We receive an energy payment in the amount of the wholesale market price for the electricity that the customer does not consume and share this payment with that customer. If prices in a given market approach a given strike price, our solutions automatically notify the customer and initiate processes that reduce electrical consumption from the electric power grid. We currently participate in price response programs in the Mid-Atlantic and New England.

        Ancillary Services.     Demand response is utilized for short-term reserve requirements, referred to in the electric power industry as ancillary services, including operating reserves. This solution is called upon by grid operators and utilities during short-term contingency events such as the loss of a transmission line or large power plant. Through our technology, certain end-use customers are able to provide near instantaneous response for these numerous short-term system events, and often do so with negligible impact on their business operations. Grid operators and utilities rely on a reserve pool of these quick-start resources to step in and provide short-term support as needed during these contingency events. The goal of grid operators and utilities is to get these resources back into standby mode as quickly as possible after they are dispatched so that the reserve pool of available capacity is replenished. Examples of ancillary services markets in which we participate include PJM's Synchronized Reserves Market, in which we were the first provider of demand response capacity, and ISO-NE's Demand Response Reserves Pilot program.

Energy Management Solutions

        We have an expanding portfolio of additional energy management solutions. We believe that our demand response solutions have positioned us to deliver additional energy management solutions to our growing network of commercial, institutional and industrial customers. By collecting and reporting real-time energy consumption data and by delivering a stream of recurring payments to our end-use customers through demand response solutions, we hope to be viewed as a trusted partner who can help address their increasingly complex energy challenges. Our energy management solutions are aimed at

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helping address these challenges and at expanding our customer relationships. The diagram below provides an overview of these solutions.

LOGO


        In September 2007, we acquired MDE, an energy procurement services provider, to augment our expanding portfolio of additional energy management solutions. The MDE acquisition included the addition of hundreds of new commercial, institutional and industrial customers to whom we were providing EPS solutions as of December 31, 2008. In May 2008, we acquired SRC, an energy procurement and risk management services provider, which acquisition strengthens our position in a growing energy procurement services market and provides a local presence for us in the PJM service region. We intend to pursue and have pursued opportunities to provide demand response solutions to a substantial number of the new customers derived from these acquisitions.

        We currently offer the following technology-enabled energy management solutions to our commercial, institutional and industrial customers:

    Monitoring-Based Commissioning.   Our MBCx solution is a technology-based energy analytics service designed to help optimize the way buildings operate, measure the impact of key energy and environmental decisions, and enhance the comfort of occupants. Our PowerTrak application integrates data from disparate energy management systems with utility metering to gather data on a customer's overall energy usage. Our analysts then use analysis tools, filters, and applications to monitor and review this data, and provide distilled information and recommendations designed to optimize performance; reduce energy consumption; reduce carbon emissions; prioritize maintenance needs; and enhance occupant comfort.

    Energy Procurement Services.   We offer to our end-use commercial, institutional and industrial customers various services related to procuring commodity supply contracts from competitive electricity suppliers. We use our market knowledge and industry relationships, along with actual customer electricity usage data that we track and manage through PowerTrak, to achieve savings for customers. We bring customers strategic advice to help them capture favorable energy procurement contracts from competitive electricity suppliers. We take no position in the commodities market and assume no associated risk.

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Technology and Operations

Technology

        Since inception, we have focused on delivering industry-leading, technology-enabled demand response and energy management solutions. Our proprietary technology has been developed to be highly reliable and scalable and to provide a platform on which to design, customize, and implement demand response and energy management solutions. Our proprietary technology infrastructure is built on Linux, Java and Oracle and supports an open web services architecture. Our PowerTrak enterprise energy management software platform enables us to efficiently scale our demand response offerings in new geographic regions and rapidly grow the end-use customers in our network.

        Web services connect applications directly with other applications. They do this through a form of "loose coupling" which allows connections to be established across applications without customization. As a result, these connections can be established without regard to technology platform or programming language, making it easy to share technology across a broad range of users and companies. Web services enable business collaboration at the process level. Process-level collaboration requires software that is architected for communication across firewalls. We believe that business process collaboration over the Internet has wide-reaching implications for the ways in which energy transactions will be performed.

        Our technology can be broken down into three primary components: the Network Operations Center, the EnerNOC Site Server, or ESS, and PowerTrak, our enterprise energy management software.

Network Operations Center

        Our technology enables our NOC to automatically respond to signals sent by grid operators and utilities to deliver demand reductions within targeted geographic regions. We can customize our technology to receive and interpret many types of dispatch signals sent directly from a grid operator or utility to our NOC. Following the receipt of such a signal, our NOC automatically notifies specified end-use customer personnel of the demand response event. After relaying this notification to our commercial, institutional and industrial customers, we initiate processes that reduce their electricity consumption from the electric power grid. These processes may include dimming lights, shifting equipment to power save mode, adjusting heating and cooling set points and activating a back-up generator. Demand reduction is monitored remotely with real-time data feeds, the results of which are displayed in our NOC through various data presentment screens. Each participating customer site is monitored for the duration of the demand response event and operations are automatically restored to normal when the event ends. We currently participate in demand response programs across North America, some of which require demand reductions within 10 minutes or less. We have built a comprehensive security infrastructure, including firewalls, intrusion detection systems, and encryption for transmissions over the Internet, and have established fail-over redundancy for the information technology systems that support our NOC. The following diagram illustrates how we use our NOC to reduce electricity consumption from the electric power grid.

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Our Technology Platform and Operational Processes

LOGO


The EnerNOC Site Server

        We work directly with end-use customers to ensure that they are able to respond quickly and completely to demand reduction instructions. We install a hardware device, called an EnerNOC Site Server, or ESS, at each end-use customer site to collect and communicate real-time electricity consumption data and, in many cases, enable remote control. The ESS communicates to our NOC through the customer's LAN or other internet connection. The ESS is an open, integrated system consisting of a central hardware device residing inside a standard electrical box.

        The ESS serves as a gateway to connect our NOC with a variety of data collection systems and equipment at end-use customer sites. The ESS is typically installed in the electrical room at an end-use customer's site and is equipped to read and record voltage, current, power and other power quality electrical data of certain customer-owned electrical equipment, along with other important energy usage parameters, including natural gas, chilled water, steam and compressed air. It includes a web-based service software application which enables the secure, bi-directional transfer of data across firewalls and over the Internet. The ESS is used to locally connect into many types of building management equipment and systems that support a range of communications protocols and interfaces such as LonWorks, BACnet/IP, Modbus RTU, Modbus TCP/IP, and SNMP. The ESS also provides protocol

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translation so that data from legacy building management systems can be connected directly to our NOC. This advanced connectivity allows us to use a customer's existing infrastructure investment, lowering our overall cost of enablement and making data available to corporate networks and the Internet through industry standard communication protocols.

PowerTrak Enterprise Energy Management Software

        PowerTrak is our web-based enterprise energy management software platform used for power measurement, load control and energy analysis, and is the underlying software that runs our NOC. It utilizes a modular web services architecture that is designed to allow application modules to be easily integrated into the platform. We believe that a key factor to successfully offering clean and intelligent energy solutions is integrating data from disparate sources and utilizing it to deliver customer-focused solutions utilizing open protocols. The following diagram and description provide an overview of our system architecture.

LOGO


    Energy Intelligence.   This proprietary suite of web-enabled modules delivers demand response and energy management capabilities by processing near real-time and historical data from our data warehouse. Energy intelligence provides actionable energy information to users and offers a way for users to view and manipulate this data. Modules include: Profiling, which enables usage tracking; PowerTrak Analytics, which enables users to conduct asset performance and emissions tracking, load forecasting, benchmarking and scorecard reporting; Rate Analysis, which enables users to compare utility tariffs with competitive supply offers; Curtailment, which enables us to curtail electricity consumption and dispatch generators based on signals from grid operators; Billing, which enables users to generate energy bills for internal cost allocation purposes; and MyPowerTrak, which is a customizable portal that enables our personnel and our customers to create user-defined dashboards with customized content.

    Enterprise Applications.   This Java-based middle layer of the application is where we have defined and implemented our business processes, business rules, and business logic that pertain to global device management, security, messaging, file transfer, scheduling and business process management. These enterprise applications provide the core web services that coordinate the near real-time exchange of data between devices, people, external data sources, and other enterprise applications.

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    Data Layer.   The data layer is a relational database that is designed for query, analysis and transaction processing and data collection, processing, aggregation and validation. It contains historical energy data and data from other sources. It separates analysis workload from transaction workload and enables us to consolidate data from several sources. These records include customer demographics, interval energy information (for example, 1-minute, 5-minute and 15-minute), as well as weather, emissions, pricing and aggregated summary data.

        Currently, PowerTrak collects facility consumption data on a 1-minute, 5-minute, 15-minute and hourly basis and integrates that data with near real-time, historical and forecasted market variables. We use PowerTrak to measure, manage, benchmark and optimize end-use customers' energy consumption and facility operations. We use this data to help end-use customers analyze consumption patterns, forecast demand, measure real-time performance during demand response events, continuously monitor building management equipment to optimize system operation, model rates and tariffs and create energy scorecards to benchmark similar facilities. In addition, PowerTrak enables us to track each end-use customer's greenhouse gas emissions by mapping their energy consumption with the fuel mix used for generation in their location, such as the proportion of coal, nuclear, natural gas, fuel oil and other sources used.

        We have generally provided basic PowerTrak functionality as part of the overall service offering to the end-use customers who participate in our demand response programs. As part of our MBCx solutions, we use PowerTrak to identify and deliver energy efficiency strategies for our customers. We believe that end-use customers will become increasingly aware of their energy costs and consumption and will look to advanced analytics and trusted third-party providers to help them better manage their overall energy expenditures.

Operations

        As of December 31, 2008, our operations team consisted of 136 employees. This group comprises several functionally distinct sub-groups:

    Customer Operations —customer operations is responsible for all on-site project management, hardware installation, and on-going customer relationship management. Members of this group include project managers, site technicians including electricians, energy engineers, materials management, and staff with large capital project experience.

    Network Operations —the network operations group is responsible for maintaining the connectivity and preparedness of approximately 4,000 commercial, industrial, and institutional facilities. This group is also responsible for demand response event execution and call center support through our NOC.

    Energy Markets —the energy markets group is responsible for managing our portfolio of demand response resources to maximize revenue and minimize risk of underperformance and penalties. The group is composed of experts in market rules and regulations, bidding and enrollment procedures, performance measurements, and financial settlements. Combining this knowledge with near real-time data from thousands of end-use sites, energy markets actively manages its resource portfolios to ensure reliable and consistent event performance.

    Energy Services Operations —the energy services operations group is responsible for our MBCx solutions, EPS solutions and carbon avoidance services. Energy services operations leverages our PowerTrak platform, customer relationships, network of installed devices and customers' pre-existing energy management systems to identify and implement energy savings opportunities. In addition to this activity, energy services operations is responsible for the analysis behind, and execution of, our EPS solutions.

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Sales

        As of December 31, 2008, our sales team consisted of 98 employees. We organize our sales efforts by customer type. Our utility sales group sells to grid operators and utilities, while our commercial and industrial sales group sells to commercial, institutional and industrial customers.

        Our utility sales group is responsible for securing additional long-term contracts from grid operators and utilities. These sales typically take 12 to 18 months to complete and, when successful, typically result in multi-million dollar contracts with terms that generally range between three and 10 years. We actively pursue long-term contracts in both restructured markets and in traditionally regulated markets.

        Our commercial and industrial sales group sells our demand response and energy management solutions to commercial, institutional and industrial customers. These sales typically take two to four months to complete and have terms that generally range between three and five years. Our commercial and industrial sales group is located in major electricity regions throughout the United States, including New England, New York, the Mid-Atlantic, Texas, Florida, California and Ontario, Canada. In each of these territories, we have a regional sales director, who reports to our senior vice president of sales and business development.

Marketing

        Our marketing organization consisted of 20 employees as of December 31, 2008. This group is responsible for influencing all market stakeholders including customers, energy users and policymakers, attracting prospects to our business, enabling the sales engagement process with messaging, training and sales tools, and sustaining and expanding relationships with existing customers through renewal and retention programs and by identifying cross selling opportunities. This group researches our current and future markets and leads our strategies for growth, competitiveness, profitability and increasing market share.

Customers

End-Use Customers

        As of December 31, 2008, we managed over 2,050 MW of technology-enabled demand response capacity from over 1,650 different commercial, institutional and industrial customers in our demand response network across approximately 4,000 customer sites. The following table lists some of our largest customers by capacity under management as of December 31, 2008 in each of the six key vertical markets that our commercial and industrial sales group primarily targets for demand response opportunities:

  Technology   Education   Food Sales and Storage
  AT&T
Level 3 Communications
General Electric
Adobe Systems
  University of San Diego
The California State University
Southern Connecticut State University
Western Connecticut State University
New Haven Public Schools
  Albertsons
Raley's
Pathmark
Stop & Shop
Shop Rite

 

Government

 

Healthcare

 

Manufacturing/Industrial
  Suffolk County, NY   Partners Healthcare   O&G Industries
  City of Stamford, CT   Stamford Hospital   Pfizer
  Town of Vernon, CT   Greenwich Hospital   Verso Paper
  City of Brockton, MA   Hartford Hospital   Cascades
  City of New Haven, CT   UMass Memorial Health Care    

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        Supermarkets are a good example of how our technology and solutions function to deliver demand response capacity to grid operators and utilities while delivering significant value to the end-use customer. Supermarkets operate with thin margins, and energy savings can significantly impact financial results. It has been calculated that a 10% reduction in energy costs for the average supermarket is equivalent to increasing net profit margins by 16%. Because the profit margins of supermarkets are so thin, on the order of 1%, the U.S. Environmental Protection Agency estimates that $1.00 in energy savings is equivalent to increasing sales by $59.00.

        Supermarkets have a number of measures that can be taken to reduce their electrical demand from the grid. Most supermarkets have a natural gas-fired emergency generator to ensure that shoppers who are in the checkout line can pay for products in the event of a power disruption. In many regions, these can be activated at times when a supermarket is called on to reduce demand. Supermarkets also have the option to curtail non-critical electrical loads that do not interfere with shopping. Lighting in many supermarkets is separated into different circuits and curtailing approximately one-third of the lights does not impact business continuity. Additionally, air handlers, anti-sweat heaters, and other ancillary loads can be curtailed. On average, our supermarket customers are able to achieve 69 kW of demand reduction from the grid for each supermarket location by implementing these types of demand response strategies.

        Our demand response solutions enable this demand reduction. Our hardware is installed in each store to provide for remote control of devices and collection and communication of real-time electricity consumption information (i.e., metering). Our hardware communicates through the supermarket's LAN or through a broadband wireless connection. Our hardware has the ability to communicate directly with the physical building management system at many supermarket sites. It also may have the ability to communicate directly with discrete lighting panels and automatic transfer switches coupled to emergency generators in the event that a building management system does not exist. From our NOC, depending on the configuration of our curtailment protocol at each supermarket, we are able to send a command over the Internet to reduce electrical consumption. Demand reduction is monitored remotely with real-time data feeds, the results of which are displayed in our NOC through various data presentment screens. Each supermarket is monitored for the duration of the demand response event and operations are automatically restored to normal when the event ends.

Grid Operator and Utility Customers

        We have significantly grown our base of grid operator and utility customers since inception. As of December 31, 2008, our grid operator and utility customer base included ISO-NE, The New York Independent System Operator, PJM, Pacific Gas and Electric Company, Southern California Edison Company, SDG&E, Burlington Electric Department, Public Service Company of New Mexico, Ontario Power Authority, Tennessee Valley Authority and Tampa Electric Company. We provide reliability-based demand response, price-based demand response and ancillary services for them.

Competition

        We face competition from other clean and intelligent energy solutions providers, advanced metering infrastructure service providers, as well as utilities and competitive electricity suppliers who offer their own demand response and energy management solutions. We also compete with traditional supply-side resources, such as peaking power plants.

        The clean and intelligent energy solutions sector is fragmented. In the demand response sector, we compete with various providers on a regional basis. When competing for grid operator and utility customers, we believe that the primary factors on which we compete are pricing of the capacity that is made available, as well as the financial stability, historical performance levels and overall experience of the demand response solutions provider. When competing for commercial, institutional and industrial customers, we believe that the primary factors are the level of capacity payments shared with the end-use customer for their demand response capacity, level of sophistication employed by the demand

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response service provider to identify and optimize demand response capabilities at their facilities and ability of the demand response service provider to service multiple sites across different geographic regions and provide additional technology-enabled energy management solutions. Some providers of advanced metering solutions have added, or may add, demand response products and services to their existing business. Some advanced metering infrastructure service providers are substantially larger and better capitalized than we are and have the ability to combine advanced metering and demand response solutions into an integrated offering to a large existing customer base. We believe that our operational experience, first mover advantage, leadership in the clean and intelligent energy solutions sector and our established base of customers gives us an advantage when competing for commercial, institutional and industrial customers.

        Utilities and competitive electricity suppliers could and sometimes do also offer their own demand response solutions, which could decrease our base of potential customers and could decrease our revenues and profitability. However, demand response programs, as administered by utilities alone, are bound to standard tariffs to which all end-use customers in the utility's service territory must abide. Utilities must treat all rate class customers equally in order to serve them under public utility commission-approved tariffs. In contrast, we have the flexibility to offer customized solutions to different customers. We believe that we also have technology and operational experience at the facility-level, behind the meter, that both utilities and competitive electricity suppliers lack. Furthermore, we believe that our solutions are complementary to utilities and competitive electricity suppliers' demand response efforts because we can help enlist customers to their existing programs, reduce their workload by serving as a single point of contact for an aggregated pool of customers who choose to participate in their programs, and act to uphold or enhance end-use customer satisfaction. However, utilities and competitive electricity suppliers may offer clean and intelligent energy solutions at prices below cost or even for free in order to improve their customer relations or competitive positions, which would decrease our base of potential customers and could decrease our revenues and profitability.

        We also compete with traditional supply-side resources such as natural gas-fired peaking plants. In some cases, utilities have an incentive to invest in these fixed assets rather than develop demand response as they are able to include the cost of fixed assets in their rate base and in turn receive a return on investment. In addition, some utilities have a financial disincentive to invest in demand response and even more so in energy efficiency because reducing demand can have the effect of reducing their sales of electricity. However, we believe that our solutions are gaining substantial regulatory support and will continue to do so as they are faster to market, require no electric power generation, transmission or distribution infrastructure, and are more cost-effective and more environmentally sound than traditional alternatives.

Regulatory

        We provide demand response solutions in restructured electricity markets and in traditionally regulated electricity markets. In restructured markets, we often provide our solutions to the regional grid operators that are responsible for the reliability and efficient operation of the bulk electric power system, such as PJM. In traditionally regulated markets, we provide our solutions to utilities, such as Public Service Company of New Mexico and Tampa Electric Company.

        Regulations within both types of markets impact how quickly our solutions may be adopted, the prices we can charge and margins we can earn, the timing with respect to when we begin earning revenue, and the various ways in which we are permitted or may choose to do business and accordingly, impact our assessments of which potential markets to most aggressively pursue. In addition, certain of our contracts with utilities are subject to regulatory approval, which regulatory approval may not be obtained on a timely basis, if at all.

        The prices we can charge and margins we can earn can be impacted by market policies, such as program rules that discount the value of demand response resources because they can only be available

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during a limited number of peak demand hours, unlike other types of capacity resources that may be available 24 hours per day, every day of the week. Similarly, regulations defining what constitutes a demand response event can affect the amount of demand response capacity that we are able to enlist from end-use customers and the amount that we need to pay them for their participation.

        The policies regarding the measurement and verification of demand response resources, safety regulations and air quality or emissions regulations, which vary by state, affect how we do business. For example, some state environmental agencies may limit the amount of emissions allowed from back-up generators utilized by end-use customers, even when back-up generators are strictly used to maintain system reliability. For example, in California, demand response capacity is generally not permitted to come from end-use customers who activate back-up generators in order to reduce their electric power grid usage. Therefore, the use of back-up generators is limited under all of our contracts with that state's utilities, with the exception of a contract that our subsidiary, Celerity Energy Partners San Diego, LLC, or Celerity, entered into with SDG&E, which allows use of back-up generators on which we install emissions control equipment. Measurement and verification policies of various markets influence how we modify the metering and control devices we install and data we record at each customer site in those markets. In limited cases, we provide an interconnected demand response resource that exports power to the electric power grid for resale, such as in the case of the contract between Celerity and SDG&E. The export of power for resale is subject to the requirements of the Federal Power Act and FERC's direct regulation.

Intellectual Property

        We utilize a combination of intellectual property safeguards, including patents, copyrights, trademarks and trade secrets, as well as employee and third-party confidentiality and proprietary information agreements, to protect our intellectual property. As of December 31, 2008, in the United States we held two patents, one of which expires in 2024 and the other of which expires in 2022, and one pending patent application. We also had three pending patent applications filed under the Patent Cooperation Treaty for Canada and Australia. Our patent applications, and any future patent applications might not result in a patent being issued with the scope of the claims we seek, or at all; and any patents we may receive may be challenged, invalidated or declared unenforceable. We continually assess appropriate circumstances for seeking patent protection for those aspects of our technology, designs and methodologies and processes that we believe provide significant competitive advantages.

        As of December 31, 2008, we held 12 trademarks/service marks in the United States. These are EnerNOC, ENERBLOG, Get More from Energy, Energy for Education, Capacity on Demand, PowerTrak, Celerity Energy, eNode, The Greenest Kilowatt-hour is the One Never Used, One-Click Curtailment, Clean Green California and CarbonTrak. Several of these trademarks are also registered in Australia and Canada. In addition, we have a number of trademark applications pending in the United States, Canada, and Australia.

        With respect to, among other things, proprietary know-how that is not patentable and processes for which patent protection may not offer the best legal and business protection, we rely on trade secret protection and employ confidentiality and proprietary information agreements to safeguard our interests. We believe that many elements of our demand response solutions involve proprietary know-how, technology or data that are not covered by patents or patent applications, including technical processes, equipment designs, algorithms and procedures. We have taken security measures to protect these elements. All of our employees have entered into confidentiality and proprietary information agreements with us. These agreements address intellectual property protection issues and require our employees to assign to us all of the inventions, designs, and technologies they develop during the course of employment with us. We also seek confidentiality and proprietary information protection from our customers and business partners before we disclose any sensitive aspects of our demand

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response and energy management technology or business strategies. We have not been subject to any material intellectual property claims.

Seasonality

        Peak demand for electricity and other capacity constraints tend to be seasonal. Peak demand in the United States tends to be most extreme in warmer months, which may lead some capacity markets to yield higher prices for capacity or contract for the availability of a greater amount of capacity during these warmer months. As a result, our revenues can fluctuate from quarter to quarter based upon the seasonality of our demand response business in certain of the markets in which we operate, where payments under certain of our long-term capacity contracts and pursuant to certain open market bidding programs in which we participate are higher or concentrated in particular seasons and months. For example, in the PJM forward capacity market, which is a market in which we materially increased our participation beginning in the first quarter of 2008 and in which we expect to continue to increase our participation and derive revenues for the foreseeable future, we recognize capacity-based revenue from PJM over the four month delivery period of June through September. This typically results in higher revenues in our second and third quarters as compared to our first and fourth quarters.

Employees

        As of December 31, 2008, we had 345 full-time employees, including 118 in sales and marketing, 136 in operations, 45 in research and development and 46 in general and administrative. Of these full-time employees, 204 were located in New England, 21 were located in New York, 40 were located in the Mid-Atlantic, 48 were located in California, six were located in Ontario, Canada, eight were located in Texas, five were located in Illinois, four were located in Tennessee and nine were located in other areas across the United States. We expect to grow our employee base and our future success will depend in part on our ability to attract, retain and motivate highly qualified personnel, for whom competition is intense. Our employees are not represented by any labor unions or covered by a collective bargaining agreement and we have not experienced any work stoppages. We consider our relations with our employees to be good.

Available Information

        We were incorporated in Delaware on June 5, 2003 and have our corporate headquarters at 75 Federal Street, Suite 300, Boston, Massachusetts 02110. We operated as EnerNOC, LLC, a New Hampshire limited liability company, from December 2001 until June 2003. We conduct operations and maintain a number of subsidiaries in the United States and Canada. We also maintain EnerNOC Securities Corporation, a Massachusetts securities corporation, to invest our cash balances on a short-term basis. Our Internet website address is www.enernoc.com. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, are available through the investor relations page of our internet website as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission, or the SEC.

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Item 1A.    Risk Factors

         The statements contained in this section, as well as statements described elsewhere in this Annual Report on Form 10-K, or in our other SEC filings, describe risks that could materially and adversely affect our business, financial condition and results of operations and the trading price of our securities. These risks are not the only risks that we face. Our business, financial condition and results of operations could also be materially affected by additional factors that are not presently known to us or that we currently consider to be immaterial to our operations.

