EnerNOC, Inc.
ENERNOC INC (Form: 10-K, Received: 03/28/2008 10:19:00)

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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, 2007

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 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 at least 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 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.  ý

         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  o   Non-accelerated filer  ý
(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 29, 2007, the last business day of the Registrant's second quarter of fiscal 2007, was approximately $286.5 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 24, 2008 was 19,501,993.

DOCUMENTS INCORPORATED BY REFERENCE

         The Registrant intends to file a proxy statement pursuant to Regulation 14A within 120 days of the end of the fiscal year ended December 31, 2007. Pursuant to Paragraph G(3) of the General Instructions to Form 10-K, information required by Items 10, 11, 12, 13 and 14 of Part III have been omitted from this report (except for information required with respect to our corporate code of conduct and ethics, which is set forth under Item 10 of Part III of this report) and are incorporated by reference to the definitive proxy statement for the 2008 Annual Meeting of Stockholders to be held on May 9, 2008, to be filed with the Securities and Exchange Commission.




ENERNOC, INC.
ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2007

Table of Contents

PART I    
Item 1.   Business   1
Item 1A.   Risk Factors   21
Item 1B.   Unresolved Staff Comments   40
Item 2.   Properties   40
Item 3.   Legal Proceedings   40
Item 4.   Submission of Matters to a Vote of Security Holders   41

Part II

 

 
Item 5.   Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities   42
Item 6.   Selected Financial Data   45
Item 7.   Management's Discussion and Analysis of Financial Condition and Results of Operations   46
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk   72
Item 8.   Financial Statements and Supplementary Data   73
Item 9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure   73
Item 9A(T).   Controls and Procedures   73
Item 9B.   Other Information   74

PART III

 

 
Item 10.   Directors, Executive Officers and Corporate Governance   74
Item 11.   Executive Compensation   74
Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters   74
Item 13.   Certain Relationships and Related Transactions, and Director Independence   74
Item 14.   Principal Accounting Fees and Services   75

PART IV

 

 
Item 15.   Exhibits, Financial Statement Schedules   75
Signatures   76
Appendix A   Consolidated Financial Statements   F-1
Report of Ernst & Young LLP, Independent Registered Public Accounting Firm   F-2
Exhibit Index    

        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, or the Exchange Act, and Section 27A of the Securities Act of 1933, as amended, or the Securities Act. For this purpose, any statements contained herein regarding our strategy, future operations, financial position, future revenues, 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 28, 2008.

        Our trademarks include: EnerNOC, Get More from Energy, Energy for Education, Capacity on Demand, PowerTrak, EnerNOC Exchange, Celerity Energy, eNode, ebidenergy.com and ENTREX. We have trademark applications pending that correspond to the following marks: The Greenest kWh is the One Never Used, The Greenest Kilowatt-hour is the One Never Used, The Greenest kW is the One Never Built, The Greenest Kilowatt is the One Never Built, The Cleanest kWh is the One Never Used, One-Click Curtailment, Negawatt Network and CarbonTrak.

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



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 advanced metering applications, energy analytics and control, energy procurement services and emissions tracking and trading support.

        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. From June 2005 through May 2006, we acquired Pinpoint Power DR LLC, or Pinpoint Power DR, the demand response business of Pinpoint Power LLC, substantially all of the assets of eBidenergy, Inc., and certain assets of Celerity Energy Partners LLC, a demand response provider for grid operators and utilities. Since inception, our business has grown substantially. With 2,189 customer sites in our demand response network and 1,112 megawatts, or MW, of demand response capacity under our management as of December 31, 2007, we believe that we are the largest national demand response solutions provider focused on the commercial, institutional and industrial market. Our revenues grew from $0.8 million for the year ended December 31, 2004 to $60.8 million for the year ended December 31, 2007.

        Significant developments for us in 2007 included the completion in May 2007 of our initial public offering, or IPO, of 4,312,500 shares of common stock at a price of $26.00 per share, 4,087,500 of which were sold by EnerNOC, which resulted in net proceeds to us of approximately $95.2 million. In September 2007, we completed our acquisition of Mdenergy, LLC, or MDE, an energy procurement services provider, which has allowed us to augment the energy management solutions that we offer to our customers. We completed a follow-on public offering of 2,500,000 shares of our common stock at a price of $43.00 per share in November 2007, 500,000 shares of which were sold by EnerNOC, resulting in net proceeds to us of approximately $19.4 million. In December 2007, we entered into an employment offer letter with Darren P. Brady, an expert in utility operations and energy efficiency, who became our Chief Operating Officer and Senior Vice President effective January 22, 2008.

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        We are registered as a reporting company under the Exchange Act. Accordingly, we file or furnish with the Securities and Exchange Commission, or the Commission or SEC, annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as required by the Exchange Act and the rules and regulations of the Commission. We refer to these reports as Periodic Reports. The public may read and copy any Periodic Reports or other materials we file with the Commission at the Commission's Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information on the operation of the Public Reference Room is available by calling 1-800-SEC-0330. In addition, the Commission maintains an Internet website that contains reports, proxy and information statements and other information regarding issuers, such as EnerNOC, that file electronically with the Commission. The address of this website is http://www.sec.gov .

        Our Internet website address is www.enernoc.com. We make available, free of charge, on or through our website our Periodic Reports and amendments to those Periodic Reports as soon as reasonably practicable after we electronically file them with the Commission. We are not, however, including the information contained on our website, or information that may be accessed through links on our website, as part of, or incorporating it by reference into, this Annual Report on Form 10-K.

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 increasing demand for electricity. Because electricity cannot be economically stored using commercially available technology, 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

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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, 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.

        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 8% in the United States during that same period. As a result, the margin between electric supply and demand is projected to drop below minimum target levels in Texas, New England, the Mid-Atlantic, the Midwest and the Rocky Mountain region in the next two to three years, with other portions of the Northeastern United States, Southwest, and Western United States falling below minimum target levels in the next 10 years. According to the International Energy Agency, North America is expected to add 932,000 MW of additional capacity at a cost of $1.98 trillion between 2005 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 9% during the 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.

Our Market Opportunity

        According to the International Energy Agency, electric power infrastructure expenditures in North America are expected to exceed $1.98 trillion between 2005 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 $7.92 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 $45.1 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

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industrial market, which represents over 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 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 advanced metering applications, energy analytics and control, energy procurement services and emissions tracking and trading support.

        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, or by bidding period. We began providing demand response solutions in one state in 2003 and expanded nationally to over 22 states in six regions by December 31, 2007. From our start in one open market in 2003 to our current 21 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 from 137 MW as of December 31, 2005 to 1,112 MW as of December 31, 2007.

        As indicated in the table below, we have substantial opportunities to continue expanding our capacity under management in the regions in which we already provide our demand response solutions as well as in other regions. The table depicts each of our geographic markets currently served, the length of time we have operated in that region, the contracts and programs in each region through which we generate revenues, the demand response capacity 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 capacity 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, 2007

Region
(Years of Operation In Region)

  Type of
Contract/Open
Market Program
(OMP)

  Date of
Contract/
Initial
Enrollment
IN OMP

  Initial
Expiration
Date

  Demand
Response
Capacity Under
Management
12/31/07
(MW)

  Regional
Peak Demand
2007
(MW)

  Demand
Response
Potential
Market
Opportunity
(MW)(1)

New England
(5 Years)
  Reliability-Based OMP(2)
Price-Based OMP
  Mar 2003
Jul 2003
  May 2010
May 2010
           

 

 

Reliability-Based Contract(2)

 

Jun 2004

 

May 2008(3)

 

 

 

 

 

 
    Reliability-Based Contract(2)   Jun 2004   May 2008(3)            

 

 

Reliability-Based Contract(2)

 

Apr 2006

 

Dec 2008

 

764

 

28,127

 

2,813

 

 

Price-Based OMP

 

Jul 2006

 

May 2010

 

 

 

 

 

 

 

 

Ancillary Services

 

Oct 2006

 

May 2008

 

 

 

 

 

 

 

 

Reliability-Based OMP(2)

 

Dec 2006

 

May 2010

 

 

 

 

 

 

 

 

Reliability-based OMP

 

Jun 2010

 

Open-Ended

 

 

 

 

 

 
   
New York
(3.5 Years)
  Reliability-Based OMP   Aug 2004   Open-Ended            
    Reliability-Based Contract   Oct 2006   Mar 2012   79   33,939   3,394
   
California
(3 Years)
  Reliability-Based Contract   May 2006   Dec 2017            
    Reliability-Based OMP
Reliability-Based OMP
  Mar 2007
May 2007
  Dec 2008
Dec 2008
  79   50,270   5,027

 

 

Reliability-Based Contract

 

Feb 2007

 

Dec 2011

 

 

 

 

 

 

 

 

Reliability-Based Contract

 

Feb 2007

 

Dec 2008

 

 

 

 

 

 
   
Mid-Atlantic/Part Mid-West (1.5 Years)   Ancillary Services OMP
Price-Based OMP
Reliability-Based OMP
  Aug 2006
Aug 2006
Jun 2007
  Open-Ended
Open-Ended
Open-Ended
  184   144,644   14,464
   
New Mexico
(1 Year)
  Reliability-Based Contract   Feb 2007   Dec 2017   0   1,855 (4) 186
   
Florida
(0.5 Years)
  Reliability-Based Contract   Aug 2007   Dec 2011   6   43,824 (5) 4,382
               
 
 
  Total               1,112   302,659   30,266
               
 
 

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

(2)
We expect to transition capacity committed to grid operators and utilities under these contracts and programs, to the extent they are not extended or replaced, into reliability-based open market programs that have been introduced.

(3)
These contracts have not been extended and will expire on May 31, 2008.

(4)
2005 Public Service Company of New Mexico system peak demand.

(5)
Peak demand of Florida Reliability Coordinating Council, the territory of which does not include a portion of the Florida Panhandle.

        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 or by bidding period. 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 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 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.

        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

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consumption and reducing costs. The real-time energy consumption data that we gather in our PowerTrak enterprise energy management software platform empowers us to develop customized energy management solutions that can be used across departments and functions throughout a customer's operations on an enterprise-wide basis, to reduce our end-use customers' energy costs. The devices that we have installed in connection with our demand response solutions enable us to implement many of these 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.

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 2,189 customer sites in our demand response network across multiple electric power grids as of December 31, 2007, 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 2007, when called upon by grid operators and utilities. We have responded to simultaneous events in multiple geographic regions and on August 15, 2007, we dispatched resources within our demand response network in response to nine contemporaneous events in three different regions of the United States. 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 enterprise energy management software platform,

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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 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 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.

        Growing Customer Base.     We have rapidly and significantly grown our base of grid operator and utility customers since inception. As of December 31, 2007, our grid operator and utility customer base included ISO New England, New York ISO, PJM Interconnection, The Connecticut Light and Power Company, Pacific Gas and Electric Company, Southern California Edison Company, San Diego Gas and Electric Company, Public Service Company of New Mexico and Tampa Electric Company, among others. As of December 31, 2007, we had 793 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

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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 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 North American 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. 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 to use real-time and historical energy data to help end-use customers analyze and control their consumption of electricity, 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, we will offer energy procurement-related services and emissions tracking solutions to 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.

        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 September 2007, we acquired MDE, an energy procurement services provider to expand our portfolio of energy management solutions.

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

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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.

        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 three 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 the New York Independent System Operator, The Connecticut Light and Power Company, San Diego Gas and Electric Company, Southern California Edison Company and Pacific Gas and Electric Company, among others.

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        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, New England and California.

        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 currently participate include PJM Interconnection's Synchronized Reserves Market, in which we were the first provider of demand response capacity, and ISO New England's Demand Response Reserves Pilot program.

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

GRAPHIC

        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

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addition of over 400 new commercial, institutional and industrial customers to whom we were providing energy procurement services as of December 31, 2007. We intend to pursue opportunities to provide demand response solutions to a substantial number of these new customers.

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

    Advanced Metering Applications.   We offer meter data gathering and storage services for advanced meters that either we have installed as part of our demand response solutions or other entities have installed for various energy management and reporting purposes. In special cases, we provide our advanced metering applications to other, smaller demand response service providers.

    Energy Analytics and Control.   We offer 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.

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.

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        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.


Our Technology Platform and Operational Processes

GRAPHIC

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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 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.

GRAPHIC

    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

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      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.

    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 energy management 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, 2007, our operations team consisted of 91 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 2,189 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.

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      The group is composed of experts in market rules and regulations, 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 monitoring-based commissioning, energy efficiency, energy procurement 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 energy procurement consulting services.

Sales

        As of December 31, 2007, our sales team consisted of 73 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 of 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 of between one 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 17 employees as of December 31, 2007. 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, 2007, we managed 1,112 MW of technology-enabled demand response capacity from 793 different commercial, institutional and industrial customers in our demand response network across 2,189 customer sites. The following table lists some of our largest customers by capacity

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under management as of December 31, 2007 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
Navisite
  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
City of Stamford, CT
Town of Vernon, CT
City of Brockton, MA
City of New Haven, CT
  Partners Healthcare
Stamford Hospital
Greenwich Hospital
Hartford Hospital
Umass Memorial
  O&G Industries
Pfizer
Verso Paper
Cascades

        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 increase net income. On average, the supermarket industry generates net income of 1.5% of revenues and electricity constitutes approximately 1.7% of the cost of doing business, as a percentage of revenues. This means that even modest savings in electricity costs can result in a disproportionate increase in net income.

        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 90 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.

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Grid Operator and Utility Customers

        We have significantly grown our base of grid operator and utility customers since inception. As of December 31, 2007, our grid operator and utility customer base included ISO New England Inc., The New York Independent System Operator, PJM Interconnection, L.L.C., The Connecticut Light and Power Company, Pacific Gas and Electric Company, Southern California Edison Company, San Diego Gas and Electric Company, Public Service Company of New Mexico 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 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

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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 environmentally sound.

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 Interconnection. 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 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 regarding the frequency and duration of demand response events 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 our contract with San Diego Gas & Electric Company, 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 our contract with San Diego Gas & Electric Company. The export of power for resale is subject to the requirements of the Federal Power Act and the Federal Energy Regulatory Commission'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 agreements, to protect our intellectual property. As of December 31, 2007, in the United States we held one business method patent, which expires in 2024, and we had eight pending patent applications, including two pending United States applications, two pending Patent Cooperation Treaty international applications and four pending foreign applications. 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

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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, 2007, we held ten trademarks/service marks in the United States. These are EnerNOC, Get More from Energy, Energy for Education, Capacity on Demand, PowerTrak, EnerNOC Exchange, Celerity Energy, eNode, ebidenergy.com and ENTREX. We also have trademark applications pending that correspond to the following marks: The Greenest kWh is the One Never Used, The Greenest Kilowatt-hour is the One Never Used, The Greenest kW is the One Never Built, The Greenest Kilowatt is the One Never Built, the Cleanest kWh is the One Never Used, One-Click Curtailment, Negawatt Network and CarbonTrak.

        With respect to, among other things, proprietary know-how that is not patentable and processes for which patents are difficult to enforce, we rely on trade secret protection and confidentiality 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 from our customers and business partners before we disclose any sensitive aspects of our demand response and energy management technology or business strategies. We have not been subject to any material intellectual property claims.

