Enernoc (ENOC) 10-Q 2011 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2011

or

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

For the transition period from            to

Commission File Number: 001-33471

EnerNOC, Inc.

(Exact Name of Registrant as Specified in Its Charter)

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

101 Federal Street
Suite 1100
Boston, Massachusetts	02110
(Address of Principal Executive Offices)	(Zip Code)

(617) 224-9900
(Registrant’s Telephone Number, Including Area Code)

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yesþ Noo

     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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filerþ	Accelerated filero	Non-accelerated filero	Smaller reporting companyo
		(Do not check if a smaller reporting company)

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

     There were 26,763,839 shares of the registrant’s common stock, $0.001 par value per share, outstanding as of August 2, 2011.

EnerNOC, Inc.

Index to Form 10-Q

	Page
Part I — Financial Information
Item 1. Financial Statements
Unaudited Condensed Consolidated Balance Sheets at June 30, 2011 and December 31, 2010		3
Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2011 and 2010		4
Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2011 and 2010		5
Notes to Unaudited Condensed Consolidated Financial Statements		6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		29
Item 3. Quantitative and Qualitative Disclosures About Market Risk		50
Item 4. Controls and Procedures		50
Part II — Other Information
Item 1. Legal Proceedings		50
Item 1A Risk Factors		50
Item 6. Exhibits		57
Signatures		58
Exhibit Index		59
EX-10.1
EX-10.2
EX-31.1
EX-31.2
EX-32.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

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EnerNOC, Inc.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except par value and share data)

	June 30, 2011			December 31, 2010
ASSETS
Current assets
Cash and cash equivalents	$	79,236		$	153,416
Restricted cash		71			1,537
Trade accounts receivable, net of allowance for doubtful accounts of $200 and $150 at June 30, 2011 and December 31, 2010, respectively		33,240			22,137
Unbilled revenue		17,081			73,144
Inventory		239			—
Prepaid expenses, deposits and other current assets		12,602			6,707
Cash held by third party for potential acquisition		28,082			—
Total current assets		170,551			256,941
Property and equipment, net of accumulated depreciation of $42,934 and $36,309 at June 30, 2011 and December 31, 2010, respectively		39,524			34,690
Goodwill		63,895			24,653
Definite-lived intangible assets, net		23,931			5,823
Indefinite-lived intangible assets		530			920
Deposits and other assets		6,392			2,872
Total assets	$	304,823		$	325,899
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	916		$	111
Accrued capacity payments		42,467			65,792
Accrued payroll and related expenses		11,816			11,135
Accrued expenses and other current liabilities		10,403			9,307
Accrued acquisition contingent consideration		—			1,500
Deferred revenue		7,677			5,540
Current portion of long-term debt		17			37
Total current liabilities		73,296			93,422
Long-term liabilities
Deferred acquisition consideration		4,108			—
Deferred tax liability		1,842			1,141
Deferred revenue, long-term		6,609			4,696
Other liabilities		482			514
Total long-term liabilities		13,041			6,351
Commitments and contingencies (Note 8 and Note 12)		—			—
Stockholders’ equity
Undesignated preferred stock, $0.001 par value; 5,000,000 shares authorized; no shares issued		—			—
Common stock, $0.001 par value; 50,000,000 shares authorized, 26,552,123 and 25,155,067 shares issued and outstanding at June 30, 2011 and December 31, 2010, respectively		27			25
Additional paid-in capital		318,516			293,942
Accumulated other comprehensive loss		(46	)		(75	)
Accumulated deficit		(100,011	)		(67,766	)
Total stockholders’ equity		218,486			226,126
Total liabilities and stockholders’ equity	$	304,823		$	325,899

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

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EnerNOC, Inc.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share and per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Revenues	$	58,904		$	66,548		$	90,666		$	94,669
Cost of revenues		38,527			37,556			57,728			56,102
Gross profit		20,377			28,992			32,938			38,567
Operating expenses:
Selling and marketing		13,620			11,531			25,207			20,645
General and administrative		15,899			13,152			32,212			26,901
Research and development		3,350			2,494			6,582			4,551
Total operating expenses		32,869			27,177			64,001			52,097
(Loss) income from operations		(12,492	)		1,815			(31,063	)		(13,530	)
Other expense		(142	)		(14	)		(14	)		(11	)
Interest expense		(238	)		(466	)		(401	)		(491	)
(Loss) income before income tax		(12,872	)		1,335			(31,478	)		(14,032	)
(Provision for) benefit from income tax		(101	)		(257	)		(767	)		910
Net (loss) income	$	(12,973	)	$	1,078		$	(32,245	)	$	(13,122	)
(Loss) income per common share
Basic	$	(0.51	)	$	0.04		$	(1.27	)	$	(0.54	)
Diluted	$	(0.51	)	$	0.04		$	(1.27	)	$	(0.54	)
Weighted average number of common shares outstanding
Basic		25,537,483			24,371,125			25,393,864			24,212,004
Diluted		25,537,483			25,861,957			25,393,864			24,212,004

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

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EnerNOC, Inc.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Six Months Ended June 30,
	2011			2010
Cash flows from operating activities
Net loss	$	(32,245	)	$	(13,122	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation		7,439			6,574
Amortization of acquired intangible assets		2,525			756
Stock-based compensation expense		7,267			8,004
Impairment of property and equipment		340			756
Unrealized foreign exchange transaction (gain) loss		(110	)		30
Deferred taxes		701			(317	)
Non-cash interest expense		56			30
Accretion of fair value of deferred purchase price consideration related to acquisition		183			—
Other, net		159			43
Changes in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable, trade		(8,765	)		(6,118	)
Unbilled revenue		56,063			10,589
Prepaid expenses and other current assets		(2,506	)		(5,055	)
Inventory		199			—
Other assets		(2,794	)		(2	)
Other noncurrent liabilities		(32	)		1,220
Deferred revenue		3,920			2,863
Accrued capacity payments		(23,349	)		(299	)
Accrued payroll and related expenses		1,114			365
Accounts payable and accrued expenses and other current liabilities		(2,113	)		4,659
Net cash provided by operating activities		8,052			10,976
Cash flows from investing activities
Payments made for acquisitions of businesses, net of cash acquired		(41,047	)		(2,001	)
Payments made for contingent consideration related to acquisitions		(1,500	)		—
Cash held by third party for potential acquisition		(28,077	)		—
Purchases of property and equipment		(12,144	)		(12,039	)
Change in restricted cash and deposits		(597	)		(607	)
Change in long-term assets		(522	)		—
Net cash used in investing activities		(83,887	)		(14,647	)
Cash flows from financing activities
Proceeds from exercises of stock options		1,737			2,473
Repayment of borrowings and payments under capital leases		(20	)		(18	)
Net cash provided by financing activities		1,717			2,455
Effects of exchange rate changes on cash		(62	)		(12	)
Net change in cash and cash equivalents		(74,180	)		(1,228	)
Cash and cash equivalents at beginning of period		153,416			119,739
Cash and cash equivalents at end of period	$	79,236		$	118,511
Non-cash financing and investing activities
Issuance of common stock in connection with acquisitions	$	15,132		$	1,066
Issuance of common stock in satisfaction of bonuses	$	440		$	775
Increase in deferred acquisition consideration	$	3,925		$	—

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

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EnerNOC, Inc.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(in thousands, except share and per share data)

1. Description of Business and Basis of Presentation

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 clean and intelligent energy management applications and services for the smart grid, which include comprehensive demand response, data-driven energy efficiency, energy price and risk management, and enterprise carbon management applications and services. The Company’s energy management applications and services enable cost effective energy management strategies for its commercial, institutional and industrial end-users of energy (C&I customers) and its electric power grid operator and utility customers by reducing real-time demand for electricity, increasing energy efficiency, improving energy supply transparency, and mitigating emissions. The Company uses its Network Operations Center (NOC) and comprehensive demand response application, DemandSMART, to remotely manage and reduce electricity consumption across a growing network of C&I customer sites, making demand response capacity available to electric power grid operators and utilities on demand while helping C&I customers achieve energy savings, improved financial results and environmental benefits. To date, the Company has received substantially all of its revenues from electric power grid operators and utilities, who make recurring payments to the Company for managing demand response capacity that it shares with its C&I customers in exchange for those C&I customers reducing their power consumption when called upon.