Risks Related to Our Business

We have incurred net losses since our inception, and we may continue to incur net losses in the future and may never reach profitability.

        Our net losses in 2008, 2007 and 2006 were $36.7 million, $23.6 million and $5.8 million, respectively. We have not achieved profitability for any calendar year, although we have for certain quarters, and we may continue to incur operating losses in the future. As of December 31, 2008, we had an accumulated deficit of $70.5 million. Initially, our operating losses were principally driven by start-up costs and the costs of developing our technology, which included research and development expenses. More recently, our net losses have been principally driven by selling and marketing, and general and administrative expenses, including, without limitation, expenses related to increased headcount and the expansion of the number of MW under our management. As we seek to grow our revenues and customer base, we plan to continue to expand our demand response and energy management solutions, which will require increased selling and marketing, general and administrative, and research and development expenses. These increased operating costs may cause us to incur net losses for the foreseeable future, and there can be no assurance that we will be able to grow our revenues, sustain the growth rate of our revenues, expand our customer base or become profitable. Furthermore, these expenses are not the only factors that may contribute to our net losses. For example, interest expense on our currently outstanding debt and on any debt that we incur in the future could contribute to our net losses. As a result, even if we significantly increase our revenues, we may continue to incur net losses in the future. If we fail to achieve profitability, the market price of our common stock could decline substantially.

We have a limited operating history in an emerging market, which may make it difficult to evaluate our business and prospects, and may expose us to increased risks and uncertainties.

        We began operating as a New Hampshire limited liability company in December 2001 and were incorporated as a Delaware corporation in June 2003. We first began generating revenues in 2003. Accordingly, we have only a limited history of generating revenues, and the future revenue potential of our business in the emerging market for clean and intelligent energy solutions is uncertain. As a result of our short operating history, we have limited financial data that can be used to evaluate our business, strategies, performance and prospects or an investment in our common stock. Any evaluation of our business and our prospects must be considered in light of our limited operating history and the risks and uncertainties encountered by companies at our stage of development. To address these risks and uncertainties, we must do the following:

    maintain our current relationships and develop new relationships with grid operators and utilities and the entities that regulate them;

    maintain and expand our current relationships and develop new relationships with commercial, institutional and industrial customers;

    maintain and enhance our existing demand response and energy management solutions, and technology systems;

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    continue to develop clean and intelligent energy solutions that achieve significant market acceptance;

    continue to enhance our information processing systems;

    execute our business and marketing strategies successfully, including accurately nominating demand response capacity to our grid operator and utility customers, and delivering a high level of performance by assisting our end-use customers to reduce their usage during demand response events;

    respond to competitive developments;

    attract, integrate, retain and motivate qualified personnel; and

    continue to participate in shaping the regulatory environment.

        We may be unable to accomplish one or more of these objectives, which could cause our business to suffer. In addition, accomplishing many of these goals might be very expensive, which could adversely impact our operating results and financial condition. Any predictions about our future operating results may not be as accurate as they could be if we had a longer operating history and if the market in which we operate was more mature.

A substantial majority of our revenues are and have been generated from contracts with, and open market sales to, a small number of grid operator and utility customers, and the modification or termination of these contracts or sales relationships could materially adversely affect our business.

        During the years ended December 31, 2008, 2007 and 2006, revenues generated from open market sales to PJM, a grid operator customer, accounted for 28%, 4% and 1%, respectively, of our total revenues. The PJM forward capacity market is a market in which we materially increased our participation beginning in the first quarter of 2008 and in which we expect to continue to increase our participation and derive revenues for the foreseeable future. The modification or termination of our sales relationship with PJM, or the modification to or termination of any of its programs in which we participate, could significantly reduce our future revenues and have a material adverse effect on our results of operations and financial position and delay or prevent our future profitability.

        Revenues generated from two fixed price contracts with, and open market sales to, ISO-NE, a grid operator customer, accounted for 36%, 60% and 65%, respectively, of our total revenues for the years ended December 31, 2008, 2007 and 2006. Our fixed price contracts with ISO-NE expired on May 31, 2008. We have enrolled a significant portion of the MW represented by our expired fixed price contracts with ISO-NE in ISO-NE's Real-Time Demand Response program; however, capacity payments currently available under this program are significantly lower than the capacity payments we received under our expired fixed price contracts with ISO-NE, which could reduce our future revenues. Additionally, other available demand response programs in which we may choose to enroll these MW may provide lower capacity payments than ISO-NE's Real-Time Demand Response program. The modification or termination of our sales relationship with ISO-NE, or the modification to or termination of any of its programs in which we participate, could significantly reduce our future revenues and have a material adverse effect on our results of operations and financial position and delay or prevent our future profitability.

        In addition, 15%, 21% and 19%, respectively, of our total revenues for the years ended December 31, 2008, 2007 and 2006 were generated under a fixed price contract with CL&P, a grid operator customer, which expired on December 31, 2008. Although we have enrolled a significant portion of the MW represented by this fixed price contract in other available demand response programs, these other programs, including ISO-NE's Real-Time Demand Response program, provide significantly lower capacity payments. Therefore, the expiration of our fixed price contract with CL&P

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could significantly reduce our future revenues and have a material adverse effect on our results of operations and financial position and delay or prevent our future profitability.

Our results of operations could be adversely affected if our operating expenses and cost of sales do not correspond with the timing of our revenues.

        Most of our operating expenses, such as employee compensation and rental expense for properties, are either relatively fixed in the short-term or incurred in advance of sales. Moreover, our spending levels are based in part on our expectations regarding future revenues. As a result, if revenues for a particular quarter are below expectations, we may not be able to proportionately reduce operating expenses for that quarter. For example, if a demand response event or metering and verification test does not occur in a particular quarter, we may not be able to recognize revenues for the undemonstrated capacity in that quarter. This shortfall in revenues could adversely affect our operating results for that quarter and could cause the market price of our common stock to decline substantially.

        We incur significant up-front costs associated with the expansion of the number of MW under our management and the infrastructure necessary to enable those MW. In most of the markets in which we originally focused our growth, we generally begin earning revenues from our MW under management within approximately one month from enablement of those MW. However, in certain forward capacity markets in which we choose to participate, it may take longer for us to begin earning revenues on MW that we enable, in some cases up to a year after enablement. For example, the PJM forward capacity market, which is a market in which we materially increased our participation beginning in the first quarter of 2008 and in which we expect to continue to increase our participation and derive revenues, operates on a June to May program-year basis, which means that a MW that we enable after June of each year will typically not begin earning revenue until June of the following year. This results in a longer average lag time in our portfolio from the point in time when we consider a MW to be under management to when we earn revenues from those MW. The up-front costs we incur to expand our MW under management in PJM and other similar markets, coupled with the delay in receiving revenues from those MW, could adversely affect our operating results and could cause the market price of our common stock to decline substantially.

We operate in highly competitive markets; if we are unable to compete successfully, we could lose market share and revenues.

        The market for clean and intelligent energy solutions is fragmented. Some traditional providers of advanced metering solutions have added, or may add, demand response services to their existing business. We face strong competition from clean and intelligent energy solutions providers, both larger and smaller than we are. We also compete against traditional supply-side resources such as natural gas-fired peaking power plants. In addition, utilities and competitive electricity suppliers offer their own demand response solutions, which could decrease our base of potential customers and revenues and could delay or prevent our future profitability.

        Many of our competitors have greater financial resources than we do. Our competitors could focus their substantial financial resources to develop a competing business model or develop products or services that are more attractive to potential customers than what we offer. Some advanced metering infrastructure service providers, for example, are substantially larger and better capitalized than we are and have the ability to combine advanced metering and demand response solutions into an integrated offering to a large, existing customer base. Our competitors may offer clean and intelligent energy solutions at prices below cost or even for free in order to improve their competitive positions. Any of these competitive factors could make it more difficult for us to attract and retain customers, cause us to lower our prices in order to compete, and reduce our market share and revenues, any of which could have a material adverse effect on our financial condition and results of operations. In addition, we may also face competition based on technological developments that reduce peak demand for

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electricity, increase power supplies through existing infrastructure or that otherwise compete with our demand response and energy management solutions.

If we fail to successfully educate existing and potential grid operator and utility customers regarding the benefits of our demand response and energy management solutions or a market otherwise fails to develop for those solutions, our ability to sell our solutions and grow our business could be limited.

        Our future success depends on commercial acceptance of our clean and intelligent energy solutions and our ability to obtain additional contracts and enter into new open market bidding programs. We anticipate that revenues related to our demand response solutions will constitute a substantial portion of our revenues for the foreseeable future. The market for clean and intelligent energy solutions in general is relatively new. If we are unable to educate our potential customers about the advantages of our solutions over competing products and services, or our existing customers no longer rely on our demand response solutions, our ability to sell our solutions will be limited. In addition, because the clean and intelligent energy solutions sector is rapidly evolving, we cannot accurately assess the size of the market, and we may have limited insight into trends that may emerge and affect our business. For example, we may have difficulty predicting customer needs and developing clean and intelligent energy solutions that address those needs. Further, we are subject to the risk that the current global financial crisis will result in lower overall demand for electricity in the United States and other markets that we are seeking to penetrate over the next few years. Such a reduction in the demand for electricity could create a corresponding reduction in both supply- and demand-side resources being implemented by grid operators and utilities. In addition, because of reduced demand for electricity, prices for capacity, both demand-side and supply-side, may be lower for the foreseeable future. If the market for our demand response and our energy management solutions does not continue to develop, our ability to grow our business could be limited and we may not be able to achieve profitability.

If the actual amount of demand response capacity that we make available under our capacity commitments is less than required, our committed capacity could be reduced and we could be required to make refunds and pay penalty fees.

        We provide demand response capacity to our grid operator and utility customers either under fixed price long-term contracts, or under terms established in open bidding markets where capacity is purchased. Under the long-term contracts and open bidding market commitments, grid operators and utilities make periodic payments to us based on the amount of demand response capacity that we are obligated to make available to them during the contract period, or make periodic payments to us based on the amount of demand response capacity that we bid to make available to them during the relevant period. We refer to these payments as committed capacity payments. Committed capacity is negotiated and established by the contract or set in the open market bidding process and is subject to subsequent confirmation by measurement and verification tests or performance in a demand response event. In our open bidding markets, we offer different amounts of committed capacity to our grid operator and utility customers based on market rules on a periodic basis. We refer to measured and verified capacity as our demonstrated or proven capacity. Once demonstrated, the proven capacity amounts typically establish a baseline of capacity for each end-use customer site in our portfolio, on which committed capacity payments are calculated going forward and until the next demand response event or measurement and verification test when we are called to make capacity available.

        The capacity level that we are able to achieve varies with the electricity demand of targeted equipment, such as heating and cooling equipment, at the time an end-use customer is called to perform. Accordingly, our ability to deliver committed capacity depends on factors beyond our control, such as the temperature and humidity, and then-current electricity use by our end-use customers when such end-use customers are called to perform. The correct operation of, and timely communication with, devices used to control equipment are also important factors that affect available capacity. Under

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some of our contracts and in certain open market bidding programs, any difference between our demonstrated capacity and the committed capacity on which capacity payments were previously made will result in either a refund payment from us to our grid operator or utility customer or an additional payment to us by such customer. Any refund payable by us would reduce our deferred revenues, but would not impact our previously recognized revenues. If there is a true-up settlement due to a grid operator or utility customer, we generally make a corresponding adjustment in our payments to the end-use customer or customers who failed to make the appropriate level of capacity available, however we are sometimes unable to do so. In addition, some of our contracts with and open market programs established by our grid operator and utility customers provide for penalty payments, which can be substantial, in certain circumstances in which we do not meet our capacity commitments, either in measurement and verification tests or in demand response events. Further, because measurement and verification test results for some capacity contracts and in certain open market bidding programs establish capacity levels on which payments will be made until the next test or demand response event, the payments to be made to us under such capacity contracts and open market bidding programs would be reduced until the level of capacity is established at the next test or demand response event. We could experience significant period-to-period fluctuations in our financial results in future periods due to true-up settlements, capacity payment adjustments, replacement costs or other payments, which could be substantial. We incurred aggregate penalty payments of $82,639, $152,913 and $52,118 during the years ended December 31, 2008, 2007 and 2006, respectively.

Our business is subject to government regulation, and may become subject to modified or new government regulation, which may negatively impact our ability to sell and market our clean and intelligent energy solutions.

        While the electric power markets in which we operate are regulated, most of our business is not directly subject to the regulatory framework applicable to the generation and transmission of electricity. However, we may become directly subject to the regulation of FERC, to the extent we own, operate, or control generation used to make wholesale sales of power. In addition, our subsidiary Celerity is subject to direct regulation by FERC, because Celerity exports power to the electric power grid for resale pursuant to a contract with SDG&E.

        The installation of devices used in providing our solutions and electric generators sometimes installed or activated when providing demand response solutions may be subject to governmental oversight and regulation under state and local ordinances relating to building codes, public safety regulations pertaining to electrical connections and local and state licensing requirements. In a relatively few instances, we have agreed to own and operate a back-up generator at a commercial, institutional or industrial customer location for a period of time and to activate the generator when capacity is called for dispatch so that the commercial, institutional or industrial customer can reduce its consumption of electricity from the electric power grid. These generators could become ineligible to participate in demand response programs in the future, or be compensated less for such participation, thereby reducing our revenues and adversely affecting our financial position. In addition, certain of our contracts and expansion of existing contracts with grid operators and utility customers are subject to approval by federal, state, provincial or local regulatory agencies. There can be no assurance that such approvals will be obtained or be issued on a timely basis, if at all. For example, we received notification in March 2008 from the California Public Utilities Commission, or the CPUC, that the CPUC denied a request by Southern California Edison Company, or SCE, for approval of a contract with us for up to 160 MW of demand response capacity. Although we entered into a revised contract with SCE, which contract SCE has submitted to the CPUC for approval, we cannot be certain that the revised contract will be approved by the CPUC.

        Additionally, federal, state, provincial or local governmental entities may seek to change existing regulations, impose additional regulations or change their interpretation of the applicability of existing

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regulations. Any modified or new government regulation applicable to our current or future solutions, whether at the federal, state, provincial or local level, may negatively impact the installation, servicing and marketing of those solutions and increase our costs and the price of our solutions.

We depend on the electric power industry for revenues and, as a result, our operating results have experienced, and may continue to experience, significant variability due to volatility in electric power industry spending and other factors affecting the electric utility industry, such as seasonality of peak demand and overall demand for electricity.

        We currently derive substantially all of our revenues from the sale of our demand response solutions, directly or indirectly, to the electric power industry. Purchases of our demand response solutions by grid operators or electric utilities may be deferred, cancelled or otherwise negatively impacted as a result of many factors, including challenging economic conditions, mergers and acquisitions involving electric utilities, changing regulations or program rules, fluctuations in interest rates and increased electric utility capital spending on traditional supply-side resources. For example, in February 2008, ISO-NE implemented a market rule change to its Day-Ahead Load Response program, a program in which we have historically been an active participant. This change, which was approved by FERC in April 2008, resulted in less opportunity for demand response to participate in this program and, along with other possible market rule changes, could negatively impact our future revenues and could delay or prevent our profitability. Further, on October 31, 2008, ISO-NE requested that FERC approve its modification to the market rules applicable to ISO-NE's Forward Capacity Market that reduces the value placed on demand resources beginning with the 2012/2013 capacity commitment period. This change, ultimately approved by FERC and made effective December 31, 2008, may result in reduced participation by demand resources in the Forward Capacity Market and may negatively impact our future revenues and could delay or prevent our profitability. In addition, sales of capacity in open markets are particularly susceptible to variability based on changes in the spending patterns of our grid operator and utility customers and on associated fluctuating market prices for capacity.

        Peak demand for electricity and other capacity constraints tend to be seasonal. Peak demand in the United States tends to be most extreme in warmer months, which may lead some capacity markets to yield higher prices for capacity or contract for the availability of a greater amount of capacity during these warmer months. As a result, our demand response revenues may be seasonal. For example, in the PJM forward capacity market, which is a market in which we materially increased our participation beginning in the first quarter of 2008 and in which we expect to continue to increase our participation and derive revenues for the foreseeable future, we recognize capacity-based revenue from PJM over the four month delivery period of June through September. This typically results in higher revenues in our second and third quarters as compared to our first and fourth quarters. As a result of this seasonality, we believe that quarter to quarter comparisons of our operating results are not necessarily meaningful and that these comparisons cannot be relied upon as indicators of future performance. Further, occasional events, such as a spike in natural gas prices or potential decreases in availability, can lead grid operators and utilities to implement short-term calls for demand response capacity to respond to these events, but we cannot be sure that such calls will continue or that we will be in a position to generate revenues when they do occur. In addition, given the current economic slowdown and the related potential reduction in demand for electricity, there can be no assurance that there will not be a corresponding reduction in the implementation of both supply and demand-side resources by grid operators and utilities. We have experienced, and may in the future experience, significant variability in our revenues, on both an annual and a quarterly basis, as a result of these and other factors. Pronounced variability or an extended period of reduction in spending by grid operators and utilities, or continued requests from grid operators and utilities to pay for demand response capacity at prices that are not equal on a monthly or quarterly basis over the course of a contract year, could negatively impact our business and make it difficult for us to accurately forecast our future sales, which could lead to increased spending by us that does not result in increases in revenues.

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Failure of third parties to manufacture quality products or provide reliable services in a timely manner could cause delays in the delivery of our solutions, which could damage our reputation, cause us to lose customers and negatively impact our growth.

        Our success depends on our ability to provide quality, reliable demand response and energy management solutions in a timely manner, which in part requires the proper functioning of facilities and equipment owned, operated or manufactured by third parties upon which we depend. For example, our reliance on third parties includes:

    utilizing components that we or third parties install or have installed at commercial, institutional and industrial locations;

    outsourcing email notification and cellular and paging wireless communications that are used to notify our end-use customers of their need to reduce electricity consumption at a particular time and to execute instructions to devices installed at our customer locations and which are programmed to automatically reduce consumption on receipt of such communications; and

    outsourcing certain installation and maintenance operations to third-party providers.

        Any delays, malfunctions, inefficiencies or interruptions in these products, services or operations could adversely affect the reliability or operation of our demand response and energy management solutions, which could cause us to experience difficulty monitoring or retaining current customers and attracting new customers. Such delays could also result in our making refunds or paying penalty fees to our grid operator and utility customers. In addition, our brand, reputation and growth could be negatively impacted.

If we lose key personnel upon whom we are dependent, we may not be able to manage our operations and meet our strategic objectives.

        Our continued success depends upon the continued availability, contributions, vision, skills, experience and effort of our senior management, sales and marketing, engineering and operations teams. We do not maintain "key person" insurance on any of our employees. We have entered into employment agreements with certain members of our senior management team, but none of these agreements guarantees the services of the individual for a specified period of time. All of the employment arrangements with our key personnel, including the members of our senior management team, provide that employment is at-will and may be terminated by the employee at any time and without notice. Although we do not have any reason to believe that we may lose the services of any of these persons in the foreseeable future, the loss of the services of any of these persons might impede our operations or the achievement of our strategic and financial objectives. We rely on our engineering team to research, design and develop new and enhanced demand response and energy management solutions. We rely on our operations team to install, test, deliver and manage our demand response solutions. We rely on our sales and marketing team to sell our solutions to grid operators, utilities and commercial, institutional and industrial customers, and to build our brand and promote our company. The loss or interruption of the service of members of our senior management, sales and marketing, engineering or operations teams, or our inability to attract or retain other qualified personnel or advisors could have a material adverse effect on our business, financial condition and results of operations and could significantly reduce our ability to manage our operations and implement our strategy.

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We expect to continue to expand our sales and marketing, operations, engineering, and research and development capabilities, as well as our financial and reporting systems, and as a result, we may encounter difficulties in managing our growth, which could disrupt our operations.

        We expect to experience growth in the number of our employees and significant growth in the scope of our operations. To manage our anticipated future growth, we must continue to implement and improve our managerial, operational, financial and reporting systems, expand our facilities, and continue to recruit and train additional qualified personnel. All of these measures will require significant expenditures and will demand the attention of management. Due to our limited resources, we may not be able to effectively manage the expansion of our operations or recruit and adequately train additional qualified personnel. The physical expansion of our operations may lead to significant costs and may divert our management and business development resources. Any inability to manage growth could delay the execution of our business plans or disrupt our operations.

        We compete for personnel and advisors with other companies and other organizations, many of which are larger and have greater name recognition and financial and other resources than we do. If we are not able to hire, train and retain the necessary personnel, or if these managerial, operational, financial and reporting improvements are not implemented successfully, we could lose customers and revenues.

        We allocate our operations, sales and marketing, research and development, general and administrative, and financial resources based on our business plan, which includes assumptions about current and future contracts with grid operator and utility customers and commercial, institutional and industrial customers, variable prices in open markets for demand response capacity, the development of ancillary services markets which enable demand response as a revenue generating resource and a variety of other factors relating to electricity markets, and the resulting demand for our demand response and energy management solutions. However, these factors are uncertain. If our assumptions regarding these factors prove to be incorrect or if alternatives to those offered by our solutions gain further acceptance, then actual demand for our demand response and energy management solutions could be significantly less than the demand we anticipate and we may not be able to sustain our revenue growth or achieve profitability.

An oversupply of electric generation capacity and varying regulatory structures, program rules and program designs in certain regional power markets could negatively affect our business and results of operations.

        Although demand for electric capacity has been increasing throughout North America, a buildup of new electric generation facilities could result in excess electric generation capacity in certain regional power markets. In addition, the electric power industry is highly regulated. The regulatory structures in regional electricity markets are varied and some regulatory requirements make it more difficult for us to provide some or all of our demand response and energy management solutions in those regions. For instance, in some markets, regulated quantity or payment levels for demand response capacity or energy make it more difficult for us to cost-effectively enroll and manage many commercial, institutional and industrial customers in demand response programs. Further, some markets, such as New York, have regulatory structures that do not yet include demand response as a qualifying resource for purposes of short-term reserve requirements known as ancillary services. As part of our business strategy, we intend to expand into additional regional electricity markets. However, the combination of excess electric generation capacity and unfavorable regulatory structures could limit the number of regional electricity markets available to us for expansion. In addition, unfavorable regulatory decisions in markets where we currently operate could also negatively affect our business. For example, regulators could modify market rules in certain areas to further limit the use of back-up generators in demand response markets or could implement bidding floors or caps that could lower our revenue opportunities. A limit on back-up generators would mean that some of the capacity reductions we aggregate from end-use customers willing to reduce consumption from the grid by activating their own

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back-up generators during demand response events would not qualify as capacity, and we would have to find alternative sources of capacity from end-use customers willing to reduce load by curtailing consumption rather than by generating electricity themselves. Regulators could also modify market rules to change the design of a particular demand response program, which design may adversely affect our participation in that program, or regulators could entirely eliminate a demand response program in which we currently participate. Any elimination or change in the design of a demand response program, including any supplemental program, in which we participate, especially in the PJM or ISO-NE markets, could adversely impact our ability to successfully provide our demand response solutions or manage our portfolio of MW under management in that program, thereby reducing our revenues and profit margins and having a material adverse effect on our results of operations and financial condition.

We face pricing pressure relating to electric capacity made available to grid operators and utilities and in the percentage or fixed amount paid to commercial, institutional and industrial customers for making capacity available, which could adversely affect our results of operations and financial position and delay or prevent our future profitability.

        The rapid growth of the clean and intelligent energy solutions sector is resulting in increasingly aggressive pricing, which could cause the prices for clean and intelligent energy solutions to decrease over time. Our grid operator and utility customers may switch to other clean and intelligent energy solutions providers based on price, particularly if they perceive the quality of our competitors' products or services to be equal or superior to ours. Continued decreases in the price of capacity by our competitors could result in a loss of grid operator and utility customers or a decrease in the growth of our business, or it may require us to lower our prices for capacity to remain competitive, which would result in reduced revenues and lower profit margins and would adversely affect our results of operations and financial position and delay or prevent our future profitability. Continued increases in the percentage or fixed amount paid to commercial, institutional and industrial customers by our competitors for making capacity available could result in a loss of commercial, institutional and industrial customers or a decrease in the growth of our business and could delay or prevent our profitability. It also may require us to increase the percentage or fixed amount we pay to our commercial, institutional and industrial customers to remain competitive, which would result in increases in the cost of revenues and lower profit margins and would adversely affect our results of operations and financial position and delay or prevent our future profitability.

We are currently subject to securities class action litigation, the unfavorable outcome of which may have a material adverse effect on our financial condition, results of operations and cash flows.