Employees

        As of December 31, 2007, we had 253 full-time employees, including 90 in sales and marketing, 91 in operations, 36 in research and development and 36 in general and administrative. Of these full-time employees, 170 were located in New England, 22 were located in New York, seven were located in the Mid-Atlantic, 40 were located in California, five were located in Toronto, Ontario, three were located in Texas, one was located in Florida and five 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.

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Item 1A.    Risk Factors

         The statements 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 2007, 2006 and 2005 were $23.6 million, $5.8 million and $1.7 million, respectively. We have not achieved profitability for any calendar year, although we have for certain quarters, and we expect to continue to incur operating losses for the foreseeable future. As of December 31, 2007, we had an accumulated deficit of $33.9 million. Initially, our operating losses were principally driven by start-up costs and the costs of developing our technology, which included research and development. More recently, our net losses have been principally driven by selling and marketing, and general and administrative expenses, including, without limitation, expenses related to 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;

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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;

    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 generated from contracts with, and open market sales to, a small number of grid operator and utility customers, including in particular one grid operator customer with which certain of our contracts are expiring in May 2008, and the modification or termination of these contracts or sales relationships could materially adversely affect our business.

        A majority of our revenues have been generated from contracts with, and open market sales to, ISO New England Inc., or ISO-NE. This customer accounted for 60%, 65% and 86% of our total revenues in 2007, 2006 and 2005, respectively. Moreover, revenues from our three largest grid operator and utility customers represented approximately 88%, 93% and 88% of our total revenues in 2007, 2006 and 2005, respectively.

        A substantial portion of our revenues historically have been derived from three fixed price contracts, two of which are with ISO-NE and one of which is with Connecticut Light and Power Company, or CL&P. In 2007, 2006, and 2005, these contracts accounted for approximately 41%, 62%, and 86%, respectively, of our total revenues. Both fixed price contracts with ISO-NE expire in May 2008, and ISO-NE has notified us that it will not extend either contract beyond that date. The fixed price contract with CL&P expires in December 2008. These three contracts relate to an aggregate of approximately 190 MW of demand response capacity under our management as of December 31, 2007. Although we entered into a new 170 MW fixed price contract with CL&P in February 2008, which, if approved, will expire on May 31, 2010 and which we expect will partially offset the impact of the expiration of our existing fixed price contracts with ISO-NE and CL&P on our revenues, the new CL&P contract is subject to approval by the Connecticut Department of Public Utility Control. There can be no assurance that such approval will be obtained or, if obtained, be issued on a timely basis. If we are unable to obtain such approval, other available program options will likely provide significantly lower capacity payments than our existing fixed price contracts with ISO-NE and CL&P. For example, the capacity payments available under ISO-NE's Real-Time Demand Response program are significantly lower than the capacity payments available under our existing fixed price contracts with ISO-NE and CL&P. Thus, the failure to obtain regulatory approval for our new contract with CL&P could significantly reduce our future revenues and have a material adverse effect on our business.

Our results of operations could be adversely affected if our operating expenses 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

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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 such 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 such 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 Interconnection, or PJM, forward capacity market, which is a market in which we materially increased our participation during 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 delivery-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 such 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 such 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 along with our revenues and 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 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. We anticipate that revenues related to our demand

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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. 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 materially 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 temperature and humidity and the time of day that an end-use customer is 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 some of our contracts, 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 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 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

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payments, which could be substantial. We incurred aggregate penalty payments of $152,913 and $52,118 during the years ended December 31, 2007 and December 31, 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 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 the Federal Energy Regulatory Commission, or FERC, to the extent we own, operate, or control generation used to make wholesale sales of power. In addition, our subsidiary Celerity Energy Partners San Diego, LLC, or Celerity, is subject to direct regulation by FERC, because Celerity exports power to the electric power grid for resale pursuant to a contract with San Diego Gas & Electric Company.

        In addition, 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 our request for approval of our contract with Southern California Edison Company, or SCE, for up to 160 MW of demand response capacity. Although we are working with SCE to submit a revised proposal in connection with this contract, we cannot be certain that any revised proposal will be submitted to, or 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 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.

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 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

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      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 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.

We expect to continue to expand our sales and marketing, operations, engineering, research and development capabilities and 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 significant growth in the number of our employees and 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,

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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 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 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. 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 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.

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

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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, the Exchange Act and Rule 10b-5 promulgated thereunder. 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.

Our 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 demand response solutions. We hold two issued patents, nine 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 copyright, trademark and trade secrecy laws, as well as confidentiality agreements and licensing arrangements, to establish and protect our intellectual property. However, we have not obtained confidentiality agreements from all of our customers and vendors and although we have entered into confidentiality agreements with all of our employees, we cannot be certain that these agreements will be honored. Some of our confidentiality 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.

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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 be applicable 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 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 contracts 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.

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.

        We currently derive substantially all of our revenues from the sale of 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 or cancelled as a result of many factors, including 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. 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. For example, in February 2008, ISO-NE implemented a market rule change to its

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Day-Ahead Load Response program, a program in which we have historically been an active participant. The change, which is currently being reviewed by FERC, would result in less opportunity for demand response to participate in this program and may negatively impact our revenues and could delay or prevent our profitability. In addition, 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 2006, our demand response revenues in the third quarter were higher than our demand response revenues in the fourth quarter. Further, occasional events, such as a spike in natural gas prices, 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. 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.

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.

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 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 2008 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.

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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 Energy Partners San Diego, LLC, or 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 determined that prior to our acquisition of Celerity in May 2006, Celerity may have failed to make requisite filings with FERC in connection with transactions relating to our acquisition. Our internal investigation is ongoing, and, once completed, Celerity will make any required filings with FERC but may be subject to penalties and fines, any of which may have a material adverse effect on our business, financial condition and results of operations.

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.

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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 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 acquisition of Mdenergy, LLC, or MDE, 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. 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 our senior loan and security agreement with Bluecrest Capital Partners, L.P., or Bluecrest Capital, as assignee of Ritchie Capital Finance, L.L.C., impose restrictions on our ability to, among other things:

    incur more debt;

    pay dividends and make distributions;

    redeem or repurchase capital stock;

    create liens;

    enter into transactions with affiliates; and

    merge or consolidate.

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        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 Bluecrest Capital. In addition to preventing additional borrowings under our loan and security agreement, an event of default, if not cured or waived, may 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

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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 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 September 2007, we acquired MDE 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 bid bonds, performance bonds or letters of credit is limited and could negatively affect our ability to bid on or enter into significant long-term agreements.

        We are occasionally required to provide bid bonds or performance bonds to secure our performance under long-term contracts with our grid operator and utility customers. In addition, some of our 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 bonds and 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 surety market. Surety companies consider those factors in relation to the amount of our tangible net worth and other underwriting standards that may change from time to time. Events that affect surety markets generally may result in bonding becoming more difficult to obtain in the future, or being available only at a significantly greater cost. As of December 31, 2007, we had $3.0 million of letters of credit outstanding. In addition, in 2007, we posted collateral of $1.2 million and $10.9 million for PJM, the majority of which we expect to be returned to us in June 2008, and $1.8 million for ISO-NE in connection with our open market bidding programs. Our inability to obtain adequate bonding or letters of credit and, as a result, to bid or enter into significant long-term agreements, 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 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 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

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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;

    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 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, 2007, we had approximately $70.2 million in cash and cash equivalents and approximately $15.5 million in investments in marketable securities. Historically, our investments in securities have included auction-rate securities and municipal bonds. Certain of these investments are subject to general credit, liquidity, market and interest rate risks. During the year ended December 31, 2007, we did not have any unrealized losses on any of our investments or 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.

        At December 31, 2007, we had investments in AAA-rated auction-rate securities with various state student loan authorities of $5.6 million. At the time of our initial investment and up to March 28, 2008, all of the securities we have invested in are rated AAA, the highest rating issued by a rating agency. Auction-rate securities are long-term variable rate bonds tied to short-term interest rates and are classified as current assets. After the initial issuance of the securities, the interest rate on the securities is reset periodically, at intervals established at the time of issuance (e.g., every seven, twenty-eight, or thirty-five days; every six months; etc.), based on market demand for a reset period. Auction-rate securities are bought and sold in the marketplace through a competitive bidding process often referred to as a "Dutch auction." If there is insufficient interest in the securities at the time of an auction, the auction may not be completed and the rates may be reset to predetermined higher "penalty" or "maximum" rates. Following such a failed auction, we would not be able to access our funds that are invested in the corresponding auction-rate securities until a future auction of these investments is successful, new buyers express interest in purchasing these securities in between reset dates, issuers

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establish a different form of financing to replace these securities or final payments become due according to contractual maturities. Given the current negative liquidity conditions in the global credit markets, subsequent to December 31, 2007 and as of March 28, 2008, $3.9 million of auction-rate securities we held as of December 31, 2007 experienced failed auctions, and as a result our ability to liquidate our investment and fully recover the carrying value of our investment in the near term may be limited or not exist. If future auctions fail and we believe we will not hold the security to maturity, we may in the future be required to record an impairment charge on these investments, which would reduce the value of the assets on our balance sheet and impact our future operating results. We may similarly be required to record impairment charges if the ratings on any of these securities are reduced or if any of the issuers default on their obligations. In addition to impairment charges, any of these events could cause us to lose part or all of our investment in these securities. Any of these events could materially affect our results of operations and our financial condition. We currently believe these securities are not impaired, primarily due to the AAA credit rating of the issuers and the government backing of the loans made by the issuers; however, it could take until the final maturity of the underlying notes (up to 30 years) to realize our investments' recorded value. Based on our expected sources of cash, we do not anticipate the potential lack of liquidity on these investments will affect our ability to execute our current business plan.

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;

    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 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 such 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 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;

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    the pricing terms of some long-term capacity contracts that provide for higher payments during warmer months and lower payments during the rest of the year;

    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; 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 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, 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 19,180,504 shares of common stock were outstanding at December 31, 2007. Of these shares, the shares of common stock sold in our IPO and follow-on public offering are freely transferable without restriction or further registration under the Securities Act by persons other than "affiliates," as that term is defined in Rule 144 under the Securities Act. In addition, substantially all of our shares of outstanding common stock became freely tradable upon the termination of the lock-up agreements described below. 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.

        Our executive officers and directors and most of our stockholders entered into lock-up agreements in connection with our IPO and follow-on public offering, pursuant to which they agreed, subject to certain exceptions and extensions, not to sell or transfer, directly or indirectly, any shares of our common stock for a certain period of time from the date of our final prospectus related to each of our IPO and follow-on public offering, both of which are on file with the SEC, or to exercise registration rights during such period with respect to such shares. These lock-up periods expired in February 2008, and such persons are currently able to sell their shares and exercise registration rights to cause them to be registered. We cannot predict the size of future issuances of our common stock or the effect, if any, that future sales and issuances of shares of our common stock, or the perception of such sales or issuances, would have on the market price of our common stock.

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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 the shares. 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 incentive 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, 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.

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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, we must comply with statutes and regulations of the SEC and requirements of The Nasdaq Global Market, 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 will 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.

Our 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 required to document and test our internal controls and procedures to assess the effectiveness of our internal control over financial reporting beginning in 2008. In addition, our independent registered public accounting firm is 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 in 2008. If we are unable to maintain effective control over financial reporting, such conclusion would be disclosed in our Annual Report on Form 10-K for the year ending December 31, 2008. 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 The Nasdaq Global Market, 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.

Insiders will continue to have substantial control over us, which could delay or prevent a change of corporate control or result in the entrenchment of management and/or the board of directors.

        As of December 31, 2007, our directors, executive officers and principal stockholders, together with their affiliates and related persons, beneficially owned, in the aggregate, approximately 55% of our outstanding common stock. As a result, these stockholders, if acting together, will continue to have the ability to determine the outcome of matters submitted to our stockholders for approval, including the election and removal of directors and any merger, consolidation or sale of all or substantially all of our assets. In addition, these persons, if acting together, will have the ability to control the management

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and affairs of our company. Accordingly, this concentration of ownership may harm the market price of our common stock by:

    delaying, deferring or preventing a change of control;

    entrenching our management and/or the board of directors;

    impeding a merger, consolidation, takeover or other business combination involving us;

    discouraging a potential acquirer from making a tender offer or otherwise attempting to obtain control of us; or

    causing us to enter into transactions or agreements that are not in the best interests of all stockholders.

        In addition, Delaware law limits the protection afforded minority stockholders, and we do not intend to enact provisions that may be beneficial to minority holders, such as cumulative voting.

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 occupy approximately 21,965 square feet under a sublease agreement expiring in June 2009 and approximately 15,425 square feet under a lease agreement expiring in November 2008. We also occupy 3,892 square feet in New York, New York under a sublease agreement expiring in September 2008. In addition, we lease space in various locations throughout the United States for local sales, marketing, and field operations personnel. We expect to add new facilities and/or expand existing facilities in the near future as existing leases expire and we continue to add employees and operate in new geographic areas, and we believe that suitable space will be available as needed to accommodate any such expansion of our operations. We do not own any facilities.

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 against us, several of our officers and directors and certain of the underwriters from our November 2007 follow-on public offering of our common stock. The plaintiffs claim to represent those persons who purchased shares of our common stock from November 1, 2007

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through February 27, 2008 and/or those persons who purchased shares of our common stock in connection with our follow-on public offering. The plaintiffs allege, among other things, that the defendants made false and misleading statements and failed to disclose material information in various SEC filings, press releases and other public statements. The complaints allege various claims under the Securities Act, the Exchange Act and Rule 10b-5 promulgated thereunder. The complaints seek, among other relief, class certification, unspecified damages, fees and such other relief as the court may deem just and proper.

        We believe that we and the other defendants have substantial legal and factual defenses to the claims and allegations contained in the 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

        Not applicable.

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PART II

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

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 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 24, 2008, there were approximately 154 record holders of the 19,501,993 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 Bluecrest Capital 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 discounts and commissions and expenses incurred in connection with the offering, were approximately $95.2 million. These expenses consisted of direct payments of:

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

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

No payments for such expenses were 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.

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        Through December 31, 2007, approximately $2.3 million of the proceeds from our IPO have been used to fund the operations of our business and for general corporate purposes, approximately $5.2 million have been used to purchase and install equipment, approximately $650,000 have been used to repay indebtedness and approximately $2.8 million have been used to fund acquisitions and make payments outstanding on prior acquisitions. The remainder of the net proceeds from the 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).