     The Company builds on its position as a leading demand response services provider by using its NOC and energy management application platform to deliver a portfolio of additional energy management applications and services to new and existing C&I, electric power grid operator and utility customers. These additional energy management applications and services include its EfficiencySMART, SupplySMART and CarbonSMART applications and services. EfficiencySMART is its data-driven energy efficiency suite that includes commissioning and retro-commissioning authority services, energy consulting and engineering services, a persistent commissioning application and an enterprise energy management application for managing energy across a portfolio of sites. SupplySMART is its energy price and risk management application that provides its C&I 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, budget forecasting, and utility bill information management. CarbonSMART is its enterprise carbon management application that supports and manages the measurement, tracking, analysis, reporting and management of greenhouse gas emissions.

Reclassifications

     The Company has reclassified certain costs in its unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2010 totaling $754 and $1,491, respectively, previously included in selling and marketing expenses as general and administrative expenses to more appropriately reflect the nature of these costs.

Basis of Consolidation

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

     On January 3, 2011, the Company acquired all of the outstanding capital stock of Global Energy Partners, Inc. (Global Energy) in a purchase business combination. Accordingly, the results of Global Energy subsequent to that date are included in the Company’s unaudited condensed consolidated statements of operations.

     On January 25, 2011, the Company acquired all of the outstanding capital stock of M2M Communications Corporation (M2M) in a purchase business combination. Accordingly, the results of M2M subsequent to that date are included in the Company’s unaudited condensed consolidated statements of operations.

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Subsequent Events Consideration

     The Company considers events or transactions that occur after the balance sheet date but prior to the issuance of the financial statements to provide additional evidence relative to certain estimates or to identify matters that require additional disclosure. Subsequent events have been evaluated as required.

Energy Response Holdings Pty Ltd Acquisition

     On July 1, 2011, the Company and one of its subsidiaries completed an acquisition of all of the outstanding stock of Energy Response Holdings Pty Ltd (Energy Response), a privately-held company headquartered in Australia specializing in demand response and other energy management services in Australia and New Zealand, pursuant to a definitive agreement dated July 1, 2011. The Company concluded that this acquisition represented a business combination and, therefore, has accounted for it as such. The Company believes Energy Response will enhance and broaden the Company’s service offerings in Australia and New Zealand.

     The Company acquired Energy Response for an aggregate purchase price of $29,286, plus an additional $470 paid as working capital and other adjustments, consisting of $27,265 in cash paid at closing and $2,491 representing the fair value of 156,697 shares of stock issued as of the acquisition date. In addition to the amounts paid at closing, the Company may be obligated to pay additional contingent purchase price consideration related to an earn-out amount of $10,718. The earn-out payment, if any, will be based on the development of a demand response reserve capacity market in the National Electricity Market in Australia by December 31, 2013 that meets certain market size and price per megawatt conditions. This milestone needs to be achieved in order for the earn-out payment to occur and there will be no partial payment if the milestone is not fully achieved. The Company is still gathering information in order to determine the fair value of the contingent purchase price consideration as of the acquisition date. Any changes in fair value after the completion of this fair value analysis will be recorded to the Company’s consolidated statements of operations. The difference between the $29,286 aggregate purchase price disclosed above and the $29,475 aggregate purchase price set forth in the definitive agreement was due to the fact that the fair value of stock issued in connection with the acquisition was based upon the Company’s stock price as of the closing date of the acquisition of $15.90 per share, as compared to a per share value of $17.10 determined in accordance with the definitive agreement, which is based upon the average of the per share last sale price for the Company’s common stock for the thirty trading day period ending two trading days prior to the closing.

     Transaction costs related to this business combination have been expensed as incurred, which are included in general and administrative expenses in the accompanying consolidated statements of operations. The Company’s consolidated financial statements will reflect Energy Response’s results of operations from July 1, 2011 forward.

     The Company is in the process of gathering information to complete its preliminary valuation of certain assets and liabilities in order to complete a preliminary purchase price allocation.

     There were no other material recognizable subsequent events recorded or requiring disclosure in the June 30, 2011 unaudited condensed consolidated financial statements.

Use of Estimates in Preparation of Financial Statements

     The accompanying unaudited condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to SEC rules and regulations. In the opinion of the Company’s management, the unaudited condensed consolidated financial statements and notes have been prepared on the same basis as the audited consolidated financial statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, and include all adjustments (consisting of normal, recurring adjustments) necessary for the fair presentation of the Company’s financial position at June 30, 2011 and statements of operations and statements of cash flows for the three and six months ended June 30, 2011 and 2010. Operating results for the three and six months ended June 30, 2011 are not necessarily indicative of the results to be expected for any other interim period or the entire fiscal year ending December 31, 2011.

     The preparation of these unaudited condensed consolidated financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, the Company evaluates its estimates, including those related to revenue recognition, allowance for doubtful accounts, valuations and purchase price allocations related to business combinations, fair value of deferred acquisition consideration, expected future cash flows including growth rates, discount rates, terminal values and other assumptions and estimates used to evaluate the recoverability of long-lived assets and goodwill, estimated fair values of intangible assets and goodwill,

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amortization methods and periods, certain accrued expenses and other related charges, stock-based compensation, contingent liabilities, tax reserves and recoverability of the Company’s net deferred tax rates and related valuation allowance.

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

     The Company is subject to a number of risks similar to those of other companies of similar and different sizes both inside and outside its industry, including, but not limited to, rapid technological changes, competition from substitute energy management applications and services provided by larger companies, customer concentration, government regulations, market or program rule changes, protection of proprietary rights and dependence on key individuals.

Restricted Cash, Cash Equivalents and Cash Held by Third Party for Potential Acquisition

     Restricted cash is comprised of certificates of deposit and cash held to collateralize the Company’s outstanding letters of credit and certain other commitments. Cash equivalents are highly liquid investments with insignificant interest rate risk and maturities of three months or less at the time of acquisition. Investments qualifying as cash equivalents consist of investments in money market funds, which have no withdrawal restrictions or penalties and totaled $62,638 and $108,000 at June 30, 2011 and December 31, 2010, respectively.

     Cash held by third party for potential acquisition represents cash that the Company transferred to a third party agent at the end of June 2011 in anticipation of the potential acquisition of Energy Response. On July 1, 2011, the Company completed its acquisition of all of the outstanding stock of Energy Response. Cash utilized to complete the acquisition of Energy Response totaled $27,265 and the excess cash held by the third party was returned to the Company in July 2011.