        In March 2008, purported class action lawsuits were filed against us, certain of our executive officers, the members of our board of directors and certain of the underwriters from our November 2007 follow-on public offering of our common stock by investors alleging violations of the Securities Act of 1933, as amended, or the Securities Act, the Exchange Act and Rule 10b-5 promulgated thereunder. In addition, on May 14, 2008, a complaint was filed derivatively on our behalf against several of our officers and directors and certain of the underwriters of our follow-on public offering alleging various common law and equitable claims, including, among other things, breach of fiduciary duty, gross mismanagement, abuse of control, waste of corporate assets and unjust enrichment. While we believe we have substantial legal and factual defenses to each of the claims in these lawsuits and we will vigorously defend the lawsuits, the outcome of litigation is difficult to predict and quantify, and the defense against such claims or actions can be costly. In addition to decreasing sales and profitability, diverting financial and management resources and general business disruption, we may suffer from adverse publicity that could harm our brand, regardless of whether the allegations are valid or whether we are ultimately liable. A judgment significantly in excess of our insurance coverage for any claims could materially and adversely affect our financial condition, results of operations and cash flows. Additionally, publicity about these claims may harm our reputation or prospects and adversely affect our results.

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An inability to protect our intellectual property could negatively affect our business and results of operations.

        Our ability to compete effectively depends in part upon the maintenance and protection of the intellectual property related to our clean and intelligent energy solutions. We hold two issued patents, 12 registered trademarks and numerous copyrights. Patent protection is unavailable for certain aspects of the technology and operational processes that are important to our business. Any patent held by us or to be issued to us, or any of our pending patent applications, could be challenged, invalidated, unenforceable or circumvented. Moreover, some of our trademarks which are not in use may become available to others. To date, we have relied principally on patent, copyright, trademark and trade secrecy laws, as well as confidentiality and proprietary information agreements and licensing arrangements, to establish and protect our intellectual property. However, we have not obtained confidentiality and proprietary information agreements from all of our customers and vendors, and although we have entered into confidentiality and proprietary information agreements with all of our employees, we cannot be certain that these agreements will be honored. Some of our confidentiality and proprietary information agreements are not in writing, and some customers are subject to laws and regulations that require them to disclose information that we would otherwise seek to keep confidential. Policing unauthorized use of our intellectual property is difficult and expensive, as is enforcing our rights against unauthorized use. The steps that we have taken or may take may not prevent misappropriation of the intellectual property on which we rely. In addition, effective protection may be unavailable or limited if we expand to other jurisdictions outside the United States, as the intellectual property laws of foreign countries sometimes offer less protection or have onerous filing requirements. From time to time, third parties may infringe our intellectual property rights. Litigation may be necessary to enforce or protect our rights or to determine the validity and scope of the rights of others. Any litigation could be unsuccessful, cause us to incur substantial costs, divert resources away from our daily operations and result in the impairment of our intellectual property. Failure to adequately enforce our rights could cause us to lose rights in our intellectual property and may negatively affect our business.

We may be subject to damaging and disruptive intellectual property litigation related to allegations that our demand response and energy management solutions infringe on intellectual property held by others, which could result in the loss of use of those solutions.

        Third-party patent applications and patents may relate to our clean and intelligent energy solutions. As a result, third-parties may in the future make infringement and other allegations that could subject us to intellectual property litigation relating to our solutions, which litigation could be time-consuming and expensive, divert attention and resources away from our daily operations, impede or prevent delivery of our solutions, and require us to pay significant royalties, licensing fees and damages. In addition, parties making infringement and other claims may be able to obtain injunctive or other equitable relief that could effectively block our ability to provide our solutions and could cause us to pay substantial damages. In the event of a successful claim of infringement, we may need to obtain one or more licenses from third parties, which may not be available at a reasonable cost, or at all.

If our information technology systems fail to adequately gather and assess data used in providing our clean and intelligent energy solutions, or if we experience an interruption in their operation, our business, financial condition and results of operations could be adversely affected.

        The efficient operation of our business is dependent on our information technology systems. We rely on our information technology systems to effectively control the devices which enable our demand response solutions; gather and assess data used in providing our energy management solutions; manage relationships with our customers; and maintain our research and development data. The failure of our information technology systems to perform as we anticipate could disrupt our business and product

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development and make us unable, or severely limit our ability, to respond to demand response events. In addition, our information technology systems are vulnerable to damage or interruption from:

    earthquake, fire, flood and other natural disasters;

    terrorist attacks and attacks by computer viruses or hackers;

    power loss; and

    computer systems, Internet, telecommunications or data network failure.

        Although our information technology systems have fail-over redundancy where they are housed, we do not have geographic fail-over redundancy. Any interruption in the operation of our information technology systems could result in decreased revenues under our demand response and energy management contracts and commitments, reduced margins on revenues where fixed payments are due to our commercial, institutional and industrial customers, reductions in our demonstrated capacity levels going forward, customer dissatisfaction and lawsuits and could subject us to penalties, any of which could have a material adverse effect on our business, financial condition and results of operations.

Global economic and credit market conditions, and any associated impact on spending by utilities or grid operators or on the continued operations of our commercial, institutional and industrial customers, could have a material adverse effect on our business, operating results, and financial condition.

        Volatility and disruption in the global capital and credit markets in 2008 and early 2009 have led to a significant reduction in the availability of business credit, decreased liquidity, a contraction of consumer credit, business failures, higher unemployment, and declines in consumer confidence and spending in the United States and internationally. If global economic and financial market conditions deteriorate or remain weak for an extended period of time, numerous economic and financial factors could have a material adverse effect on our business, operating results, and financial condition, including:

    decreased spending by utilities or grid operators, or by commercial, institutional or industrial end-users of electricity, may result in reduced demand for our clean and intelligent energy solutions;

    consumer demand for electricity may be reduced, which could result in lower prices for both demand-side and supply-side capacity in open market programs and pursuant to long-term utility contracts;

    if commercial, institutional and industrial customers in our demand response network experience financial difficulty, some may cease or reduce business operations, or reduce their electricity usage, all of which could reduce the number of MW of demand response capacity under our management;

    we may be unable to find suitable investments that are safe, liquid, and provide a reasonable return, which could result in lower interest income or longer investment horizons, and disruptions to capital markets or the banking system may also impair the value of investments or bank deposits we currently consider safe or liquid;

    if our commercial, institutional and industrial customers to whom we provide our MBCx solutions experience financial difficulty, it could result in their inability to timely meet their payment obligations to us, extended payment terms, higher accounts receivable, reduced cash flows, greater expense associated with collection efforts, and an increase in charges for uncollectable receivables; and

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    due to stricter lending standards, commercial, institutional and industrial end-users of electricity to whom we offer our EPS solutions may be unable to obtain adequate credit ratings acceptable to electricity suppliers, resulting in increased costs, which might make our solutions less attractive or result in their inability to contract with us for our EPS solutions.

        Uncertainty about current global economic conditions could also continue to increase the volatility of our stock price.

Electric power industry sales cycles can be lengthy and unpredictable and require significant employee time and financial resources with no assurances that we will realize revenues.

        Sales cycles with grid operator and utility customers are generally long and unpredictable. The grid operators and utilities that are our potential customers generally have extended budgeting, procurement and regulatory approval processes. They also tend to be risk averse and tend to follow industry trends rather than be the first to purchase new products or services, which can extend the lead time for or prevent acceptance of new products or services such as our demand response solutions. Accordingly, our potential customers may take longer to reach a decision to purchase services. This extended sales process requires the dedication of significant time by our personnel and our use of significant financial resources, with no certainty of success or recovery of our related expenses. It is not unusual for a grid operator or utility customer to go through the entire sales process and not accept any proposal or quote. Long and unpredictable sales cycles with grid operator and utility customers could have a material adverse effect on our business, financial condition and results of operations.

An increased rate of terminations by our commercial, institutional and industrial customers, or their failure to renew contracts when they expire, would negatively impact our business by reducing our revenues, delaying or preventing our profitability and requiring us to spend more money to maintain and grow our commercial, institutional and industrial customer base.

        Our ability to provide demand response capacity under our demand response contracts and in open market bidding programs depends on the amount of MW that we manage across commercial, institutional and industrial customers who enter into agreements with us to reduce electricity consumption on demand. A significant portion of our agreements with our existing commercial, institutional and industrial customers are scheduled for renewal in 2009 and annually thereafter. If customers do not renew their contracts as they expire, we will need to acquire MW from additional commercial, institutional and industrial customers or expand our relationships with existing commercial, institutional and industrial customers in order to maintain our revenues and grow our business. The loss of revenues resulting from contract terminations could be significant, and limiting customer terminations is an important factor in our ability to achieve future profitability. If we are unsuccessful in controlling our commercial, institutional and industrial customer terminations, we may be unable to acquire a sufficient amount of MW or we may incur significant costs to replace MW, which could cause our revenues to decrease and our cost of revenues to increase, and delay or prevent our profitability.

We may incur significant penalties and fines if found to be in non-compliance with any applicable State or Federal regulation, despite best efforts at compliance and adherence.

        While the electric power markets in which we operate are regulated, most of our business is not directly subject to the regulatory framework applicable to the generation and transmission of electricity. However, regulations by FERC related to market design, market rules, tariffs, and bidding rules impact how we can interact with our grid operator and utility customers. In addition, we are aware that our subsidiary Celerity exports some power to the electric power grid and is thus subject to direct regulation by FERC and its regulations related to the sale of wholesale power at market based rates. Despite our efforts to manage compliance with such regulations, we may be found to be in non-compliance with such regulations and therefore subject to penalties or fines. For example, we recently

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determined that prior to our acquisition of Celerity in May 2006, Celerity failed to make requisite filings with FERC in connection with transactions relating to our acquisition. Celerity made such required filings with FERC on April 25, 2008. On October 20, 2008 and October 28, 2008, FERC issued orders authorizing the transaction with Celerity on a prospective basis, and did not order Celerity to pay a penalty. Although the Celerity matter was resolved in our favor, any similar non-compliance activities by us or our subsidiaries could subject us to substantial fines or penalties.

The success of our businesses depends in part on our ability to develop new clean and intelligent energy solutions and increase the functionality of our current demand response and energy management solutions.

        The market for demand response and energy management solutions is characterized by rapid technological changes, frequent new software introductions, Internet-related technology enhancements, uncertain product life cycles, changes in customer demands and evolving industry standards and regulations. We may not be able to successfully develop and market new clean and intelligent energy solutions that comply with present or emerging industry regulations and technology standards. Also, any new regulation or technology standard could increase our cost of doing business.

        From time to time, our customers have expressed a need for increased functionality in our solutions. In response, and as part of our strategy to enhance our clean and intelligent energy solutions and grow our business, we plan to continue to make substantial investments in the research and development of new technologies. Our future success will depend in part on our ability to continue to design and sell new, competitive clean and intelligent energy solutions, enhance our existing demand response and energy management solutions and provide new, value-added services to our customers. Initiatives to develop new solutions will require continued investment, and we may experience unforeseen problems in the performance of our technologies and operational processes, including new technologies and operational processes that we develop and deploy, to implement our solutions. In addition, software addressing the procurement and management of energy assets is complex and can be expensive to develop, and new software and software enhancements can require long development and testing periods. If we are unable to develop new clean and intelligent energy solutions or enhancements to our existing demand response and energy management solutions on a timely basis, or if the market does not accept such solutions, we will lose opportunities to realize revenues and obtain customers, and our business and results of operations will be adversely affected.

Any internal or external security breaches involving our demand response and energy management solutions, and even the perception of security risks of our solutions or the transmission of data over the Internet, whether or not valid, could harm our reputation and inhibit market acceptance of our solutions and cause us to lose customers.

        We and our customers use our demand response and energy management solutions to compile and analyze sensitive or confidential information related to our customers. In addition, some of our demand response and energy management solutions allow us to remotely control equipment at commercial, institutional and industrial customer sites. Our demand response and energy management solutions rely on the secure transmission of proprietary data over the Internet for some of this functionality.

        Well-publicized compromises of Internet security could have the effect of substantially reducing confidence in the Internet as a medium of data transmission. The occurrence or perception of security breaches in our demand response and energy management solutions or our customers' concerns about Internet security or the security of our solutions, whether or not they are warranted, could have a material adverse effect on our business, harm our reputation, inhibit market acceptance of our demand response and energy management solutions and cause us to lose customers, any of which could have a material adverse effect on our financial condition and results of operations.

        We may come into contact with sensitive consumer information or data when we perform operational, installation or maintenance functions for our customers. Even the perception that we have

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improperly handled sensitive, confidential information could have a negative effect on our business. If, in handling this information, we fail to comply with privacy or security laws, we could incur civil liability to government agencies, customers and individuals whose privacy is compromised. In addition, third parties may attempt to breach our security or inappropriately use our demand response and energy management solutions through computer viruses, electronic break-ins and other disruptions. If a breach is successful, confidential information may be improperly obtained, and we may be subject to lawsuits and other liabilities.

We may require significant additional capital to pursue our growth strategy, but we may not be able to obtain additional financing on acceptable terms or at all.

        The growth of our business will depend on substantial amounts of additional capital for marketing and product development of our demand response and energy management solutions. Our capital requirements will depend on many factors, including the rate of our revenue growth, our introduction of new solutions and enhancements to existing solutions, and our expansion of sales and marketing and product development activities. In addition, we may consider strategic acquisitions of complementary businesses or technologies to grow our business, such as our recent acquisition of SRC, which could require significant capital and could increase our capital expenditures related to future operation of the acquired business or technology. Because of our losses, we do not fit traditional credit lending criteria. Moreover, the current financial turmoil affecting the banking system and financial markets and the possibility that financial institutions may consolidate or go out of business have resulted in a reduction in the availability of credit in the credit markets, which may adversely affect our ability to obtain additional funding. We may not be able to obtain loans or additional capital on acceptable terms or at all. Moreover, our current loan and security agreement contains restrictions on our ability to incur additional indebtedness, which, if not waived, could prevent us from obtaining needed capital. Any future credit facilities would likely contain similar restrictions. In the event additional funding is required, we may not be able to obtain bank credit arrangements or effect an equity or debt financing on terms acceptable to us or at all. A failure to obtain additional financing when needed could adversely affect our ability to maintain and grow our business.

Our loan and security agreement contains financial and operating restrictions that may limit our access to credit. If we fail to comply with covenants in our loan and security agreement, we may be required to repay our indebtedness thereunder, which may have an adverse effect on our liquidity.

        Provisions in the loan and security agreement that we and one of our subsidiaries entered into with SVB impose restrictions on our ability to, among other things:

    incur additional indebtedness;

    create liens;

    enter into transactions with affiliates;

    transfer assets;

    pay dividends or make distributions on, or repurchase, EnerNOC stock; or

    merge or consolidate.

In addition, we are required to meet certain financial covenants customary with this type of agreement, including maintaining a minimum specified tangible net worth and a minimum specified ratio of current assets to current liabilities. Our loan and security agreement also contains other customary covenants. 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 could cause us to be unable to borrow under our loan and security agreement with SVB. In addition to preventing additional borrowings under our loan and security agreement, an event of default, if not cured or waived, may

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result in the acceleration of the maturity of indebtedness outstanding under the agreement, 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.

Our ability to use our net operating loss carryforwards may be subject to limitation.

        Generally, a change of more than 50% in the ownership of a company's stock, by value, over a three year period constitutes an ownership change for United States federal income tax purposes. An ownership change may limit a company's ability to use its net operating loss carryforwards attributable to the period prior to such change. The number of shares of our common stock that we issued in our IPO and follow-on public offering, together with any subsequent shares of stock we issue, may be sufficient, taking into account prior or future shifts in our ownership over a three year period, to cause us to undergo an ownership change. As a result, if we earn net taxable income, our ability to use our pre-change net operating loss carryforwards to offset United States federal taxable income may become subject to limitations, which could potentially result in increased future tax liability for us.

We may not be able to identify suitable acquisition candidates or complete acquisitions successfully, which may inhibit our rate of growth, and acquisitions that we complete may expose us to a number of unanticipated operational and financial risks.

        In addition to organic growth, we intend to continue to pursue growth through the acquisition of companies or assets that may enable us to enhance our technology and capabilities, expand our geographic market, add experienced management personnel and increase our service offerings. However, we may be unable to implement this growth strategy if we cannot identify suitable acquisition candidates, reach agreement on potential acquisitions on acceptable terms, successfully integrate personnel or assets that we acquire or for other reasons. Our acquisition efforts may involve certain risks, including:

    we may have difficulty integrating operations and systems;

    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;

    we may incur significant additional operating expenses;

    our ongoing business may be disrupted or receive insufficient management attention; and

    we may not be able to realize the cost savings or other financial and operational benefits we anticipated.

        The process of negotiating acquisitions and integrating acquired products, services, technologies, personnel or businesses might result in operating difficulties and expenditures and might require significant management attention that would otherwise be available for ongoing development of our business, whether or not any such transaction is ever consummated. Moreover, we might never realize the anticipated benefits of any acquisition. Future acquisitions could result in potentially dilutive issuances of equity securities, the incurrence of debt, contingent liabilities, or impairment expenses related to goodwill, and impairment or amortization expenses related to other intangible assets, which

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could harm our financial condition. In addition, if we are unable to integrate any acquired businesses, products or technologies effectively, our business, financial condition and results of operations may be materially adversely affected. In May 2008, we acquired SRC and there can be no assurance that we will be able to successfully integrate it or any other companies, products or technologies that we acquire.

Our ability to provide security deposits or letters of credit is limited and could negatively affect our ability to bid on or enter into significant long-term agreements or arrangements with utilities or grid operators.

        We are occasionally required to provide security deposits in the form of cash to secure our performance under long-term contracts or open market bidding programs with our grid operator and utility customers. In addition, some of our utility or grid operator customers also require collateral in the form of letters of credit to secure performance or to fund possible damages or true-up payments as the result of a failure to make available capacity at agreed levels or an event of default under our contracts with them. Our ability to obtain such letters of credit primarily depends upon our capitalization, working capital, past performance, management expertise and reputation and external factors beyond our control, including the overall capacity of the credit market. Events that affect credit markets generally may result in letters of credit becoming more difficult to obtain in the future, or being available only at a significantly greater cost. As of December 31, 2008, we had $14.3 million of letters of credit outstanding. Our inability to obtain letters of credit and, as a result, to bid or enter into significant long-term agreements or arrangements with utilities or grid operators, could have a material adverse effect on our future revenues and business prospects. In addition, in the event that we default under long-term contracts or open market bidding programs with our grid operator and utility customers pursuant to which we have posted collateral, we may lose a portion or all of such collateral, which could have a material adverse effect on our financial condition and results of operations.

If the software we use in providing our demand response and energy management solutions produces inaccurate information or is incompatible with the systems used by our customers, it could make us unable to provide our solutions, which could lead to a loss of revenues and trigger penalty payments.

        Our software is complex and, accordingly, may contain undetected errors or failures when introduced or subsequently modified. Software defects or inaccurate data may cause incorrect recording, reporting or display of information about the level of demand reduction at a commercial, institutional and industrial customer location, which could cause us to fail to meet our commitments to have capacity available. Any such failures could cause us to be subject to penalty payments to our grid operator and utility customers or reduce revenue in the period the adjustment is identified and result in reductions in capacity payments under contracts and in open market bidding programs in subsequent periods. In addition, such defects and inaccurate data may prevent us from successfully providing our energy management solutions, which would result in lost revenues. Software defects or inaccurate data may lead to customer dissatisfaction and our customers may seek to hold us liable for any damages incurred. As a result, we could lose customers, our reputation could be harmed and our financial condition and results of operations could be materially adversely affected.

        We currently serve a commercial, institutional and industrial customer base that uses a wide variety of constantly changing hardware, software applications and operating systems. Building control, process control and metering systems frequently reside on non-standard operating systems. Our demand response and energy management solutions need to interface with these non-standard systems in order to gather and assess data and to implement changes in electricity consumption. Our business depends on the following factors, among others:

    our ability to integrate our technology with new and existing hardware and software systems, including metering, building control, process control, and distributed generation systems;

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    our ability to anticipate and support new standards, especially Internet-based standards and building control and metering system protocol languages; and

    our ability to integrate additional software modules under development with our existing technology and operational processes.

        If we are unable to adequately address any of these factors, our results of operations and prospects for growth and profitability could be materially adversely effected.

We may face certain product liability or warranty claims if we disrupt our customers' networks or applications.

        For some of our current and planned solutions, our software and hardware is integrated with our commercial, institutional and industrial customers' networks and software applications. The integration of our software and hardware may entail the risk of product liability or warranty claims based on disruption to these networks or applications. In addition, the failure of our software and hardware to perform to customer expectations could give rise to warranty claims against us. Any of these claims, even if without merit, could result in costly litigation or divert management's attention and resources. Although we carry general liability insurance, our current insurance coverage could be insufficient to protect us from all liability that may be imposed under these types of claims. A material product liability claim may seriously harm our results of operations.

Our investments in marketable securities are subject to market risks which may cause losses and affect the liquidity of these investments.

        At December 31, 2008, we had approximately $60.8 million in cash and cash equivalents and approximately $2.0 million in investments in marketable securities. Historically, our investments in securities have included auction-rate securities and municipal bonds. Certain of our investments may be subject to general credit, liquidity, market and interest rate risks. During the year ended December 31, 2008, we had no significant unrealized gains or losses on our investments in marketable securities. There may be declines in the value of these investments, which we may determine to be other-than-temporary. These market risks associated with our investment portfolio may have an adverse effect on our results of operations, liquidity and financial condition.

Risks Related to Our Common Stock

We expect our quarterly revenues and operating results to fluctuate. If we fail to meet the expectations of market analysts or investors, the market price of our common stock could decline substantially.

        Our quarterly revenues and operating results have fluctuated in the past and may vary from quarter to quarter in the future. Accordingly, we believe that period-to-period comparisons of our results of operations may be misleading. The results of one quarter should not be used as an indication of future performance. Our revenues and operating results may fall below the expectations of securities analysts or investors in some future quarter or quarters. Our failure to meet these expectations could cause the market price of our common stock to decline substantially.

        Our quarterly revenues and operating results may vary depending on a number of factors, including:

    demand for and acceptance of our clean and intelligent energy solutions;

    the seasonality of our demand response business in certain of the markets in which we operate, where payments under certain long-term capacity contracts and pursuant to certain open market bidding programs can be higher or concentrated in particular seasons and months;

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    delays in the implementation and delivery of our clean and intelligent energy solutions, which may impact the timing of our recognition of revenues;

    delays or reductions in spending for clean and intelligent energy solutions by our grid operator or utility customers and potential customers;

    the long lead time associated with securing new customer contracts;

    the structure of any forward capacity market in which we participate, which may impact the timing of our recognition of revenues related to that market;

    the mix of our revenues during any period, particularly on a regional basis, since local payments for demand response capacity tend to vary according to the level of available capacity in given regions;

    the termination or expiration of existing contracts with grid operator and utility customers and commercial, institutional and industrial customers;

    the potential interruptions of our customers' operations;

    development of new relationships and maintenance and enhancement of existing relationships with customers and strategic partners;

    temporary capacity programs that could be implemented by grid operators and utilities to address short-term capacity deficiencies;

    changes in open market rules and pricing for demand response capacity;

    flaws in the design of any demand response program in which we participate;

    the current global economic and credit market crisis; and

    increased expenditures for sales and marketing, software development and other corporate activities.

We do not intend to pay dividends on our common stock.

        We have not declared or paid any cash dividends on our common stock to date, and we do not anticipate paying any dividends on our common stock in the foreseeable future. We currently intend to retain all available funds and any future earnings for use in the development, operation and growth of our business. In addition, our loan and security agreement with SVB prohibits us from paying dividends and future loan agreements may also prohibit the payment of dividends. Any future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements, business opportunities, contractual restrictions and other factors deemed relevant. To the extent we do not pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in our common stock.

Shares eligible for future sale may cause the market price for our common stock to decline even if our business is doing well.

        Sales of substantial amounts of our common stock in the public market, whether by our executive officers, directors or other stockholders, or the perception that these sales may occur, could cause the market price of our common stock to decline. This could also impair our ability to raise additional capital in the future through the sale of our equity securities. Under our certificate of incorporation, we are authorized to issue up to 50,000,000 shares of common stock, of which 20,254,548 shares of common stock were outstanding at December 31, 2008. Of these shares, the shares of common stock sold in our IPO and follow-on public offering are freely transferable without restriction or further

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registration under the Securities Act by persons other than "affiliates," as that term is defined in Rule 144 under the Securities Act. In addition, certain of our stockholders will be able to cause us to register common stock that they own under the Securities Act pursuant to registration rights that are described in "Certain Relationships and Related Transactions—Registration Rights" contained in our final prospectus related to our follow-on public offering, which we filed with the SEC on November 14, 2007. We also registered all shares of common stock that we may issue under our Amended and Restated 2003 Stock Option and Incentive Plan, or 2003 Stock Plan, and our 2007 Employee, Director and Consultant Stock Plan, or 2007 Stock Plan.