Unregistered Sales of Securities

        During the year ended December 31, 2007, we made the following issuances of securities which were not registered under the Securities Act:

    on January 5, 2007, we issued and sold 166,425 shares of Series C Convertible Preferred Stock to four accredited investors at a price of $55.28 per share, and these shares of convertible preferred stock were converted into shares of our common stock in connection with our IPO;

    on April 25, 2007, we made a one-time grant to our chief executive officer and our president of a total of 104,392 shares of our common stock that had been held in treasury as of March 31, 2007;

    on May 23, 2007, in connection with our IPO, we issued 26,447 shares of our common stock to BlueCrest Venture Finance Master Fund Limited upon the net exercise of warrants to purchase shares of our common stock;

    on June 1, 2007, in connection with our 2005 acquisition of 100% of the membership interests of Pinpoint Power DR, LLC, we issued 65,951 shares of our common stock to Thomas E. Atkins. The shares of common stock issued to Mr. Atkins were valued at $0.35 per share;

    on September 13, 2007, we issued 66,921 shares of our common stock to each of Lighthouse Capital Partners IV, L.P. and Lighthouse Capital Partners V, L.P. upon each entity's net exercise of warrants to purchase shares of our common stock; and

    on September 13, 2007, in connection with our acquisition of 100% of the membership interests of Mdenergy, LLC, or MDE, we issued an aggregate of 139,056 shares of our common stock to the holders of membership interests in MDE. The shares of common stock issued were valued at $34.17 per share.

        These issuances of securities were made in reliance on an exemption from the registration provisions of the Securities Act set forth in Rule 506 of Regulation D promulgated thereunder. The recipients of securities in each such transaction represented their intention to acquire the securities for investment only and not with a view to or for sale in connection with any distribution thereof and appropriate legends were affixed to the share certificates and other instruments issued in such transactions. The sales of these securities were made without general solicitation or advertising.

        From January 2007 until June 2007, we granted options to employees, consultants and directors to purchase an aggregate of 662,614 shares of our common stock pursuant to our stock option plans, at a weighted average exercise price of $10.54 per share. In addition, we issued 198,488 shares of common stock in connection with the exercise of outstanding options under our stock option plans by optionees, at a weighted exercise price of $0.33 per share. These option exercises resulted in aggregate proceeds to us of approximately $64,826. No underwriters were involved in the foregoing stock or option issuances. The foregoing stock and option issuances were exempt from registration under the Securities Act, either pursuant to Rule 701 under the Securities Act, as transactions pursuant to a compensatory

43



benefit plan, or pursuant to Section 4(2) under the Securities Act, as a transaction by an issuer not involving a public offering.

Equity Compensation Plan Information

        The following table provides certain aggregate information with respect to all of our equity compensation plans in effect as of December 31, 2007.

 
  (a)
  (b)
  (c)
Plan category

  Number of
securities to be
issued upon
exercise of
outstanding options,
warrants and rights

  Weighted-average
exercise price of
outstanding options,
warrants and rights

  Number of securities remaining available for future issuance under
equity compensation
plans (excluding securities reflected in column (a))

Equity compensation plans approved by security holders(1)(2)   3,037,114   $ 8.73   2,022,581
Equity compensation plans not approved by security holders        
   
 
 
Total   3,037,114   $ 8.73   2,022,581
   
 
 

(1)
These plans consist of our Amended and Restated 2003 Stock Option and Incentive Plan and our 2007 Employee, Director and Consultant Stock Plan, or the 2007 Stock Plan.

(2)
Includes options to purchase 15,918 shares of our common stock issued under the 2007 Stock Plan that were cancelled after December 31, 2007.

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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 Operation" and our consolidated financial statements and accompanying notes thereto included in Item 7 and Appendix A, respectively.

 
  Year Ended December 31,
 
 
  2007(1)
  2006(1)
  2005
  2004
  2003
 
 
  (In thousands, except per share data)

 
Selected Balance Sheet Data:                                
Cash and cash equivalents   $ 70,242   $ 9,184   $ 9,719   $ 213   $ 167  
Marketable securities     15,500                  
Total assets     155,584     29,950     19,651     2,776     328  
Total long-term debt, including current portion     6,091     5,200     1,989     1,750      

Redeemable convertible preferred stock warrant liability

 

 


 

 

606

 

 


 

 


 

 


 
Total redeemable convertible preferred stock and stockholders' equity     122,417     8,608     6,101     51     199  
Selected Income Statement Data:                                
Revenues   $ 60,838   $ 26,100   $ 9,826   $ 819   $ 15  
Cost of revenues     38,949     16,839     4,190     362     9  
Gross profit     21,889     9,261     5,636     457     6  
Selling and marketing expenses     17,145     5,932     2,228     751     58  
General and administrative expenses     27,917     8,000     4,211     835     254  
Research and development expenses     3,097     955     981     778     271  
   
 
 
 
 
 
  Loss from operations     (26,270 )   (5,626 )   (1,784 )   (1,907 )   (577 )
Interest and other income (expense), net     2,788     (145 )   78     14      
   
 
 
 
 
 
Net loss before income taxes     (23,482 )   (5,771 )   (1,706 )   (1,893 )   (577 )
Income taxes     (100 )                
   
 
 
 
 
 
Net loss   $ (23,582 ) $ (5,771 ) $ (1,706 ) $ (1,893 ) $ (577 )
   
 
 
 
 
 
Net loss per share, basic and diluted   $ (1.80 ) $ (1.60 ) $ (0.56 ) $ (0.67 ) $ (0.20 )
   
 
 
 
 
 

(1)
We include the expense associated with stock options in the statement of operations effective in 2006 upon the adoption of SFAS 123R.

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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 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. In doing so, we establish a base of installed users for an expanding portfolio of our technology-enabled energy management solutions.

        We operated as a New Hampshire limited liability company from December 2001 until June 2003, when we were incorporated in Delaware. From our incorporation in June 2003 through January 2007, we raised an aggregate of $28.1 million through the issuance of preferred stock in a series of financings, the proceeds of which we invested in expanding our research and development organization, building our sales, marketing, operations and administration functions, and acquiring complementary businesses and technologies. Our customer base has grown from 19 commercial, institutional and industrial customers with 70 sites in our network as of December 31, 2004 to 793 end-use customers for our demand response solutions with 2,189 sites in our demand response network as of December 31, 2007. The demand response capacity we manage through our network has grown from 10 megawatts, or MW, as of December 31, 2004 to 1,112 MW as of December 31, 2007. Our revenues have grown from $0.8 million in 2004 to $60.8 million in 2007.

        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 $33.9 million from inception to December 31, 2007. Our net losses were $23.6 million, $5.8 million, and $1.7 million for the years ended December 31, 2007, 2006 and 2005, respectively.

        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

46



called EnerNOC Exchange, to help commercial, institutional, and industrial customers make more informed commodity purchasing decisions. The MDE acquisition included the addition of over 400 new commercial, institutional and industrial customers to whom we now provide energy management solutions. We intend to pursue opportunities to provide demand response solutions to a substantial number of these new customers.

        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 includes 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, net of underwriting discounts and commissions and offering expenses.

        We made three other acquisitions through December 31, 2007. In June 2005, we acquired Pinpoint Power DR, the demand response business of Pinpoint Power LLC. This acquisition increased our base of end-use customers and capacity under management in the New England region. 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 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. 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. In addition, 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 month.

        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. 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. 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. 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

47



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. 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 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, in connection with subsequent verification events. Revenues recognized between demand response events or tests are not subject to customer refund.

        As of December 31, 2007, we had 1,112 MW under management in our demand response network, meaning that we had entered into definitive contracts with respect to 1,112 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" such MW, or the date on which we can reduce such MW from the electricity grid if called upon to do so. An exception is the PJM Interconnection, or PJM, forward capacity market, which is a market in which we materially increased our participation during the first quarter of 2008 and in which we expect to continue to increase our participation and derive revenues. Because PJM operates on a June to May delivery-year basis, a MW that we enable after June of each year may 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 such MW. Of the 1,112 MW under management as of December 31, 2007, 82 were subject to this PJM lag, which means that those 82 MW will not begin generating revenue for us until June 2008, and 176 MW were subject to our normal deployment queue, which means that those 176 MW will begin earning revenue within approximately one month from enablement. As we approach June of each year, we expect the number of MW subject to the PJM lag to increase.

        Our energy management solutions include energy procurement services where we evaluate our end-use customers' energy purchasing needs and assist them in procuring more cost effective electricity. We receive a monthly fee from the competitive electricity provider based upon the actual consumption of electricity used by our end-use customers. Demand response audits where 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 receive a fee from our electric grid operator and utility customers for each audit typically based upon a rate times the amount of kilowatts, or kW, we identify that can be reduced from the electric power grid. We also use our PowerTrak platform to deliver energy analytics and control and emissions tracking and trading support. We generally receive either a subscription-based fee or a percentage savings fee for these energy management solutions. We have yet to earn substantial revenues from these energy management solutions.

        A majority of our revenues have been generated from contracts with, and open market sales to, ISO-NE, a grid operator customer. This customer accounted for 60%, 65% and 86% of our total revenues in 2007, 2006 and 2005, respectively. Moreover, revenues from our three largest grid operator and utility customers represented approximately 88%, 93% and 88% of our total revenues in 2007, 2006 and 2005, respectively. A substantial portion of our revenues are derived from three fixed price contracts, two with ISO New England Inc., or ISO-NE, and one with Connecticut Light and Power Company, or CL&P. In 2007, 2006 and 2005, these contracts accounted for approximately 41%, 62% and 86%, respectively, of our total revenues. We anticipate that our dependence on these customer relationships will decrease as we expand further into existing geographic markets and continue to extend our network to encompass new markets. Both fixed price contracts with ISO-NE expire in May

48


2008, and ISO-NE has notified us that it will not extend either contract beyond that date. The fixed price contract with CL&P expires in December 2008. Although we entered into a new 170 MW fixed price contract with CL&P in February 2008, which we expect will partially offset the impact of the expiration of our existing fixed price contracts with ISO-NE and CL&P on our revenues, this new contract is subject to approval by the Connecticut Department of Public Utility Control. There can be no assurance that such approval will be obtained or be issued on a timely basis, if at all. If we are unable to obtain such approval, other available program options will likely provide significantly lower capacity payments than our existing fixed price contracts with ISO-NE and CL&P. For example, the capacity payments available under ISO-NE's Real-Time Demand Response program are significantly lower than the capacity payments available under our existing fixed price contracts with ISO-NE and CL&P.

        Under our first contract with ISO-NE, which will terminate on May 31, 2008, we generated 13% and 25% of our 2007 and 2006 revenues, respectively, for services that we provided. Under this contract, we provide demand response capacity to ISO-NE from end-use customers who contract to reduce electricity consumption from the electric power grid on demand either by curtailing their demand for electricity or utilizing back-up generation instead of consuming electricity from the electric power grid. The amount of demand response capacity that we are required to make available is referred to as our committed capacity. Our level of committed capacity under this contract is approximately 46 MW per month and we can provide and get paid for up to a maximum capacity of 51 MW per month. We receive monthly payments from ISO-NE based upon our level of committed capacity at the time of the payment and the then current dollar amount per MW under the contract. The amount that we are paid per MW of committed capacity fluctuates based on the month for which payment is made, with the amount per MW being higher during the summer months of June through September than during the months of January through May and October through December, which are known as the shoulder months. Under the contract, we also receive an additional payment from ISO-NE each time we are called upon to reduce electricity consumption by end-use customers from the electric power grid. These instances are known as demand response events. The amount of demand response capacity that we are able to deliver during a demand response event or to demonstrate the ability to deliver during one of the periodic verification tests that are performed is referred to as our demonstrated capacity. If our demonstrated capacity is below our committed capacity during a demand response event or during a verification test, we are required to make penalty payments based on the difference between our demonstrated and committed capacities. Additionally, the contract provides that ISO-NE may reduce our monthly committed capacity payments going forward until the next verification test or demand response event, at which time the payment may be readjusted based upon our new demonstrated capacity. Under our other contract with ISO-NE, which will terminate on May 31, 2008, we generated 7% and 17% of our 2007 and 2006 revenues for services we provided. Under this contract, we provide demand response capacity to ISO-NE from end-use customers who contract to reduce electricity consumption from the electric power grid on demand either by curtailing their demand for electricity or utilizing back-up generation instead of consuming electricity from the electric power grid. Our level of committed capacity under the contract increases over time, up to 30 MW per month, and we can provide and get paid for up to a maximum capacity of 110% of our committed capacity. We receive monthly payments from ISO-NE based upon our level of committed capacity at the time of the payment and the then current dollar amount per MW under the contract. Under the contract, we also received an additional payment from ISO-NE for demand response capacity that we deliver during each demand response event. If our demonstrated capacity is below our committed capacity during a demand response event or during a verification test, we are required to make penalty payments based on the difference between our demonstrated and committed capacities. Additionally, the contract provides that ISO-NE may reduce our monthly committed capacity payments going forward until the next test or demand response event, at which time the payment may be readjusted based upon our new demonstrated capacity.

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        We entered into a contract in September 2007 with Southern California Edison Company, or SCE, relating to up to 160 MW of demand response capacity, which we amended in February 2008 to, among other things, extend the date by which regulatory approval must be obtained. On March 13, 2008, the California Public Utilities Commission, or CPUC, issued an order denying approval of certain demand response contracts, including our 160 MW contract with SCE. Pursuant to the terms of the contract and as a result of the CPUC's decision, this contract is expected to automatically terminate on April 30, 2008. We have already entered into discussions with SCE regarding our intention to submit another proposal to the CPUC related to this contract, and we are currently weighing our other options with respect to the CPUC's decision. In the meantime, we will continue to provide demand response services under our original 40MW contract with SCE that we entered into in March 2007, which was unaffected by the CPUC's decision.

    Cost of Revenues

        Cost of revenues for our demand response solutions consists of payments that we make to our commercial, institutional and industrial customers for their participation in our demand response network. We generally enter into one 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 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/data costs we incur as a result of being connected to our commercial, institutional and industrial sites. Cost of revenues for energy management solutions include the wages and associated benefits that we pay to our project managers for the performance of those 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/regions and expand deeper into markets we already serve.

    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 eight employees at December 31, 2003 to 253 employees at December 31, 2007. 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.

    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

50


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 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, and (d) other related overhead. We expect general and administrative expenses to continue to increase in absolute dollar terms and as a percentage of total annual revenues for the foreseeable future as we invest in infrastructure to support continued growth and incur additional 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.

    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 2006 and through a portion of 2007, we capitalized internal software and development costs of $1.5 million in accordance with SOP 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, 2007. 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 and 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 (SFAS) No. 123R, Share Based Payment (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. Under our 2007 Employee, Director and Consultant Stock Plan, or the 2007 Plan, we offer performance based stock awards to certain members of our sales team for meeting their quarterly and annual objectives. For the years ended December 31, 2007, 2006 and 2005, we recorded expenses of approximately $7.6 million, $0.4 million and $1,000, respectively, in connection with share-based payment awards to employees and non-employees. Included in the year ended December 31, 2007 is $2.3 million in compensation expense associated with a grant that we made to our chief executive officer and president in April 2007. With respect to grants through December 31, 2007, a future expense of non-vested options of approximately $21.8 million is to be recognized over a weighted average period of 3.4 years and a future expense of restricted stock awards of approximately $1.5 million is to be recognized over a weighted average period of 3.5 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.

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    Interest Expense

        Interest expense consists of interest on our debt facilities.

