The following discussion should be read in conjunction with our unaudited condensed consolidated financial statements and related notes thereto included elsewhere in this Quarterly Report on Form 10-Q, as well as our audited financial statements and notes thereto and Management's Discussion and Analysis of Financial Condition and Results of Operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008, as filed with the Securities and Exchange Commission, or the SEC, on March 16, 2009. This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Without limiting the foregoing, the words "may," "will," "should," "could," "expect," "plan," "intend," "anticipate," "believe," "estimate," "predict," "potential," "continue," "target" and variations of those terms or the negatives of those terms and similar expressions are intended to identify forward-looking statements. All forward-looking statements included in this Quarterly Report on Form 10-Q are based on current expectations, estimates, forecasts and projections and the beliefs and assumptions of our management including, without limitation, our expectations regarding our results of operations, operating expenses and the sufficiency of our cash for future operations. We assume no obligation to revise or update any such forward-looking statements. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of certain important factors, including those set forth below under this Item 2 - "Management's Discussion and Analysis of Financial Condition and Results of Operations," Part II, Item 1A - "Risk Factors" and elsewhere in this Quarterly Report on Form 10-Q, as well as in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008. You should carefully review those factors and also carefully review the risks outlined in other documents that we file from time to time with the SEC.

Overview

We are a leading provider of clean and intelligent energy solutions, which include demand response services, energy efficiency, or monitoring-based commissioning, services, energy procurement services and emissions tracking and trading services. These solutions help optimize the balance of electric supply and demand, provide cost-efficient alternatives to traditional power generation, transmission and distribution resources, and drive significant cost-savings for our customers. Our customers are commercial, institutional and industrial end-users of energy, as well as electric power grid operators and utilities.

We believe that we are the largest national demand response service provider for commercial, institutional and industrial customers. As of September 30, 2009, we had over 3,250 megawatts, or MW, under management in our demand response network across an end-use customer base of approximately 2,500 accounts and 5,600 customer sites throughout multiple electric power grids. Demand response is an alternative to traditional power generation and transmission infrastructure projects that enables grid operators and utilities to reduce the likelihood of service disruptions, such as brownouts and blackouts, during periods of peak electricity demand, and otherwise manage the electric power grid during short-term imbalances of supply and demand. We use our Network Operations Center, or NOC, and PowerTrak enterprise software platform to remotely manage and reduce electricity consumption across a growing network of commercial, institutional and industrial customer sites, making demand response capacity available to grid operators and utilities on demand while helping end-users of electricity achieve energy savings, environmental benefits and improved financial results. To date, we have received substantially all of our revenues from grid operators and utilities, who make recurring payments to us for managing demand response capacity that we share with end-users of electricity in exchange for such end-users reducing their power consumption when called upon.

We build on our position as a leading demand response services provider by using our NOC and scalable PowerTrak technology platform to also deliver a portfolio of additional energy management services to our customers, including cross-selling of these energy management services to existing end-use customers. These additional solutions include our monitoring-based commissioning, or MBCx, services, energy procurement services and emissions tracking and trading services. Our MBCx services combine advanced metering, building management systems, and energy analytics software applications to identify energy efficiency opportunities in large buildings. Our energy procurement services provide our commercial, institutional and industrial customers located in restructured or deregulated markets throughout the United States with the ability to more effectively manage the energy supplier selection process, including energy supply product procurement and implementation. Our emissions tracking and trading services include a comprehensive, software-based accounting system for our commercial, institutional and industrial customers to effectively monitor, mitigate and monetize their greenhouse gas emissions in response to existing and pending greenhouse gas reporting requirements.

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 $62.1 million from inception to September 30, 2009. Our net income was $26.6 million and $8.4 million, respectively, for the three and nine months ended September 30, 2009.

Significant Recent Developments

In July 2009, we and Neal C. Isaacson, our then-current chief financial officer and treasurer, agreed that Mr. Isaacson would resign as chief financial officer and treasurer effective as of the close of business on July 30, 2009. Also in July 2009, we entered into

an employment offer letter to hire and retain Timothy Weller as our chief financial officer and treasurer. Mr. Weller's employment with our company commenced on July 31, 2009.