Provisions of our charter, bylaws and Delaware law, and of some of our employment arrangements, may make an acquisition of us or a change in our management more difficult and could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

        Certain provisions of our certificate of incorporation and bylaws could discourage, delay or prevent a merger, acquisition or other change of control that stockholders may consider favorable, including transactions in which we may have otherwise received a premium on our shares of common stock. These provisions also could limit the price that investors might be willing to pay in the future for shares of our common stock, thereby depressing the market price of our common stock. Stockholders who wish to participate in these transactions may not have the opportunity to do so. Furthermore, these provisions could prevent or frustrate attempts by our stockholders to replace or remove our management. These provisions:

    allow the authorized number of directors to be changed only by resolution of our board of directors;

    require that vacancies on the board of directors, including newly-created directorships, be filled only by a majority vote of directors then in office;

    establish a classified board of directors, providing that not all members of the board be elected at one time;

    authorize our board of directors to issue, without stockholder approval, blank check preferred stock that, if issued, could operate as a "poison pill" to dilute the stock ownership of a potential hostile acquirer to prevent an acquisition that is not approved by our board of directors;

    require that stockholder actions must be effected at a duly called stockholder meeting and prohibit stockholder action by written consent;

    prohibit cumulative voting in the election of directors, which would otherwise allow holders of less than a majority of stock to elect some directors;

    establish advance notice requirements for stockholder nominations to our board of directors or for stockholder proposals that can be acted on at stockholder meetings;

    limit who may call stockholder meetings; and

    require the approval of the holders of 75% of the outstanding shares of our capital stock entitled to vote in order to amend certain provisions of our certificate of incorporation and bylaws.

        Some of our employment arrangements and restricted stock and stock option agreements provide for severance payments and accelerated vesting of benefits, including accelerated vesting of restricted stock and options, upon a change of control. These provisions may discourage or prevent a change of control. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the Delaware General Corporation Law, which may, unless certain criteria are met,

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prohibit large stockholders, in particular those owning 15% or more of our outstanding voting stock, from merging or combining with us for a proscribed period of time.

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and The NASDAQ Global Market, require significant resources, increase our costs and distract our management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

        As a public company with equity securities listed on The NASDAQ Global Market, or NASDAQ, we must comply with statutes and regulations of the SEC and requirements of NASDAQ, with which we were not required to comply prior to the completion of our IPO in May 2007. Complying with these statutes, regulations and requirements occupies a significant amount of the time of our board of directors and management and significantly increases our costs and expenses. In addition, as a public company we incur substantially higher costs to obtain director and officer liability insurance policies than we did as a private company. These factors could make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee.

A failure to maintain adequate internal control over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act of 2002 or prevent or detect material misstatements in our annual or interim consolidated financial statements in the future could materially harm our business and cause our stock price to decline.

        As a public company, our internal control over financial reporting is required to comply with the standards adopted by the Public Company Accounting Oversight Board in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002. Accordingly, we are currently required to document and test our internal controls and procedures to assess the effectiveness of our internal control over financial reporting. In addition, our independent registered public accounting firm is currently required to report on management's assessment of the effectiveness of our internal control over financial reporting and the effectiveness of our internal control over financial reporting. If we are unable to maintain effective control over financial reporting, such conclusion would be disclosed in this and/or subsequent Annual Reports on Form 10-K. In the future, we may identify material weaknesses and deficiencies which we may not be able to remediate in a timely manner. If we fail to maintain effective internal control over financial reporting in accordance with Section 404, we will not be able to conclude that we have and maintain effective internal control over financial reporting or our independent registered accounting firm may not be able to issue an unqualified report on the effectiveness of our internal control over financial reporting. As a result, our ability to report our financial results on a timely and accurate basis may be adversely affected, we may be subject to sanctions or investigation by regulatory authorities, including the SEC or NASDAQ, and investors may lose confidence in our financial information, which in turn could cause the market price of our common stock to decrease. We may also be required to restate our financial statements from prior periods. In addition, testing and maintaining internal control in accordance with Section 404 requires increased management time and resources. Any failure to maintain effective internal control over financial reporting could impair the success of our business and harm our financial results, and you could lose all or a significant portion of your investment.

Our directors and management will exercise significant control over our company, which will limit your ability to influence corporate matters.

        As of December 31, 2008, our directors and executive officers and their affiliates collectively beneficially owned approximately 28% of our outstanding common stock. As a result, these stockholders, if they act together, will be able to influence our management and affairs and all matters requiring stockholder approval, including the election of directors and approval of significant corporate

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transactions. This concentration of ownership may have the effect of delaying or preventing a change in control of our company and might negatively affect the market price of our common stock.

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 common stock will continue to depend in part on the research and reports that securities or industry analysts publish about us or our business. If these analysts do not continue to provide adequate research coverage or if one or more of the analysts who covers us downgrades our stock or publishes inaccurate or unfavorable research about our business, our stock price would likely decline. If one or more of these analysts ceases coverage of our company or fails to publish reports on us regularly, demand for our stock could decrease, which could cause our stock price and trading volume to decline.

Item 1B.    Unresolved Staff Comments

        Not applicable.

Item 2.    Properties

        Our corporate headquarters and principal office is located in Boston, Massachusetts, where we lease approximately 21,965 square feet under a sublease agreement expiring in June 2009 and approximately 35,069 square feet under a lease agreement expiring in June 2014. Upon the expiration of the sublease in June 2009, the lease agreement will be expanded to include the approximate 21,965 square feet currently being subleased. We lease approximately 8,766 square feet in San Francisco, California under a sublease agreement expiring in February 2012. We also lease approximately 6,600 square feet in New York, New York under a lease agreement expiring in December 2011. In addition, we lease space in various locations throughout the United States and Canada for local sales, marketing, and field operations personnel. We do not own any real property. We believe that our leased facilities will be adequate to meet our needs for the foreseeable future.

Item 3.    Legal Proceedings

        We are subject to legal proceedings, claims and litigation arising in the ordinary course of business. We do not expect the ultimate costs to resolve these matters to have a material adverse effect on our consolidated financial position, results of operations or cash flows. In addition to ordinary-course litigation, we are a party to the litigation described below.

        In March 2008, three purported class action lawsuits were filed in the United States District Court for the District of Massachusetts, or the Court, against us, several of our officers and directors, and certain of the underwriters of our November 2007 follow-on public offering of our common stock. The three class action complaints have been consolidated by the Court into a single action and an amended consolidated complaint was filed on September 24, 2008. The lead plaintiff in the consolidated class action claims to represent two purported classes: (i) an "Exchange Act Class" consisting of persons who purchased shares of our common stock from November 1, 2007 through February 27, 2008 and (ii) a "Securities Act Class" consisting of persons who purchased shares of our common stock pursuant or traceable to the follow-on public offering. The lead plaintiff alleges, among other things, that the defendants made false and misleading statements and failed to disclose material information in various SEC filings and other public statements. The amended consolidated class action complaint asserts, on behalf of the purported Securities Act Class, various claims under the Securities Act against all defendants and, on behalf of the purported Exchange Act Class, various claims under the Exchange Act and Rule 10b-5 against us and the individual officer and director defendants. The amended consolidated class action complaint seeks, among other relief, class certification, unspecified damages,

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fees, and such other relief as the Court may deem just and proper. The defendants filed a motion to dismiss the amended consolidated complaint on October 27, 2008 and a hearing on the motion was held on January 8, 2009. The Court took defendants' motion under advisement following the hearing. During the hearing and thereafter, lead plaintiff expressed an intention to abandon his claims against all defendants under the Securities Act. Lead plaintiff has since voluntarily dismissed the underwriter defendants, against whom only Securities Act claims were alleged, from the matter. The Court has not taken any action on the defendants' motion.

        In addition, on May 14, 2008, a complaint was filed derivatively on our behalf in the Court against several of our officers and directors and certain of the underwriters of our follow-on public offering. The derivative complaint alleges various common law and equitable claims, including, among other things, breach of fiduciary duty, gross mismanagement, abuse of control, waste of corporate assets and unjust enrichment, in connection with purported false and misleading statements and failures to disclose material information in certain SEC filings and other public statements from November 1, 2007 to May 14, 2008. The derivative plaintiff seeks, among other relief, unspecified damages, injunctive relief, restitution, disgorgement, fees and such other relief as the Court may deem proper. On August 12, 2008, the Court stayed our obligation to respond to the derivative complaint pending a denial, if any, of the defendants' motion to dismiss the amended consolidated class action complaint.

        We believe that we and the other defendants have substantial legal and factual defenses to the claims and allegations contained in the amended consolidated class action and derivative suit complaints, and we will pursue these defenses vigorously. There can be no assurance, however, that we will be successful, and an adverse resolution of any of the lawsuits could have a material effect on our consolidated financial position and results of operations in the period in which a lawsuit is resolved. In addition, although we carry insurance for these types of claims, a judgment significantly in excess of our insurance coverage could materially and adversely affect our financial condition, results of operations and cash flows. We are not presently able to reasonably estimate potential losses, if any, related to the lawsuits.

Item 4.    Submission of Matters to a Vote of Security Holders

        There were no matters submitted to a vote of security holders during the quarter ended December 31, 2008.

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PART II

Item 5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Price Range of Our Common Stock

        Our common stock has been listed on The NASDAQ Global Market under the symbol "ENOC" since May 18, 2007. Prior to this time, there was no public market for our common stock. The following table sets forth the range of high and low sales prices per share as reported on The NASDAQ Global Market since our IPO for the periods indicated.

Fiscal 2008
  High   Low  

First Quarter

  $ 48.92   $ 9.29  

Second Quarter

  $ 19.25   $ 9.26  

Third Quarter

  $ 24.10   $ 9.06  

Fourth Quarter

  $ 10.52   $ 4.80  

 

Fiscal 2007
  High   Low  

Second Quarter (beginning May 18, 2007)

  $ 43.49   $ 30.16  

Third Quarter

  $ 41.99   $ 29.09  

Fourth Quarter

  $ 50.50   $ 37.31  

Stockholders

        As of March 11, 2009, there were approximately 161 record holders of the 20,375,900 outstanding shares of our common stock. This number does not include stockholders for whom shares are held in a "nominee" or "street" name.

Dividend Policy

        We have never paid or declared any cash dividends on our common stock. We currently intend to retain all available funds and any future earnings to fund the development and expansion of our business, and we do not anticipate paying any cash dividends in the foreseeable future. Any future determination to pay dividends will be at the discretion of our board of directors and will depend on our financial condition, results of operations, capital requirements, and other factors that our board of directors deems relevant. The terms of our current loan and security agreement with SVB preclude us, and the terms of any future debt or credit facility may preclude us, from paying dividends.

Use of Proceeds

        We registered shares of our common stock in connection with our IPO under the Securities Act. The registration statement on Form S-1 (File No. 333-140632) filed in connection with our IPO was declared effective by the SEC on May 17, 2007. The offering commenced on May 17, 2007 and did not terminate before any securities were sold. As of the date of this filing, the offering has terminated. Including shares sold pursuant to the exercise by the underwriters of their over-allotment option, 4,087,500 shares of our common stock were registered and sold in the IPO by us and an additional 225,000 shares of common stock were registered and sold by the selling stockholders named in the registration statement. All the shares were sold at a price to the public of $26.00 per share.

        The managing underwriters of the offering were Credit Suisse Securities (USA) LLC and Morgan Stanley & Co. Incorporated. The net offering proceeds received by us, after deducting underwriting

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discounts and commissions and expenses incurred in connection with the offering, were approximately $95.2 million. These expenses consisted of direct payments of:

    $7.4 million in underwriters discounts, fees and commissions; and

    $3.6 million in legal, accounting and printing fees and miscellaneous expenses.

No payments for such expenses were made directly or indirectly to (i) any of our directors, officers or their associates, (ii) any person(s) owning 10% or more of any class of our equity securities or (iii) any of our affiliates.

        Through December 31, 2008, approximately $19.2 million of the proceeds from our IPO have been used to fund the operation of our business and for general corporate purposes, approximately $21.5 million have been used to purchase and install equipment, approximately $2.6 million have been used to repay indebtedness and approximately $12.4 million have been used to fund acquisitions and make payments outstanding on prior acquisitions. The remainder of the net proceeds from our IPO are invested in short-term investment grade securities and money market accounts. There has been no material change in the planned use of proceeds from our IPO as described in our final prospectus filed with the SEC on May 18, 2007 pursuant to Rule 424(b).

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Item 6.    Selected Financial Data

        Our selected consolidated financial data set forth below is derived from our audited financial statements. The following selected consolidated financial data should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and accompanying notes thereto included in Item 7 and Appendix A, respectively.

 
  Year Ended December 31,  
 
  2008(1)   2007(1)   2006(1)   2005   2004  
 
  (In thousands, except per share data)
 

Selected Balance Sheet Data:

                               

Cash and cash equivalents

  $ 60,782   $ 70,242   $ 9,184   $ 9,719   $ 213  

Marketable securities

    2,000     15,500              

Total assets

    136,964     155,584     29,950     19,651     2,776  

Total long-term debt, including current portion

    4,563     6,091     5,200     1,989     1,750  

Redeemable convertible preferred stock warrant liability

   
   
   
606
   
   
 

Total redeemable convertible preferred stock and stockholders' equity

    99,220     122,417     8,608     6,101     51  

Selected Statement of Operations Data:

                               

Revenues

  $ 106,115   $ 60,838   $ 26,100   $ 9,826   $ 819  

Cost of revenues

    64,819     38,949     16,839     4,190     362  

Gross profit

    41,296     21,889     9,261     5,636     457  

Selling and marketing expenses

    27,641     17,145     5,932     2,228     751  

General and administrative expenses

    46,037     27,917     8,000     4,211     835  

Research and development expenses

    4,816     3,097     955     981     778  
                       
 

Loss from operations

    (37,198 )   (26,270 )   (5,626 )   (1,784 )   (1,907 )

Interest and other income (expense), net

    798     2,788     (145 )   78     14  

Net Loss before income taxes

    (36,400 )   (23,482 )   (5,771 )   (1,706 )   (1,893 )

Income taxes

    (262 )   (100 )            
                       

Net loss

  $ (36,662 ) $ (23,582 ) $ (5,771 ) $ (1,706 ) $ (1,893 )
                       

Net loss per share, basic and diluted(2)

  $ (1.88 ) $ (1.80 ) $ (1.60 ) $ (0.56 ) $ (0.67 )
                       

(1)
Includes the results of operations from the date of acquisition relating to our acquisitions of SRC in May 2008, MDE in September 2007, and eBidenergy and Celerity Energy in 2006. See Note 2 of our accompanying consolidated financial statements contained in Appendix A to this Annual Report on Form 10-K.

(2)
On May 1, 2007, we effected a 2.831 for one split of our common stock. All amounts reflect the impact of that split.

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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 "Selected Financial Data" and consolidated financial statements and accompanying notes thereto included elsewhere in this Annual Report on Form 10-K. In addition to the historical information, the discussion contains certain forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those expressed or implied by the forward-looking statements due to applications of our critical accounting policies and factors including, but not limited to, those set forth under the caption "Risk Factors" in Item 1A of Part I of this Annual Report on Form 10-K.

Overview

        We are a leading developer and provider of clean and intelligent energy solutions. We use our Network Operations Center, or NOC, to remotely manage and reduce electricity consumption across a network of commercial, institutional and industrial customer sites to enable a more information-based and responsive, or intelligent, electric power grid. Our customers are electric power grid operators and utilities, as well as commercial, institutional and industrial end-users of electricity. Our demand response and energy management solutions help optimize the balance of electric supply and demand and create a lower risk and more environmentally sound alternative to building additional power plants and transmission lines. Grid operators and utilities pay us a stream of recurring cash flows for managing demand response capacity that we share with participating end-use customers. We receive most of our revenues from these grid operators and utilities and we make payments to end-users of electricity for both contracting to reduce electricity usage and actually doing so when called upon.

        We build upon our position as a leading demand response solutions provider by using our NOC and scalable technology platform to also deliver a portfolio of additional energy management solutions to our customers, including our monitoring-based commissioning services, or MBCx solutions, energy procurement services, or EPS solutions, and emissions tracking and trading support. Our MBCx solutions combine advanced metering applications, energy analytics and control to provide our end-use customers with the ability to identify energy efficiency opportunities through the continuous analysis of such end-use customers' real-time energy data. Our EPS solutions provide our commercial, institutional and industrial customers located in restructured or deregulated markets throughout the United States with the ability to more effectively manage the energy supplier selection process, including energy supply product procurement and implementation.

        Since inception, our business has grown substantially. With over 1,650 commercial, institutional and industrial customers across approximately 4,000 customer sites in our demand response network and over 2,050 megawatts, or MW, of demand response capacity under our management as of December 31, 2008, we believe that we are the largest national demand response solutions provider focused on the commercial, institutional and industrial market. Our total revenues increased from $26.1 million to $60.8 million to $106.1 million for the years ended December 31, 2006, 2007 and 2008, respectively. Revenues derived from our energy management solutions increased from $0.4 million to $1.6 million to $6.8 million for the years ended December 31, 2006, 2007 and 2008, respectively.

        We continue to devote substantially all of our efforts toward the sale of our demand response and energy management solutions. We have incurred cumulative net losses of $70.5 million from inception to December 31, 2008. Our net losses were $36.7 million, $23.6 million and $5.8 million for the years ended December 31, 2008, 2007 and 2006, respectively.

Significant Developments in 2008

        In December 2008, our board of directors approved a one-time offer, which we refer to as the exchange offer, to our employees, including our executive officers, and directors to exchange option

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grants that had an exercise price per share that was equal to or greater than the higher of $12.00 or the closing price of our common stock as reported on The NASDAQ Global Market on January 21, 2009. The exchange offer closed on January 21, 2009, and we exchanged options that had exercise prices equal to or greater than $12.00 per share. As a result, an aggregate of 744,401 options, with exercise prices ranging from $12.27 to $48.54 per share, were exchanged for an aggregate of 612,554 options with exercise prices per share of $8.63 for employees who are not also executive officers of ours, $11.47 for executive officers who are not also directors of ours and $12.94 for our directors.

        In October 2008, James L. Turner was elected to serve as a member of our board of directors and was appointed to the nominating and governance committee of our board of directors.

        In August 2008, we and a subsidiary of ours entered into a $35.0 million secured revolving credit and term loan facility with SVB which provides for, among other things, revolving credit and term loan advances and letters of credit for our account. Our obligations under this credit facility are secured by all of our assets and the assets of our subsidiaries, excluding any intellectual property. This credit facility replaced our credit facility with BlueCrest.

        In June 2008, Arthur W. Coviello, Jr. was elected to serve as a member of our board of directors and was appointed to the audit committee of our board of directors.

        In May 2008, we acquired 100% of the membership interests of SRC, an energy procurement and risk management services provider. The acquisition of SRC strengthens our position in a growing energy procurement services market and provides a local presence for us in the PJM service region.

        In April 2008, we were notified by the Connecticut Department of Public Utility Control that the Agreement, dated as of February 29, 2008, between CL&P and EnerNOC for up to 170 megawatts of demand response capacity was denied regulatory approval. Also in April 2008, FERC issued an order accepting proposed changes to the market rules governing ISO-NE's day-ahead load response program, effective February 7, 2008, which changes resulted in less opportunity for demand response to participate in this program.

        In January 2008, Darren P. Brady commenced employment as our senior vice president and chief operating officer.

Other Significant Developments

        In November 2007, we successfully completed a follow-on public offering of 2,500,000 shares of our common stock at a price of $43.00 per share, of which we sold 500,000 shares and selling stockholders sold 2,000,000 shares. This transaction resulted in net proceeds to us of approximately $19.4 million.

        In September 2007, we acquired all of the outstanding membership interests of MDE, an energy procurement service provider, for a total purchase price of approximately $11.6 million, of which approximately $6.5 million was paid in cash and the remainder of which was paid by the issuance of 139,056 shares of our common stock. The acquisition of MDE enables us to apply leading energy market intelligence as well as an online reverse auction technology platform, now called EnerNOC Exchange, to help commercial, institutional, and industrial customers make more informed commodity purchasing decisions.

        In May 2007, we completed our IPO of 4,312,500 shares of common stock at a price of $26.00 per share, which included the exercise of the underwriters' over-allotment option to purchase 562,500 shares and the sale of 225,000 shares by certain of our stockholders. Net proceeds to us from the offering were approximately $95.2 million.

        To further strengthen our technology platform, we acquired substantially all of the assets of eBidenergy, Inc. from Trillium Capital Partners LLC in February 2006. In May 2006, we acquired

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certain of the assets of Celerity Energy Partners LLC, a demand response provider for grid operators and utilities, including all of the membership interests in Celerity Energy Partners San Diego LLC. This acquisition increased our base of end-use customers and capacity under management in California.

Revenues and Expense Components

    Revenues

        We derive recurring revenues from the sale of our demand response and energy management solutions. Our revenues from our demand response solutions primarily consist of capacity and energy payments. We derive revenues from demand response capacity that we make available in open market programs, which are open market bidding opportunities established by grid operators or utilities. In these open market programs, grid operators and utilities generally seek bids from companies such as ours to provide demand response capacity based on prices offered in competitive bidding. These opportunities are generally characterized by flexible capacity commitments and prices that vary by hour, by day, by month, by bidding period or by supplemental, new or modified programs. In certain markets, we enter into long-term capacity contracts with grid operators and utilities, generally ranging from three to 10 years in duration, to deploy our demand response solutions.

        Where we operate in open markets, our revenues from demand response capacity payments generally vary month-to-month based upon our enrolled capacity and the market payment rate. Where we have a long-term contract, we receive periodic capacity payments, which may vary monthly or seasonally, based upon enrolled capacity and predetermined payment rates. Under both long-term contracts and open market programs, we receive capacity payments regardless of whether we are called upon to reduce demand for electricity from the electric power grid. Under both long-term contracts and open market programs, we recognize revenue over the applicable delivery period, even where payments are made over a different period. At least once per year, we demonstrate our capacity either through a demand response event or a measurement and verification test. This demonstrated capacity is typically used to calculate the continuing periodic capacity payments to be made to us until the next demand response event or test establishes a new demonstrated capacity amount. In most cases, we also receive an additional payment for the amount of energy usage that we actually curtail from the grid; we call this an energy payment. The energy payment is based upon the amount of energy usage that we actually reduce from the electricity grid in kilowatt hours during the demand response event.

        In accordance with Staff Accounting Bulletin No. 104, Revenue Recognition , or SAB No. 104, in all of our arrangements, we do not recognize any revenues until we can determine that persuasive evidence of an arrangement exists, delivery has occurred, the fee is fixed or determinable, and we deem collection to be probable. As program rules may differ for each contract and/or region where we operate, we assess whether or not we have met the specific delivery requirements and defer revenues as necessary. In accordance with SAB No. 104, we recognize demand response revenues when we have provided verification to the grid operator or utility of our ability to deliver the committed capacity under the agreement or open market program. Committed capacity is verified through the results of an actual demand response event or a measurement and verification test. Once the capacity amount has been verified, the revenues are recognized and future revenues become fixed or determinable and are recognized monthly until the next verification event. In subsequent verification events, if our verified capacity is below the previously verified amount, the grid operator or utility customer will reduce future payments based on the adjusted verified capacity amounts. The payments received from the grid operator or utility customer can be decreased or increased, up to the committed capacity amounts under the agreement or open market program, in connection with subsequent verification events. Revenues recognized between demand response events or tests are not subject to grid operator or utility customer refund.

        As of December 31, 2008, we had over 2,050 MW under management in our demand response network, meaning that we had entered into definitive contracts with our commercial, institutional and

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industrial customers with respect to over 2,050 MW of demand response capacity. In most of the markets in which we originally focused our growth, we generally begin earning revenues from our MW under management within approximately one month from the date on which we "enable" the MW, or the date on which we can reduce the MW from the electricity grid if called upon to do so. An exception is the PJM forward capacity market, which is a market in which we materially increased our participation beginning in the first quarter of 2008 and in which we expect to continue to increase our participation and derive revenues for the foreseeable future. Because PJM operates on a June to May program-year basis, a MW that we enable after June of each year will not begin earning revenue until June of the following year. This results in a longer average lag time in our portfolio from the point in time when we consider a MW to be under management to when we earn revenues from the MW.

        Our portfolio of additional energy management solutions includes our EPS and MBCx solutions, and emissions tracking and trading support. Our EPS solutions provide our end-use customers located in restructured or deregulated markets throughout the United States with the ability to more effectively manage the energy supplier selection process, including energy supply product procurement and implementation. We receive a monthly fee from the competitive electricity provider based upon the actual consumption of electricity used by our end-use customers or a consulting fee from the end-use customer directly. Our MBCx solutions combine advanced metering applications, and energy analytics and control to provide our end-use customers with the ability to identify energy efficiency opportunities through the continuous analysis of such end-use customers' real-time energy data. We also use our PowerTrak platform to deliver emissions tracking and trading support. We generally receive either a subscription-based fee or a percentage savings fee for these energy management solutions. Revenues derived from our energy management solutions increased from $0.4 million to $1.6 million to $6.8 million for the years ended December 31, 2006, 2007 and 2008, respectively.