Consolidated Results of Operations

    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):

 
  Year Ended
December 31,

   
 
 
  Percentage Change
 
 
  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 %
   
 
     

        Our demand response solutions revenues were $59.2 million for the year ended December 31, 2007 compared to $25.7 million for the year ended December 31, 2006, an increase of $33.5 million, or 129.9%. 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. Of those 1,112 MW under management, 855 MW were generating revenue as of December 31, 2007.

        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 energy procurement services offering where we evaluate our end-use customers' energy purchasing needs and assist them in procuring more cost effective electricity. We also received income from our demand response audits where 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 expect our revenues to increase in 2008 as we further increase our MW under management in all operating regions, 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. In February 2008, ISO-NE notified us that it will not extend the two fixed price contracts that expire in May 2008. Although we entered into a new 170 MW fixed price contract with CL&P in February 2008, which we believe will partially offset the impact of the expiration of the ISO-NE contracts on our revenues, this new contract remains subject to approval by the Connecticut Department of Public Utility Control. If we do not obtain such approval, and are unable to enroll the capacity that we make available under such contracts in another demand response capacity program, our revenues will be adversely affected.

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        In February 2008, prior to the Federal Energy Regulatory Commission, or FERC, approval, 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, which change would result in less opportunity for demand response to participate in this program. Given that the rule change and certain challenges thereto are still in the process of being considered by FERC and that certain of our potential revenues are dependent on electricity prices, we cannot accurately quantify the effect that any final rule change will have on our future revenues and gross margins.

    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 % $ 9,261   35 %

        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.

        Our gross profit was $21.9 million for the year ended December 31, 2007 compared to $9.3 million for the year ended December 31, 2006, an increase of $12.6 million, or 136.4%. 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. In 2008, we expect our gross margin percentage to increase as we seek to sell higher gross margin energy management solutions to our existing demand response customers, seek to achieve more favorable contract terms with our commercial, institutional and industrial customers and seek to capitalize on efficiencies with respect to our customer site activation process.

    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 Change
 
 
  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 %
   
 
     

        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, including costs associated with share-based payment awards. We grew from 100 employees at December 31, 2006 to 253 employees at December 31, 2007. In 2008, we expect to increase our headcount by approximately 40% to 50%, and we expect to continue to hire employees to

53



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 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

        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.

        The increases in selling and marketing expenses were 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

        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, and (d) 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 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.

        The increases in general and administrative expenses were 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 the 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

        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,

54


(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 2006 and through a portion of 2007, we have 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. We intend to increase our investment in research and development in absolute dollar terms for the foreseeable future.

        The increase in research and development expenses from 2006 to 2007 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. 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. Expense increases for the year ended December 31, 2007 were partially offset by capitalized internal software and development costs of $0.7 million.

    Interest and Other Income (Expense), Net

        Interest and other income (expense) consists primarily of interest income earned on cash balances. We historically have invested our cash in money market funds. Interest and other income (expense) includes interest expense on our debt facilities.

        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.

        The increase in interest and other income in the year ended December 31, 2007 as compared to 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 are 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.

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    Year ended December 31, 2006 Compared to Year ended December 31, 2005

    Revenues

        The following table summarizes our revenues for the years ended December 31, 2006 and 2005 (dollars in thousands):

 
  Year Ended
December 31,

   
 
 
  Percentage Change
 
 
  2006
  2005
 
Revenues:                  
  Demand response solutions   $ 25,747   $ 9,348   175.4 %
  Energy management solutions     353     478   (26.2 )%
   
 
     
    Total revenues   $ 26,100   $ 9,826   165.6 %
   
 
     

        For the year ended December 31, 2006, we had revenues of $26.1 million compared to $9.8 million for the year ended December 31, 2005, an increase of $16.3 million, or 166%.

        Our demand response solutions revenues were $25.7 million for the year ended December 31, 2006 compared to $9.3 million for the year ended December 31, 2005, an increase of $16.4 million, or 175%. During the year ended December 31, 2006, we increased our capacity under management in all operating regions and entered the territory covered by the grid operator PJM Interconnection, in the Mid-Atlantic and parts of the Mid-West. As of December 31, 2006, we had approximately 464 MW of demand response capacity under management compared to 137 MW of demand response capacity as of December 31, 2005.

        Our energy management solutions revenues were $0.4 million for the year ended December 31, 2006, compared to $0.5 million for the year ended December 31, 2005, a decrease of $0.1 million, or 26%. While our demand response audit activity increased by $0.2 million during the year ended December 31, 2006 due to an increase in the number of audits performed, our energy management solutions revenues were lower than the corresponding period in 2005 due primarily to a one-time project we performed during 2005.

    Gross Profit and Gross Margin

        The following table summarizes our gross profit and gross margin percentages for the years ended December 31, 2006 and 2005 (dollars in thousands):

Year Ended December 31,
 
2006
  2005
 
Gross
Profit

  Gross
Margin

  Gross
Profit

  Gross
Margin

 
$ 9,261   35 % $ 5,636   57 %

        Our gross profit was $9.3 million for the year ended December 31, 2006 compared to $5.6 million for the year ended December 31, 2005, an increase of $3.6 million, or 64%. Our gross margin for the year ended December 31, 2006 was 35% compared to 57% for the year ended December 31, 2005. Our gross margin in 2005 was unusually high compared to 2006 due to the fluctuation in our cost of revenues.

        Our gross margins of 35% and 57% for the years ended December 31, 2006 and 2005 were directly impacted by our acquisition of Pinpoint Power DR on June 1, 2005. Pinpoint Power DR's demand response revenue is higher in the summer months (June to September) than the rest of the year while the majority of the commercial, institutional and industrial customer contracts we acquired in our

56



acquisition of Pinpoint Power DR require us to make fixed payments to end-use customers rather than variable payments based upon a percentage of monthly revenue. Accordingly, gross margins associated with the Pinpoint Power DR demand response revenue are higher in June to September than the rest of the year. Because we acquired Pinpoint Power DR in June 2005, our 2005 revenues included the higher gross margin months and fewer of the lower gross margin months, which positively impacted our gross margin in 2005. Excluding the impact of the acquisition of Pinpoint Power DR, our gross margins would have been 36% and 51% for the years ended December 31, 2006 and 2005, respectively.

        Our gross margin also fluctuates due to the amount of the payments we make to our commercial, institutional and industrial customers for their participation in our demand response network. The payments vary on a customer-by-customer basis primarily due to the following factors: (i) the amount of capacity in megawatts a particular commercial, institutional and industrial customer can reliably reduce, (ii) whether a particular commercial, institutional and industrial customer contracts to receive a fixed payment amount or a fluctuating payment based upon a percentage of the monthly payment received from our grid operators and utility customers and (iii) the general characteristics of the demand response opportunity such as the program term and number of hours that a customer may be called upon to reduce their electricity consumption from the electric power grid.

        For example, in December 2005, ISO New England Inc. implemented its temporary Demand Response Winter Supplemental program, established in response to an anticipated shortage in natural gas resulting from Hurricanes Katrina and Rita. The program ran from December 2005 through March 2006. Due to the short-term nature of the program, we made payments to our commercial, institutional and industrial customers for their participation that were higher than those we offer in most of our long term programs resulting in lower gross margins associated with the program. The associated revenues and costs of revenues were not recognized until 2006 and contributed to our lower gross margins in 2006.

    Operating Expenses

        The following table summarizes our operating expenses for the years ended December 31, 2006 and 2005 (dollars in thousands):

 
  Year Ended
December 31,

   
 
 
  Percentage Change
 
 
  2006
  2005
 
Operating Expenses:                  
  Selling and marketing expenses   $ 5,932   $ 2,228   166.3 %
  General and administrative expenses     8,000     4,211   90.0 %
  Research and development expenses     955     981   (2.7 )%
   
 
     
    Total   $ 14,887   $ 7,420   100.6 %
   
 
     

    Selling and Marketing Expenses

        Selling and marketing expenses were $5.9 million for the year ended December 31, 2006 compared to $2.2 million for the year ended December 31, 2005, an increase of $3.7 million, or 166%. The increase was primarily due to an increase of $2.4 million in employee-related costs as the number of selling and marketing employees increased from 16 at December 31, 2005 to 41 at December 31, 2006. We also incurred an additional $1.3 million of external fees related to consulting, legal, marketing and research, public relations and other services to facilitate penetration into new markets and support growth in existing markets. As discussed above under the caption "Revenues and Expense Components—Operating Expenses," we expect increases in selling and marketing expenses in absolute

57


dollar terms for the foreseeable future, though we expect those expenses to decrease as a percentage of total annual revenues.

    General and Administrative Expenses

        General and administrative expenses were $8.0 million for the year ended December 31, 2006 compared to $4.2 million for the year ended December 31, 2005, an increase of $3.8 million, or 90%. The increase was primarily due to an increase of $2.0 million in employee-related costs as the number of general and administrative employees increased from 20 at December 31, 2005 to 43 at December 31, 2006. The addition of larger office facilities and increases in professional fees and other general expenses to support operations resulted in $0.6 million of additional expenses. Depreciation and amortization were also $1.2 million higher for the year ended December 31, 2006 compared to the year ended December 31, 2005 due to our acquisitions of certain assets of Pinpoint Power DR, eBidenergy, Inc. and Celerity Energy Partners LLC. As discussed above under the caption "—Revenues and Expense Components—Operating Expenses," we expect general and administrative expenses to continue to increase in absolute dollar terms and as a percentage of total annual revenues for the foreseeable future.

    Research and Development Expenses

        Research and development expenses were $1.0 million for the year ended December 31, 2006 and 2005. During 2006, an increase in the number of employees as of December 31, 2006 contributed to a $0.5 million increase in research and development expenses due primarily to increased compensation and benefits expenses. Higher operating expenses of $0.3 million to support our demand response programs contributed to the increase in research and development expenses. Both of these increases were offset by $0.8 million of capitalized internal software and development costs.

    Interest and Other Income (Expense), Net

        Net interest and other expense was $145,000 for the year ended December 31, 2006 compared to net interest and other income of $78,000 for the year ended December 31, 2005, due to a decrease in interest income of $124,000 related to lower average cash balances and an increase in interest expense of $99,000 from higher average debt balances outstanding during the year ended December 31, 2006 compared to the year ended December 31, 2005.

        For the years ended December 31, 2006 and 2005, we capitalized interest expense of $127,000 and $0, respectively.

    Income Taxes

        No provision for income taxes was recorded for either the year ended December 31, 2006 or December 31, 2005. 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, 2006 or December 31, 2005.

Liquidity and Capital Resources

    Overview

        In November 2007, we completed a 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.

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        In May 2007, we completed our IPO of 4,312,500 shares of common stock at a price of $26.00 per share, which includes 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. 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 loan and security agreement. We used these proceeds to fund our operations, to develop our technology for our demand response programs, to open new markets and for acquisitions.

        We had approximately $70.2 million in cash and cash equivalents as of December 31, 2007, compared to $9.2 million at December 31, 2006. In October 2007, we posted cash collateral of $10.9 million in connection with certain of our open market bidding commitments, the majority of which we expect will be refunded to us in June 2008 once we enroll our committed capacity in a certain program. We believe that our existing cash and cash equivalents and marketable securities at December 31, 2007, our anticipated cash flows from operating activities and borrowings under our loan and security agreement will be sufficient to meet our anticipated cash needs, including investing activities, for at least the next 24 months.

        Our investments in securities include auction-rate securities, or ARS. The ARS we typically invest in are AAA-rated government-backed securities with interest rates typically ranging from 6.5% to 6.8% that have approximate contractual maturities of at least 26 years. However, because of the short-term nature of our investment in these ARS, they have been classified as available-for-sale and included in short-term investments on our consolidated balance sheet. Our holdings of ARS as of December 31, 2007 and 2006 were $5.6 million and $0, respectively.

        Subsequent to December 31, 2007, several of our ARS failed at auction; however, that did not impact the valuation of our ARS as of December 31, 2007 because all of our holdings as of that date succeeded in at least the first auction subsequent to year-end. As of March 28, 2008, we held $3.9 million worth of face amount auction rate securities, all of which have experienced a failed auction and the status of which remains unchanged. As a result of these failed auctions, we have the potential to benefit from a penalty feature in our interest rates, which allows us to earn an additional 5.1% to 14.0% of interest on these ARS until the next auction is set to occur. All of our investments are AAA-rated government backed securities, backed by creditworthy financial institutions, and have the ability to potentially be sold in a secondary market. Based on the underlying market conditions and liquidity of the capital markets, we will continue to reevaluate the appropriate valuation and classification of these ARS throughout 2008.

        We are contingently liable under unused letters of credit. Included in the December 31, 2007 and December 31, 2006 restricted cash balances are unused letters of credit in the amount of $3.0 million and $0.5 million, respectively.

    Cash Flows

        The following table summarizes our cash flows for the years ended December 31, 2007, 2006 and 2005 (dollars in thousands):

 
  Year Ended December 31,
 
 
  2007
  2006
  2005
 
Cash flows (used in) provided by operating activities   $ (7,163 ) $ (964 ) $ 2,498  
Cash flows used in investing activities     (57,019 )   (10,453 )   (885 )
Cash flows provided by financing activities     125,240     10,882     7,893  
   
 
 
 
Increase (decrease) in cash and cash equivalents   $ 61,058   $ (535 ) $ 9,506  
   
 
 
 

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    Cash Flows (Used in) Provided by 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 in 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 purposes 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 in 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 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 provided by operating activities in the year ended December 31, 2005 was $2.5 million and consisted of $1.7 million of net loss offset by $1.5 million of non-cash items, primarily consisting of depreciation and amortization and stock-based compensation charges, and $2.7 million of net cash provided by working capital and other activities. Cash provided by working capital primarily reflected a $1.5 million increase in accrued capacity payment, an increase of $0.4 million in accrued payroll and related expenses, a decrease of $0.6 million in accounts receivable, a decrease of $0.6 million in prepaid expenses and other current assets, an increase of $0.4 million of deferred revenues, and an increase of $0.1 million in other noncurrent liabilities. These amounts were partially offset by a decrease in accounts payable and accrued expenses of $1.1 million.

    Cash Flows Used in Investing Activities

        Cash used in investing activities was $57.0 million, $10.5 million and $0.9 million for 2007, 2006 and 2005, respectively. Our principal cash investments are related to purchases of equipment, including those related to demand response programs, furniture and fixtures, the cash portion of the purchase price for our acquisitions of MDE, Pinpoint Power DR, substantially all of the assets of eBidenergy, Inc. and certain of the assets of Celerity Energy Partners LLC. During the year ended December 31, 2007, we incurred $19.9 million in capital expenditures, of which $13.1 million was related to generating equipment, $3.2 million was related to office equipment, $2.1 million was related to production equipment, $0.9 million was related to leasehold improvements, and $0.7 million was related to furniture and fixtures. In addition, purchases of available-for-sale securities during the year ended December 31, 2007 were approximately $35.4 million and sales and maturities of available-for-sale maturities were $19.9 million during the same period. Also, we had an increase of restricted cash and deposits on our customer programs of $16.4 million as we posted collateral of

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$1.2 million and $10.9 million for PJM and $1.8 million for ISO-NE in connection with our open market bidding programs. In 2007, we made a payment of approximately $3.3 million and $1.9 million in connection with our purchases of MDE and Pinpoint Power DR, respectively. During 2006, we made payments of $3.0 million, $1.7 million and $27,000 for the purchase of certain all of the assets of Celerity Energy Partners LLC, Pinpoint Power DR and substantially all of the assets of eBidenergy, Inc., respectively. In addition, we incurred $5.0 million in capital expenditures for construction-in-progress, equipment, furniture and fixtures. During 2005 and in conjunction with our acquisition of Pinpoint Power DR, we made payments of $1.6 million net of $1.2 million of cash acquired in the transaction, received payments of $1.1 million on related party notes receivable and we had an additional $1.6 million in capital expenditures for equipment, furniture and fixtures.