In August 2009, we completed an underwritten public offering of 3,963,889 shares of our common stock at an offering price of $27.00 per share, which includes the exercise of the underwriters' over-allotment option to purchase 213,889 shares and the sale of 709,026 shares by certain of our selling stockholders. After deducting underwriting discounts and commissions and offering expenses payable by us, we received net proceeds of approximately $83.5 million from the offering.

Revenues and Expense Components

Revenues

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

Where we operate in open markets, our revenues from demand response capacity payments generally vary month-to-month based upon our enrolled capacity and the market payment rate. Where we have a long-term contract, we receive periodic capacity payments, which may vary monthly or seasonally, based upon enrolled capacity and predetermined payment rates. Under both long-term contracts and open market programs, we receive capacity payments regardless of whether we are called upon to reduce demand for electricity from the electric power grid and we recognize revenue over the applicable delivery period, even where payments are made over a different period. We generally 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 during a demand response event; we call this an energy payment.

We do not recognize any revenues until we can determine that persuasive evidence of an arrangement exists, delivery has occurred, the fee is fixed or determinable, and we deem collection to be probable. As program rules may differ for each contract and/or region where we operate, we assess whether or not we have met the specific service requirements under the program rules and recognize or defer revenues as necessary. 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 contract or open market program. Committed capacity is verified through the results of an actual demand response event or a measurement and verification test. Once the capacity amount has been verified, the revenues are recognized and future revenues become fixed or determinable and are recognized monthly until the next verification event. In subsequent verification events, if our verified capacity is below the previously verified amount, the grid operator or utility customer will reduce future payments based on the adjusted verified capacity amounts. The payments received from the grid operator or utility customer can be decreased or increased, up to the committed capacity amounts under the contract or open market program, in connection with subsequent verification events.

We defer incremental direct costs incurred related to the acquisition or origination of a contract or open market program in a transaction that results in the deferral or delay of revenue recognition. We had deferred contract origination costs of approximately $0.9 million as of September 30, 2009 and $0.0 million as of December 31, 2008. These deferred expenses would not have been incurred without our participation in an open market bidding program and will be expensed in proportion to the related revenue being recognized. We believe that this accounting treatment appropriately matches expenses with the associated revenue.

As of September 30, 2009, we had over 3,250 MW under management in our demand response network, meaning that we had entered into definitive contracts with our commercial, institutional and industrial customers with respect to over 3,250 MW of demand response capacity. We generally begin earning revenues from our MW under management within approximately one month from the date on which we "enable" the MW, or the date on which we can reduce the MW from the electricity grid if called upon to do so. An exception is the PJM Interconnection, or PJM, forward capacity market, which is a market in which we materially increased our participation beginning in the first quarter of 2008 and in which we expect to continue to increase our participation and derive revenues for the foreseeable future. Because PJM operates on a June to May program-year basis, a MW that we enable after June of each year may not begin earning revenue until June of the following year. This results in a longer average revenue recognition lag time in our end-use customer portfolio from the point in time when we consider a MW to be under management to when we earn revenues from the MW. Certain other markets in which we currently participate or choose to participate in the future may operate in a manner similar to the PJM forward capacity market, which would create a delay in recognizing revenue from the MW that we enable in those markets.

Our portfolio of additional energy management solutions includes our MBCx services, energy procurement services, and emissions tracking and trading services. Our MBCx services combine advanced metering, building management systems, and energy analytics software applications to identify energy efficiency opportunities in large buildings. Our energy procurement services provide our end-use customers located in restructured or deregulated markets throughout the United States with the ability to more effectively manage the energy supplier selection process, including energy supply product procurement and implementation. We also use our PowerTrak platform to deliver emissions tracking and trading services, which include a comprehensive, software-based accounting system for our commercial, institutional and industrial customers to enable them to more effectively monitor, mitigate and monetize their greenhouse gas emissions in response to existing and pending greenhouse gas reporting requirements. We generally receive either a subscription-based or consulting fee or a percentage savings fee for these energy management solutions. Revenues derived from our energy management solutions increased from $4.8 million to $5.0 million, respectively, for the nine months ended September 30, 2008 and 2009.