        Revenues generated from two fixed price contracts with, and open market sales to, ISO-NE, a grid operator customer, accounted for 36%, 60% and 65%, respectively, of our total revenues for the years ended December 31, 2008, 2007 and 2006. Our two fixed price contracts with ISO-NE expired on May 31, 2008. In addition, 15%, 21% and 19%, respectively, of our total revenues for the years ended December 31, 2008, 2007 and 2006 were generated under a fixed price contract with CL&P, which expired on December 31, 2008. We have enrolled a significant portion of the MW represented by our expired fixed price contracts with ISO-NE and CL&P in other available demand response programs. These programs have provided, and could continue to provide significantly lower capacity payments. For example, capacity payments currently available under ISO-NE's Real-Time Demand Response program are significantly lower than the capacity payments that were available under our expired fixed price contracts with ISO-NE and CL&P.

        During the years ended December 31, 2008, 2007 and 2006, revenues generated from open market sales to PJM, a grid operator customer, accounted for 28%, 4% and 1%, respectively, of our total revenues. Under certain contracts and programs, such as PJM's Emergency Load Response Program, or ELRP, the period during which we are required to perform may be shorter than the period over which we receive payments under that contract or program. In these cases, we record revenue over the mandatory performance obligation period, and a portion of the revenues that has been earned is recorded and accrued as unbilled revenue. Our unbilled revenues of $11.6 million at December 31, 2008 will be collected through May 31, 2009.

    Cost of Revenues

        Cost of revenues for our demand response solutions consists primarily of payments that we make to our commercial, institutional and industrial customers for their participation in our demand response network. We generally enter into three to five year contracts with our end-use customers under which we deliver recurring cash payments to them for the capacity they commit to make available on demand. We also generally make an additional payment when a customer reduces consumption of energy from

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the electric power grid. The equipment and installation costs for our devices at our commercial, institutional and industrial customer sites are capitalized and depreciated over the lesser of the remaining term of the contract, for fixed contracts, or the estimated useful life of the equipment and this depreciation is also reflected in cost of revenues. We also include the monthly telecommunications and data costs we incur as a result of being connected to our commercial, institutional and industrial sites and our internal payroll and related costs specifically allocated to a customer site. Cost of revenues for energy management solutions include third party services, equipment depreciation and the wages and associated benefits that we pay to our project managers for the performance of their services.

    Gross Profit

        Gross profit consists of our total revenues less our cost of revenues. Our gross profit has been, and will be, affected by many factors, including (a) the demand for our demand response and energy management solutions, (b) the selling price of our solutions, (c) our cost of revenues, (d) the introduction of new clean and intelligent energy solutions and (e) our ability to open and enter new markets and regions and expand deeper into markets we already serve. In addition, gross profit will be affected by the way in which we manage our portfolio of demand response capacity in certain supplemental demand response programs in which we participate.

    Operating Expenses

        Operating expenses consist of selling and marketing, general and administrative, and research and development expenses. Personnel-related costs are the most significant component of each of these expense categories. We grew from 100 full-time employees at December 31, 2006 to 253 full-time employees at December 31, 2007 to 345 full-time employees at December 31, 2008. We expect to continue to hire employees to support our growth for the foreseeable future. In addition, we incur significant up-front costs associated with the expansion of the number of MW under our management, which we expect to continue for the foreseeable future. Although we expect our overall operating expenses to increase in absolute dollar terms for the foreseeable future as we grow our MW under management and further increase our headcount, we expect our overall annual operating expenses to decrease as a percentage of total annual revenues as we leverage our existing employee base and continue generating revenues from our MW under management.

    Selling and Marketing

        Selling and marketing expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards, (b) commissions, (c) travel, lodging and other out-of-pocket expenses, (d) marketing programs such as trade shows, and (e) other related overhead. Commissions are recorded as an expense when earned by the employee. We expect increases in selling and marketing expenses in absolute dollar terms for the foreseeable future as we further increase the number of sales professionals and, to a lesser extent, increase our marketing activities. We expect annual selling and marketing expenses to decrease as a percentage of total annual revenues as we leverage our current sales and marketing personnel.

    General and Administrative

        General and administrative expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards, related to our executive, finance, human resource, information technology and operations organizations, (b) facilities expenses, (c) accounting and legal professional fees, (d) depreciation and amortization and (e) other related overhead. We expect general and administrative expenses to continue to increase in absolute dollar terms for the foreseeable future as we invest in infrastructure to support continued growth and incur additional

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expenses related to being a public company, including increased audit and legal professional fees, costs of compliance with securities and other regulations, investor relations expenses, and higher insurance premiums. We expect general and administrative expenses to decrease as a percentage of total annual revenues as we leverage our current infrastructure and employee base.

    Research and Development

        Research and development expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards, related to our engineering organization, (b) payments to suppliers for design and consulting services, (c) costs relating to the design and development of new solutions and enhancement of existing solutions, (d) quality assurance and testing, and (e) other related overhead. During the year ended December 31, 2008, 2007 and 2006, we capitalized $1.3 million, $0.7 million and $0.8 million, respectively, of software and development costs in accordance with Statement of Position 98-1, Accounting for the Cost of Computer Software Developed or Obtained for Internal Use, and the amount is included as software in property and equipment at December 31, 2008. We intend to continue to invest in our research and development efforts. We expect research and development expenses to increase in absolute dollar terms for the foreseeable future, but to decrease as a percentage of total revenues in the long term.

    Stock-Based Compensation

        Effective as of January 1, 2006, we adopted the requirements of Statement of Financial Accounting Standards, or SFAS, No. 123R, Share Based Payment, or SFAS No. 123(R), using the modified prospective method. SFAS No. 123(R) addresses all forms of share-based payment awards, including shares issued under employee stock purchase plans, stock options, restricted stock and stock appreciation rights. SFAS No. 123(R) requires us to expense share-based payment awards with compensation cost for share-based payment transactions measured at fair value. For the years ended December 31, 2008, 2007 and 2006, we recorded expenses of approximately $10.4 million, $7.6 million and $0.4 million, respectively, in connection with share-based payment awards to employees and non-employees. With respect to grants through December 31, 2008, a future expense of non-vested options of approximately $21.4 million is expected to be recognized over a weighted average period of 2.6 years and a future expense of restricted stock awards of approximately $3.1 million is expected to be recognized over a weighted average period of 2.9 years.

    Interest and Other Income

        Interest and other income consist primarily of interest income earned on cash balances and other non-operating income. We historically have invested our cash in money market funds, municipal bonds and auction rate securities.

    Interest Expense

        Interest expense consists of interest on our debt facilities.

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Consolidated Results of Operations

    Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

    Revenues

        The following table summarizes our revenues for the years ended December 31, 2008 and 2007 (dollars in thousands):

 
  For the years ended
December 31,
   
 
 
  Percentage
Increase
 
 
  2008   2007  

Revenues:

                   
 

Demand response solutions

  $ 99,317   $ 59,197     67.8 %
 

Energy management solutions

    6,798     1,641     314.3 %
                 
   

Total revenues

  $ 106,115   $ 60,838     74.4 %
                 

        For the year ended December 31, 2008, our demand response solutions revenues increased by $40.1 million, or 67.8%, as compared to the year ended December 31, 2007, of which $27.5 million resulted from our participation in PJM demand response programs. For the year ended December 31, 2007, we recognized revenues of $2.5 million from our participation in PJM demand response programs. We had over 500 megawatts enrolled in PJM demand response programs as of December 31, 2008 as compared to 81 MW as of December 31, 2007, and we recognize capacity-based revenue from PJM demand response programs over the PJM delivery period of June through September. The remainder of the increase in our demand response solutions revenues for the year ended December 31, 2008 resulted from an increase in our MW under management in certain other operating areas, our expansion into new markets and programs, and energy payments in connection with a certain demand response event, offset by the expiration of our fixed price contracts with ISO-NE and a reduction in energy payments due to fewer demand response events being called as compared to the year ended December 31, 2007.

        For the year ended December 31, 2008, our energy management solutions revenues increased by $5.2 million, or 314.3%, as compared to the year ended December 31, 2007. Approximately $2.6 million and $2.0 million, respectively, of this increase resulted from our acquisitions of MDE, an energy procurement services provider, and SRC, an energy procurement and risk management services provider. The remainder of the increase in our energy management solutions revenues for the year ended December 31, 2008 resulted from end-use customers continuing to utilize our EPS solutions, pursuant to which we evaluate our end-use customers' energy purchasing needs and assist them in procuring more cost effective electricity, and from revenues we received from providing our MBCx solutions, pursuant to which we evaluate end-use customers' energy utilization and operating flexibility to determine potential savings opportunities from implementing demand response, conserving energy and limiting peak demand.

        We currently expect our revenues to increase in 2009 compared to 2008 as we seek to further increase our MW under management in all operating regions, including PJM where we had over 500 megawatts enrolled in demand response programs as of December 31, 2008, enroll new end-use customers in our demand response programs, continue to sell our energy management solutions to our new and existing demand response customers and pursue more favorable pricing opportunities. Although we expect our annual revenues to increase in 2009 as compared to 2008, we currently expect that revenues for the first quarter of 2009 will be slightly lower than, or comparable to, the same period in 2008, primarily as a result of our recognizing capacity-based revenue from the ELRP over its delivery period of June through September. We currently expect increased revenues in our second and third fiscal quarters compared to other quarters in our fiscal year due to seasonal demand related to the demand response market.

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    Gross Profit and Gross Margin

        The following table summarizes our gross profit and gross margin percentages for our demand response and energy management solutions for the years ended December 31, 2008 and 2007 (dollars in thousands):

Year Ended December 31,  
2008   2007  
Gross
    Profit    
  Gross
Margin
  Gross
Profit
  Gross
Margin
 
$ 41,296     38.9 % $ 21,889     36.0 %

        Our gross profit increased during the year ended December 31, 2008 when compared to the year ended December 31, 2007 primarily due to our increased participation in PJM's demand response programs, under which we recognize capacity-based revenue over the four-month delivery period of June through September, as well as to the increase in our MW under management in other operating regions and more favorable contract terms with our commercial, institutional and industrial customers. A significant portion of the increase in gross margin for the year ended December 31, 2008 as compared to the year ended December 31, 2007 was attributable to the way in which we managed our portfolio of demand response capacity in certain supplemental demand response programs in which we participate. The remainder of the increase in gross margin for the year ended December 31, 2008 as compared to the year ended December 31, 2007 was due to our higher gross margin energy management services business comprising a greater percentage of our overall revenues.

    Operating Expenses

        The following table summarizes our operating expenses for the years ended December 31, 2008 and 2007 (dollars in thousands):

 
  Year Ended
December 31,
   
 
 
  Percentage
Increase
 
 
  2008   2007  

Operating Expenses:

                   
 

Selling and marketing expenses

  $ 27,641   $ 17,145     61.2 %
 

General and administrative expenses

    46,037     27,917     64.9 %
 

Research and development expenses

    4,816     3,097     55.5 %
                 
   

Total

  $ 78,494   $ 48,159     63.0 %
                 

        Personnel-related costs are the most significant component of each of our operating expense categories, including costs associated with share-based payment awards. We grew from 253 full-time employees at December 31, 2007 to 345 full-time employees at December 31, 2008. We expect to continue to hire employees to support our growth for the foreseeable future. In addition, we incur significant up-front costs associated with the expansion of the number of MW under our management, which we expect to continue for the foreseeable future. Although we expect our overall operating expenses to increase in absolute dollar terms for the foreseeable future as we grow our MW under management and further increase our headcount, we expect our overall operating expenses to decrease as a percentage of total annual revenues as we leverage our existing employee base and continue generating revenues from our MW under management.

        In certain forward capacity markets in which we choose to participate, such as PJM, we may enable our commercial, institutional and industrial customers up to twelve months in advance of enrolling them in a particular program. This market feature creates a longer average lag time across our portfolio from the point in time when we consider a MW to be under management to when we

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earn revenues from such MW. Because we incur selling and marketing and operational expenses, including salaries and related personnel costs, at the time of enrollment, we believe there may be a trend of higher up-front costs than we have incurred historically.

    Selling and Marketing Expenses

 
  Year Ended
December 31,
   
 
 
  Percentage
Increase
 
 
  2008   2007  

Payroll and related costs

  $ 20,905   $ 12,424     68.3 %

Stock-based compensation

    3,692     2,150     71.7 %

Other

    3,044     2,571     18.4 %
                 
 

Total

  $ 27,641   $ 17,145     61.2 %
                 

        The increase in selling and marketing expenses was primarily driven by the costs associated with an increase in the number of selling and marketing full-time employees from 90 at December 31, 2007 to 118 at December 31, 2008. Also contributing to the increase in selling and marketing expenses for the year ended December 31, 2008 compared to the same period in 2007 was an increase in sales commissions payable to certain of our selling and marketing employees, which commissions are reflective of the increase in our revenues for the year ended December 31, 2008, as well as the timing associated with our hiring new full-time employees during 2008 as compared to 2007. Stock-based compensation expense related to selling and marketing employees for the year ended December 31, 2008 increased from $2.2 million to $3.7 million when compared to the same period in 2007.

    General and Administrative Expenses

 
  Year Ended
December 31,
   
 
 
  Percentage
Increase
 
 
  2008   2007  

Payroll and related costs

  $ 21,197   $ 12,215     73.5 %

Stock-based compensation

    6,201     5,098     21.6 %

Other

    18,639     10,604     75.8 %
                 
 

Total

  $ 46,037   $ 27,917     64.9 %
                 

        The increase in general and administrative expenses was primarily due to costs associated with an increase in the number of general and administrative full-time employees from 127 at December 31, 2007 to 182 at December 31, 2008. Also contributing to the increase in general and administrative expenses for the year ended December 31, 2008 compared to the same period in 2007 was the timing associated with our hiring new full-time employees during 2008 as compared to 2007. Stock-based compensation expense related to general and administrative employees for the year ended December 31, 2008 increased from $5.1 million to $6.2 million, or $1.1 million, when compared to the same period in 2007. Included in stock-based compensation during 2007 is $2.3 million related to stock granted to certain of our executives, which was recognized in full as compensation expense. The increase in other is primarily due to increases in telecommunication costs of $0.9 million, facilities costs of $4.2 million and professional services of $2.6 million.

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    Research and Development Expenses

 
  Year Ended
December 31,
   
 
 
  Percentage
Increase
 
 
  2008   2007  

Payroll and related costs

  $ 3,840   $ 2,333     64.6 %

Stock-based compensation

    546     349     56.4 %

Other

    430     415     3.6 %
                 
 

Total

  $ 4,816   $ 3,097     55.5 %
                 

        The increase in research and development expenses was primarily due to costs associated with an increase in the number of research and development full-time employees from 36 at December 31, 2007 to 45 at December 31, 2008, partially offset by capitalized internal software and development costs of $1.3 million in 2008 as compared to $0.7 million in 2007. Stock-based compensation expense related to research and development employees for the year ended December 31, 2008 increased from $0.3 million to $0.5 million when compared to the same period in 2007.

    Interest and Other Income

        Interest and other income for the year ended December 31, 2008 was $1.9 million as compared to $3.2 million for the year ended December 31, 2007. The decrease in interest and other income for the year ended December 31, 2008 as compared to the year ended December 31, 2007 was primarily due to the global decrease in interest rates, which has reduced the yields on our investments and, to a lesser extent, lower average investment balances.

    Interest Expense

        Interest expense for the years ended December 31, 2008 and 2007 was $1.2 million and $0.4 million, respectively. Interest expense for the year ended December 31, 2008 included the write off of $0.4 million in deferred financing fees associated with our BlueCrest debt, which was replaced in August 2008 with our revolving credit and term loan facility with SVB, and interest expense on outstanding debt during 2008. For the year ended December 31, 2007, interest expense was reduced by capitalized interest related to construction in progress projects totaling approximately $0.7 million.

    Income Taxes

        We had a provision for income taxes of $0.3 million and $0.1 million, respectively, for the years ended December 31, 2008 and December 31, 2007. The provision for income taxes relates to the amortization of tax deductible goodwill, which generates a deferred tax liability that cannot be offset by net operating losses or other deferred tax assets since its reversal is considered indefinite in nature. We provided a full valuation allowance for our deferred tax assets because the realization of any future tax benefits could not be sufficiently assured as of December 31, 2008.

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    Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

    Revenues

        The following table summarizes our revenues for the years ended December 31, 2007 and 2006 (dollars in thousands):

 
  For the Years Ended
December 31,
   
 
 
  Percentage
Increase
 
 
  2007   2006  

Revenues:

                   
 

Demand response solutions

  $ 59,197   $ 25,747     129.9 %
 

Energy management solutions

    1,641     353     364.9 %
                 
   

Total revenues

  $ 60,838   $ 26,100     133.1 %
                 

        During the year ended December 31, 2007, the increase in our demand response solutions revenues was primarily due to an increase in our MW under management in all operating regions and the enrollment of new end-use customers in our demand response programs. Also contributing to the increase in our demand response solutions revenues was an increase in the number of our commercial, institutional and industrial customers utilizing our price-based demand response solutions to reduce their electrical consumption from the electric power grid during times of high wholesale market prices. As of December 31, 2007, we had 1,112 MW of electric capacity under management compared to 464 MW under management as of December 31, 2006.

        Our energy management solutions revenues were $1.6 million for the year ended December 31, 2007 compared to $0.4 million for the year ended December 31, 2006, an increase of $1.3 million, or 364.9.%. The increase in our energy management solutions was primarily due to our EPS solutions where we evaluate our end-use customers' energy purchasing needs and assist them in procuring more cost effective electricity.

    Gross Profit and Gross Margin

        The following table summarizes our gross profit and gross margin percentages for our demand response and energy management solutions for the years ended December 31, 2007 and 2006 (dollars in thousands):

Year Ended December 31,  
2007   2006  
Gross
    Profit    
  Gross
Margin
  Gross
Profit
  Gross
Margin
 
$ 21,889     36.0 % $ 9,261     35.5 %

        Our gross profit has been, and will be, affected by many factors, including (a) the demand for our demand response and energy management solutions, (b) the selling price of our solutions, (c) our cost of revenues, (d) the introduction of new clean and intelligent energy solutions and (e) our ability to open and enter new markets/regions and expand deeper into markets we already serve.

        The slight increase in the gross margin percentage for the year ended December 31, 2007 was primarily due to our continued growth and more favorable contract terms with our commercial, institutional and industrial customers.

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    Operating Expenses

        The following table summarizes our operating expenses for the years ended December 31, 2007 and 2006 (dollars in thousands):

 
  Year Ended December 31,    
 
 
  Percentage
Increase
 
 
  2007   2006  

Operating Expenses:

                   
 

Selling and marketing expenses

  $ 17,145   $ 5,932     189.0 %
 

General and administrative expenses

    27,917     8,000     249.0 %
 

Research and development expenses

    3,097     955     224.3 %
                 
   

Total

  $ 48,159   $ 14,887     223.5 %
                 

        Personnel-related costs are the most significant component of each of our operating expense categories, including costs associated with share-based payment awards. We grew from 100 employees at December 31, 2006 to 253 employees at December 31, 2007.

    Selling and Marketing Expenses

        The increase in selling and marketing expenses was primarily driven by the costs associated with an increase in the number of selling and marketing employees from 41 at December 31, 2006 to 90 at December 31, 2007. Stock-based compensation expense related to selling and marketing employees for the year ended December 31, 2007 increased from $0 to $2.2 million when compared to the same period in 2006.

    General and Administrative Expenses

        The increase in general and administrative expenses was primarily due to costs associated with an increase in the number of general and administrative employees from 43 at December 31, 2006 to 127 at December 31, 2007, as well as to greater costs associated with being a public company. Stock-based compensation expense related to general and administrative employees for the year ended December 31, 2007 increased from $0.4 million to $5.1 million, or $4.7 million, when compared to the same period in 2006. Included in stock-based compensation during 2007 is $2.3 million related to stock granted to certain of our executives, which was recognized in full as compensation expense.

    Research and Development Expenses

        The increase in research and development expenses was primarily due to costs associated with an increase in the number of research and development employees from 16 at December 31, 2006 to 36 at December 31, 2007, partially offset by capitalized internal software and development costs of $0.7 million. Stock-based compensation expense related to research and development employees for the year ended December 31, 2007 increased from $0 to $0.3 million when compared to the same period in 2006. During 2006 and through a portion of 2007, we capitalized internal software and development costs of $1.5 million in accordance with Statement of Position 98-1, Accounting for the Cost of Computer Software Developed or Obtained for Internal Use , and this amount is included as software in property and equipment at December 31, 2007.

    Interest and Other Income (Expense), Net

        Net interest and other income was $2.8 million for the year ended December 31, 2007, compared to net interest and other expense of $0.1 million for the year ended December 31, 2006.

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        The increase in interest and other income for the year ended December 31, 2007 as compared to the year ended December 31, 2006 was primarily due to interest income earned on the proceeds from our IPO and follow-on public offering. In 2007, we invested in auction rate securities that yielded a higher rate of return compared to the money market accounts we held at December 31, 2006. At December 31, 2007, we held approximately $5.6 million in AAA-rated auction rate securities. The majority of these auction rate securities were student loan backed where the loans participate in the Federal Family Education Loan Program and were ultimately re-insured by the US Department of Education.

        The increase in interest expense for the year ended December 31, 2007 compared to the same period in 2006 was primarily due to a higher average outstanding debt balance. In addition, for the year ended December 31, 2007, we capitalized interest related to construction in progress projects totaling approximately $0.7 million. During the same period in 2006, we capitalized interest of $0.1 million.

    Income Taxes

        We had a provision for income taxes of $0.1 million and $0 for the years ended December 31, 2007 and 2006, respectively. The provision in 2007 relates to the non-deductibility of a portion of our goodwill. We provided a full valuation allowance for our deferred tax assets because the realization of any future tax benefits could not be sufficiently assured as of December 31, 2007 or December 31, 2006.

Liquidity and Capital Resources

    Overview

        Since inception, we have generated significant losses. As of December 31, 2008, we had an accumulated deficit of $70.5 million. As of December 31, 2008, our principal sources of liquidity were cash, cash equivalents, and marketable securities totaling $62.8 million, a decrease of $22.9 million from the December 31, 2007 balance of $85.7 million. In addition, we had $16.2 million available under our credit and term loan facility with SVB as of December 31, 2008. We are contingently liable for $14.3 million in connection with unused letters of credit under the SVB line of credit. Included in the December 31, 2008 and 2007 restricted cash balances are amounts used to collateralize unused letters of credit in the amount of $1.4 million and $3.0 million, respectively.

        Our investments in securities included state and municipal bonds at December 31, 2008. They have been classified as available-for-sale and included in short-term investments on our accompanying condensed consolidated balance sheet. Our holdings of marketable securities as of December 31, 2008 and December 31, 2007 were $2.0 million and $15.5 million, respectively.

        We believe our existing cash, cash equivalents and marketable securities at December 31, 2008, our anticipated net cash flows from operating activities and amounts available under our credit and term loan facility with SVB will be sufficient to meet our anticipated cash needs, including investing activities, for at least the next 12 months. Our future working capital requirements will depend on many factors, including, without limitation, the rate at which we sell our demand response solutions to utilities and grid operators and any letters of credit or security deposits required by those utilities and grid operators, the introduction and market acceptance of new demand response and energy management solutions, and the expansion of our sales and marketing and research and development activities. To the extent that our cash, cash equivalents and marketable securities, our anticipated net cash flows from operating activities and amounts available under our credit and term loan facility with SVB are insufficient to fund our future activities, we may be required to raise additional funds through bank credit arrangements or public or private equity or debt financings. We also may need to raise additional funds in the event we determine in the future to effect one or more acquisitions of

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businesses, technologies or products. In the event we require additional cash resources, we may not be able to obtain bank credit arrangements or effect any equity or debt financing on terms acceptable to us or at all.

    Cash Flows

        The following table summarizes our cash flows for the years ended December 31, 2008, 2007 and 2006 (dollars in thousands):

 
  Year Ended December 31,  
 
  2008   2007   2006  

Cash flows used in operating activities

  $ (15,207 ) $ (7,163 ) $ (964 )

Cash flows provided by (used in) investing activities

    6,894     (57,019 )   (10,453 )

Cash flows (used in) provided by financing activities

    (1,070 )   125,240     10,882  

Effect of foreign exchange on cash and cash equivalents

    (77 )        
               

(Decrease) increase in cash and cash equivalents

  $ (9,460 ) $ 61,058   $ (535 )
               

    Cash Flows Used in Operating Activities

        Cash used in operating activities primarily consists of net income (loss) adjusted for certain non-cash items including depreciation and amortization, stock-based compensation expenses, and the effect of changes in working capital and other activities.