Revenue Recognition

     The Company recognizes revenues in accordance with Accounting Standards Codification (ASC) 605,Revenue Recognition. 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 reasonably assured. In making these judgments, the Company evaluates these criteria as follows:

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

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

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

• Collection is reasonably assured.The Company conducts a credit review at the inception of an arrangement to determine the creditworthiness of the customer. Collection is reasonably assured if, based upon evaluation, the Company 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 reasonably assured, revenues are deferred and recognized upon the receipt of cash.

     The Company enters into contracts and open market bidding programs with utilities and electric power grid operators to provide demand response applications and services. Demand response revenues consist of two elements: revenue earned based on the Company’s ability to deliver committed capacity to its electric power grid operator and utility customers, which the Company refers to as capacity revenue; and revenue earned based on additional payments made to the Company for the amount of energy usage actually curtailed from the grid during a demand response event, which the Company refers to as energy event revenue.

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     The Company recognizes demand response revenue when it has provided verification to the electric power grid operator or utility of its ability to deliver the committed capacity which entitles the Company to payments under the contract or open market program. Committed capacity is generally 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 electric power grid operator or utility customer will reduce future payments based on the adjusted verified capacity amounts. 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 and the amount of refund cannot be reliably estimated, the revenue is deferred until the right of refund lapses.

     In one of the open market programs in which the Company participates, the program year operates on a June to May basis and performance is measured based on the aggregate performance during the months of June through September. As a result, fees received for the month of June could potentially be subject to adjustment or refund based on performance during the months of July through September. The Company has concluded that it can reliably estimate the amount of fees potentially subject to adjustment or refund and records a reserve for this amount in the month of June. As of June 30, 2011, the Company had recorded an estimated reserve of $9,260 related to potential subsequent performance adjustments. The fees under this program are fixed as of September 30 and the Company will record any change in estimate based on final performance during the three months ending September 30, 2011. Historically, the changes in estimate have not been material.

     As a result of a contractual amendment entered into during the three months ended March 31, 2011 to amend certain refund provisions included in one of the Company’s contracts with a utility customer, the Company concluded that it could reliably estimate the fees potentially subject to refund as of March 31, 2011 and therefore, the fees under this arrangement were fixed or determinable. As a result, during the three months ended March 31, 2011, the Company recognized as revenues $3,025 of fees that had been previously deferred as of December 31, 2010.

     Certain of the forward capacity programs in which the Company participates may be deemed derivative contracts under ASC 815,Derivatives and Hedging(ASC 815). In such situations, the Company believes it meets the scope exception under ASC 815 as a normal purchase, normal sale as that term is defined in ASC and, accordingly, the arrangement is not treated as a derivative contract.

     Energy event revenues are 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 electric power grid operator or utility customer and the Company has responded under the terms of the contract or open market program.

     Under certain of the Company’s arrangements, in particular those arrangements entered into by M2M, the Company sells proprietary equipment to a C&I customer that is utilized to provide the ongoing services that the Company delivers. Currently, this equipment has been determined to not have stand-alone value. As a result, the Company defers the fees associated with the equipment and, once the C&I customer is receiving the ongoing services from the Company, recognizes those fees ratably over the expected C&I customer relationship period, which is generally three years. In addition, the Company capitalizes the associated direct and incremental costs, which primarily represent the equipment and third-party installation costs, and recognizes such costs over the expected C&I customer relationship period.

     In September 2009, the Financial Accounting Standards Board (FASB) ratified ASC Update No. 2009-13,Multiple-Deliverable Revenue Arrangements(ASU 2009-13). ASU 2009-13 amends existing revenue recognition accounting pronouncements that are currently within the scope of ASC Subtopic 605-25, which is the revenue recognition guidance for multiple-element arrangements. ASU 2009-13 provides for three significant changes to the existing multiple-element revenue recognition guidance as follows:

• deletes the requirement to have objective and reliable evidence of fair value for undelivered elements in an arrangement. This may result in more deliverables being treated as separate units of accounting;

• modifies the manner in which the arrangement consideration is allocated to the separately identified deliverables. ASU 2009-13 requires an entity to allocate revenue in an arrangement using its best estimate of selling prices (ESP) of deliverables if a vendor does not have vendor-specific objective evidence of selling price (VSOE) or third-party evidence of selling price (TPE), if VSOE is not available. Each separate unit of accounting must have a selling price, which can be based on management’s estimate when there is no other means (VSOE or TPE) to determine the selling price of that deliverable. The arrangement consideration is allocated based on the elements’ relative selling prices; and

• eliminates use of the residual method and requires an entity to allocate revenue using the relative selling price method, which results in the discount in the transaction being evenly allocated to the separate units of accounting.

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     As required, the Company adopted this new accounting guidance at the beginning of its first quarter of the fiscal year ending December 31, 2011 (fiscal 2011) on a prospective basis for transactions originating or materially modified on or after January 1, 2011. This accounting guidance generally does not change the units of accounting for the Company’s revenue transactions. The impact of adopting this new accounting guidance was not material to the Company’s financial statements during the six months ended June 30, 2011, and if they were applied in the same manner to the fiscal year ending December 31, 2010 (fiscal 2010) would not have had a material impact to revenue for the six months ended June 30, 2010. The Company does not expect the adoption of this new accounting guidance to have a significant impact on the timing and pattern of revenue recognition in the future due to the Company’s limited number of multiple element arrangements. The key impact that the Company expects the adoption of this new accounting guidance to have relates to certain EfficiencySMART service arrangements with C&I customers who also provide curtailment of capacity as part of the Company’s demand response arrangements. Historically, the Company had recorded the fees recognized under these arrangements as a reduction of cost of revenues as evidence of fair value did not exist for persistent commissioning services due to the limited history of selling these separately and lack of availability of TPE. As previously stated, the impact of this change has not been and is not expected to be material.

     The Company typically determines the selling price of its services based on VSOE. Consistent with its methodology under previous accounting guidance, the Company determines VSOE based on its normal pricing and discounting practices for the specific service when sold on a stand-alone basis. In determining VSOE, the Company’s policy is to require a substantial majority of selling prices for a product or service to be within a reasonably narrow range. The Company also considers the class of customer, method of distribution, and the geographies into which its products and services are sold into when determining VSOE. The Company typically has had VSOE for its products and services.

     In certain circumstances, the Company is not able to establish VSOE for all deliverables in a multiple element arrangement. This may be due to the infrequent occurrence of stand-alone sales for an element, a limited sales history for new services or pricing within a broader range than permissible by the Company’s policy to establish VSOE. In those circumstances, the Company proceeds to the alternative levels in the hierarchy of determining selling price. TPE of selling price is established by evaluating largely similar and interchangeable competitor products or services in stand-alone sales to similarly situated customers. The Company is typically not able to determine TPE and has not used this measure since the Company has been unable to reliably verify standalone prices of competitive solutions. ESP is established in those instances where neither VSOE nor TPE are available, considering internal factors such as margin objectives, pricing practices and controls, customer segment pricing strategies and the product life cycle. Consideration is also given to market conditions such as competitor pricing information gathered from experience in customer negotiations, market research and information, recent technological trends, competitive landscape and geographies. Use of ESP is limited to a very small portion of the Company’s services, principally certain EfficiencySMART services.