    Cash Flows Provided by Financing Activities

        Cash flows provided by financing activities were $125.2 million, $10.9 million and $7.9 million for the years 2007, 2006 and 2005, respectively. Cash flows provided by financing activities consisted of the following:

    Equity Financing Activities

        In May 2007, we completed our IPO of 4,312,500 shares of common stock at a price of $26.00 per share, which includes 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. 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 addition, we received approximately $0.2 million from exercises of stock options during both of the years ended December 31, 2007 and December 31, 2006, respectively.

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

        We raised $5.0 million of proceeds through sales of a portion of our Series C Convertible Preferred Stock in December 2006. The remainder of the proceeds from the Series C Convertible Preferred Stock of $10.0 million was received in January 2007. We raised $2.6 million of net proceeds through sales of our Series B-1 Convertible Preferred Stock in May 2006. We raised $7.6 million of net proceeds through sales of our Series B Convertible Preferred Stock in January and September 2005.

    Credit Facility Borrowings

        In November 2006, we entered into a loan and security agreement with Ritchie Capital Finance, L.L.C, which has been assigned to Bluecrest Capital. We borrowed $5.0 million on November 20, 2006 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 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.

        During the years ended December 31, 2007, 2006 and 2005, we made $1.6 million, $2.0 million (including the $1.5 million payment on the Lighthouse loan) and $0.5 million, respectively, of scheduled principal payments under the loan and security agreement.

    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

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totaled $20.0 million in 2007, $5.0 million in 2006, and $1.6 million in 2005. Under certain of our contracts, we are required to make capital expenditures of $4.0 million to $6.0 million related to environmental control facilities. Most of those expenditures were made in 2007 and will be made in the first half of 2008. We do not expect to make additional capital expenditures in connection with those contracts unless our capacity commitment is expanded under the contracts.

Contractual Obligations

        Information regarding our significant contractual obligations of the types described below as of December 31, 2007 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, including interest   $ 6,786   $ 2,979   $ 3,807   $     $
Capital lease obligations     200     59     101     40    
Operating lease obligations     3,195     1,583     1,094     518    
Deferred acquisition payments resulting from acquisition of Mdenergy     4,257     3,657     600        
Deferred acquisition payments to related party (cash and stock)     431     431            
   
 
 
 
 
  Total   $ 14,869   $ 8,709   $ 5,602   $ 558   $
   
 
 
 
 

        As of December 31, 2007, our debt obligations consisted of a $6.8 million loan from Ritchie Capital Finance, L.L.C., which has been assigned to Bluecrest Capital. We used the proceeds to pay off our then outstanding loan from Lighthouse in an amount of $1.5 million and the rest for working capital purposes. The term loan portion of the facility had $2.5 million drawn down at December 31, 2007, and the equipment loan portion of the facility allows us to borrow up to an additional $12.0 million. We are not aware of any events of default under this agreement.

        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, our offices in New York, New York, Rochester, New York, San Francisco, California and Meriden, Connecticut and other property and equipment.

        On June 1, 2005, we acquired all the outstanding membership interests of Pinpoint Power DR for fixed payments of $5.9 million and were required to issue shares of our common stock valued at $0.3 million, the fair value at the date of the transaction. As of December 31, 2007, we had issued 545,788 shares of our common stock and 44,260 additional shares of common stock will be issued through 2008.

        In addition to the amounts paid at closing, we were 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, such earnout to be payable in cash during the first quarter of 2008. The contingent consideration, in the amount of approximately $3.3 million related to the earnout was paid in January of 2008 and was recorded as additional purchase price.

        Pursuant to the merger agreement, we are also obligated to pay to certain employees of MDE a cash bonus payment of up to $0.3 million in the first quarter of 2008 and up to $0.6 million in the first quarter of 2009 upon the achievement of certain revenue-based milestones during 2007 and 2008,

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respectively. These payments are considered bonuses for post combination services and will be expensed over the service period. We paid $0.3 million related to this obligation in February of 2008.

Off-Balance Sheet Arrangements

        We have no off-balance sheet arrangements other than letters of credit issued in the ordinary course of business.

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.

        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 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 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.

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        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 under the agreement which entitles us to payments under the contract. 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 customer can be decreased or increased, up to the committed capacity amounts under the agreement, 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.

        In certain contracts, we receive both non refundable up-front payments for set up fees and monthly demand response fees. These up-front payments are deferred and recognized on a straight-line basis over the estimated customer life as a component of demand response revenue. The costs incurred for the customer set up are capitalized and included in property and equipment as demand response equipment.

        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.

        As described above, customer contracts 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, 2007, the allowance for doubtful accounts was $368,000.

    Impairment of 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 intend to test goodwill for impairment each year, under the guidance of SFAS No. 142, Goodwill and Other Intangible Assets . To date, we have not recorded any impairment charges on these long-lived assets.

    Stock-Based Compensation

        Through December 31, 2005, we accounted for our stock-based awards to employees using the intrinsic value method prescribed in Accounting Principles Board (APB) Opinion No. 25, Accounting

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for Stock Issued to Employees , and related interpretations. Under the intrinsic value method, compensation expense is measured on the date of the grant as the difference between the deemed fair value of our common stock and the exercise or purchase price multiplied by the number of stock options or restricted stock awards granted.

        Through December 31, 2005, we accounted for stock-based compensation expense for non-employees using the fair value method prescribed by SFAS No. 123 and the Black-Scholes option-pricing model, and recorded the fair value, for financial reporting purposes, of non-employee stock options as an expense over either the vesting term of the option or the service period.

        In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123(R), which requires companies to expense the fair value of employee stock options and other forms of 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 will continue to apply APB Opinion No. 25 in future periods 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 will 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 have 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 our IPO in May 2007, we have determined the volatility for options granted in 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 common stock. The expected volatility for options granted during 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, 2007 was 6.25 years. For 2007 and 2006, the weighted-average risk free interest rate used was between 3.4-5.0%. The risk-free interest rate is based on a treasury instrument whose term is consistent with the expected life of the stock options. 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 our actual forfeiture rate of 10% in 2007 and 2006 in determining the expense recorded in our consolidated statement of operations.

        For grants through the years ended December 31, 2007 and 2006, we recorded expense of approximately $7.6 million and $0.4 million, respectively in connection with stock-based awards. With respect to grants through December 31, 2007, a future expense of non-vested stock options and restricted stock of approximately $23.2 million is expected to be recognized over a weighted-average period of 3.5 years.

        In connection with our issuance of stock options and restricted stock awards prior to our IPO, our board of directors, with input from management, determined the fair value of our common stock. The board exercised judgment in determining the estimated fair value of our common stock on the date of grant based on several factors, including the liquidation preferences, dividend rights and voting control attributable to our then-outstanding redeemable convertible preferred stock and, primarily, the likelihood of achieving a liquidity event such as an initial public offering or sale of our company. In the absence of a public trading market for our common stock, the board considered objective and subjective factors in determining the fair value of our common stock. In addition, in 2006, our board

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engaged an unrelated third-party valuation specialist, that we refer to as the valuation specialist, to assist management in preparing valuation reports for stock options and restricted stock awards granted by the board. Based upon our internal peer company analyses and based on several arm's-length transactions involving our common stock supportive of the results produced by this valuation methodology, we believe the methodology used was reasonable.

        In connection with the preparation of our financial statements for the years ended December 31, 2007 and in preparing for our IPO, we examined the valuations of our common stock during those periods, in light of the Practice Aid of the American Institute of Certified Public Accountants entitled Valuation of Privately-Held-Company Equity Securities Issued as Compensation , or the Practice Aid. In March 2006, we engaged the valuation specialist to provide a contemporaneous appraisal of the fair value of our common stock as of March 31, 2006. The resulting report provides the valuation specialist's opinion that the fair value of our common stock was approximately $0.51 as of March 31, 2006. We believe that the valuation methodologies that we used prior to our IPO were consistent with the Practice Aid.

        During 2007, 2006, 2005, 2004 and 2003 we granted stock options and restricted stock awards to employees to purchase a total of 4,711,417 shares of common stock at exercise or purchase prices ranging from $0.00 to $48.54 per share.

        From our inception through December 31, 2002, we were considered a development stage company. We did not recognize any revenue during this period and incurred cumulative operating losses of $25,000. During 2003, we recognized revenue of $15,000 and incurred an operating loss of $0.6 million. During 2003 we granted stock options and restricted stock awards to purchase shares of our common stock at an exercise or purchase price of $0.11 per share, the estimated fair value of our common stock. This fair value was determined by our board using the market approach, taking into consideration the issuance price and associated liquidation preferences and rights of our Series A Convertible Preferred Stock, as well as the high degree of uncertainty surrounding our future prospects and markets. The sales price of our Series A Convertible Preferred Stock on June 17, 2003 was $1.20 per share. Each share of the Series A Convertible Preferred Stock was convertible into 2.831 shares of our common stock and held a liquidation preference of $1.20 per share. Given the size of the liquidation preference, the values assigned to stock-based awards at the time of grant time were deemed by our board to be fair value.

        In January 2004, our Series A-1 Convertible Preferred Stock financing was completed at an issuance price of $1.90 per share. Based upon this issuance price, our board increased the estimated fair value of our common stock by 58% to $0.17 per share. The fair value was determined by our board using the market approach, taking into consideration the issuance price and associated liquidation preferences and rights of the Series A and A-1 Convertible Preferred Stock, as well as the high degree of uncertainty surrounding our future prospects and markets. Each share of Series A-1 Convertible Preferred Stock was convertible into 2.831 shares of our common stock and held a liquidation preference of $1.90 per share. Given the size of the liquidation preference of the combined Series A and A-1 Convertible Preferred Stock, the values assigned to stock-based awards at the time of grant time were deemed to be fair value.

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        In December 2004, we finalized the negotiations of the terms of our Series B Convertible Preferred Stock with our investors. In January 2005, our Series B Convertible Preferred Stock financing was completed at an issuance price of $6.58 per share. Based upon this issuance price, our board increased the estimated fair value of our common stock by 111% to $0.35 per share. The fair value was determined by our board using the market approach, taking into consideration the issuance price and associated liquidation preferences and rights of our Series A, A-1 and B Convertible Preferred Stock, as well as the high degree of uncertainty surrounding our future prospects and markets. Each share of Series B Convertible Preferred Stock was convertible into 2.831 shares of our common stock and held a liquidation preference of $6.58 per share. Given the size of the liquidation preference of the combined Series A, A-1 and B Convertible Preferred Stock, the values assigned to stock-based awards at the time of grant time were deemed to be fair value.

        On each of July 7, August 1, and September 15, 2005, the board granted stock options and restricted stock awards to purchase shares of our common stock at an exercise or purchase price of $0.35 per share, the fair value of our common stock determined by the board on each of those dates. During the first half of 2005 we continued to operate in a loss position, and therefore used cash to fund operations. Certain acquisition discussions concluded without a transaction being consummated, our California open market program posed certain challenges and key management positions remained unfilled. The board determined that there were no other significant events that had occurred during this period that would have given rise to an increase in the fair value of our common stock.

        On both October 26, 2005 and December 15, 2005, the board granted stock options and restricted stock awards to purchase shares of our common stock at an exercise or purchase price of $0.35 per share, the fair value of our common stock determined by the board on each of those dates. The board considered, among other factors, our positive financial performance through December 31, 2005, management's operating forecast for 2006 and the continued uncertainty with respect to our ability to open and enter new markets, as evidenced by the rejection of our proposal to provide demand response services in Laredo, Texas by the Electric Reliability Council of Texas.

        During the period January 1, 2006 through April 30, 2007, we granted stock-based awards, consisting of stock options and restricted stock awards with exercise or purchase prices as follows:

Grants Made during the period January 1, 2006 through April 30, 2007

  Number of Option
and Restricted
Shares Granted

  Exercise or
Purchase Price(1)

  Weighted-Average
Fair Value of
Common Stock(2)

April 13, 2006   204,524   $ 0.51   $ 1.67
May 11, 2006   242,047     0.51     1.67
September 7, 2006   189,111     0.51     1.82
November 6, 2006   354,038     0.51     1.82
December 7, 2006   775,912     0.51     8.87
February 7, 2007   279,527     7.54     8.87
March 26, 2007   171,976     9.94     12.61
April 11, 2007   64,544     11.34     11.34
April 25, 2007   146,567     16.60     16.60
   
           
Total:   2,428,246            
   
           

(1)
Fair value as determined in a contemporaneous valuation by an unrelated valuation specialist.

(2)
Subsequently reassessed in preparation for our initial public offering.

        In March 2006, we engaged the valuation specialist to perform a contemporaneous valuation of our common stock as of March 31, 2006. The appraisal of our common stock was performed using the probability weighted-expected return method consistent with the Practice Aid. For the future liquidity

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events, liquidity dates of March 31, 2009 and March 31, 2010, were assumed. The most likely liquidity event was assumed to be our continued operations in our current geographic territory and acquisition by a company seeking to consolidate regional market participants, which we refer to as the regional sale scenario, which was assigned a probability weighting of 50%. An initial public offering was assigned a probability of 10%, and the expansion of the geographic scope of our business and our subsequent sale to an industry leader, which we refer to as the geographic growth sale scenario, was assigned a probability of 20%.

        The indicated value for our common stock was determined by the valuation specialist to be $0.51 per share. The indicated value was equal to 5% of the price of our Series B-1 Convertible Preferred Stock of $9.90 per share issued on May 16, 2006, which included an assumption of marketability. In determining the fair value of our common stock, the valuation specialist applied a discount for lack of marketability to reflect the fact that there is no established trading market for our stock. The valuation specialist determined the size of the discount for lack of marketability by using as a starting point the average discount for lack of marketability applicable to shares of restricted stock issued by publicly traded companies, which various published studies have calculated to be approximately 60% to 65%, and adjusting such average discount to reflect those factors that were considered to make our common stock less marketable than shares of restricted stock of public companies. These factors included the following: the prospects and timeframe for an initial public offering of our stock or a sale of our company; existing contractual restrictions on the transferability of our common stock; the perceived risk of the enterprise; the concentration of ownership of our stock among our venture capital investors; the difficulty of valuing the enterprise and our common stock; and absence of dividend payments on our common stock. The valuation specialist assessed these factors and their impact in further reducing the marketability of our common stock. A discount for lack of marketability was applied by the valuation specialist, which yielded a fair value of approximately $0.51 per share, corroborating the fair value determined by the board on April 13, 2006.