        Cash used in operating activities for the year ended December 31, 2008 was $15.2 million and consisted of a $36.7 million net loss, which was offset by approximately $0.7 million of net cash provided by working capital and other activities and by $20.7 million of non-cash items, primarily consisting of depreciation and amortization, interest expense, impairment of fixed assets and stock-based compensation charges. Cash provided by working capital consisted of an increase of $2.0 million in accounts payable and accrued expenses due to our relative size compared to the prior period, an increase in accrued capacity payments of $9.6 million due to our relative size compared to the prior period, an increase in accrued payroll and related expenses of $1.4 million, an increase in other noncurrent liabilities of $0.5 million, and a decrease in prepaid expenses and other current assets of $0.7 million. These amounts were partially offset by cash used for working capital and other activities, which reflected a $0.9 million increase in accounts receivable due to increased revenues, an increase of unbilled revenues relating to the PJM demand response market of $11.6 million, an increase in other noncurrent assets of $0.1 million and a decrease of deferred revenue of $0.9 million.

        Cash used in operating activities for the year ended December 31, 2007 was $7.2 million and consisted of a $23.6 million net loss, which was offset by approximately $3.1 million of net cash provided by working capital and other activities and by $13.3 million of non-cash items, primarily consisting of depreciation and amortization, interest expense and stock-based compensation charges. Cash provided by working capital consisted of an increase of $0.8 million in accounts payable and accrued expenses, an increase in accrued capacity payments of $3.9 million, an increase in accrued payroll and related expenses of $3.6 million, an increase in other noncurrent liabilities of $0.8 million, an increase of deferred revenue of $0.9 million and a decrease in other noncurrent assets of $0.4 million. These amounts were partially offset by cash used for working capital and other activities, which reflected a $5.7 million increase in accounts receivable due to increased revenues and an increase in prepaid and other current assets of $1.6 million.

        Cash used in operating activities for the year ended December 31, 2006 was $1.0 million and consisted of a $5.8 million net loss offset by $3.4 million of non-cash items, primarily consisting of

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depreciation and amortization and stock-based compensation charges, and $1.4 million of net cash provided by working capital and other activities. Cash provided by working capital and other activities primarily reflected a $1.8 million increase in accounts payable and accrued expenses as our operations continued to grow, a $0.4 million increase in accrued payroll and related expenses, a $2.9 million increase in accrued capacity payments, and a $0.6 million increase in deferred revenue as new and untested capacity was added. These amounts were partially offset by a $3.5 million increase in accounts receivable attributable to the significant increase in revenues, a $0.6 million increase in prepaid expenses and other current assets and a $0.3 million increase in other noncurrent assets.

    Cash Flows Provided by (Used in) Investing Activities

        Cash provided by investing activities was $6.9 million for the year ended December 31, 2008. For the years ended December 31, 2007 and 2006, cash used in investing activities was $57.0 million and $10.5 million, respectively. In 2008, our principal cash investments related to installation services used to build out and expand our demand response programs, purchases of property and equipment of $12.5 million, a cash earn-out payment in connection with our acquisition of MDE of $3.4 million, $3.8 million of cash used for our acquisition of SRC and $0.4 million of the deferred acquisition payment made to Pinpoint Power DR, LLC, or PPDR. For the year ended December 31, 2008, purchases of available-for-sale securities were approximately $13.6 million and sales of available-for-sale securities were $27.1 million. Also in 2008, we had a decrease of restricted cash and deposits on our customer programs of $13.4 million primarily as a result of our new financing arrangement with SVB, which allows for the issuance of letters of credit in connection with customer programs.

        In 2007, we made a payment of approximately $3.3 million and $1.9 million, respectively, in connection with our purchases of MDE and PPDR. For the year ended December 31, 2007, purchases of available-for-sale securities were approximately $35.4 million and sales of available-for-sale securities were $19.9 million. In addition, we incurred $19.9 million in capital expenditures for generating equipment, office equipment, leasehold improvements, and furniture and fixtures.

        During 2006, we made payments of $3.0 million, $1.7 million and $27,000, respectively, for the purchase of certain of the assets of Celerity Energy Partners LLC, PPDR and substantially all of the assets of eBidenergy, Inc. In addition, for the year ended December 31, 2006 we incurred $5.0 million in capital expenditures for construction-in-progress, equipment, furniture and fixtures.

    Cash Flows (Used in) Provided by Financing Activities

        Cash flows used in financing activities were $1.1 million for the year ended December 31, 2008. Cash flows provided by financing activities were $125.2 million and $10.9 million for the years ended December 31, 2007 and 2006, respectively. Cash flows (used in) provided by financing activities consisted of the following:

    Equity Financing Activities

        In November 2007, we successfully completed our follow-on public offering of 2,500,000 shares of our common stock at a price of $43.00 per share. Of the 2,500,000 shares, we sold 500,000 shares and selling stockholders sold 2,000,000 shares. This transaction resulted in net proceeds to us of approximately $19.4 million. In May 2007, we completed our IPO of 4,312,500 shares of common stock at a price of $26.00 per share, which included the exercise of the underwriters' over-allotment option to purchase 562,500 shares and the sale of 225,000 shares by certain of our stockholders. Net proceeds to us from our IPO were approximately $95.2 million.

        In February 2007, we repurchased 104,392 shares of our common stock for $0.4 million.

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        Prior to our IPO and follow-on offering, we primarily funded our operations through the issuance of an aggregate of $27.9 million in preferred stock and $7.5 million in borrowings under our then current loan and security agreement with BlueCrest. We used these proceeds to fund our operations, to develop our technology for our demand response programs, to open new markets and for acquisitions.

        In addition, we received approximately $0.5 million, $0.1 million and $0.1, respectively, from exercises of options to purchase shares of our common stock during the years ended December 31, 2008, 2007 and 2006.

    Credit Facility Borrowings

        In November 2006, we entered into a loan and security agreement with Ritchie Capital Finance, L.L.C, which was subsequently assigned to BlueCrest. We borrowed $5.0 million on November 20, 2006 under this agreement and used the proceeds to pay off our then outstanding loan from Lighthouse Capital Partners V, L.P., or Lighthouse, in an amount of $1.5 million with the remainder for working capital purposes. The term loan portion of the BlueCrest facility allowed us to borrow up to an additional $2.5 million on or before March 31, 2007, which we borrowed on March 20, 2007 for working capital purposes.

        In August 2008, we and one of our subsidiaries entered into a $35.0 million secured revolving credit and term loan facility with SVB, under which SVB will, among other things, make revolving credit and term loan advances and issue letters of credit for our account. This credit facility replaced our credit facility with BlueCrest. All unpaid principal and accrued interest is due and payable in full on August 5, 2010, which is the maturity date. Our obligations under this credit facility are secured by all of our assets and the assets of our subsidiaries, excluding any intellectual property. This credit facility contains customary terms and conditions for credit facilities of this type. In addition, we are required to meet certain financial covenants customary with this type of facility, including maintaining a minimum specified tangible net worth and a minimum modified quick ratio. This credit facility contains customary events of default. If a default occurs and is not cured within any applicable cure period or is not waived, our obligations under the credit facility may be accelerated. We were in compliance with all financial covenants under this credit facility at December 31, 2008. As of December 31, 2008, we had borrowings of $4.4 outstanding under the SVB credit and term loan facility in addition to an aggregate of $14.3 million in letters of credit issued for our account. For additional information regarding the credit and term loan facility with SVB, see Note 8 to our consolidated financial statements contained in Appendix A to this Annual Report on Form 10-K.

        During the year ended December 31, 2008, we made scheduled payments on our outstanding debt and capital lease obligations of $1.5 million and refinanced $4.4 million of our debt through borrowings of $4.4 million under our new credit and term loan facility with SVB. During the years ended December 31, 2007 and December 31, 2006, we made scheduled payments on our outstanding debt and capital lease obligations of $1.6 million and $2.0 million, respectively.

    Capital Spending

        We have made capital expenditures primarily for general corporate purposes to support our growth and for equipment installation related to our demand response programs. Our capital expenditures totaled $12.5 million in 2008, $20.0 million in 2007 and $5.0 million in 2006. As we continue to grow, we expect our capital expenditures for 2009 to increase as compared to 2008. In the event that the California Public Utilities Commission approves our proposed Clean Gen contract with SDG&E to provide up to 25 additional MW of capacity in SDG&E's service territory, we estimate that we will make capital expenditures of approximately $4.4 million related to environmental control facilities associated with this contract.

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Contractual Obligations

        Information regarding our significant contractual obligations of the types described below as of December 31, 2008 is set forth in the following table (dollars in thousands):

 
  Payments Due by Period  
Contractual Obligations
  Total   Less than
1 Year
  1-3 Years   3-5 Years   More Than
5 Years
 

Debt obligations

  $ 4,442   $   $ 4,442   $   $  

Capital lease obligations

    143     59     84          

Operating lease obligations

    18,364     3,385     10,819     4,160      
                       
 

Total

  $ 22,949   $ 3,444   $ 15,345   $ 4,160   $  
                       

        As of December 31, 2008, our debt obligations under our credit and term loan facility with SVB consisted of approximately $4.4 million. We are not aware of any events of default under our credit and term loan facility with SVB.

        Our capital lease obligations consist of computer equipment associated with our acquisition of substantially all of the assets of eBidenergy, Inc. from Trillium Capital Partners LLC in February 2006 and a telephone system we lease for which we have a bargain purchase option at the end of the five year term.

        Our operating lease obligations relate primarily to the lease of our corporate headquarters in Boston, Massachusetts and our offices in New York, New York, Rochester, New York, San Francisco, California and Meriden, Connecticut, as well as certain property and equipment.

        As part of our acquisition of SRC, we may be obligated to pay the former holders of SRC membership interests an earnout amount equal to 50% to 60% of the revenues of SRC's business during each twelve-month period from May 1, 2008 through April 30, 2010. The earnout payments will be based on the achievement of certain minimum revenue-based milestones of SRC and will be paid in a combination of cash and shares of our common stock.

Off-Balance Sheet Arrangements

        As of December 31, 2008, we did not have any off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K, that have or are reasonably likely to have a current or future effect on our financial condition, changes in our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. We have issued letters of credit in the ordinary course of our business in order to participate in certain demand response programs. As of December 31, 2008, we had outstanding letters of credit totaling $14.3 million. For information on these commitments and contingent obligations, see Note 14 to our consolidated financial statements contained in Appendix A to this Annual Report on Form 10-K .

Application of Critical Accounting Policies and Use of Estimates

        Our financial statements are prepared in accordance with accounting principles generally accepted in the United States, or GAAP. The preparation of these financial statements requires that we make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances. We evaluate our estimates and assumptions on an ongoing basis. Our actual results may differ significantly from these estimates under different assumptions or conditions. There have been no material changes to these estimates for the periods presented in this Annual Report on Form 10-K.

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        We believe that of our significant accounting policies, which are described in Note 1 to our consolidated financial statements included in this Annual Report on Form 10-K, the following accounting policies involve a greater degree of judgment and complexity. Accordingly, these are the policies we believe are the most critical to aid in fully understanding and evaluating our financial condition and results of operations.

    Revenue Recognition

        We recognize revenues in accordance with SAB No. 104. In all of our arrangements, we do not recognize any revenues until we can determine that persuasive evidence of an arrangement exists, delivery has occurred, the fee is fixed or determinable, and we deem collection to be probable. In making these judgments, we evaluate these criteria as follows:

    Evidence of an arrangement.   We consider a non-cancelable agreement signed by the customer and us or an arrangement enforceable under the rules of an open market bidding program to be representative of persuasive evidence of an arrangement.

    Delivery has occurred.   We consider delivery to have occurred when service has been delivered to the customer and no post-delivery obligations exist. In instances where customer acceptance is required, delivery is deemed to have occurred when customer acceptance has been achieved.

    Fees are fixed or determinable.   We consider the fee to be fixed or determinable unless the fee is subject to refund or adjustment or is not payable within normal payment terms. If the fee is subject to refund or adjustment, we recognize revenues when the right to a refund or adjustment lapses. If offered payment terms exceed our normal terms, we recognize revenues as the amounts become due and payable or upon the receipt of cash.

    Collection is deemed probable.   We conduct a credit review for all transactions at the inception of an arrangement to determine the creditworthiness of the customer. Collection is deemed probable if, based upon our evaluation, we expect that the customer will be able to pay amounts under the arrangement as payments become due. If we determine that collection is not probable, revenues are deferred and recognized upon the receipt of cash.

        We enter into agreements and open market bidding programs to provide demand response solutions. Demand response revenues are earned based on our ability to deliver committed capacity. Energy event revenue is contingent revenue earned based upon the actual amount of energy provided during the energy event.

        In accordance with SAB No. 104, we recognize demand response revenue when we have provided verification to the grid operator or utility of our ability to deliver the committed capacity which entitles us to payments under the contract or open market program. Committed capacity is verified through the results of an actual demand response event or a measurement and verification test. Once the capacity amount has been verified, the revenue is recognized and future revenue becomes fixed or determinable and is recognized monthly until the next demand response event or test. In subsequent verification events, if our verified capacity is below the previously verified amount, the customer will reduce future payments based on the adjusted verified capacity amounts. The payments received from the utility or grid operator customer can be decreased or increased, up to the committed capacity amounts under the contract or open market program, in connection with subsequent verification events. Ongoing demand response revenue recognized between demand response events or tests that are not subject to penalty or customer refund are recognized in revenue. If the revenue is subject to refund, the revenue is deferred until the liability is resolved.

        Revenue from energy events is recognized when earned. Energy event revenue is deemed to be substantive and represents the culmination of a separate earnings process and is recognized when the energy event is initiated by the customer.

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        As described above, utility or grid operator customer contracts or open market programs may include performance guarantees. We do not recognize any revenue prior to the successful completion of the performance requirement.

    Allowance for Doubtful Accounts

        The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our existing accounts receivable. We review our allowance for doubtful accounts on a regular basis, and all past due balances are reviewed individually for collectability. Account balances are charged against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Provisions for allowance for doubtful accounts are recorded in general and administrative expense. If our historical collection experience does not reflect our future ability to collect outstanding accounts receivables, our future provision for doubtful accounts could be materially affected. To date, we have not incurred any significant write-offs of accounts receivable and have not been required to revise any of our assumptions or estimates used in determining our allowance for doubtful accounts. As of December 31, 2008, the allowance for doubtful accounts was $37,000.

    Business Combinations

        When we acquire new businesses, we allocate the purchase price to the acquired assets, including intangible assets, and the liabilities assumed based on their estimated fair values, with any amount in excess of such allocations designated as goodwill. Significant management judgments and assumptions are required in determining the fair value of acquired assets and liabilities, particularly acquired intangible assets. The valuation of purchased intangible assets is based on estimates of the future performance and cash flows from the acquired business. The use of different assumptions could materially impact the purchase price allocation and our financial position and results of operations.

    Impairment of Goodwill and Intangible Assets and Long-Lived Assets

        Long-lived assets, such as property and equipment, goodwill and intangible assets, are reviewed for impairment at least annually or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. All of our identifiable intangible assets are amortized using the straight-line method over their estimated useful lives. We use estimates in determining the value of goodwill and intangible assets, including estimates of useful lives of intangible assets, discounted future cash flows and fair values of the related operations. We test goodwill for impairment at least once each year, under the guidance of SFAS No. 142, Goodwill and Other Intangible Assets . Based on the results of the test, we determined that no impairment had occurred, as the fair value of the reporting unit exceeded the respective carrying value.

        Consistent with SFAS No. 144, Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of , when impairment indicators exist, we evaluate our long-lived assets for potential impairment. For the year ended December 31, 2008, the carrying value of a portion of our demand response equipment and generation equipment exceeded the undiscounted future cash flows based upon their anticipated retirement dates. As a result, we recognized an impairment charge of $701 representing the difference between the demand response equipment and generation equipments' carrying value and fair market value.

    Software Development Costs

        We capitalize eligible costs associated with software developed or obtained for internal use in accordance with American Institute of Certified Public Accountants Statement of Position 98-1, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. We capitalize the payroll and payroll-related costs of employees who devote time to the development of internal-use

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computer software. We amortize these costs on a straight-line basis over the estimated useful life of the software which is generally three years. Our judgment is required in determining the point at which various projects enter the stages at which costs may be capitalized, in assessing the ongoing value and impairment of the capitalized costs, and in determining the estimated useful lives over which the costs are amortized.

    Stock-Based Compensation

        We adopted SFAS No. 123(R) effective January 1, 2006. SFAS No. 123(R) requires nonpublic companies that used the minimum value method in SFAS No. 123 for either recognition or pro forma disclosures to apply SFAS No. 123(R) using the prospective-transition method. As such, we continue to apply Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, to equity awards outstanding on the date we adopted SFAS No. 123(R) that were measured using the minimum value method. In accordance with SFAS No. 123(R), we recognize the compensation cost of stock-based awards on a straight-line basis over the vesting period of the award. Effective with our adoption of SFAS No. 123(R), we elected to use the Black-Scholes option pricing model to determine the weighted-average fair value of stock options granted on and after the date of adoption.

        As there was no public market for our common stock prior to the effective date of our IPO, we determined the volatility for options granted in 2008, 2007 and 2006 based on an analysis of reported data for a peer group of companies that issued options with substantially similar terms. The expected volatility of options granted has been determined using an average of the historical volatility measures of this peer group of companies, as well as the historical volatility of our common stock beginning January 1, 2008. The expected volatility for options granted during 2008, 2007 and 2006 was 87%. The expected life of options has been determined utilizing the "simplified" method as prescribed by SAB No. 107, Share-Based Payment. The expected life of options granted during the year ended December 31, 2008 was 4.25-6.25 years. The risk-free interest rate is based on a treasury instrument whose term is consistent with the expected life of the stock options. For 2008, the weighted-average risk free interest rate used was 2.9%. We have not paid and do not anticipate paying cash dividends on our shares of common stock; therefore, the expected dividend yield is assumed to be zero. In addition, SFAS No. 123(R) requires companies to utilize an estimated forfeiture rate when calculating the expense for the period, whereas SFAS No. 123 permitted companies to record forfeitures based on actual forfeitures, which was our historical policy under SFAS No. 123. As a result, we applied an estimated forfeiture rate of 10.0% for the years ended December 31, 2008, 2007 and 2006 in determining the expense recorded in the accompanying consolidated statements of operations.

        For the years ended December 31, 2008 and 2007, we recorded expenses of approximately $10.4 million and $7.6 million, respectively, in connection with share-based payment awards to employees and non-employees. With respect to grants through December 31, 2008, a future expense of non-vested options of approximately $21.4 million is expected to be recognized over a weighted average period of 2.6 years and a future expense of restricted stock awards of approximately $3.1 million is expected to be recognized over a weighted average period of 2.9 years.

        For awards with graded vesting, we allocate compensation costs under SFAS No. 123(R) on a straight-line basis over the requisite service period. Accordingly, we amortized the fair value of each option over each option's service period, which is generally the vesting period.

        We account for stock options issued to non-employees in accordance with the provisions of SFAS No. 123 and EITF No. 96-18, Accounting for Equity Instruments that are Issued to Other than Employees, or in Conjunction with Selling Goods or Services, which requires valuing and remeasuring such stock options to the current fair value until the performance date has been reached.

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    Accounting for Income Taxes

        We have incurred net losses since our inception. We account for income taxes in accordance with SFAS No. 109, Accounting for Income Taxes, or SFAS No. 109, which requires companies to recognize deferred income tax assets and liabilities for temporary differences between the financial reporting and tax bases of recorded assets and liabilities and the expected benefits of net operating loss and credit carryforwards. SFAS No. 109 requires that deferred income tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred income tax assets will not be realized. We evaluate the realizability of our deferred income tax assets, primarily resulting from net operating loss and credit carryforwards, and adjust our valuation allowance, if necessary.

        Once we utilize our net operating loss carryforwards, we would expect our provision for income tax expense in future periods to reflect an effective tax rate that will be significantly higher than past periods. The adoption of SFAS No. 123(R) will potentially result in tax benefits that are currently difficult to predict.

        In July 2006, the Financial Accounting Standards Board, or FASB, issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109 , or FIN 48, which clarifies the accounting for uncertainty in tax positions. This interpretation requires that we recognize in our financial statements the impact of a tax position if that position is more likely than not of being sustained upon examination, based on the technical merits of the position. We adopted FIN 48 on January 1, 2007. The adoption did not have a material impact on our consolidated financial statements.

New Accounting Pronouncements

        In April 2008, the FASB issued FASB Staff Position, or FSP, No. 142-3, or FSP 142-3, Determination of the Useful Life of Intangible Assets. FSP 142-3 amends the factors that an entity should consider in developing renewal or extension assumptions used in determining the useful life of recognized intangible assets under FASB Statement No. 142, Goodwill and Other Intangible Assets. This new guidance applies prospectively to intangible assets that are acquired individually or with a group of other assets in business combinations and asset acquisitions. FSP 142-3 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. Early adoption is prohibited. Since this guidance will be applied prospectively, on adoption, there will be no impact on our current consolidated financial statements.

        On December 4, 2007, the FASB issued SFAS 141(R), Business Combinations , or SFAS 141R. SFAS 141R replaces SFAS 141, Business Combinations , and applies to all transactions or other events in which an entity obtains control of one or more businesses. SFAS 141R requires the acquiring entity in a business combination to recognize all (and only) the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose additional information needed to evaluate and understand the nature and financial effect of the business combination. SFAS 141R is effective prospectively for fiscal years beginning after December 15, 2008 and may not be applied before that date. The adoption of SFAS No, 141R may have a significant impact on our accounting for future acquisitions.

Selected Quarterly Financial Data (Unaudited)

        The table below sets forth selected unaudited quarterly financial information. The information is derived from our unaudited consolidated financial statements and includes, in the opinion of management, all normal and recurring adjustments that management considers necessary for a fair

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statement of results for such periods. The operating results for any quarter are not necessarily indicative of results for any future period.

Year ended December 31, 2008
  1st Qtr   2nd Qtr   3rd Qtr   4th Qtr  
 
  In thousands, except per share data
 

Revenues

  $ 18,612   $ 23,686   $ 44,152   $ 19,665  

Gross profit

    6,471     8,871     18,360     7,594  

Operating expenses

    18,168     19,492     21,133     19,701  

Loss from operations

    (11,697 )   (10,621 )   (2,773 )   (12,107 )

Net loss

    (11,000 )   (10,436 )   (3,060 )   (12,166 )
 

Basic and diluted net loss per share:

  $ (0.57 ) $ (0.54 ) $ (0.16 ) $ (0.61 )

 

Year ended December 31, 2007
  1st Qtr(1)   2nd Qtr(1)   3rd Qtr   4th Qtr  
 
  In thousands, except per share data
 

Revenues

  $ 9,971   $ 12,015   $ 19,139   $ 19,713  

Gross profit

    2,906     4,105     7,881     6,997  

Operating expenses

    6,874     12,777     12,046     16,462  

Loss from operations

    (3,968 )   (8,672 )   (4,165 )   (9,465 )

Net loss

    (3,814 )   (8,206 )   (2,525 )   (9,037 )
 

Basic and diluted net loss per share:

  $ (0.91 ) $ (0.74 ) $ (0.14 ) $ (0.48 )

(1)
On May 1, 2007, we effected a 2.831 for one split of our common stock. All amounts reflect the impact of that split.

Item 7A.    Quantitative and Qualitative Disclosure About Market Risk

    Foreign Exchange Risk

        We face minimal exposure to adverse movements in foreign currency exchange rates.

    Interest Rate Risk

        As of December 31, 2008, we had $4.4 million of outstanding debt under our credit and term loan facility with SVB that is subject to floating interest rates. Based on our outstanding floating rate debt of $4.4 million as of December 31, 2008, an increase of 1.0% in SVB's prime rate would result in an increase in our interest expense of approximately $44,000.

        The recent market events have not required us to materially modify or change our financial risk management strategies with respect to our exposure to interest rate risk.

        We manage our cash and cash equivalents and marketable securities portfolio considering investment opportunities and risks, tax consequences and overall financing strategies. Our investment portfolio consists primarily of cash and cash equivalents, money market funds, and commercial paper. We have, in the past, held municipal auction rate securities that have since been redeemed. As our investments are made with highly rated securities, we are not anticipating any significant impact in the short term from a change in interest rates.

Item 8.    Financial Statements and Supplementary Data

        All financial statements and schedules required to be filed hereunder are included as Appendix A hereto and incorporated into this Annual Report on Form 10-K by reference.

Item 9.    Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

        Not applicable.

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Item 9A.    Controls and Procedures

    Disclosure Controls and Procedures.

        Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of EnerNOC's disclosure controls and procedures as of December 31, 2008. The term "disclosure controls and procedures," as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company's management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their desired control objectives. Based on the evaluation of our disclosure controls and procedures as of December 31, 2008, our Chief Executive Officer and Chief Financial Officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.

    Management's Annual Report on Internal Control Over Financial Reporting

        Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act as a process designed by, or under the supervision of, our principal executive and principal financial officers and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, and includes those policies and procedures that:

    pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets;

    provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and directors: and

    provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

        Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2008. In making this assessment, management used the criteria set forth by the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria).