Revenues generated from open market sales to PJM, a grid operator customer, accounted for 73% and 50%, respectively, of our total revenues in each of the three months ended September 30, 2009 and 2008 and 60% and 34%, respectively, of our total revenues in each of the nine months ended September 30, 2009 and 2008.

Revenues generated from two fixed price contracts with, and open market sales to, ISO New England Inc., or ISO-NE, a grid operator customer, accounted for 12% and 18%, respectively, of our total revenues in each of the three months ended September 30, 2009 and 2008 and 23% and 32%, respectively, of our total revenues in each of the nine months ended September 30, 2009 and 2008. Our two fixed price contracts with ISO-NE expired on May 31, 2008. In addition, 0% and 14% of our total revenues for each of the nine months ended September 30, 2009 and 2008 were generated under a fixed price contract with The Connecticut Light and Power Company, or CL&P, which expired on December 31, 2008. We have enrolled a significant portion of the MW represented by our expired fixed price contracts with ISO-NE and CL&P in other available demand response programs.

Cost of Revenues

Cost of revenues for our demand response solutions consists primarily of payments that we make to our commercial, institutional and industrial customers for their participation in our demand response network. We generally enter into three to five year contracts with our end-use customers under which we deliver recurring cash payments to them for the capacity they commit to make available on demand. We also generally make an additional payment when a customer reduces consumption of energy from 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 reflected in cost of revenues. We also include in cost of revenues the monthly telecommunications and data costs we incur as a result of being connected to our commercial, institutional and industrial sites and our internal payroll and related costs specifically allocated to a customer site. Cost of revenues for energy management solutions include third party services, equipment depreciation and the wages and associated benefits that we pay to our project managers for the performance of their services.

Gross Profit and Gross Margin

Gross profit consists of our total revenues less our cost of revenues. Our gross profit has been, and will be, affected by many factors, including (a) the demand for our demand response and energy management solutions, (b) the selling price of our solutions, (c) our cost of revenues, (d) the introduction of new clean and intelligent energy solutions and (e) our ability to open and enter new markets and regions and expand deeper into markets we already serve. In our demand response business we match obligation, in the form of MW that we agree to deliver to our utility and grid operator customers, with supply, in the form of MW that we are able to curtail from the electric power grid. We increase, and occasionally decrease, our obligation through open market bidding programs and auctions, open program registrations and bilateral contracts. We increase our ability to curtail demand from the electric power grid by deploying a sales team to contract with our commercial, institutional and industrial customers and by installing our equipment at these customers' sites to connect them to our network. When we are called upon by our utility or grid operator customers to deliver MW, we use our software application to dispatch this network to meet the demands of these utility and grid operator customers. We refer to the above activities as managing our portfolio of demand response capacity. In some of our arrangements, we collect additional revenues for successful performance or we pay penalties for underperformance. Our outcomes in negotiating favorable contracts with our commercial, institutional and industrial customers, as well as with our utility and grid operator customers, and managing our portfolio of demand response capacity are the primary determinants of our gross profit and margin.

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 335 full-time employees at September 30, 2008 to 370 full-time employees at September 30, 2009. We expect to continue to hire employees to support our growth for the foreseeable future. In addition, we incur significant up-front costs associated with the expansion of the number of MW under our management, which we expect to continue for the foreseeable future. Although we expect our overall operating expenses to increase in absolute dollar terms for the foreseeable future as we grow our MW under management and further

increase our headcount, we expect our overall annual operating expenses to decrease as a percentage of total annual revenues as we leverage our existing employee base and continue generating revenues from our MW under management.