Comprehensive (Loss) Income

     Comprehensive (loss) income is defined as the change in equity of a business enterprise during a period resulting from transactions and other events and circumstances from non-owner sources. Comprehensive (loss) income is composed of net (loss) income and foreign currency translation adjustments. As of June 30, 2011 and 2010, accumulated other comprehensive loss was comprised solely of cumulative foreign currency translation adjustments. The Company presents its components of other comprehensive (loss) income, net of related tax effects, which have not been material to date.

Comprehensive (loss) income for the three and six months ended June 30, 2011 and 2010 was as follows:

	Three months ended June 30,					Six months ended June 30,
	2011			2010		2011			2010
Net (loss) income	$	(12,973	)	$	1,078	$	(32,245	)	$	(13,122	)
Foreign currency translation adjustments		28			80		29			32
Total comprehensive (loss) income	$	(12,945	)	$	1,158	$	(32,216	)	$	(13,090	)

Software Development Costs

     The Company applies the provisions of ASC 350-40,Internal-Use Software(ASC 350-40).ASC 350-40 requires computer software costs associated with internal use software to be expensed as incurred until certain capitalization criteria are met, and it also defines which types of costs should be capitalized and which should be expensed. The Company capitalizes the payroll and payroll-related costs of employees and third-party consultants who devote time to the development of internal-use computer software. The

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

     Software development costs of $2,272 and $2,774 for the three months ended June 30, 2011 and 2010, respectively, and $3,109 and $4,018 for the six months ended June 30, 2011 and 2010, respectively, have been capitalized in accordance with ASC 350-40. The capitalized amount was included as software in property and equipment at June 30, 2011 and December 31, 2010. The Company capitalized $0 and $390 during the three months ended June 30, 2011 and 2010, respectively, and $13 and $968 for the six months ended June 30, 2011 and 2010, respectively, related to a company-wide enterprise resource planning systems implementation project, which was put into production in June 2011 and is being amortized over a five year useful life. Amortization of capitalized internal use software costs was $1,026 and $676 for the three months ended June 30, 2011 and 2010, respectively, and $1,868 and $1,374 for the six months ended June 30, 2011 and 2010, respectively. Accumulated amortization of capitalized internal use software costs was $9,002 and $7,134 as of June 30, 2011 and December 31, 2010, respectively.

Impairment of Property and Equipment

     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. If these assets are considered to be impaired, the impairment is recognized in earnings and equals the amount by which the carrying value of the assets exceeds their fair market value determined by either a quoted market price, if any, or a value determined by utilizing a discounted cash flow technique. If these assets are not impaired, but their useful lives have decreased, the remaining net book value is amortized over the revised useful life.

     During the three months ended June 30, 2011, the Company identified a potential impairment indicator related to certain demand response and back-up generator equipment as a result of lower than estimated demand response event performance by these assets. As a result of this potential indicator of impairment, the Company performed an impairment test during the three months ended June 30, 2011. The applicable long-lived assets are measured for impairment at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets or liabilities. The Company determined that the undiscounted cash flows to be generated by the asset group over its remaining estimated useful life would not be sufficient to recover the carrying value of the asset group. The Company determined the fair value of the asset group using a discounted cash flow technique based on Level 3 inputs, as defined by ASC 820,Fair Value Measurements and Disclosures(ASC 820), and a discount rate of 11%, which the Company determined represents a market rate of return for the assets being evaluated for impairment. The Company determined that the fair value of the asset group was $57 compared to the carrying value of the asset group of $83, and as a result recorded an impairment charge of $26 during the three months ended June 30, 2011, which is reflected in cost of revenues in the accompanying unaudited condensed consolidated statements of operations. The impairment charge was allocated to the individual assets within the asset group on a pro-rata basis using the relative carrying amounts of those assets.

     During the three months ended June 30, 2011, the Company identified an impairment indicator related to certain demand response equipment as a result of the removal of such equipment from service during the three months ended June 30, 2011. As a result of this impairment indicator, the Company performed an impairment test during the three months ended June 30, 2011 and recognized an impairment charge of $204 during the three months ended June 30, 2011, representing the difference between the carrying value and fair market value of the demand response equipment, which is included in cost of revenues in the accompanying consolidated statements of operations. The fair market value was determined utilizing Level 3 inputs, as defined by ASC 820, based on the projected future cash flows discounted using the estimated market participant rate of return for this type of asset.

     During the three months ended March 31, 2011, the Company identified an impairment indicator related to certain demand response equipment as a result of the removal of such equipment from service during the three months ended March 31, 2011. As a result of this impairment indicator, the Company performed an impairment test during the three months ended March 31, 2011 and recognized an impairment charge of $110 during the three months ended March 31, 2011, representing the difference between the carrying value and fair market value of the demand response equipment, which is included in cost of revenues in the accompanying consolidated statements of operations. The fair market value was determined utilizing Level 3 inputs, as defined by ASC 820, based on the projected future cash flows discounted using the estimated market participant rate of return for this type of asset.

     As of June 30, 2011, approximately $1,819 of the Company’s generation equipment is utilized in open market programs. The recoverability of the carrying value of this generation equipment is largely dependent on the rates that the Company is compensated for its committed capacity within these programs. These rates represent market rates and can fluctuate based on the supply and demand of capacity. Although these market rates are established up to three years in advance of the service delivery, these market rates have not yet been established for the entire remaining useful life of this generation equipment. In performing its impairment analysis, the Company estimates the expected future market rates based on current existing market rates and trends. A decline in the expected future market rates of 10% by itself would not result in an impairment charge related to this generation equipment.

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Inventories

     Inventories are valued at the lower of cost or market on a first in, first out basis. Work-in-process and finished goods inventories consist of materials, labor and manufacturing overhead. The valuation of inventory requires management to estimate excess and obsolete inventory. The Company employs a variety of methodologies to determine the net realizable value of its inventory. Provisions for excess and obsolete inventory are primarily based on management’s estimates of forecasted net sales and service usage levels. A significant change in the timing or level of demand for the Company’s products as compared to forecasted amounts may result in recording additional provisions for excess and obsolete inventory in the future. The Company records provisions for excess and obsolete inventory as cost of product sales. As of June 30, 2011, the Company had $239 of inventory, which primarily consisted of raw materials related to M2M.

Industry Segment Information

     The Company is required to disclose the standards for reporting information about its operating segments in annual financial statements and required selected information of these segments being presented in interim financial reports issued to stockholders. Operating segments are defined as components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, in making decisions on how to allocate resources and assess performance. The Company’s chief decision maker is considered to be the team comprised of the chief executive officer and the executive management team. The Company views its operations and manages its business as one operating segment.

     The Company operates in the several geographic areas, primarily the United States, Canada, United Kingdom and Australia. Revenues derived from United States operations comprise the majority of consolidated revenues. International subsidiaries comprised less than 10% of consolidated revenues for the three and six months ended June 30, 2011 and June 30, 2010, respectively, and are not expected to exceed 10% of consolidated revenues for fiscal 2011.

     As of June 30, 2011 and December 31, 2010, the long-lived assets related to the Company’s international subsidiaries were not material to the accompanying unaudited condensed consolidated financial statements taken as a whole.

2. Acquisitions

Global Energy Partners, Inc.

     In January 2011, the Company acquired all of the outstanding stock of Global Energy, a privately-held company located in California specializing in the design and implementation of utility energy efficiency and demand response programs. The Company believes that Global Energy’s service offerings will enhance and broaden its portfolio of service offerings in the area of energy efficiency and demand response.