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        Based on this assessment, management believes that, as of December 31, 2008, our internal control over financial reporting was effective at a reasonable assurance level based on these criteria.

        Ernst & Young LLP, the independent registered public accounting firm that audited our consolidated financial statements included elsewhere in this Annual Report on Form 10-K, has issued an attestation report on our internal control over financial reporting. That report appears in this Item 9A under the heading "Report of Independent Registered Public Accounting Firm."

    Changes in Internal Control Over Financial Reporting

        No change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the fiscal quarter ended December 31, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of

EnerNOC, Inc.

        We have audited EnerNOC, Inc.'s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). EnerNOC, Inc.'s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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        In our opinion, EnerNOC, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of EnerNOC, Inc. as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2008 of EnerNOC, Inc. and our report dated March 13, 2009 expressed an unqualified opinion thereon.

Boston, Massachusetts   /s/ Ernst & Young LLP
March 13, 2009    

Item 9B.    Other Information

        Not applicable.


PART III

Item 10.    Directors, Executive Officers and Corporate Governance

        The complete response to this Item regarding the backgrounds of our executive officers and directors and other information contemplated by Items 401, 405 and 407 of Regulation S-K will be contained in our definitive proxy statement for our 2009 Annual Meeting of Stockholders under the captions "Directors and Executive Officers," "Corporate Governance and Board Matters" and "Section 16(a) Beneficial Ownership Reporting Compliance" and is incorporated by reference herein.

        We have adopted a written code of business conduct and ethics that applies to our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions and have posted it in the "Corporate Governance" section of the "Investors" section of our website which is located at www.enernoc.com. We intend to satisfy any disclosure requirement under Item 5.05 of Form 8-K regarding any amendments to, or waivers from, our code of business conduct and ethics by posting such information on our website which is located at www.enernoc.com.

Item 11.    Executive Compensation

        The information required by this Item will be contained in our definitive proxy statement for our 2009 Annual Meeting of Stockholders under the captions "Compensation Discussion and Analysis," "Corporate Governance and Board Matters" and "Compensation Committee Report" and is incorporated by reference herein.

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

        The information required by this Item will be contained in our definitive proxy statement for our 2009 Annual Meeting of Stockholders under the captions "Compensation Discussion and Analysis," "Equity Compensation Plan Information" and "Security Ownership of Certain Beneficial Owners and Management" and is incorporated by reference herein.

Item 13.    Certain Relationships and Related Transactions, and Director Independence

        The information required by this Item will be contained in our definitive proxy statement for our 2009 Annual Meeting of Stockholders under the captions "Certain Relationships and Related

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Transactions" and "Corporate Governance and Board Matters" and is incorporated by reference herein.

Item 14.    Principal Accounting Fees and Services

        The information required by this Item will be contained in our definitive proxy statement for our 2009 Annual Meeting of Stockholders under the caption "Proposal Two—Ratification of Appointment of Independent Registered Public Accounting Firm" and is incorporated by reference herein.


PART IV

Item 15.    Exhibits, Financial Statement Schedules

(a)    The following are filed as part of this Annual Report on Form 10-K:

1.     Financial Statements

        The following consolidated financial statements beginning on page F-1 are included in this Annual Report on Form 10-K:

    Report of Independent Registered Public Accounting Firm

    Consolidated Balance Sheets as of December 31, 2008 and 2007

    Consolidated Statements of Operations for the years ended December 31, 2008, 2007 and 2006

    Consolidated Statements of Changes in Stockholders' Equity (Deficit) and Comprehensive Loss for the years ended December 31, 2008, 2007 and 2006

    Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006

    Notes to the Consolidated Financial Statements

(b)   Exhibits

        The exhibits listed in the Exhibit Index immediately preceding the exhibits are filed with or incorporated by reference in this Annual Report on Form 10-K.

(c)   Financial Statement Schedules

        All other schedules have been omitted since the required information is not present, or not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or the Notes thereto.

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SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

    ENERNOC, INC.

Date: March 16, 2009

 

By:

 

/s/ TIMOTHY G. HEALY

        Name:   Timothy G. Healy
        Title:   Chairman of the Board and
Chief Executive Officer

        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature
 
Title
 
Date

 

 

 

 

 
/s/ TIMOTHY G. HEALY

Timothy G. Healy
  Chairman of the Board, Chief Executive Officer and Director
(principal executive officer)
  March 16, 2009

/s/ NEAL C. ISAACSON

Neal C. Isaacson

 

Chief Financial Officer
(principal financial officer and principal accounting officer)

 

March 16, 2009

/s/ DAVID B. BREWSTER

David B. Brewster

 

Director and President

 

March 16, 2009

/s/ TJ GLAUTHIER

TJ Glauthier

 

Director

 

March 16, 2009

/s/ ADAM GROSSER

Adam Grosser

 

Director

 

March 16, 2009

/s/ RICHARD DIETER

Richard Dieter

 

Director

 

March 16, 2009

/s/ ARTHUR W. COVIELLO, JR.

Arthur W. Coviello, Jr.

 

Director

 

March 16, 2009

/s/ JAMES L. TURNER

James L. Turner

 

Director

 

March 16, 2009

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APPENDIX A

EnerNOC, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 
  Page
Annual Consolidated Financial Statements of EnerNOC, Inc.:    

Report of Independent Registered Public Accounting Firm

 

F-2

Consolidated Balance Sheets as of December 31, 2008 and 2007

 

F-3

Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006

 

F-4

Consolidated Statements of Changes in Stockholders' Equity (Deficit) and Comprehensive Loss for the Years Ended December 31, 2008, 2007 and 2006

 

F-5

Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006

 

F-6

Notes to Consolidated Financial Statements

 

F-7

F-1


Table of Contents


Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of EnerNOC, Inc.

        We have audited the accompanying consolidated balance sheets of EnerNOC, Inc. as of December 31, 2008 and 2007, and the related consolidated statements of operations, changes in stockholders' equity (deficit) and comprehensive loss, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of EnerNOC, Inc. at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), EnerNOC, Inc.'s internal control over financial reporting as of December 31, 2008, based on criteria established in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 13, 2009 expressed an unqualified opinion thereon.

    /s/ Ernst & Young LLP

Boston, Massachusetts
March 13, 2009

F-2


Table of Contents


EnerNOC, INC.

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)

 
  December 31,
2008
  December 31,
2007
 

Assets

             

Current assets

             
 

Cash and cash equivalents

  $ 60,782   $ 70,242  
 

Restricted cash

    1,419     1,248  
 

Marketable securities

    2,000     15,500  
 

Accounts receivable, net allowance for doubtful accounts of $37 at December 31, 2008 and $368 at December 31, 2007

    11,150     10,134  
 

Unbilled revenue

    11,585      
 

Prepaid expenses and other current assets

    3,250     4,270  
           
   

Total current assets

    90,186     101,394  

Property and equipment, net

    26,975     23,195  

Goodwill and other intangible assets, net

    18,535     16,421  

Restricted cash

        1,770  

Deposits

    933     12,496  

Other assets

    65     308  
           
   

Total assets

  $ 136,694   $ 155,584  
           

Liabilities and Stockholders' Equity

             

Current liabilities

             
 

Accounts payable

  $ 1,171   $ 2,112  
 

Accrued capacity payments

    18,643     9,069  
 

Current portion of deferred related-party acquisition payments

        431  
 

Accrued payroll and related expenses

    6,309     4,902  
 

Accrued Mdenergy earn-out

        3,357  
 

Accrued expenses and other current liabilities

    3,822     1,586  
 

Deferred revenue

    1,057     2,403  
 

Contingent consideration provision

        2,247  
 

Current portion of long-term debt

    47     2,451  
           
   

Total current liabilities

    31,049     28,558  

Long-term liabilities

             
 

Long-term debt, net of current portion

    4,516     3,640  
 

Deferred tax liability

    362     100  
 

Other liabilities

    1,547     869  
           
   

Total long-term liabilities

    6,425     4,609  

Commitments and contingencies (Notes 14 and 15)

         

Stockholders' equity

             
 

Undesignated preferred stock, $0.001 par value; 5,000,000 shares authorized; 0 shares issued and outstanding at December 31, 2008 and 2007, respectively

             
 

Common stock, $0.001 par value; 50,000,000 shares authorized; 20,254,548 and 19,180,504 shares issued and outstanding at December 31, 2008 and 2007, respectively

    20     19  

Additional paid-in capital

    169,800     156,250  

Accumulated other comprehensive loss

    (86 )    

Accumulated deficit

    (70,514 )   (33,852 )
           
   

Total stockholders' equity

    99,220     122,417  
           
   

Total liabilities and stockholders' equity

  $ 136,694   $ 155,584  
           

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

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EnerNOC, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share and per share data)

 
  Year Ended December 31,  
 
  2008   2007   2006  

Revenues

  $ 106,115   $ 60,838   $ 26,100  

Cost of revenues

    64,819     38,949     16,839  
               

Gross profit

    41,296     21,889     9,261  
               

Operating expenses:

                   
 

Selling and marketing expenses

    27,641     17,145     5,932  
 

General and administrative expenses

    46,037     27,917     8,000  
 

Research and development expenses

    4,816     3,097     955  
               
   

Total operating expenses

    78,494     48,159     14,887  
               

Loss from operations

    (37,198 )   (26,270 )   (5,626 )
 

Interest and other income

    1,949     3,161     167  
 

Interest expense

    (1,151 )   (373 )   (312 )
               
 

Loss before income tax expense

    (36,400 )   (23,482 )   (5,771 )
 

Provision for income tax expense

    (262 )   (100 )    
               
   

Net loss

  $ (36,662 ) $ (23,582 ) $ (5,771 )
               

Net loss per share

                   
 

Basic and diluted

  $ (1.88 ) $ (1.80 )   (1.60 )
               
 

Weighted average number of basic and diluted shares

    19,505,065     13,106,114     3,607,822  
               

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

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EnerNOC, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDERS' EQUITY (DEFICIT) AND COMPREHENSIVE LOSS

(in thousands, except share data)

 
  Common Stock    
   
   
   
   
 
 
   
   
  Accumulated
Other
Comprehensive
Income (Loss)
   
   
 
 
  Number
of Shares
  Amount   Additional
Paid in
Capital
  Accumulated
Deficit
  Total   Comprehensive
Income (Loss)
 

Balances as of December 31, 2005

    3,199,856   $ 3   $ 122   $ (4,245 )     $ (4,120 ) $  

Issuance of common stock upon exercise of stock options

    560,603     1     165             166      

Issuance of restricted stock

    152,461                          

Issuance of common stock in connection with the acquisition of Pinpoint Power DR LLC

    260,568         92             92      

Issuance of common stock in connection with the acquisition of eBidenergy, Inc. 

    71,836         25             25      

Stock-based compensation expense

            367             367      

Accretion of issuance costs

                (43 )       (43 )    

Net loss

                (5,771 )       (5,771 )   (5,771 )
                               

Balances as of December 31, 2006

    4,245,324     4     771     (10,059 )       (9,284 )   (5,771 )
                               

Issuance of common stock upon exercise of stock options

    437,321         150             150      

Issuance of restricted stock

    45,500                          

Exercise of warrant

    160,287         606             606      

Conversion of Preferred Stock

    9,499,565     10     28,080             28,090      

Vesting of restricted stock

            24             24      

Accretion of issuance costs

                (211 )       (211 )    

Purchase and subsequent reissuance of treasury stock

            (395 )           (395 )    

Issuance of common stock in connection with the initial public offering

    4,087,500     4     95,155             95,159      

Issuance of common stock in connection with the secondary offering

    500,000     1     19,445             19,446      

Issuance of common stock in connection with the acquisition of Pinpoint Power DR LLC

    65,951         66             66      

Issuance of common stock in connection with the acquisition of MDEnergy LLC

    139,056         4,751             4,751      

Stock-based compensation expense

            7,597             7,597      

Net loss

                (23,582 )       (23,582 )   (23,582 )
                               

Balances as of December 31, 2007

    19,180,504     19     156,250     (33,852 )       122,417     (23,582 )
                               

Issuance of common stock upon exercise of stock options

    706,823     1     456             457      

Issuance of restricted stock

    177,500                          

Vesting of restricted stock

            20             20      

Cancellation of restricted stock

    (1,500 )                        

Issuance of common stock in satisfaction of bonuses

    26,961         845             845      

Issuance of common stock in connection with the acquisition of Pinpoint Power DR LLC

    44,260         44             44      

Issuance of common stock in connection with the acquisition of South River Consulting LLC

    120,000         1,746             1,746      

Stock-based compensation expense

            10,439             10,439      

Unrealized gain on marketable securities

                    5     5     5  

Foreign currency translation loss

                    (91 )   (91 )   (91 )

Net loss

                (36,662 )       (36,662 )   (36,662 )
                               

Balances as of December 31, 2008

    20,254,548   $ 20   $ 169,800   $ (70,514 ) $ (86 ) $ 99,220   $ (36,748 )
                               

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

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EnerNOC, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

 
  Year ended December 31,  
 
  2008   2007   2006  

Cash flows from operating activities

                   

Net loss

  $ (36,662 ) $ (23,582 ) $ (5,771 )

Adjustments to reconcile net loss to net cash used in operating activities:

                   

Depreciation

    8,035     3,218     815  

Amortization of intangible assets

    1,019     2,287     2,230  

Impairment of property and equipment

    701          

Stock-based compensation expense

    10,439     7,597     367  

Non-cash interest expense

    520     175     16  

Increase (decrease) in cash from changes in operating assets and liabilities, net of acquisitions:

                   

Accounts receivable

    (887 )   (5,686 )   (3,477 )

Unbilled revenue

    (11,585 )        

Deferred revenue

    (884 )   898     619  

Prepaid expenses and other current assets

    657     (1,577 )   (562 )

Other noncurrent assets

    (103 )   387     (280 )

Deferred tax liability

    262     100      

Other noncurrent liabilities

    247     742     (72 )

Accrued capacity payments

    9,579     3,859     2,944  

Accrued payroll and related expenses

    1,408     3,627     432  

Accounts payable and accrued expenses

    2,047     792     1,775  
               

Net cash used in operating activities

    (15,207 )   (7,163 )   (964 )

Cash flows from investing activities

                   

Purchase of marketable securities

    (13,637 )   (35,449 )    

Sales and maturities of marketable securities

    27,142     19,949      

Payments made for acquisitions of businesses, net of cash acquired

    (7,523 )   (5,215 )   (4,792 )

Purchases of property and equipment

    (12,459 )   (19,866 )   (4,993 )

Increase (decrease) in restricted cash and deposits for customer programs

    13,371     (16,438 )   (668 )
               

Net cash provided by (used in) investing activities

    6,894     (57,019 )   (10,453 )

Cash flows from financing activities

                   

Proceeds from the issuance of restricted stock

            78  

Proceeds from public offerings of common stock, net of issuance costs

        114,605      

Proceeds from exercises of stock options

    457     152     166  

Proceeds from borrowing

    4,352     2,500     5,000  

Repayment of borrowings

    (5,879 )   (1,610 )   (1,990 )

Proceeds from the issuance of redeemable preferred stock, net of issuance costs

        9,988     7,628  

Repurchase and reissuance of treasury stock

        (395 )    
               

Net cash (used in) provided by financing activities

    (1,070 )   125,240     10,882  

Effects of exchange rate changes on cash

    (77 )        
               

Net change in cash and cash equivalents

    (9,460 )   61,058     (535 )

Cash and cash equivalents at beginning of year

    70,242     9,184     9,719  
               

Cash and cash equivalents at end of year

 
$

60,782
 
$

70,242
 
$

9,184
 
               

Supplemental disclosure of cash flow information

                   

Cash paid for interest

  $ 524   $ 789   $ 482  
               

Non-cash financing and investing activities

                   

Preferred stock subscription receivable

  $   $   $ 800  
               

Conversion and net exercise into common stock of preferred stock warrant

  $   $ 606   $  
               

Purchase of equipment through a capital lease obligation

  $   $   $ 200  
               

Deferred related party stock issuance for Pinpoint Power DR LLC

  $ 44   $ 66   $  
               

Issuance of common stock in connection with acquisitions

  $ 1,746   $ 4,571   $ 117  
               

Issuance of common stock in satisfaction of bonuses

  $ 845   $   $  
               

Issuance of common stock to related party

  $   $ 395   $  
               

Accretion of preferred stock issuance costs

  $   $ 211   $ 43  
               

Issuance of warrants

  $   $   $ 606  
               

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

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EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands, except share and per share data)

1. Description of Business, Basis of Presentation and Summary of Significant Accounting Policies

Description of Business

        EnerNOC, Inc. (the Company) is a service company that was incorporated in Delaware on June 5, 2003. The Company operates in a single segment providing full-service demand response and energy management solutions. The Company enables energy users, energy suppliers, system operators, and utilities to reduce demand for electricity during periods of peak demand or supply shortfalls by proactively shedding noncritical loads, dispatching backup generators, and analyzing real-time data to optimize energy consumption. The Company also delivers a portfolio of additional energy management solutions to its customers, including its monitoring-based commissioning services, energy procurement services, and emissions tracking and trading support. The Company's demand response and energy management solutions deliver immediate bottom-line benefits to end-use customers and energy suppliers while helping to create a more reliable and efficient electricity grid for system operators and utilities.

Basis of Consolidation

        The consolidated financial statements of the Company include the accounts of its wholly-owned subsidiaries in the United States and in Canada and have been prepared in conformity with accounting principles generally accepted in the United States (GAAP). Intercompany transactions and balances are eliminated upon consolidation.

        On May 5, 2008, the Company acquired 100% of the membership interests of South River Consulting, LLC (SRC) in a business purchase combination. Accordingly, the results of SRC subsequent to May 2008 are included in the Company's consolidated statements of operations.

        On September 13, 2007, the Company purchased all of the outstanding membership interests of Mdenergy LLC (MDE) in a business purchase combination. Accordingly, the results of MDE subsequent to September 13, 2007 are included in the Company's consolidated statements of operations.

Use of Estimates in Preparation of Financial Statements

        The preparation of financial statements in conformity with GAAP requires the Company's management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

        Significant estimates and judgments relied upon by management in preparing these financial statements include revenue recognition, allowances for doubtful accounts, capitalization of software development costs, stock-based compensation expense, business combinations, impairment of long-lived assets and income taxes.

        Although the Company regularly assesses these estimates, actual results could differ materially from these estimates. Changes in estimates are recorded in the period in which they become known. The Company bases its estimates on historical experience and various other assumptions that it believes to be reasonable under the circumstances. Actual results may differ from management's estimates if these results differ from historical experience or other assumptions prove not to be substantially accurate, even if such assumptions are reasonable when made.

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EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

1. Description of Business, Basis of Presentation and Summary of Significant Accounting Policies (Continued)

        The Company is subject to a number of risks similar to those of other companies of similar size in its industry, including, but not limited to, rapid technological changes, competition from substitute products and services from larger companies, customer concentration, government regulations, protection of proprietary rights and dependence on key individuals.

Significant Accounting Policies

Cash and Cash Equivalents

        The Company considers all highly liquid investment instruments with an original maturity when purchased of three months or less to be cash equivalents. Investments qualifying as cash equivalents consist of investments in money market funds, marketable securities and certificates of deposits which totaled $44,504 and $49,653 at December 31, 2008 and 2007, respectively.

Marketable Securities

        Marketable securities at December 31, 2008 and 2007 are classified as "available-for-sale." The Company's investments in securities include agency and municipal bonds. Available-for-sale securities are carried at fair value, with the unrealized gains and losses reported in a separate component of accumulated other comprehensive income (loss) in stockholders' equity (deficit). The cost of debt securities that are deemed available-for-sale securities is adjusted for amortization of premiums and accretion of discounts to maturity. Such amortization and accretion are included in interest and other income. Realized gains and losses and declines in value judged to be other-than-temporary on available-for-sale securities and other investments are included in investment income. For the year ended December 31, 2008, there was $5 of unrealized gains on the Company's marketable securities. The cost of securities sold is based on the specific identification method. Interest and dividends on securities classified as available-for-sale are included in interest and other income.

        The Company periodically evaluates these investments for impairment in accordance with EITF No. 03-01, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments (EITF No. 03-01). When a decline in fair value is deemed to be other-than-temporary, the Company records an impairment adjustment in the statement of operations. There were no other than temporary impairments of marketable securities at December 31, 2008 and 2007 (See Note 4).

Concentrations of Credit Risk

        Financial instruments that potentially subject the Company to significant concentrations of credit risk principally consist of cash and cash equivalents, marketable securities and accounts receivable. The Company maintains its cash and cash equivalent balances with high-quality financial institutions and, consequently, such funds are subject to minimal credit risk. Accounts receivable are primarily from customers in the northeastern and PJM Interconnection (PJM) regions of the United States. The Company estimates the allowance for doubtful accounts for trade receivables based on historical losses, existing economic conditions, and other information available at the balance sheet date.

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EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

1. Description of Business, Basis of Presentation and Summary of Significant Accounting Policies (Continued)

        For the years ended December 31, 2008, 2007 and 2006, the Company had three major customers, which accounted for 79%, 81%, and 84%, respectively, of total revenues.

 
  Year Ended December 31  
 
  2008   2007   2006  
 
  Revenues   % of Total
Revenues
  Revenues   % of Total
Revenues
  Revenues   % of Total
Revenues
 

Customer 1

  $ 38,638     36 % $ 36,617     60 % $ 16,945     65 %

Customer 2

    30,012     28 %   *     *     *     *  

Customer 3

    16,118     15 %   12,666     21 %   4,973     19 %
                           

Totals

  $ 84,768     79 % $ 49,283     81 % $ 21,918     84 %
                           

*
Less than 10% of total revenues

        Accounts receivable from these customers was approximately $9,121 and $8,696 at December 31, 2008 and 2007, respectively. Unbilled revenues from these customers were $11,585 and $0 for the years ended December 31, 2008 and 2007, respectively.

        Deposits and restricted cash consist of funds to secure performance under certain customer contracts and open market bidding programs. Deposits held by customers were $2,648 and $14,451 at December 31, 2008 and 2007, respectively. Restricted cash to secure letters of credit were $1,419 and $3,018 at December 31, 2008 and 2007, respectively.

Property and Equipment

        Property and equipment is stated at cost and depreciated using the straight-line method over the estimated useful lives of the respective assets, ranging from three to ten years. Leasehold improvements are amortized over their useful life or the life of the lease, whichever is shorter. The amortization of capital lease amounts are included in depreciation expense. Expenditures that improve or extend the life of a respective asset are capitalized while repairs and maintenance expenditures are expensed as incurred.

        The Company capitalizes interest on projects that qualify for interest capitalization under Statement of Financial Accounting Standards (SFAS) No. 34, Capitalization of Interest Costs, as amended (FAS 34). Capitalized interest is included within construction in progress and is depreciated over the useful life of the assets once the project is complete. For the years ended December 31, 2007 and 2006, the Company capitalized $722 and $127 of interest, respectively. No interest was capitalized for the year ended December 31, 2008.

Software Development Costs

        The Company capitalizes eligible costs associated with software developed or obtained for internal use in accordance with American Institute of Certified Public Accountants Statement of Position 98-1 (SOP 98-1), Accounting for the Cost of Computer Software Developed or Obtained for Internal Use. The Company capitalizes the payroll and payroll-related costs of employees who devote time to the

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EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

1. Description of Business, Basis of Presentation and Summary of Significant Accounting Policies (Continued)


development of internal-use computer software. The Company amortizes these costs on a straight-line basis over the estimated useful life of the software which is generally three years. The Company's judgment is required in determining the point at which various projects enter the stages at which costs may be capitalized, in assessing the ongoing value and impairment of the capitalized costs, and in determining the estimated useful lives over which the costs are amortized.

        Software development costs of $1,321, $677 and $786 for the years ended December 31, 2008, 2007 and 2006, respectively, have been capitalized in accordance with SOP 98-1 . The capitalized amount is included as software in property and equipment at December 31, 2008 and 2007. Amortization of capitalized software development costs was $1,424, $437 and $15 for the years ended December 31, 2008, 2007 and 2006, respectively.

Impairment of Long-Lived Assets

        Consistent with SFAS No. 144, Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of , when impairment indicators exist, the Company evaluates its long-lived assets for potential impairment. Potential impairment is assessed when there is evidence that events or changes in circumstances have occurred that indicate that the carrying amount of an asset may not be recovered. The Company noted no indicators of impairment.

        The Company reviews property and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of assets may not be recoverable. Recoverability of these assets is measured by comparison of their carrying amount to the future undiscounted cash flows the assets are expected to generate over their remaining economic lives. If such assets are considered to be impaired, the impairment is recognized in earnings and equals the amount by which the carrying value of the assets exceeds their fair market value determined by either a quoted market price, if any, or a value determined by utilizing a discounted cash flow technique. If such assets are not impaired, but their useful lives have decreased, the remaining net book value is amortized over the revised useful life. For the year ended December 31, 2008, the carrying value of a portion of the Company's demand response equipment and generation equipment exceeded the undiscounted future cash flows based upon its anticipated retirement dates. As a result, the Company recognized an impairment charge of $701 representing the difference between the demand response equipments' and generation equipments' carrying value and fair market value.