Selling and Marketing

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

General and Administrative

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

Research and Development

Research and development expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards, related to our engineering organization, (b) payments to suppliers for design and consulting services, (c) costs relating to the design and development of new solutions and enhancement of existing solutions, (d) quality assurance and testing and (e) other related overhead. During the three and nine months ended September 30, 2009, we capitalized internal software and development costs of $0.5 million and $1.7 million, respectively, and the amount is included as software in property and equipment at September 30, 2009. During the three and nine months ended September 30, 2008, we capitalized internal software and development costs of $0.4 million and $1.1 million, respectively. 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

Stock-based compensation is recognized and measured at fair value. For the three and nine months ended September 30, 2009, we recorded expenses of approximately $3.9 million and $10.0 million, respectively, in connection with share-based payment awards to employees and non-employees. With respect to grants through September 30, 2009, a future expense of non-vested options of approximately $17.6 million is expected to be recognized over a weighted average period of 2.3 years and a future expense of restricted stock awards of approximately $4.5 million is expected to be recognized over a weighted average period of 2.3 years. For stock options granted prior to January 1, 2009, the fair value for these options was estimated at the date of grant using a Black-Scholes option-pricing model and for stock options granted on or after January 1, 2009, the fair value of each award is estimated on the date of grant using a trinomial valuation model. If we had continued using the Black-Scholes option pricing model in 2009, stock-based compensation expense would not have been materially different for the three and nine months ended September 30, 2009.

In July 2009, we and Neal C. Isaacson, our then-current chief financial officer and treasurer, agreed that Mr. Isaacson would resign as chief financial officer and treasurer effective as of the close of business on July 30, 2009. In connection with Mr. Isaacson's resignation, the vesting of a certain portion of his outstanding options to purchase shares of our common stock was accelerated. Also in July 2009, we entered into an employment offer letter to hire and retain Timothy Weller as our chief financial officer and treasurer. As part of this employment offer letter, we granted Mr. Weller an aggregate of 80,000 options to purchase shares of our common stock and 20,000 shares of our common stock.

In December 2008, our board of directors approved a one-time offer to our employees, including our executive officers, and directors to exchange option grants that had an exercise price per share that was equal to or greater than the higher of $12.00 or the closing price of our common stock as reported on The NASDAQ Global Market on January 21, 2009, which we refer to as the exchange. The exchange closed on January 21, 2009, and we exchanged options that had exercise prices equal to or greater than $12.00 per share. As a result, an aggregate of 744,401 options, with exercise prices ranging from $12.27 to $48.54 per share, were exchanged for 424,722 options with an exercise price per share of $8.63 for employees who are not also our executive officers, 142,179 options with an exercise price per share of $11.47 for executive officers who are not also our directors and 45,653 options with an exercise price per share of $12.94 for our directors. On the date of the exchange, the estimated fair value of the new options

did not exceed the fair value of the exchanged options calculated immediately prior to the exchange. As such, there was no incremental fair value of the new options, and we will not record additional compensation expense related to the exchange. We will continue to recognize the remaining compensation expense related to the exchanged options over the remaining vesting period of the original options.

Other Income and Expense

Other income and expense consist primarily of interest income earned on cash balances, gain or loss on foreign currency transactions and other non-operating income. We historically have invested our cash in money market funds, treasury funds, commercial paper, municipal bonds and auction rate securities. We do not currently hold any auction rate securities.

Interest Expense

Interest expense consists of interest on our credit facility and fees associated with issuing letters of credit.

Consolidated Results of Operations



Three and Nine Months Ended September 30, 2009 Compared to the Three and Nine
Months Ended September 30, 2008



Revenues



The following table summarizes our revenues for the three and nine months ended
September 30, 2009 and 2008 (dollars in thousands):



                                 Three Months Ended September 30,        Dollar      Percentage
                                     2009                2008            Change        Change
Revenues:
Demand response solutions      $         101,227    $        42,186    $   59,041         140.0 %
Energy management solutions                1,890              1,966           (76 )        (3.9 )%
Total revenues                 $         103,117    $        44,152    $   58,965         133.6 %




                                 Nine Months Ended September 30,        Dollar       Percentage
                                     2009                2008            Change        Change
Revenues:
Demand response solutions      $         158,931    $        81,699    $   77,232           94.5 %
Energy management solutions                5,011              4,751           260            5.5 %
Total revenues                 $         163,942    $        86,450    $   77,492           89.6 %

During the three and nine months ended September 30, 2009, our demand response solutions revenues increased by $59.0 million and $77.2 million, respectively, from the same periods in 2008. The increase in our demand response solutions revenues was primarily attributable to an increase in our MW under management in the following operating areas:

                                         September 30, 2009
                              Three Months Ended     Nine Months Ended
. . .