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     The Company concluded that the acquisition of Global Energy did not represent a material business combination and therefore, no pro forma financial information has been provided herein. Subsequent to the acquisition date, the Company’s results of operations include the results of operations of Global Energy. The Company accounted for the acquisition of Global Energy as a purchase of a business under ASC 805,Business Combinations(ASC 805).

     The total purchase price paid by the Company at closing was approximately $26,658, consisting of $19,875 in cash and the remainder of which was paid by the issuance of 275,181 shares of the Company’s common stock that had a fair value of approximately $6,783. The fair value of these shares was measured as of the acquisition date using the closing price of the Company’s common stock, as reported on The NASDAQ Global Market (NASDAQ) on January 3, 2011. This acquisition had no contingent consideration or earn-out payments.

     Transaction costs related to this business combination were not material and have been expensed as incurred, which are included in general and administrative expenses in the accompanying consolidated statements of operations.

     During the three months ended June 30, 2011, based on additional information gathered related to the fair value of certain acquired assets and liabilities, the Company recorded adjustments to the allocation of the purchase price, resulting in a reduction of net tangible assets acquired of $120 and a corresponding increase to goodwill.

     The components and allocation of the purchase price consist of the following approximate amounts:

Net tangible assets acquired as of January 3, 2011	$	468
Customer relationships		6,430
Non-compete agreements		420
Developed technology		50
Trade name		260
Goodwill		19,030
Total	$	26,658

     Net tangible assets acquired in the acquisition of Global Energy primarily related to the following:

Cash	$	273
Accounts receivable		1,049
Prepaids and other assets		35
Property and equipment		183
Accounts payable		(196	)
Accrued expenses and other liabilities		(876	)
Total	$	468

Identifiable Intangible Assets

     As part of the preliminary purchase price allocation, the Company determined that Global Energy’s separately identifiable intangible assets were its customer relationships, non-compete agreements, developed technology and trade name. Developed technology represented certain proprietary software tools that Global Energy had developed and are utilized on certain consulting projects. As of the date of acquisition, the Company determined that there was no in-process research and development as the ongoing research and development efforts were nominal and related to routine, on-going maintenance efforts.

     The Company used the income approach to value the customer relationships, non-compete agreements, developed technology and trade name. This approach calculates fair value by discounting the after-tax cash flows back to a present value. The baseline data for this analysis was the cash flow estimates used to price the transaction. Cash flows were forecasted for each intangible asset then discounted based on an appropriate discount rate. The discount rates applied, which ranged between 10% and 16%, were benchmarked with reference to the implied rate of return from the transaction model as well as an estimate of a market-participant’s weighted average cost of capital based on the capital asset pricing model.

     In estimating the useful life of the acquired assets, the Company considered ASC 350-30-35General Intangibles Other Than Goodwill(ASC 350-30-35), which lists the pertinent factors to be considered when estimating the useful life of an intangible asset.

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These factors included a review of the expected use by the combined company of the assets acquired, the expected useful life of another asset (or group of assets) related to the acquired assets, legal, regulatory or other contractual provisions that may limit the useful life of an acquired asset or may enable the extension of the useful life of an acquired asset without substantial cost, the effects of obsolescence, demand, competition and other economic factors, and the level of maintenance expenditures required to obtain the expected future cash flows from the asset. The Company is amortizing these intangible assets over their estimated useful lives using a method that is based on estimated future cash flows, as the Company believes this will approximate the pattern in which the economic benefits of the assets will be utilized, or where the Company has determined if it was deemed that the cash flows were not reliably determinable, on a straight-line basis. The acquisition of Global Energy was deemed to be an asset purchase for income tax purposes. Accordingly, no deferred taxes were established relating to the fair value of the acquired intangible assets.

     The factors contributing to the recognition of this amount of goodwill were based upon several strategic and synergistic benefits that are expected to be realized from the combination. Substantially all of the goodwill is expected to be deductible for tax purposes.

M2M Communications Corporation

     On January 21, 2011, the Company entered into a definitive agreement to acquire M2M, a privately-held company located in Idaho. The acquisition closed on January 25, 2011. M2M is a leading provider of wireless technology solutions for demand response. By integrating M2M’s wireless technology solutions into the Company’s energy management applications and services, the Company believes that it will be able to enhance its automated demand response offering and deliver more value to its rapidly growing C&I customer base.

     The Company concluded that the acquisition of M2M did not represent a material business combination and therefore, no pro forma financial information has been provided herein. Subsequent to the acquisition date, the Company’s results of operations include the results of operations of M2M. The Company accounted for the acquisition of M2M as a purchase of a business under ASC 805.

     The total initial purchase price paid by the Company at closing was approximately $29,871, consisting of $17,597 in cash, $3,925 representing the estimated fair value of $7,000 of deferred purchase price consideration determined at closing, and the remainder of which was paid by the issuance of 351,665 shares of the Company’s common stock that had a fair value of approximately $8,349. The fair value of these shares was measured as of the acquisition date using the closing price of the Company’s common stock, as reported on NASDAQ on January 25, 2011. The deferred purchase price consideration of $7,000 will be paid upon the earlier of the satisfaction of certain conditions contained in the definitive agreement or seven years after the acquisition date of January 25, 2011. The deferred purchase price consideration is not subject to adjustment or forfeiture. The Company recorded its estimate of the fair value of the deferred purchase price consideration based on the evaluation of the likelihood of the achievement of the contractual conditions that would result in the payment of the deferred purchase price consideration prior to seven years from the acquisition date and weighted probability assumptions of these outcomes. This fair value measurement was based on significant inputs not observable in the market and therefore, represented a Level 3 measurement as defined in ASC 820,Fair Value Measurements and Disclosures (ASC 820). As of June 30, 2011, there were no significant changes in the estimated timing of payment of the deferred purchase price consideration. Since this liability has been discounted, as the time period to payment shortens, the liability will increase and this change in fair value is being recorded as an expense in the Company’s accompanying unaudited condensed consolidated statements of operations with a portion of the charge being recorded to cost of revenues related to the component of the deferred purchase price consideration related to the achievement of certain gross profit metrics and the remaining portion of the charge being recorded to general and administrative expenses. During the three and six months ended June 30, 2011, the Company recorded a charge of $110 and $183, respectively. Of the $110 recorded for the three months ended June 30, 2011, $52 was recorded to cost of revenues and $58 was recorded to general and administrative expenses. Of the $183 recorded for the six months ended June 30, 2011, $87 was recorded to cost of revenues and $96 was recorded to general and administrative expenses. At June 30, 2011, the liability was recorded at $4,108. This acquisition had no contingent consideration or earn-out payments.

     As a result of gathering information to update the Company’s valuation allocation, the Company asserted that the estimated merger consideration paid at the closing exceeded the final merger consideration. The Company and the former stockholders of M2M reached a settlement agreement to reduce the purchase price by $1,250, which was recorded in prepaids, deposits and other current assets in the accompanying unaudited condensed consolidated balance sheets as of June 30, 2011. This reduction in purchase price reduced the fair value of the customer relationships and non-compete agreements intangible assets acquired by $100 and $10, respectively. The additional $1,140 reduction in purchase price was recorded as a reduction of goodwill. The Company will receive 45,473 shares of common stock, which is based on the fair value used to determine the stock consideration issued in connection with the acquisition of $23.74 per share and represents a fair value of $1,125, and cash of $125 from escrow.