Goodwill and Other Intangible Assets

        The Company accounts for goodwill and other intangible assets under SFAS No. 141, Business Combinations , and SFAS No. 142, Goodwill and Other Intangible Assets . Under SFAS No. 142, purchased goodwill and intangible assets with indefinite lives are not amortized, but instead tested for impairment at least annually or whenever events or changes in circumstances indicate the carrying value may not be recoverable. Intangible assets with finite lives continue to be amortized over their useful lives. The Company performed its annual impairment test as of November 30, 2008. Based on the results of the Company's most recent review, there is no indicated impairment as of December 31, 2008.

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EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

1. Description of Business, Basis of Presentation and Summary of Significant Accounting Policies (Continued)

Income Taxes

        The Company provides for income taxes as set forth in SFAS No. 109, Accounting for Income Taxes . Under SFAS No. 109, the liability method is used in accounting for income taxes. Deferred tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates in effect when the differences are expected to reverse. Deferred tax assets are reduced by a valuation allowance to reflect the uncertainty associated with their ultimate realization.

        The Company adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109 on January 1, 2007 (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with SFAS No. 109 and prescribes a recognition threshold and measurement process for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. At the adoption date and as of December 31, 2008 and 2007, the Company had no material unrecognized tax benefits and no adjustments to liabilities, retained earnings or operations were required.

Industry Segment Information

        SFAS No. 131, Disclosures About Segments of an Enterprise and Related Information , establishes standards for reporting information about operating segments in annual financial statements and requires selected information of these segments be presented in interim financial reports issued to stockholders. Operating segments are defined as components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, in making decisions on how to allocate resources and assess performance. The Company's chief decision maker, as defined under SFAS No. 131, is considered to be the team comprised of the chief executive officer and the executive management team. The Company views its operations and manages its business as one operating segment.

        For the years ended December 31, 2008, 2007 and 2006, operations related to the Company's international subsidiaries were not material to the accompanying consolidated financial statements taken as a whole.

Revenue Recognition

        The Company recognizes revenues in accordance with Staff Accounting Bulletin (SAB) No. 104, Revenue Recognition (SAB No. 104). In all of the Company's arrangements, it does not recognize any revenues until it can determine that persuasive evidence of an arrangement exists, delivery has

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EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

1. Description of Business, Basis of Presentation and Summary of Significant Accounting Policies (Continued)


occurred, the fee is fixed or determinable, and it deems collection to be probable. In making these judgments, the Company evaluates these criteria as follows:

    Evidence of an arrangement.   The Company considers a non-cancelable agreement signed by the customer and the Company or an arrangement enforceable under the rules of an open market bidding program to be representative of persuasive evidence of an arrangement.

    Delivery has occurred.   The Company considers delivery to have occurred when service has been delivered to the customer and no post-delivery obligations exist. In instances where customer acceptance is required, delivery is deemed to have occurred when customer acceptance has been achieved.

    Fees are fixed or determinable.   The Company considers the fee to be fixed or determinable unless the fee is subject to refund or adjustment or is not payable within normal payment terms. If the fee is subject to refund or adjustment, the Company recognizes revenues when the right to a refund or adjustment lapses. If offered payment terms exceed the Company's normal terms, the Company recognizes revenues as the amounts become due and payable or upon the receipt of cash.

    Collection is deemed probable.   The Company conducts a credit review for all transactions at the inception of an arrangement to determine the creditworthiness of the customer. Collection is deemed probable if, based upon the Company's evaluation, it expects that the customer will be able to pay amounts under the arrangement as payments become due. If the Company determines that collection is not probable, revenues are deferred and recognized upon the receipt of cash.

        The Company enters into agreements and open market bidding programs to provide demand response solutions. Demand response revenues are earned based on the Company's ability to deliver committed capacity. Energy event revenue, which reflects additional payments made to the Company for the amount of energy usage it actually curtails from the grid, is contingent revenue earned based upon the actual amount of energy provided during the demand response event.

        In accordance with SAB No. 104, the Company recognizes demand response revenue when it has provided verification to the grid operator or utility of its ability to deliver the committed capacity which entitles it to payments under the agreement or open market bidding program. Committed capacity is verified through the results of an actual demand response event or a measurement and verification test. Once the capacity amount has been verified, the revenue is recognized and future revenue becomes fixed or determinable and is recognized monthly until the next demand response event or test. In subsequent verification events, if the Company's verified capacity is below the previously verified amount, the customer will reduce future payments based on the adjusted verified capacity amounts. The payments received from the customer can be decreased or increased, up to the committed capacity amounts under the agreement or open market bidding program, in connection with subsequent verification events. Ongoing demand response revenue recognized between demand response events or tests that are not subject to penalty or customer refund are recognized in revenue. If the revenue is subject to refund, the revenue is deferred until the liability is resolved.

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EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

1. Description of Business, Basis of Presentation and Summary of Significant Accounting Policies (Continued)

        Revenue from energy events is recognized when earned. Energy event revenue is deemed to be substantive and represents the culmination of a separate earnings process and is recognized when the energy event is initiated by the customer.

Cost of Revenues

        Cost of revenues for demand response solutions consists primarily of payments made to the Company's commercial, institutional and industrial customers for their participation in the demand response network. The Company generally enters into three to five year contracts with end-use customers under which it delivers recurring cash payments to them for the capacity they commit to make available on demand. The Company also generally makes an additional payment when a customer reduces consumption of energy from the electric power grid. The equipment and installation costs for devices at commercial, institutional and industrial customer sites are capitalized and depreciated over the lesser of the remaining term of the contract, for fixed contracts, or the estimated useful life of the equipment and this depreciation is also reflected in cost of revenues. The Company also includes the monthly telecommunications and data costs incurred as a result of being connected to commercial, institutional and industrial sites and internal payroll and related costs specifically allocated to a customer site. Cost of revenues for energy management solutions include third party services, equipment depreciation and the wages and associated benefits that the Company pays to its project managers for the performance of their services. As of December 31, 2008 and 2007, the Company deferred $677 and $1,042, respectively, of corresponding direct, incremental costs related to deferred revenue under these agreements.

Research and Development Expenses

        Research and development costs incurred by the Company are expensed as incurred and primarily consist of salaries and benefits.

Stock-Based Compensation

        As of December 31, 2008, the Company had one stock-based compensation plan, which is more fully described in Note 10 below. Through December 31, 2005, the Company accounted for its stock-based awards to employees using the intrinsic value method prescribed in Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Under the intrinsic value method, compensation expense was measured on the date of grant as the difference between the deemed fair value of the Company's common stock and the stock option exercise price or restricted stock award purchase price multiplied by the number of stock options or restricted stock awards granted. Generally, the Company grants stock-based awards with exercise prices equal to the estimated fair value of its common stock; however, to the extent that the deemed fair value of the common stock exceeded the exercise or purchase price of stock-based awards granted to employees on the date of grant, the Company amortized the expense over the vesting schedule of the awards, generally four years.

        On January 1, 2006, the Company adopted SFAS No. 123(R), Share Based Payment , which is a revision of SFAS No. 123. SFAS No. 123(R) supersedes APB Opinion No. 25. SFAS No. 123(R)

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EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

1. Description of Business, Basis of Presentation and Summary of Significant Accounting Policies (Continued)


requires nonpublic companies that used the minimum value method in SFAS No. 123 for either recognition or pro forma disclosures to apply SFAS No. 123(R) using the prospective-transition method. As such, the Company continues to apply APB Opinion No. 25 to equity awards outstanding at the date of SFAS No. 123(R)'s adoption that were measured using the minimum value method.

        Effective with the adoption of SFAS No. 123(R), the Company elected to use the Black-Scholes option pricing model to determine the weighted average fair value of stock options granted. In March 2005, the Securities and Exchange Commission (SEC) issued SAB No. 107, Share-Based Payment , relating to SFAS No. 123(R). The Company has applied applicable provisions of SAB No. 107 in its adoption of SFAS No. 123(R). In accordance with SFAS No. 123(R), the Company recognizes the compensation cost of stock-based awards on a straight-line basis over the vesting period of the award. Stock based compensation to employees for the years ended December 31, 2008, 2007 and 2006 was $10,377, $7,318 and $303, respectively (See Note 10).

        The Company accounts for transactions in which services are received from non-employees in exchange for equity instruments based on the fair value of such services received or of the equity instruments issued, whichever is more reliably measured, in accordance with SFAS No. 123, Accounting for Stock-Based Compensation, and EITF No. 96-18, Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction With Selling, Goods or Services. During the years ended December 31, 2008, 2007 and 2006, the Company recognized $62, $279 and $64, respectively, of stock-based compensation to non-employees.

Foreign Currency Translation

        The financial statements of the Company's international subsidiaries are translated in accordance with SFAS No. 52, Foreign Currency Translation . The functional currency of the Company's subsidiary in Canada is the Canadian dollar. In accordance with SFAS No. 52, assets and liabilities are translated to the U.S. dollar from the local functional currency at current exchange rates, and income and expense items are translated to the U.S. dollar using the average rates of exchange prevailing during the year. Gains and losses arising from translation are recorded in other comprehensive income (loss) as a separate component of stockholders' equity. Currency gains or losses on transactions denominated in a currency other than an entity's functional currency are recorded in the results of the operations. Gains (losses) arising from transactions denominated in foreign currencies was approximately $6 for the year ended December 31, 2008 and are included in other income (expense), net in the accompanying consolidated statements of operations.

Comprehensive Loss

        SFAS No. 130, Reporting Comprehensive Income , establishes standards for reporting and displaying comprehensive income and comprehensive loss and its components in the consolidated financial statements. Comprehensive income is defined as the change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. Comprehensive income (loss) is composed of net income (loss), unrealized gains and losses on marketable securities and cumulative foreign currency translation adjustments, which are disclosed in the accompanying consolidated statements of stockholders' equity.

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EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

1. Description of Business, Basis of Presentation and Summary of Significant Accounting Policies (Continued)

        The components of accumulated other comprehensive loss were as follows (in thousands):

 
  December,  
 
  2008   2007  

Unrealized gain on marketable securities

  $ 5   $  

Cumulative loss from translation adjustments

    (91 )    
           

Accumulated other comprehensive income

  $ 86   $  
           

Recent Accounting Pronouncements

        In April 2008, the FASB issued FASB Staff Position (FSP) No. 142-3 (FSP 142-3), Determination of the Useful Life of Intangible Assets. FSP 142-3 amends the factors that an entity should consider in developing renewal or extension assumptions used in determining the useful life of recognized intangible assets under FASB Statement No. 142, Goodwill and Other Intangible Assets. This new guidance applies prospectively to intangible assets that are acquired individually or with a group of other assets in business combinations and asset acquisitions. FSP 142-3 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. Early adoption is prohibited. Since this guidance will be applied prospectively, on adoption, there will be no impact to the Company's current consolidated financial statements.

        On December 4, 2007, the FASB issued SFAS 141(R), Business Combinations (SFAS 141R). SFAS 141R replaces SFAS 141, Business Combinations , and applies to all transactions or other events in which an entity obtains control of one or more businesses. SFAS 141R requires the acquiring entity in a business combination to recognize all (and only) the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose additional information needed to evaluate and understand the nature and financial effect of the business combination. SFAS 141R is effective prospectively for fiscal years beginning after December 15, 2008 and may not be applied before that date. The adoption of SFAS No, 141R may have a significant impact on the Company's accounting for future acquisitions.

2. Acquisitions

South River Consulting, LLC

        In May 2008, the Company acquired 100% of the membership interests of SRC, an energy procurement and risk management services provider, for a purchase price equal to $5,524, which consisted of $3,603 in cash, $174 in related expenses and 120,000 shares of the Company's common stock that had a value of approximately $1,747 as of the closing date. In addition to the amounts paid at closing, the Company may be obligated to pay to the former holders of SRC membership interests an earnout amount equal to 50% to 60% of the revenues of SRC's business during each twelve-month period from May 1, 2008 through April 30, 2010. The earnout payments will be based on the achievement of certain minimum revenue-based milestones of SRC and will be paid in a combination of cash and shares of the Company's common stock. These additional earnout payments would be

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Table of Contents


EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

2. Acquisitions (Continued)


recorded as additional purchase price. The acquisition of SRC strengthens the Company's position in a growing energy procurement services market and provides a local presence for the Company in the PJM service region.

        The SRC acquisition has been accounted for under SFAS No. 141, Business Combinations . The closing of the SRC acquisition was on May 1, 2008, and as such, the Company's consolidated financial statements reflect SRC's results of operations from that date forward.

        The aggregate purchase price of $5,524 consists of the following:

Common stock, $0.001 par value

  $ 1,747  

Cash

    3,603  

Acquisition related expenses

    174  
       

Total purchase price

  $ 5,524  
       

        The aggregate purchase price has been allocated to the acquired assets based on their fair values as determined by the Company as follows:

Total purchase price

  $ 5,524  
       

Accounts receivable

  $ 132  

Prepaids and other current assets

    53  

Customer relationships

    1,720  

Property and equipment

    59  

Employment agreements

    80  

Accrued expenses

    (40 )

Accounts payable

    (60 )
       
 

Net assets acquired

    1,944  
       

Excess purchase price over the fair value of assets acquired

  $ 3,580  
       

        The financial information above reflects the preliminary allocation of the purchase price. During the third and fourth quarter of 2008, the Company allocated an additional $1,010 to customer relationships which had previously been allocated to goodwill. In addition to the amounts paid at closing, the Company may be obligated to pay the former holders of SRC membership interests an earnout payment, as described above. The customer contracts will be amortized over a period of ten years, and the employment agreements will be amortized over a period of four years. Pro forma financial information has not been presented as SRC's operations prior to acquisition were not material.

Mdenergy, LLC

        In September 2007, the Company acquired all of the outstanding membership interests of MDE, an energy procurement service provider, pursuant to the terms of a merger agreement. The total purchase price paid by the Company at closing was approximately $7,900, of which $3,501 was paid in

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Table of Contents


EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

2. Acquisitions (Continued)


cash and the remainder of which was paid by the issuance of 139,056 shares of the Company's common stock.

        In addition to the amounts paid at closing, the Company was obligated to pay to the former holders of MDE membership interests an earnout equal to two times the revenues of MDE's business during the period from July 1, 2007 through December 31, 2007. The contingent consideration related to the earnout in the amount of approximately $3,357 was paid in January of 2008 and was recorded as additional purchase price.

        Pursuant to the merger agreement, the Company is also obligated to pay to certain employees of MDE a cash bonus payment of up to $300 in the first quarter of 2008 and up to $600 in the first quarter of 2009 upon the achievement of certain revenue-based milestones during 2007 and 2008, respectively. These payments are considered bonuses for post combination services and will be expensed over the service period. The Company paid $300 and $500 related to this obligation in January and December 2008, respectively.

        The MDE acquisition has been accounted for under SFAS No. 141, Business Combinations . The closing of the MDE acquisition was September 13, 2007, and as such, the Company's consolidated financial statements reflect MDE's results of operations from that date forward.

        The aggregate purchase price of $11,609 consists of the following:

Common stock, $0.001 par value

  $ 4,751  

Cash

    6,525  

Acquisition related expenses

    333  
       

Total purchase price

  $ 11,609  
       

        The aggregate purchase price has been allocated to the acquired assets based on their fair values as determined by the Company as follows:

Total purchase price

  $ 11,609  
       

Prepaid expenses and other current assets

  $ 20  

Computer equipment

    12  

Customer contracts

    2,400  

Employment agreements

    90  
       
 

Net assets acquired

    2,522  
       

Excess purchase price over the fair value of assets acquired

  $ 9,087  
       

    Supplemental Information

        The following pro forma combined financial information is presented for comparative purposes for the year ended December 31, 2007 and gives effect to certain adjustments, including amortization of the definite life intangible assets as if the MDE acquisition occurred on January 1, 2007. The information below is not necessarily indicative of the results of operations that would have actually

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Table of Contents


EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

2. Acquisitions (Continued)

been reported had the purchase occurred at the beginning of the period presented, nor is it necessarily indicative of future financial position or results of operations (dollars in thousands, except per share data):

 
  Year ended
December 31,
2007
 

Revenues

  $ 65,131  
       

Net loss

  $ (23,921 )
       

Pro forma net loss per share—basic and diluted

  $ (1.80 )
       

eBidenergy, Inc. & Celerity Energy Partners

        On February 23, 2006, the Company entered into a purchase agreement with the secured creditors of eBidenergy, Inc. or eBid, to purchase substantially all of the assets of the company for $52, consisting of $27 in cash paid at closing, 71,836 shares of common stock at the fair market value of the common stock on the date thereof of $1.00 per share for a total value of $25 and an earn-out payment based upon a percentage of the direct margin for new business between February 2006 and August 2008 from the leads identified by the seller. The Company does not believe any payment associated with the earn-out is probable. The former CEO of eBid is now an employee of the Company. eBid developed the PowerTrak total energy management software platform that integrates real-time metering, monitoring, and control systems to bring value-added online energy procurement, data acquisition, and data analysis services to its customers.

        The eBid acquisition was accounted for in accordance with SFAS No. 141. The closing date of the eBid acquisition was February 23, 2006, and as such, the Company's consolidated financial statements reflect eBid's results of operations only from that date forward. The value of the acquired assets, assumed liabilities, and identified intangibles from the acquisition of eBid, as presented below, are based upon management's estimates of fair value as of the date of the acquisition.

        On May 15, 2006, the Company entered into a purchase agreement with the shareholders of Celerity Energy Partners (Celerity) to purchase certain assets of the company for approximately $3.0 million paid at closing. Celerity is the largest, proven demand response provider for electric utilities, power marketers and electric power users in California.

        The Celerity acquisition was accounted for in accordance with SFAS No. 141. The closing date of the Celerity acquisition was May 15, 2006, and as such, the Company's consolidated financial statements reflect Celerity's results of operations only from that date forward. The value of the acquired assets, assumed liabilities, and identified intangibles from the acquisition of Celerity, as presented below, are based upon management's estimates of fair value as of the date of the acquisition.

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EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

2. Acquisitions (Continued)

        The purchase price allocation for the eBid and Celerity acquisitions is as follows:

 
  eBid   Celerity  

Total purchase price (including acquisition costs of $0 and $57, respectively)

  $ 52   $ 3,057  
           

Trade receivables

    5      

Property, plant and equipment

    19     411  

Intangible assets

    33     1,918  
           

Total assets acquired

    57     2,329  

Accounts payable and accruals

    (5 )    
           

Net assets acquired

    52     2,329  
           

Excess purchase price over the fair value of net assets acquired

  $   $ 728  
           

        The excess of the purchase price over the fair value of the net assets acquired was recorded as goodwill. The estimated amounts recorded as intangible assets consist of the following:

 
  eBid   Celerity  

Contracts and customer relationships

  $   $ 1,918  

Software

    33      
           

Total intangible assets

  $ 33   $ 1,918  
           

        Customer relationships are subject to amortization over their estimated useful lives which reflect the anticipated periods over which the Company estimates it will benefit from the acquired assets. The Company anticipates that substantially all of this amortization is deductible for income tax purposes.

        Pro forma net loss and net loss per share are not presented because the impact of the acquisitions of eBid and Celerity were immaterial.

3. Net Loss Per Share

        Basic net loss per share is computed by dividing net loss by the weighted average number of common shares outstanding for the period adjusted for unvested restricted stock, shares held in escrow and contingently issuable shares. Diluted net loss per share is computed using the weighted average number of common shares outstanding and, when dilutive, potential common shares from options and warrants using the treasury stock method, and from convertible securities using the as-converted method. Because the Company reported a net loss for the years ended December 31, 2008, 2007, and

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EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

3. Net Loss Per Share (Continued)


2006, the following potential common shares have been excluded from the computation of dilutive net loss per share because the effect would have been antidilutive.

 
  2008   2007   2006  

Series A Redeemable Convertible Preferred Stock

            2,018,837  

Series A-1 Redeemable Convertible Preferred Stock

            2,593,796  

Series B Redeemable Convertible Preferred Stock

            3,332,362  

Series B-1 Redeemable Convertible Preferred Stock

            786,390  

Series C Redeemable Convertible Preferred Stock

            297,031  

Outstanding options, unvested restricted stock, and warrants

    1,265,217     5,884,969     1,781,274  

Shares held in escrow

    100,094     10,294      
               

    1,365,311     5,895,263     10,809,690  
               

        Included in the weighted average number of common shares outstanding at December 31, 2008, 2007 and 2006 are 20,195, 44,260 and 110,211 contingently issuable shares of common stock, respectively. These shares were issuable in connection with the acquisition of Pinpoint Power DR, LLC (PPDR). These shares have been included in the calculation as there are no restrictions for issuance except for the passage of time.

        The weighted average common shares outstanding at December 31, 2008 excludes the 120,000 shares issued in the SRC acquisition that are held in escrow. The weighted average common shares outstanding at December 31, 2007 excludes the 35,114 shares issued in the MDE acquisition that were held in escrow. In September 2008, the 35,114 shares issued in the MDE acquisition were released from escrow.

4. Marketable Securities

        Cash equivalents principally consist of money market funds, commercial paper and municipal bonds with original maturities of three months or less at the date of purchase. Marketable securities at December 31, 2008 are classified as "available-for-sale." The securities the Company typically invests in carry interest rates typically ranging from 2.75% to 4.0%.

        As of December 31, 2007, the Company held $5.6 million of auction-rate securities (ARS) that were redeemed at par value during 2008. The investments were classified as a current asset on the accompanying condensed consolidated balance sheet as of December 31, 2007. However, because of the short-term nature of the ARS, they were classified as available-for-sale and included in the Company's short-term investments on the Company's consolidated balance sheet as of December 31, 2007.

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EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

4. Marketable Securities (Continued)

        The following is a summary of the Company's available-for-sale marketable securities (dollars in thousands):

 
  Gross unrealized  
As of December 31, 2008
  Cost   Gains   Losses   Fair value  

Commercial paper

    1,499     1         1,500  

Government securities

    496     4         500  
                   
 

Total

  $ 1,995   $ 5   $   $ 2,000  
                   

        The following is a summary of the cost and fair value of current available-for-sale marketable securities at December 31, 2008, by contractual maturity (dollars in thousands):

 
  Cost   Fair value  

Due within one year

  $ 1,994   $ 2,000  
           

Total

  $ 1,994   $ 2,000  
           

 

 
  Gross unrealized  
As of December 31, 2007
  Cost   Gains   Losses   Fair value  

Auction rate securities

  $ 5,600   $   $   $ 5,600  

State and municipal bonds

    9,900             9,900  
                   

Total

  $ 15,500   $   $   $ 15,500  
                   

        The following is a summary of the cost and fair value of current available-for-sale marketable securities at December 31, 2007, by contractual maturity (dollars in thousands):

 
  Cost   Fair value  

Due after ten years

  $ 15,500   $ 15,500  
           

Fair Value Measurements

        In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS No. 157), which defines fair value, establishes a framework for measuring fair value in accordance with GAAP and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements, but its provisions apply to all other accounting pronouncements that require or permit fair value measurement. SFAS No. 157 is effective for the Company's fiscal year beginning January 1, 2008 and for interim periods within that year. In February 2008, the FASB issued FSP No 157-2, Effective date of FASB Statement No. 157, which delayed for one year the effective date of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). As required, the Company adopted SFAS No. 157 for its financial assets on January 1, 2008. Adoption does not have a material impact on the Company's financial position or results of operations at this

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EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

4. Marketable Securities (Continued)


time. The Company has not yet determined the impact on its financial statements of the January 1, 2009 adoption of SFAS No. 157 as it pertains to non-financial assets and liabilities.

        SFAS No. 157 establishes a fair value hierarchy that requires the use of observable market data, when available, and prioritizes the inputs to valuation techniques used to measure fair value in the following categories:

    Level 1—Valuation is based upon quoted prices for identical instruments traded in active markets. Level 1 instruments include securities traded on active exchange markets, such as the New York Stock Exchange.

    Level 2—Valuation is based upon quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active and model-based valuation techniques for which all significant assumptions are observable in the market.

    Level 3—Valuation is generated from model-based techniques that use significant assumptions not observable in the market. These unobservable assumptions reflect the Company's own estimates of assumptions market participants would use in pricing the asset or liability.

        The table below presents the balances of assets and liabilities measured at fair value on a recurring basis at December 31, 2008:

 
  Fair Value Measurements at December 31, 2008 Using  
 
  Totals   Quoted
Prices in Active
Markets for
Identical Assets
(Level 1)
  Significant
Other
Observable
Inputs
(Level 2)
  Unobservable
Inputs
(Level 3)
 

Commercial paper(1)

  $ 2,500   $ 2,500   $   $  

Money market funds(1)

    43,499     43,499          

Government securities

    500     <