        On both April 13 and May 11, 2006, the board granted stock options to purchase shares of our common stock at an exercise or purchase price of $0.51 per share, the fair value of our common stock as of March 31, 2006 as determined by our valuation specialist. The board considered, among other factors, the results of our operations during the first quarter of 2006, the fact that we continued to operate in a loss position and used cash to fund operations, and management's operating forecast through December 31, 2006. The board determined that there were no other significant events that had occurred during this period that would have given rise to a change in the fair value of our common stock.

        On September 7, 2006, November 6, 2006 and December 7, 2006, the board granted stock options and restricted stock awards to purchase shares of our common stock at an exercise or purchase price of $0.51 per share, the fair value of our common stock as of March 31, 2006 as determined by our valuation specialist. Through the first three quarters of 2006 we continued to operate in a loss position, and therefore used cash to fund operations. Numerous opportunities to open new markets proved unsuccessful. We were adversely impacted by the Neptune cable transmission system brought on line to serve Long Island, New York. NYISO approved a filing with the Federal Energy Regulatory Commission for an In-City Capacity Mitigation proposal that could drive down the prices for capacity in New York City. In addition, ISO New England was debating whether demand response capacity made available by replacement of electricity consumption from the electric power grid with back-up generation, rather than reductions in consumption, would be allowed to participate at existing or increased levels in upcoming capacity markets. The board determined that there were no other significant events that had occurred during this period that would have given rise to a change in the fair value of our common stock.

        In December 2006, we engaged the valuation specialist to perform a contemporaneous valuation of our common stock as of December 31, 2006. The appraisal of our common stock was performed using

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the probability weighted-expected return method consistent with the Practice Aid. For the future liquidity events, liquidity dates in the third quarter of 2007, and the fourth quarter of 2008, were assumed. The most likely liquidity event was assumed to be the initial public offering scenario as we had begun discussions with investment bankers about going public. This event was assigned a probability weighting of 50%. The regional sale scenario was assigned a probability of 25%, and the geographic growth sale scenario was assigned a probability of 10%.

        The fair value of our common stock was determined by the valuation specialist to be $7.54 per share as of December 31, 2006. This value was equal to 14% of the price of our Series C Convertible Preferred Stock of $55.28 per share issued on December 29, 2006 and January 5, 2007, which included an assumption of marketability. The Series C financing was issued to existing investors and is not a third party indicator of value. In determining the fair value of our common stock, the valuation specialist applied a discount for lack of marketability to reflect the fact that there is no established trading market for our stock. The valuation specialist determined the size of the discount for lack of marketability by using as a starting point the average discount for lack of marketability applicable to shares of restricted stock issued by publicly traded companies, which various published studies have calculated to be approximately 10% to 40%, and adjusting such average discount to reflect those factors that were considered to make our common stock less marketable than shares of restricted stock of public companies. These factors included the following: the prospects and timeframe for an initial public offering of our stock or a sale of our company; existing contractual restrictions on the transferability of our common stock; the perceived risk of the enterprise; the concentration of ownership of our stock among our venture capital investors; the difficulty of valuing the enterprise and our common stock; and lack of dividends. The valuation specialist assessed these factors and their impact in further reducing the marketability of our common stock. A discount for lack of marketability was applied by the valuation specialist, which yielded a fair value of approximately $7.54 per share.

        As a result of our engaging a valuation specialist for the purposes of determining the value at March 31, 2006 and December 31, 2006 and in connection with the preparation for our IPO, we reassessed certain assumptions used by the valuation specialist in arriving at the value. Specifically, the assumptions reassessed were (i) the discount rate applied by an investor to achieve a required rate of return for an investment in a business like ours, (ii) the probability weighting of liquidity events and (iii) the discount for lack of marketability used in determining the fair value of our common stock.

        For options granted on April 13 and on May 11, 2006, (i) the discount rate applied by an investor to achieve a required rate of return for an investment in a business like ours was reduced from 60% to 35%, (ii) the assigned probability weightings for a regional sale scenario decreased from a probability of 50% to a probability of 40%, an initial public offering increased from a probability of 10% to a probability of 20%, and a geographic growth sale scenario remained at a probability of 20% and (iii) the discount for lack of marketability decreased from 40% to 0%. As a result of these changes, we reassessed the fair value of our common stock as of April 13 and May 11, 2006 to be $1.67 per share for fair value for financial statement purposes. Based on this reassessment, we will recognize compensation expense of $0.1 million, $0.1 million, $0.1 million, $0.1 million and $39,340 in 2006, 2007, 2008, 2009 and 2010, respectively, to reflect the difference between the reassessed fair value of our common stock and the grant price using the Black-Scholes option pricing model for options granted in April and May 2006.

        For options and restricted stock granted on September 7 and on November 6, 2006, (i) the discount rate applied by an investor to achieve a required rate of return for an investment in a business like ours was decreased from 60% to 35%, (ii) the assigned probability weightings for a regional sale scenario decreased from a probability of 50% to a probability of 30%, an initial public offering increased from a probability of 10% to a probability of 30%, and a geographic growth sale scenario remained at a probability of 20% and (iii) the discount for lack of marketability decreased from 40% to 0%. As a result of these changes, we reassessed the fair value of our common stock as of September 7

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and November 6, 2006 to be $1.82 per share for fair value for financial statement purposes. Based on this reassessment, we will recognize compensation expense of $50,061, $0.2 million, $0.2 million, $0.2 million and $0.1 million in 2006, 2007, 2008, 2009 and 2010, respectively, to reflect the difference between the reassessed fair value of our common stock and the grant price using the Black-Scholes option pricing model for options granted in September and November 2006.

        For options granted on December 7, 2006, the discount for lack of marketability was decreased from 15% to 0%. As a result of that change, we reassessed the fair value of our common stock as of December 7, 2006 to be $8.87 per share for fair value for financial statement purposes. Based on this reassessment, we will recognize compensation expense of $0.1 million, $1.6 million, $1.7 million, $1.7 million and $1.5 million in 2006, 2007, 2008, 2009 and 2010, respectively, to reflect the difference between the reassessed fair value of our common stock and the grant price using the Black-Scholes option pricing model for options granted in December 2006.

        For options granted on February 7, 2007 the discount for lack of marketability was decreased from 15% to 0%. As a result of this change, the fair value of our common stock as of February 7, 2007 increased to $8.87 per share for financial statement purposes. Based on this reassessment, we will recognize compensation expense of $0.4 million, $0.4 million, $0.5 million, $0.5 million and $0.1 million in 2007, 2008, 2009, 2010 and 2011 respectively, to reflect the difference between the reassessed fair value of our common stock and the grant price using the Black-Scholes option pricing model for options granted in February 2007.

        For options granted on March 26, 2007, (i) we increased the probability of an initial public offering to 62.5% (ii) assigned probability weightings of 17.5%, 7.5% and 12.5% for a geographic growth sale, a regional growth sale and dissolution, respectively, (iii) we decreased the time to a liquidity event and (iv) decreased the discount for lack of marketability from 15% to 0%. As a result of these changes, the fair value of our common stock as of March 26, 2007 increased to $12.61 per share for financial statement purposes. Based on this reassessment, we will recognize compensation expense of $0.4 million, $0.4 million, $0.4 million, $0.4 million and $0.1 million in 2007, 2008, 2009, 2010 and 2011 respectively, to reflect the difference between the reassessed fair value of our common stock and the grant price using the Black-Scholes option pricing model for options granted in March 2007.

        On April 25, 2007, we made a grant to our chief executive officer and our president of a total of 104,392 shares of our common stock that had been held in treasury at March 31, 2007. We recognized $2.3 million as compensation expense associated with this grant in the second quarter of 2007.

        For options granted on April 11 and on April 25, 2007, we used $22.00 per share as the fair value of our common stock for financial statement purposes. This will result in us recognizing additional compensation expense of $0.8 million, $0.7 million, $0.7 million, $0.6 million and $0.1 million in 2007, 2008, 2009, 2010, and 2011 respectively, to reflect the difference between the fair value of our common stock for financial reporting purposes and the grant price.

        All options issued after our IPO on May 17, 2007 were granted with an exercise price equal to the fair market value on the date of grant.

    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 , 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

70


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 FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109 (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. The provisions of FIN 48 are effective as of January 1, 2007, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings.

        We adopted FIN 48 on January 1, 2007. The adoption did not have a material impact on our consolidated financial statements.

New Accounting Pronouncements

    SFAS No. 141R, Business Combinations

        In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141(R), Business Combinations (SFAS No. 141R). SFAS 141R will significantly change the accounting for and reporting of business combination transactions in consolidated financial statements. SFAS 141R retains the fundamental requirements in Statement 141, Business Combinations while providing additional definitions, such as the definition of the acquirer in a purchase and improvements in the application of how the acquisition method is applied. This Statement becomes effective January 1, 2009. Early adoption is not permitted. We are currently evaluating the impact this guidance will have on our consolidated financial statements.

    SFAS No. 157, Fair Value Measurements

        In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS No. 157). This statement defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in GAAP and expands disclosure related to the use of fair value measures in financial statements. SFAS No. 157 does not expand the use of fair value measures in financial statements, but standardizes its definition and guidance in GAAP. The standard emphasizes that fair value is a market-based measurement and not an entity-specific measurement based on an exchange transaction in which the entity sells an asset or transfers a liability (exit price). SFAS No. 157 establishes a fair value hierarchy from observable market data as the highest level to fair value based on an entity's own fair value assumptions as the lowest level. SFAS No. 157 became effective for our financial statements starting January 1, 2008. It does not have a significant impact on our results of operations and financial condition at this time.

    SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities

        In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities . SFAS No. 159 provides an entity with the option, at specified election dates, to measure certain financial assets and liabilities and other items at fair value, with changes in fair value recognized in earnings as those changes occur. SFAS No. 159 also establishes presentation and disclosure requirements that include displaying the fair value of those assets on the face of the balance sheet and providing management's reasons for electing the fair value option for each eligible item. The

71


provisions of SFAS No. 159 are effective beginning January 1, 2008. It does not have a significant impact on our results of operations and financial condition at this time.

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 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, 2007(1)

  1st Qtr
  2nd Qtr
  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 before income taxes     (3,814 )   (8,206 )   (2,525 )   (8,937 )
Provision for income taxes                 (100 )
Net loss     (3,814 )   (8,206 )   (2,525 )   (9,037 )
Net loss per share:                          
  Basic and diluted     (0.91 )   (0.74 )   (0.14 )   (0.48 )
 
Year ended December 31, 2006(1)

  1st Qtr
  2nd Qtr
  3rd Qtr
  4th Qtr
 
 
  In thousands, except per share data

 
Revenues   $ 5,114   $ 4,100   $ 10,978   $ 5,908  
Gross profit     700     1,431     5,766     1,364  
Operating expenses     2,702     2,923     3,879     5,383  
Operating (loss) income     (2,002 )   (1,492 )   1,887     (4,019 )
Net (loss) income     (2,025 )   (1,523 )   1,892     (4,115 )
Net (loss) income per share:                          
  Basic   $ (0.59 ) $ (0.43 ) $ 0.52   $ (1.07 )
  Diluted   $ (0.59 ) $ (0.43 ) $ 0.13   $ (1.07 )

(1)
On May 1, 2007, we effected a 2.831 for one split of its common stock. All amounts have been retroactively presented.

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, 2007, all of our $6.1 million of outstanding debt was at fixed interest rates; therefore, there was no significant impact from changes in interest rates.

        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 municipal auction rate securities with carrying amounts approximating market value. As our investments are made with highly rated municipal auction rate securities and short-term securities, we are not anticipating any significant impact in the short term from a change in interest rates.

72


        A portion of our investment balances are invested in auction rate securities, or ARS. Historically, we have had the option to liquidate these investments whenever the interest rate reset auctions close, usually every 35 days or less. In the event an auction is unsuccessful, we may be in a position where we are unable to liquidate our holdings as scheduled. Upon these occurrences, the interest earned on these investments may vary and we may be unable to predict when future auctions for ARS will be successfully completed. At December 31, 2007, we held approximately $5.6 million in AAA-rated ARS. The majority of these securities were student loan backed where the loans participate in the Federal Family Education Loan Program and are ultimately re-insured by the US Department of Education.

        Subsequent to December 31, 2007, several of our securities failed at auction; however, that did not impact the valuation of our securities as of December 31, 2007 because all of our holdings as of that date succeeded in at least the first auction subsequent to year-end. As of March 28, 2008, we held $3.9 million worth of face amount auction rate securities, all of which have experienced a failed auction and the status of which remains unchanged. As a result of these failed auctions, we have the potential to benefit from a penalty feature in our interest rates, which allows us to earn an additional 5.1% to 14.0% of interest on these securities until the next auction is set to occur. All of our investments are AAA-rated government backed securities, backed by creditworthy financial institutions, and have the ability to potentially be sold in a secondary market. Based on the underlying market conditions and liquidity of the capital markets, we will continue to reevaluate the appropriate valuation and classification of these securities throughout 2008.

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.

Item 9A(T).    Controls and Procedures

        (a)     Evaluation of 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, 2007. 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. Based on the evaluation of our disclosure controls and procedures as of December 31, 2007, 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.

        (b)     Changes in Internal Controls.     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

73



ended December 31, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

        This Annual Report on Form 10-K does not include a report of management's assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by the rules of the SEC for newly public companies.

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, 406 and 407 of Regulation S-K will be contained in our definitive proxy statement for our 2008 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 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 2008 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 2008 Annual Meeting of Stockholders under the captions "Compensation Discussion and Analysis" 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 2008 Annual Meeting of Stockholders under the captions "Certain Relationships and Related Transactions" and "Corporate Governance and Board Matters" and is incorporated by reference herein.

74



Item 14.    Principal Accounting Fees and Services

        The information required by this Item will be contained in our definitive proxy statement for our 2008 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:

    Consolidated Balance Sheets as of December 31, 2007 and December 31, 2006

    Consolidated Statements of Operations for the years ended December 31, 2007, December 31, 2006 and December 31, 2005

    Consolidated Statements of Redeemable Convertible Preferred Stock and Stockholders' Deficit for the years ended December 31, 2007, December 31, 2006 and December 31, 2005

    Consolidated Statements of Cash Flows for the years ended December 31, 2007, December 31, 2006 and December 31, 2005

    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.

75



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.

March 28, 2008

 

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 28, 2008

/s/  
NEAL C. ISAACSON       
Neal C. Isaacson

 

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

 

March 28, 2008

/s/  
DAVID B. BREWSTER       
David B. Brewster

 

Director and President

 

March 28, 2008

/s/  
TJ GLAUTHIER       
TJ Glauthier

 

Director

 

March 28, 2008

/s/  
ADAM GROSSER       
Adam Grosser

 

Director

 

March 28, 2008

/s/  
RICHARD DIETER       
Richard Dieter

 

Director

 

March 28, 2008

/s/  
WILLIAM D. LESE       
William D. Lese

 

Director

 

March 28, 2008

76


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, 2007 and 2006

 

F-3

Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005

 

F-4

Consolidated Statements of Changes in Redeemable Convertible Preferred Stock and Stockholders' Deficit for the Years Ended December 31, 2007, 2006 and 2005

 

F-5

Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005

 

F-6

Notes to Consolidated Financial Statements

 

F-7

F-1



Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of EnerNOC, Inc.:

        We have audited the accompanying consolidated balance sheets of EnerNOC, Inc. as of December 31, 2007 and 2006, and the related consolidated statements of operations, changes in redeemable convertible preferred stock and stockholders' deficit, and cash flows for each of the three years in the period ended December 31, 2007. 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. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of EnerNOC, Inc. as of December 31, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.