     Transaction costs related to this business combination were not material and have been expensed as incurred, which are included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations.

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     The allocation of the purchase price is based upon preliminary estimates of the fair value of assets acquired and liabilities assumed as of January 25, 2011. The Company is in the process of gathering information to finalize its valuation of certain assets and liabilities. The purchase price allocation is preliminary and will be finalized once the Company has all necessary information to complete its estimate, but generally no later than one year from the date of acquisition.

     The components and allocation of the purchase price consist of the following approximate amounts:

Net tangible assets acquired as of January 25, 2011	$	1,148
Customer relationships		4,700
Non-compete agreements		270
Developed technology		3,000
Trade name		400
Goodwill		19,103
Total	$	28,621

     Net tangible assets acquired in the acquisition of M2M primarily related to the following:

Cash	$	70
Accounts receivable		1,444
Inventory		437
Property and equipment		272
Other current assets		182
Accounts payable		(458	)
Accrued expenses		(286	)
Borrowing under line of credit arrangement		(500	)
Other long-term liabilities		(13	)
Total	$	1,148

     In connection with the acquisition of M2M, the Company acquired M2M’s outstanding borrowing under M2M’s line of credit arrangement with a financial institution. At closing, the Company fully repaid these borrowings and M2M’s line of credit arrangement was terminated.

Identifiable Intangible Assets

     As part of the preliminary purchase price allocation, the Company determined that M2M’s separately identifiable intangible assets were its customer relationships, non-compete agreements, developed technology and trade name. Developed technology represented the products and related software that M2M had developed for its wireless technology applications. As of the date of the acquisition, the Company determined that there was no in-process research and development as the ongoing research and development efforts related solely to routine, on-going efforts to refine, enrich, or otherwise improve the qualities of the existing product, and the adaptation of existing capability to a particular requirement or customer’s need as part of a contractual arrangement (i.e. configuring equipment for specific customer requirements) which do not meet the criteria of in-process research and development.

     The Company used the income approach to value the customer relationships, non-compete agreements, developed technology and trade name. This approach calculates fair value by discounting the after-tax cash flows back to a present value. The baseline data for this analysis was the cash flow estimates used to price the transaction. Cash flows were forecasted for each intangible asset then discounted based on an appropriate discount rate. The discount rates applied, which ranged between 10% and 18%, were benchmarked with reference to the implied rate of return from the transaction model as well as an estimate of a market-participant’s weighted average cost of capital based on the capital asset pricing model.

     In estimating the useful life of the acquired assets, the Company considered ASC 350-30-35, which lists the pertinent factors to be considered when estimating the useful life of an intangible asset. These factors included a review of the expected use by the combined company of the assets acquired, the expected useful life of another asset (or group of assets) related to the acquired assets, legal, regulatory or other contractual provisions that may limit the useful life of an acquired asset or may enable the extension of the useful life of an acquired asset without substantial cost, the effects of obsolescence, demand, competition and other economic factors, and the level of maintenance expenditures required to obtain the expected future cash flows from the asset. The Company is

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amortizing these intangible assets over their estimated useful lives using a method that is based on estimated future cash flows, as the Company believes this will approximate the pattern in which the economic benefits of the assets will be utilized, or where the Company has determined if it was deemed that the cash flows were not reliably determinable, on a straight-line basis. The acquisition of M2M was deemed to be an asset purchase for income tax purposes. Accordingly, no deferred taxes were established relating to the fair value of the acquired intangible assets.

     The factors contributing to the recognition of this amount of goodwill were based upon the Company’s determination that several strategic and synergistic benefits are expected to be realized from the combination. Substantially all of the goodwill is expected to be deductible for tax purposes.

Other Immaterial Acquisitions

     In January 2011, the Company completed its acquisition of a privately-held company specializing in demand response services. The Company believes that this acquisition will enhance and broaden the Company’s international service offerings.

     The Company concluded that the acquisition did not represent a material business combination and therefore, no pro forma financial information has been provided herein. Subsequent to the acquisition date, the Company’s results of operations include the results of operations of the acquired company. The Company accounted for this acquisition as a purchase of a business under ASC 805.

     The total purchase price paid by the Company at closing was approximately $5,193, consisting of $3,918 in cash at closing, $779 paid as consideration to settle the acquired company’s outstanding debt obligations and $496 of cash consideration to be paid upon satisfaction of certain general representations and warranties, which will be paid in one year or less and is included in accrued expenses and other current liabilities in the accompanying unaudited condensed consolidated balance sheets as of June 30, 2011. This acquisition had no contingent consideration or earn-out payments. The Company did not issue any shares of its capital stock in connection with this acquisition.

     Transaction costs related to this business combination were not material and have been expensed as incurred, which are included in general and administrative expenses in the accompanying consolidated statements of operations.

     The allocation of the purchase price is based upon preliminary estimates of the fair value of assets acquired and liabilities assumed as of January 25, 2011. The Company is in the process of gathering information to finalize its valuation of certain assets and liabilities. The purchase price allocation is preliminary and will be finalized once the Company has all necessary information to complete its estimate, but generally no later than one year from the date of acquisition.

     The components and allocation of the purchase price consist of the following approximate amounts:

Net tangible liabilities assumed as of January 25, 2011	$	(319	)
Customer relationships		4,400
Non-compete agreements		20
Trade name		50
Goodwill		1,042
Total	$	5,193

     Net tangible liabilities assumed in this acquisition primarily related to the following:

Other receivables	$	35
Accounts payable		(354	)
Total	$	(319	)

Identifiable Intangible Assets

     As part of the preliminary purchase price allocation, the Company determined that the acquired company’s separately identifiable intangible assets were its customer relationships, non-compete agreements and trade name. The acquired company had no developed technology nor were there any ongoing research and development efforts as of the date of acquisition.

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     The Company used the income approach to value the customer relationships, non-compete agreements and trade name. This approach calculates fair value by discounting the after-tax cash flows back to a present value. The baseline data for this analysis was the cash flow estimates used to price the transaction. Cash flows were forecasted for each intangible asset then discounted based on an appropriate discount rate. The discount rates applied, which ranged between 16% and 28%, were benchmarked with reference to the implied rate of return from the transaction model as well as an estimate of a market-participant’s weighted average cost of capital based on the capital asset pricing model.

     In estimating the useful life of the acquired assets, the Company considered ASC 350-30-35, which lists the pertinent factors to be considered when estimating the useful life of an intangible asset. These factors included a review of the expected use by the combined company of the assets acquired, the expected useful life of another asset (or group of assets) related to the acquired assets, legal, regulatory or other contractual provisions that may limit the useful life of an acquired asset or may enable the extension of the useful life of an acquired asset without substantial cost, the effects of obsolescence, demand, competition and other economic factors, and the level of maintenance expenditures required to obtain the expected future cash flows from the asset. The Company is amortizing these intangible assets over their estimated useful lives using a method that is based on estimated future cash flows, as the Company believes this will approximate the pattern in which the economic benefits of the assets will be utilized, or where the Company has determined if it was deemed that the cash flows were not reliably determinable, on a straight-line basis.

     The factors contributing to the recognition of this amount of goodwill were based upon the Company’s determination that several strategic and synergistic benefits were expected to be realized from the combination. None of the goodwill is expected to be expected to be currently deductible for tax purposes.