        As discussed in Note 1 to the consolidated financial statements, effective January 1, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards, No. 123(R), Share-Based Payment .

  /s/ Ernst & Young LLP

Boston, Massachusetts
March 17, 2008

F-2



EnerNOC, INC.

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)

 
  December 31,
2007

  December 31,
2006

 
Assets              
Current assets              
  Cash and cash equivalents   $ 70,242   $ 9,184  
  Restricted cash     1,248     510  
  Marketable securities     15,500      
  Accounts receivable, net allowance for doubtful accounts of $368 at December 31, 2007 and $7 at December 31, 2006     10,134     4,447  
  Deposits, current     1,955      
  Prepaid expenses and other current assets     2,315     738  
   
 
 
    Total current assets     101,394     14,879  
Property and equipment, net     23,195     6,547  
Goodwill and other intangible assets, net     16,421     7,132  
Restricted cash—non current     1,770      
Deposits, non-current     12,496     522  
Other assets     308     870  
   
 
 
    Total assets   $ 155,584   $ 29,950  
   
 
 
Liabilities and Stockholders' Equity (Deficit)              
Current liabilities              
  Accounts payable   $ 2,112   $ 1,660  
  Accrued capacity payments     9,069     5,210  
  Current portion of deferred related-party acquisition payments     431     1,989  
  Accrued payroll and related expenses     4,902     1,275  
  Accrued Mdenergy earn-out     3,357      
  Accrued expenses and other current liabilities     1,586     1,215  
  Deferred revenue     2,403     971  
  Contingent consideration provision     2,247      
  Current portion of long-term debt     2,451     1,128  
   
 
 
    Total current liabilities     28,558     13,448  
Long-term liabilities              
  Long-term debt, net of current portion     3,640     4,072  
  Deferred related-party acquisition payments, net of current portion         400  
  Deferred revenue         420  
  Contingent consideration provision         2,247  
  Redeemable convertible preferred stock warrant liability         606  
  Deferred tax liability     100      
  Other liabilities     869     149  
   
 
 
    Total long-term liabilities     4,609     7,894  
Commitments and contingencies (Note 16)          
Redeemable convertible preferred stock              
  Series A Redeemable Convertible Preferred Stock, $0.001 par value; 713,118 shares authorized, issued, and outstanding at December 31, 2006, at redemption value         828  
  Series A-1 Redeemable Convertible Preferred Stock, $0.001 par value; 916,212 shares authorized, issued, and outstanding at December 31, 2006, at redemption value         1,739  
  Series B Redeemable Convertible Preferred Stock, $0.001 par value; 1,177,097 shares authorized, issued and outstanding at December 31, 2006, at redemption value         7,685  
  Series B-1 Redeemable Convertible Preferred Stock, $0.001 par value; 296,632 shares authorized, 277,778 shares issued and outstanding at December 31, 2006, at redemption value         2,691  
  Series C Redeemable Convertible Preferred Stock, $0.001 par value; 271,346 shares authorized, 104,921 shares issued and outstanding at December 31, 2006, at redemption value         5,749  
Stockholders' equity (deficit)              
  Common stock, non-convertible, $0.001 par value; 50,000,000 shares authorized, 19,180,504 and 4,245,324 shares issued and outstanding at December 31, 2007 and December 31, 2006, respectively     19     4  
Additional paid-in capital     156,250     771  
Redeemable convertible preferred stock subscription receivable         (800 )
Accumulated deficit     (33,852 )   (10,059 )
   
 
 
    Total stockholders' equity (deficit)     122,417     (10,084 )
   
 
 
    Total liabilities, redeemable convertible preferred stock and stockholders' equity (deficit)   $ 155,584   $ 29,950  
   
 
 

See accompanying notes.

F-3



EnerNOC, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share and per share data)

 
  Year Ended December 31,
 
 
  2007
  2006
  2005
 
Revenues   $ 60,838   $ 26,100   $ 9,826  
Cost of revenues     38,949     16,839     4,190  
   
 
 
 
Gross profit     21,889     9,261     5,636  
   
 
 
 
Operating expenses:                    
  Selling and marketing expenses     17,145     5,932     2,228  
  General and administrative expenses     27,917     8,000     4,211  
  Research and development expenses     3,097     955     981  
   
 
 
 
    Total operating expenses     48,159     14,887     7,420  
   
 
 
 
Loss from operations     (26,270 )   (5,626 )   (1,784 )
  Interest and other income     3,161     167     291  
  Interest expense     (373 )   (312 )   (213 )
   
 
 
 
  Loss before income tax expense     (23,482 )   (5,771 )   (1,706 )
  Provision for income tax expense     (100 )        
   
 
 
 
    Net loss   $ (23,582 ) $ (5,771 ) $ (1,706 )
   
 
 
 
Net loss per share                    
  Basic and diluted   $ (1.80 ) $ (1.60 ) $ (0.56 )
   
 
 
 
  Weighted average number of basic and diluted shares     13,106,114     3,607,822     3,071,733  
   
 
 
 

See accompanying notes.

F-4


EnerNOC, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN REDEEMABLE CONVERTIBLE PREFERRED STOCK
AND STOCKHOLDERS' DEFICIT
(in thousands, except share data)

 
  Series A
Redeemable
Convertible
Preferred Stock

  Series A-1
Redeemable
Convertible
Preferred Stock

  Series B
Redeemable
Convertible
Preferred Stock

  Series B-1
Redeemable
Convertible
Preferred Stock

  Series C
Redeemable
Convertible
Preferred Stock

   
   
   
   
   
   
 
 
  Common Stock
   
   
   
   
 
 
   
  Redeemable Convertible Preferred Stock Subscription Receivable
   
   
 
 
  Number of Shares
  Amount
  Number of Shares
  Amount
  Number of Shares
  Amount
  Number of Shares
  Amount
  Number of Shares
  Amount
  Number of Shares
  Amount
  Additional
Paid-in Capital

  Accumulated Deficit
  Total
 
Balances as of December 31, 2004   713,118   $ 810   916,212   $ 1,738     $     $     $   2,831,003   $ 3   $ 9   $   $ (2,509 ) $ 51  
Issuance of stock upon exercise of stock options                                 83,633         11             11  
Issuance of common shares in connection with the acquisition of Pinpoint Power DR LLC                                 285,220         101             101  
Stock-based compensation expense related to issuance of stock options to non-employees                                         1             1  
Issuance of Series B Redeemable Convertible Preferred Stock, net of issuance costs               1,177,097     7,643                                   7,643  
Accretion of issuance costs       9       1       20                               (30 )    
Net loss                                                 (1,706 )   (1,706 )
   
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balances as of December 31, 2005   713,118     819   916,212     1,739   1,177,097     7,663               3,199,856     3     122         (4,245 )   6,101  
Issuance of stock upon exercise of stock options                                 560,603     1     165             166  
Issuance of restricted stock                                 152,461                      
Issuance of common shares in connection with the acquisition of Pinpoint Power DR LLC                                 260,568         92             92  
Issuance of common shares in connection with the acquisition of eBidenergy, Inc.                                  71,836         25             25  
Stock-based compensation expense                                         367             367  
Issuance of Series B-1 Redeemable Convertible Preferred Stock, net of issuance costs                     277,778     2,679                             2,679  
Issuance of Series C Redeemable Convertible Preferred Stock, net of issuance costs                           104,921     5,749               (800 )       4,949  
Accretion of issuance costs       9             22       12                         (43 )    
Net loss                                                 (5,771 )   (5,771 )
   
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balances as of December 31, 2006   713,118     828   916,212     1,739   1,177,097     7,685   277,778     2,691   104,921     5,749   4,245,324     4     771     (800 )   (10,059 )   8,608  
   
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of stock upon exercise of stock options                                 437,321         150             150  
Issuance of restricted stock                                 45,500                      
Issuance of Series C Redeemable Convertible Preferred Stock, net of issuance costs                           106,425     9,187               800         9,987  
Exercise of warrant                                 160,287         606             606  
Conversion of Preferred Stock   (713,118 ) $ (850 ) (916,212 ) $ (1,745 ) (1,177,097 ) $ (7,745 ) (277,778 ) $ (2,750 ) (211,346 ) $ (15,000 ) 9,499,565     10     28,080                
Vesting of restricted stock                                         24             24  
Accretion of issuance costs       22       6       60       59       64                   (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 shares in connection with the acquisition of Pinpoint Power DR LLC                                 65,951         66             66  
Issuance of common shares 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 )
   
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balances as of December 31, 2007     $     $     $     $     $   19,180,504   $ 19   $ 156,250   $   $ (33,852 ) $ 122,417  
   
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

See accompanying notes.

F-5



EnerNOC, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

 
  2007
  2006
  2005
 
Cash flows from operating activities                    
Net loss   $ (23,582 ) $ (5,771 ) $ (1,706 )
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:                    
Depreciation     3,218     815     302  
Amortization of intangibles     2,287     2,230     1,167  
Loss on disposal of property             14  
Stock-based compensation expense     7,597     367     1  
Non-cash interest expense     175     16     2  
Increase (decrease) in cash from changes in operating assets and liabilities:                    
Accounts receivable     (5,686 )   (3,477 )   617  
Deferred revenue     898     619     432  
Prepaid expenses and other current assets     (1,577 )   (562 )   638  
Deferred tax liability     100          
Other noncurrent assets     387     (280 )   (1 )
Other noncurrent liabilities     742     (72 )   110  
Accrued capacity payments     3,859     2,944     1,548  
Accrued payroll and related expenses     3,627     432     425  
Accounts payable and accrued expenses     792     1,775     (1,051 )
   
 
 
 
Net cash (used in) provided by operating activities     (7,163 )   (964 )   2,498  

Cash flows from investing activities

 

 

 

 

 

 

 

 

 

 
Purchase of marketable securities     (35,449 )        
Sales and maturities of marketable securities     19,949            
Proceeds from collection of related-party notes receivable             1,155  
Purchase of Mdenergy, LLC, net of cash acquired     (3,323 )        
Purchase of Pinpoint Power DR LLC, net of cash acquired     (1,892 )   (1,708 )   (428 )
Purchase of eBidenergy, Inc., net of cash acquired         (27 )    
Purchase of Celerity Energy Partners, net of cash acquired         (3,057 )    
Purchases of property and equipment     (19,866 )   (4,993 )   (1,612 )
Increase in restricted cash and deposits for customer programs     (16,438 )   (668 )    
   
 
 
 
Net cash used in investing activities     (57,019 )   (10,453 )   (885 )

Cash flows from financing activities

 

 

 

 

 

 

 

 

 

 
Proceeds from the issuance of restricted stock         78      
Proceeds from the initial public offering of common stock, net of issuance costs     95,159          
Proceeds from the follow-on offering, net of issuance costs     19,446          
Proceeds from exercises of stock options     152     166     11  
Proceeds from borrowing     2,500     5,000     750  
Repayment of borrowings     (1,610 )   (1,990 )   (511 )
Proceeds from the issuance of preferred stock, net of issuance costs     9,988     7,628     7,643  
Repurchase of treasury stock     (395 )        
   
 
 
 
Net cash provided by financing activities     125,240     10,882     7,893  
Net change in cash and cash equivalents     61,058     (535 )   9,506  
Cash and cash equivalents at beginning of year     9,184     9,719     213  

Cash and cash equivalents at end of year

 

$

70,242

 

$

9,184

 

$

9,719

 
   
 
 
 

Supplemental disclosure of cash flow information

 

 

 

 

 

 

 

 

 

 
Cash paid for interest   $ 789   $ 482   $ 146  
   
 
 
 

Non-cash financing and investing activities

 

 

 

 

 

 

 

 

 

 
Preferred stock subscription receivable   $   $ 800   $  
   
 
 
 
Conversion and net exercise into common stock of preferred stock warrant   $ 606   $   $ 6  
   
 
 
 
Purchase of fixed assets through a capital lease obligation   $   $ 200   $  
   
 
 
 
Deferred related party stock issuance for Pinpoint Power DR LLC   $ 66   $   $  
   
 
 
 
Purchase of Pinpoint Power DR LLC through the issuance of common stock   $   $ 92   $ 101  
   
 
 
 
Purchase of eBidenergy, Inc. through the issuance of common stock   $   $ 25   $  
   
 
 
 
Issuance of common stock to related party   $ 395   $   $  
   
 
 
 
Accretion of preferred stock issuance costs   $ 211   $ 43   $ 30  
   
 
 
 
Purchase of Mdenergy, LLC through the issuance of common stock   $ 4,571   $   $  
   
 
 
 
Issuance of warrants   $   $ 606   $  
   
 
 
 

See accompanying notes.

F-6



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'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.

Reclassifications

        Certain amounts in prior periods have been reclassified to conform to the 2007 presentation. These reclassifications have no material impact on previously reported results of operations or stockholders' equity (deficit). The reclassifications made related to the balance sheet account groupings and did not change the total current assets or current liabilities.

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. In the opinion of the Company's management, the consolidated financial statements include all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the results of operations for this period.

        On September 13, 2007, the Company purchased the outstanding shares 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 accounting 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 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 $70,242 and $9,184 at December 31, 2007 and 2006, respectively.

F-7


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)

Marketable Securities

        Marketable securities at December 31, 2007 are classified as "available-for-sale." Our investments in securities include auction-rate securities (ARSs) 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, 2007, there were no realized gains or losses 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 impairments of marketable securities at December 31, 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.

        For the years ended December 31, 2007, 2006 and 2005, the Company had 2 major customers, which accounted for 81%, 84% and 86%, respectively, of total revenues.

 
  Year Ended December 31
 
 
  2007
  2006
  2005
 
 
  Revenues
  % of Total
Revenues

  Revenues
  % of Total
Revenues

  Revenues
  % of Total
Revenues

 
Customer 1   $ 36,617   60 % $ 16,945   65 % $ 8,420   86 %
Customer 2     12,666   21 %   4,973   19 %     0 %
   
 
 
 
 
 
 
Totals   $ 49,283   81 % $ 21,918   84 % $ 8,420   86 %
   
 
 
 
 
 
 

        Accounts receivable from these customers was approximately $8,696 and $3,597 at December 31, 2007 and 2006, respectively.

F-8


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)

        Deposits and restricted cash consist of funds to secure performance on certain customer contracts. Deposits held by customers were $14,451 and $383 at December 31, 2007 and 2006, respectively. Restricted cash to secure letters of credit were $3,018 and $510 at December 31, 2007 and 2006, respectively.

        In January 2008, the Company paid a total of $10,903 in deposits as collateral in connection with certain open market bidding commitments.

        In February 2008, the Company issued additional letters of credit associated with various programs totaling approximately $458.