3. Impairment of Intangible Assets and Goodwill

Definite-Lived Intangible Assets

     The Company amortizes its intangible assets that have finite lives using either the straight-line method or, if reliably determinable, based on the pattern in which the economic benefit of the asset is expected to be consumed utilizing expected undiscounted future cash flows. Amortization is recorded over the estimated useful lives ranging from one to ten years.

     The following table provides the gross carrying amount and related accumulated amortization of intangible assets as of June 30, 2011 and December 31, 2010:

			As of June 30, 2011					As of December 31, 2010
	Weighted Average		Gross					Gross
	Amortization		Carrying		Accumulated			Carrying		Accumulated
	Period (in years)		Amount		Amortization			Amount		Amortization
Customer contracts		5.77	$	4,217	$	(1,800	)	$	4,217	$	(1,593	)
Employment agreements and non-compete agreements		2.64		1,482		(479	)		772		(309	)
Software		0.97		120		(83	)		120		(63	)
Developed technology		3.46		3,440		(330	)		—		—
Customer relationships		4.80		19,283		(2,724	)		3,510		(1,016	)
Trade name		2.88		825		(196	)		115		(115	)
Patents		8.69		200		(24	)		200		(15	)
Total			$	29,567	$	(5,636	)	$	8,934	$	(3,111	)

     The increase in intangibles assets from December 31, 2010 to June 30, 2011 was due to the allocation of purchase price related to the acquisitions in the six months ended June 30, 2011. Amortization expense related to intangible assets amounted to $1,373 and $368 for the three months ended June 30, 2011 and 2010, respectively, and $2,525 and $756 for six months ended June 30, 2011 and 2010, respectively. Amortization expense for developed technology, which was $199 for the three months ended June 30, 2011 and $330 for the six months ended June 30, 2011, is included in cost of revenues in the accompanying unaudited condensed consolidated statements of operations. Amortization expense for all other intangible assets is included as a component of operating expenses in the accompanying unaudited condensed consolidated statements of operations. The intangible asset lives range from one to ten years and the weighted average remaining life was 4.6 years at June 30, 2011. Estimated amortization is $5,477, $5,558, $5,496, $4,896, $2,588 and $2,441 for 2011, 2012, 2013, 2014, 2015 and thereafter, respectively.

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Indefinite-Lived Intangible Assets

     In connection with the Company’s acquisition of SmallFoot LLC (Smallfoot) and ZOX, LLC (Zox), the Company acquired certain in-process research and development projects with a carrying value of $390 and $530, respectively, through March 31, 2011. During the three months ended June 30, 2011, the Company concluded that the Smallfoot in-process research and development project had reached technological feasibility. Prior to re-classifying the asset as a definite-lived intangible asset, the Company performed an impairment test utilizing the income approach to assess whether the carrying value of the asset was impaired. The Company determined that the fair value exceeded the carrying value, and therefore, no impairment existed. Therefore, the Company re-classified the carrying value of $390 relating to the Smallfoot in-process research and development to a definite-lived intangible asset at June 30, 2011 with a useful life of three years. The amount of amortization expense recorded in the three months ended June 30, 2011 was immaterial.

     The Zox in-process research and development project has not reached technological feasibility and remained an indefinite-lived intangible asset at June 30, 2011. There were no interim impairment indicators that had been identified for Zox as of June 30, 2011.

Goodwill

     The following table shows the change of the carrying amount of goodwill from December 31, 2010 to June 30, 2011:

Balance at December 31, 2010	$	24,653
Acquisitions		40,195
Purchase price adjustments related to Global Energy		120
Purchase price adjustments related to M2M		(1,140	)
Foreign currency translation impact		67
Balance at June 30, 2011	$	63,895

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4. Net Loss Per Share

     A reconciliation of basic and diluted share amounts for the three and six months ended June 30, 2011 and 2010 are as follows (shares in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
Basic weighted average common shares outstanding		25,537		24,371		25,394		24,212
Weighted average common stock equivalents		—		1,491		—		—
Diluted weighted average common shares outstanding		25,537		25,862		25,394		24,212
Weighted average anti-dilutive shares related to:
Stock options		1,818		986		1,918		3,029
Nonvested restricted stock		623		86		518		179
Restricted stock units		263		4		293		304
Escrow shares		304		—		292		149

     In the reporting period in which the Company has reported net income, anti-dilutive shares comprise those common stock equivalents that have either an exercise price above the average stock price for the quarter or the common stock equivalent’s related average unrecognized stock compensation expense is sufficient to “buy back” the entire amount of shares. In those reporting periods in which the Company has a net loss, anti-dilutive shares comprise the impact of those number of shares that would have been dilutive had the Company had net income plus the number of common stock equivalents that would be anti-dilutive had the Company had net income.

     The Company excludes the shares issued in connection with restricted stock awards from the calculation of basic weighted average common shares outstanding until such time as those shares vest. In addition, in connection with certain of the Company’s business combinations, the Company has issued shares that were held in escrow upon closing of the applicable business combination. The Company excludes shares held in escrow from the calculation of basic weighted average common shares outstanding where the release of such shares is contingent upon an event and not solely subject to the passage of time.

5. Disclosure of Fair Value of Financial Instruments

     The Company’s financial instruments mainly consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable and debt obligations. The carrying amounts of the Company’s cash equivalents, restricted cash, accounts receivable and accounts payable approximate their fair value due to the short-term nature of these instruments. At June 30, 2011, the Company had no borrowings and outstanding letters of credit totalling $43,507 under the $75,000 senior secured revolving credit facility pursuant to the credit agreement entered into in April 2011 (2011 credit facility) with Silicon Valley Bank (SVB). At December 31, 2010, the Company had no borrowings and outstanding letters of credit totalling $36,561 under the previous credit facility pursuant to the loan and security agreement entered into with SVB in August 2008 (2008 credit facility). For additional information regarding the 2011 credit facility, see Note 7.

6. Fair Value Measurements

     ASC 820 establishes a fair value hierarchy that requires the use of observable market data, when available, and prioritizes the inputs to valuation techniques used to measure fair value in the following categories:

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

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

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

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     The table below presents the balances of assets and liabilities measured at fair value on a recurring basis at June 30, 2011:

	Fair Value Measurement at June 30, 2011 Using
			Quoted Prices in		Significant
			Active Markets		Other
			for Identical		Observable		Unobservable
	Totals		Assets (Level 1)		Inputs (Level 2)		Inputs (Level 3)
Money market funds (1)	$	62,638	$	62,638	$	—	$	—
Deferred acquisition consideration (2)	$	4,108	$	—	$	—	$	4,108

(1)

Included in cash and cash equivalents in the accompanying consolidated balance sheets.

(2)

Deferred acquisition consideration, which is a liability, represents the only asset or liability that the Company measures and records at fair value on a recurring basis using significant unobservable inputs (Level 3). The increase in fair value for the three and six months ended June 30, 2011 of $110 and $183, respectively, is due to the increase in the liability as a result of the amortization of the applicable discount. See Note 2 for further discussion.

     With respect to assets measured at fair value on a non-recurring basis, which would be impaired long-lived assets, refer to Note 1 for discussion of the determination of fair value of these assets.