        In March 2008, the Company had a deposit that converted into a letter of credit of approximately $10,243. The Company expects that this will result in an increase of restricted cash by $10,243 in 2008.

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 incurred on debt during the course of qualified construction projects. Such costs are added to the asset base and amortized over the related asset's estimated useful life. For the years ended December 31, 2007, 2006 and 2005, the Company capitalized $722, $127 and $0, respectively.

        Software development costs of $677 and $786 for the year ended December 31, 2007 and 2006, respectively, have been capitalized in accordance with Statement of Position No. 98-1, Accounting for the Cost of Computer Software Developed or Obtained for Internal Use. The capitalized amount is included as software in property and equipment at December 31, 2007.

        The Company capitalizes interest on projects that qualify for interest capitalization under Statement of Financial Accounting Standards 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.

Software Development Costs

        In accordance with AICPA Statement of Position 98-1, Accounting for the Cost of Computer Software Developed or Obtained for Internal Use, costs for the post-implementation and operation stage are expensed as incurred. Cost incurred during the application development stage are capitalized and amortized over the estimated useful life of the software.

F-9


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)

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 to be recognized in earnings 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. As of December 31, 2007, there have been no impairments to date.

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 . SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001, and that certain intangible assets acquired in a business combination be recognized as assets apart from goodwill. Under SFAS No. 142, purchased goodwill and intangible assets with indefinite lives are no longer 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, 2007. Based on the results of the first step, the Company has determined that no impairment had occurred, as the fair value of the reporting unit exceeded the respective carrying value.

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 FASB Interpretation 48, Accounting for Uncertainty in Income Taxes—An Interpretation of Statement 109 (FIN 48), as of January 1, 2007. The adoption of FIN 48 did not have any impact on the Company's consolidated financial statements.

F-10


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)

Industry Segment Information

        Based on qualitative and quantitative criteria established by Statements of Financial Accounting Standards (SFAS) No. 131, Disclosures about Segments of an Enterprise and Related Information , the Company operates within one reportable segment.

Revenue Recognition

        The Company recognizes revenues in accordance with 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 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 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 our 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 to provide demand response solutions. Demand response revenues are earned based on the Company's 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, 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 under the agreement which entitles us to payments under the contract. 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

F-11


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)


received from the customer can be decreased or increased, up to the committed capacity amounts under the agreement, 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.

        In certain contracts, the Company receives both non refundable up-front payments for set up fees and monthly demand response fees. These up-front payments are deferred and recognized on a straight-line basis over the estimated customer life as a component of demand response revenue. The costs incurred for the customer set up are capitalized and included in property and equipment as demand response equipment.

        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.

        On March 13, 2008, the California Public Utilities Commission (CPUC) issued an order denying approval of certain demand response contracts including the Company's 160 MW contract with Southern California Edison Company (SCE). Pursuant to the terms of the contract and as a result of the CPUC's decision, the contract is expected to automatically terminate on April 30, 2008. This order has no impact on the Company's historical financial statements.

Cost of Revenues

        Cost of revenues for demand response solutions consists of payments to commercial, institutional and industrial customers for their participation in demand response programs. The Company generally enters into one 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 may make an additional payment when a customer reduces consumption of energy from the electric power grid. As of December 31, 2007 and 2006, the Company deferred $1,042 and $410 of corresponding cost of deferred revenue, respectively, 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, 2007, the Company had one stock-based compensation plan, which is more fully described in Note 11. 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

F-12


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)


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 exceeds the exercise or purchase price of stock-based awards granted to employees on the date of grant, the Company amortizes the expense over the vesting schedule of the awards, generally four years.

        On January 1, 2006, the Company adopted SFAS No. 123(R), which is a revision of SFAS No. 123. SFAS No. 123(R) supersedes APB Opinion No. 25. Generally, the approach under SFAS No. 123(R) is similar to the approach described in SFAS No. 123. However, SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative.

        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, the Company will continue to apply APB Opinion No. 25 in future periods to equity awards outstanding at the date of SFAS No. 123(R)'s adoption that were measured using the minimum value method. In accordance with the requirements of SFAS No. 123(R), the Company will not present pro forma disclosures for periods prior to the adoption of SFAS No. 123(R) as the estimated fair value of the Company's stock options granted through December 31, 2005 was determined using the minimum value method.

        Effective with the adoption of SFAS No. 123(R), the Company has 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 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 year ended December 31, 2007 and 2006 was $7,318 and $303 (See Note 11), before income taxes.

        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 year ended December 31, 2007 and 2006, the Company recognized $279 and $64 of stock-based compensation to non-employees, respectively.

Recent Accounting Pronouncements

    SFAS No. 141R, Business Combinations

        In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141(R), Business Combinations (SFAS No. 141R). SFAS 141R will significantly change the accounting for and reporting of business combination transactions in consolidated financial statements. SFAS 141R retains the fundamental requirements in Statement 141, Business Combinations while providing additional

F-13


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)

definitions, such as the definition of the acquirer in a purchase and improvements in the application of how the acquisition method is applied. This Statement becomes effective January 1, 2009. Early adoption is not permitted. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements.

    SFAS No. 157, Fair Value Measurements

        In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS No. 157). This statement defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in GAAP and expands disclosure related to the use of fair value measures in financial statements. SFAS No. 157 does not expand the use of fair value measures in financial statements, but standardizes its definition and guidance in GAAP. The standard emphasizes that fair value is a market-based measurement and not an entity-specific measurement based on an exchange transaction in which the entity sells an asset or transfers a liability (exit price). SFAS No. 157 establishes a fair value hierarchy from observable market data as the highest level to fair value based on an entity's own fair value assumptions as the lowest level. SFAS No. 157 became effective for the Company's financial statements starting January 1, 2008. It does not have a significant impact on the Company's results of operations and financial condition at this time.

    SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities

        In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities . SFAS No. 159 provides an entity with the option, at specified election dates, to measure certain financial assets and liabilities and other items at fair value, with changes in fair value recognized in earnings as those changes occur. SFAS No. 159 also establishes presentation and disclosure requirements that include displaying the fair value of those assets on the face of the balance sheet and providing management's reasons for electing the fair value option for each eligible item. The provisions of SFAS No. 159 are effective beginning January 1, 2008. It does not have a significant impact on the Company's results of operations and financial condition at this time.

2. Acquisitions

Mdenergy, LLC

        On September 13, 2007, the Company acquired all of the outstanding membership interests of Mdenergy, LLC (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 $7.9 million, of which $3,501 was paid in cash and the remainder of which was paid by the issuance of 139,056 shares of the Company's common stock. Of the total shares of the Company's common stock issued in the transaction, 35,114 shares worth approximately $1,200 at the closing were deposited into an escrow fund to secure certain indemnification obligations of the former holders of MDE membership interests.

        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, such earnout to be payable in cash

F-14


EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

2. Acquisitions (Continued)


during the first quarter of 2008. The contingent consideration, in the amount of approximately $3,357 related to the earnout 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 related to this obligation in January of 2008.

        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 years ended December 31, 2007 and 2006 and gives effect to certain adjustments, including amortization of the definite life intangible assets as if the acquisition occurred on January 1, 2006. The information below is not necessarily indicative of the results of operations that would have actually been reported had the purchase occurred at the beginning of the periods presented, nor is it necessarily

F-15


EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

2. Acquisitions (Continued)

indicative of future financial position or results of operations (dollars in thousands, except per share data):

 
  Year ended December 31,
 
 
  2007
  2006
 
Revenues   $ 62,714   $ 27,943  
   
 
 
Net loss   $ (23,872 ) $ (5,225 )
   
 
 
Pro forma net loss per share—basic and diluted   $ (1.80 ) $ (1.39 )
   
 
 

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 has been 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 or 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 has been 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.

F-16


EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

2. Acquisitions (Continued)

        The purchase price allocation for our two 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 & 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. The Company is considering its options relative to the deductibility of goodwill and is unable at this time to determine what portion, if any, will be deductible for income tax purposes.

        Pro forma net loss and net loss per share are not presented because the impact of the acquisitions of eBidenergy, Inc. and Celerity Energy Partners LLC were immaterial.

Pinpoint Power DR LLC

        In May 2004, the Company entered into a purchase agreement (Purchase Agreement) to acquire all of the outstanding membership interests of Pinpoint Power DR LLC (PPDR) effective June 1, 2005. In connection with the execution of the Purchase Agreement, the Company also entered into an employment agreement with the shareholder of PPDR (Related Former Shareholder).

        In June 2004, PPDR executed two promissory notes in the aggregate of $1,400 subject to a security agreement with the Company. If the notes were not fully paid by December 2005, the Company would become the owner of all of the assets of PPDR and no further obligations would be due to PPDR. The notes were fully paid in May 2005.

F-17


EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

2. Acquisitions (Continued)

        In December 2003, the FASB issued FIN. 46R, Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51. FIN 46R establishes guidance to identify VIEs. FIN 46R requires VIEs to be consolidated by the primary beneficiary who is exposed to the majority of the VIEs' expected income/(losses), expected residual returns, or both. Prior to the acquisition of the membership interests on June 1, 2005, the Company was not entitled to the majority of expected income/(losses) and, therefore, was not the primary beneficiary required to consolidate PPDR. As discussed in the next paragraph, the acquisition has been accounted for as a purchase and, accordingly, the results of operations of PPDR subsequent to June 1, 2005 are included in the Company's consolidated statement of operations.

        On June 1, 2005, the Company acquired all the outstanding membership interests in PPDR from the Related Former Shareholder in a purchase business combination. Under the terms of the Purchase Agreement, the Company is required to (i) make fixed payments of $5,925 and (ii) issue 303,001 shares of the Company's common stock valued at $303, the fair value at date of the transaction. As of December 31, 2007, 44,260 will be issued through 2008. The amounts and timing of the cash payments are fixed and determinable; therefore, the $5,925 has been discounted using rates ranging from 2.8% to 3.8% to calculate the purchase price of $5,625.

        As part of the Purchase Agreement, the Company acquired a contract that contains a one-year option to extend, as of May 31, 2008, at the sole discretion of a certain customer. If exercised, the Company is obligated to make an additional payment of $2,366 to the Related Former Shareholder and issue an additional 28,287 shares to the Related Former Shareholder of the Company's common stock valued at $28. The fair value of the net assets acquired from PPDR exceeded the total consideration to be paid by the Company, resulting in negative goodwill of $2,247. Because the acquisition involves contingent consideration, the Company is required to recognize additional purchase consideration equal to the lesser of the negative goodwill of $2,247 or the maximum amount of contingent consideration of $2,394. This amount will be reversed and recorded against goodwill in the first quarter of 2008.

        In February 2008, the customer informed the Company that the contract would not be extended, therefore, no additional payments or shares will be due to the Related Former Shareholder.

        The aggregate purchase price of $8,175 consists of the following:

Common stock, $0.001 par value   $ 303
Deferred related-party acquisition payments     5,625
Contingent consideration provision     2,247
   
Total purchase price   $ 8,175
   

F-18


EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

2. Acquisitions (Continued)

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

Cash and cash equivalents   $ 1,211  
Accounts receivable     1,073  
Other current assets     724  
Customer contracts     7,180  
Non-compete agreements     67  
Customer relationships     603  
Accounts payable     (16 )
Accrued capacity payments     (518 )
Accrued liabilities     (2,149 )
   
 
Total purchase price   $ 8,175  
   
 


Supplemental Pro Forma Information—Unaudited

        The unaudited pro forma summary information below for the year ended December 31, 2005, gives effect to the acquisition of Pinpoint Power DR LLC as if the acquisition had occurred at the beginning of that period and is after giving effect to certain adjustments, including amortization of the definite life intangible assets.

        The pro forma summary information is based upon available information and upon certain assumptions that the Company's management believes are reasonable. As mentioned above, the acquisition is being accounted for using the purchase method of accounting. Actual amounts could differ from those reflected in the pro forma summary information and such differences could be significant.

 
  Year Ended
December 31,
2005

 
 
  (Unaudited)

 
Revenues   $ 12,147  
   
 
Net loss   $ (1,520 )
   
 
Net loss per share—basic and diluted   $ (0.49 )
   
 

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. Diluted net loss per share is computed using the weighted average number of common shares outstanding and, when dilutive, potential common shares from

F-19


EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

3. Net Loss Per Share (Continued)


options and warrants using the treasury stock method, and from convertible securities using the as-converted method. The calculation of dilutive weighted average shares outstanding is as follows:

 
  2007
  2006
  2005
Basic weighted average shares outstanding   13,106,114   3,607,822   3,071,733
Potentially dilutive effect of:            
  Series A Redeemable Convertible Preferred Stock     2,018,837   2,018,837
  Series A-1 Redeemable Convertible Preferred Stock     2,593,796   2,593,796
  Series B Redeemable Convertible Preferred Stock     3,332,362   3,332,362
  Series B-1 Redeemable Convertible Preferred Stock     786,390  
  Series C Redeemable Convertible Preferred Stock     297,031  
  Outstanding options and warrants   5,884,969   1,781,274   318,026
  Shares held in escrow (Note 2)   10,294    
   
 
 
Potentially dilutive weighted average shares outstanding   19,001,377   14,417,512   11,334,754
   
 
 

        Because the Company reported a net loss for the years ended December 31, 2007, 2006 and 2005, all potential common shares have been excluded from the computation of dilutive net loss per share because the effect would have been antidilutive.

        Included in the weighted average number of common shares outstanding at December 31, 2007, 2006 and 2005 are 44,260, 110,211 and 303,001 contingently issuable shares of common stock, respectively. These shares were issuable in connection with the acquisition of 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, 2007 excludes the 35,114 shares issued in the MDE acquisition that are held in escrow. These shares are included in the calculation of diluted shares outstanding as if the contingency period ended on December 31, 2007. These shares contain restrictions which require the holder to return all or a portion of the shares if specified conditions are not met.

4. Marketable Securities

        Cash equivalents principally consist of money market funds and municipal bonds with original maturities of three months or less at the date of purchase. Marketable securities at December 31, 2007 are classified as "available-for-sale." The Company's investments in securities include auction-rate securities (ARS) and state and municipal bonds. The securities the Company typically invests in are AAA-rated government-backed securities with interest rates typically ranging from 6.5% to 6.8% that have approximate maturities of at least 26 years. However, because of the short-term nature of the Company's investment in these securities, they have been classified as available-for-sale and included in the Company's short-term investments on the Company's consolidated balance sheet. The Company's holdings of auction rate securities as of December 31, 2007 were $5.6 million, and as of December 31, 2006 were $0.

        Subsequent to December 31, 2007, several of the Company's securities failed at auction; however, that did not impact the valuation of the Company's securities at year-end 2007 because all of its

F-20


EnerNOC, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(in thousands, except share and per share data)

4. Marketable Securities (Continued)


holdings as of that date succeeded in at least the first auction subsequent to year-end. As of March 17, 2008, the Company held $3.9 million worth of face amount auction rate securities, all of which have experienced a failed auction and the status of which remains unchanged. As a result of these failed auctions, the Company has the potential to benefit from a penalty feature in its interest rates, which allows it to earn an additional 5.1% to 14.