     At June 30, 2011, the Company had restricted cash of approximately $71 collateralizing certain other commitments. All certificates of deposit have contractual maturities of twelve months or less. The Company’s investments in certificates of deposit have a fair value that approximates cost.

7. Financing Arrangements

     In April 2011, the Company and one of its subsidiaries entered into the 2011 credit facility. Subject to continued covenant compliance, the 2011 credit facility provides for a two-year revolving line of credit in the aggregate amount of $75,000, the full amount of which may be available for issuances of letters of credit and up to $5,000 of which may be available for swing line loans. The revolving line of credit is subject to increase from time to time up to an aggregate amount of $100,000 with additional commitments from the lenders or new commitments from financial institutions acceptable to SVB. The interest on revolving loans under the 2011 credit facility will accrue, at the Company’s election, at either (i) the Eurodollar Rate with respect to the relevant interest period plus 2.00% or (ii) the ABR (defined as the highest of (x) the “prime rate” as quoted in theWall Street Journal, (y) the Federal Funds Effective Rate plus 0.50% and (z) the Eurodollar Rate for a one-month interest period plus 1.00%) plus 1.00%. In connection with the issuance or renewal of letters of credit for the Company’s account, the Company is charged a letter of credit fee of 2.125% pursuant to the 2011 credit facility. The Company expenses the interest and letter of credit fees, as applicable, in the period incurred. The 2011 credit facility terminates and all amounts outstanding thereunder are due and payable in full on April 15, 2013.

     The 2011 credit facility contains customary terms and conditions for credit facilities of this type, including restrictions on the ability of the Company and its subsidiaries to incur additional indebtedness, create liens, enter into transactions with affiliates, transfer assets, pay dividends or make distributions on, or repurchase, the Company’s common stock, consolidate or merge with other entities, or suffer a change in control. In addition, the Company is required to meet certain financial covenants customary with this type of credit facility, including maintaining a minimum specified tangible net worth and a minimum specified ratio of current assets to current liabilities.

     The 2011 credit facility contains customary events of default, including for payment defaults, breaches of representations, breaches of affirmative or negative covenants, cross defaults to other material indebtedness, bankruptcy and failure to discharge certain judgments. If a default occurs and is not cured within any applicable cure period or is not waived, the lenders may accelerate the Company’s obligations under the 2011 credit facility. The 2011 credit facility replaced the 2008 credit facility which existed as of March 31, 2011.

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     As of June 30, 2011, the Company was not in compliance with one covenant under the 2011 credit facility as a result of the transfer of cash to fund the acquisition of Energy Response and obtained a waiver of this covenant default from SVB. At June 30, 2011, the Company had no borrowings and outstanding letters of credit totaling $43,507 under the 2011 credit facility.

     In April 2011, the Company and one of its subsidiaries entered into a guarantee and collateral agreement with SVB for the benefit of the lenders. The guarantee and collateral agreement provides that the obligations under the 2011 credit facility are secured by all domestic assets of the Company and several of its subsidiaries, excluding the Company’s foreign subsidiaries.

     The Company incurred financing costs of $543 in connection with the 2011 credit facility, which were deferred and are being amortized to interest expense over the life of the 2011 credit facility, which matures on April 15, 2013.

     In April 2011, the Company was required to provide financial assurance in connection with its capacity bid in a certain open market bidding program. The Company provided this financial assurance utilizing approximately $56,000 of its available cash on hand and a $39,000 letter of credit issued under the 2011 credit facility. In May 2011, based on the capacity that the Company cleared in the above open market bidding program and the required post auction financial assurance requirements, the Company recovered all of the $56,000 of its available cash that it had provided as financial assurance prior to the auction and was able to reduce the $39,000 letter of credit to $13,500.

     In June 2011, the Company and one of its subsidiaries entered into an amendment to the 2011 credit facility, which modified certain of its covenant requirements.

8. Commitments and Contingencies

     The Company is contingently liable under outstanding letters of credit. Restricted cash balances in the amount of $0 and $1,300, respectively, collateralize certain outstanding letters of credit and cover financial assurance requirements in certain of the programs in which the Company participated at June 30, 2011 and December 31, 2010. Restricted cash to secure certain other commitments was $71 and $237 at June 30, 2011 and December 31, 2010, respectively.

     The Company is subject to performance guarantee requirements under certain utility and electric power grid operator customer contracts and open market bidding program participation rules. The Company had deposits held by certain customers of $4,750 and $3,467, respectively, at June 30, 2011 and December 31, 2010. These amounts primarily represent up-front payments required by utility and electric power grid operator customers as a condition of participation in certain demand response programs and to ensure that the Company will deliver its committed capacity amounts in those programs. If the Company fails to meet its minimum committed capacity requirements, a portion or all of the deposit may be forfeited. The Company assessed the probability of default under these customer contracts and open market bidding programs and has determined the likelihood of default and loss of deposits to be remote. In addition, under certain utility and electric power grid operator customer contracts, if the Company does not achieve the required performance guarantee requirements, the customer can terminate the arrangement and the Company would potentially be subject to termination penalties. Under these arrangements, the Company defers all fees received up to the amount of the potential termination penalty until the Company has concluded that it can reliably determine that the potential termination penalty will not be incurred or the termination penalty lapses. As of June 30, 2011, the Company had deferred fees totaling approximately $2,304, which are included in deferred revenue, long-term in the accompanying consolidated balance sheets. As of June 30, 2011, the maximum termination penalty that the Company was subject to under these arrangements, which the Company has not deemed probable of incurring, is approximately $6,375.

     In connection with the Company’s participation in an open market bidding program, the Company entered into an arrangement with a third party during the second quarter of 2009 to bid capacity into the program and provide the corresponding financial assurance required in connection with the bid. The arrangement included an up-front payment by the Company equal to $2,000, of which $1,100 was expensed as interest expense during the second quarter of 2009 and $900 was deferred and will be recognized ratably as a charge to cost of revenues as revenue is recognized over the 2012/2013 delivery year. In addition, the Company will be required to pay the third party an additional contingent fee, up to a maximum of $3,000, based on the revenue that the Company expects to earn in 2012 in connection with the bid. This additional fee will be recognized as earned.

Indemnification Provisions

     The Company includes indemnification provisions in certain of its contracts. These indemnification provisions include provisions indemnifying the customer against losses, expenses, and liabilities from damages that could be awarded against the customer in the event that the Company’s services and related enterprise software platforms are found to infringe upon a patent or copyright of a third party. The Company believes that its internal business practices and policies and the ownership of information limits the Company’s risk in paying out any claims under these indemnification provisions.

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9. Stock-Based Compensation

Stock Options

     The Company’s Amended and Restated 2003 Stock Option and Incentive Plan (2003 Plan) and the Amended and Restated 2007 Employee, Director and Consultant Stock Plan (the 2007 Plan, and together with the 2003 Plan, the Plans) provide for the grant of incentive stock options, nonqualified stock options, restricted and unrestricted stock awards and other stock-based awards to eligible employees, directors and consultants of the Company. Options granted under the Plans are exercisable for a period determined by the Company, but in no event longer than ten years from the date of the grant. Option awards are generally granted with an exercise price equal to the market price of the Company’s common stock on the date of grant. Options, restricted stock awards and restricted stock unit awards generally vest over four years, with certain exceptions. The 2003 Plan expired upon the Company’s initial public offering (IPO) in May 2007. Any forfeitures under the 2003 Plan that occurred after the effective date of the IPO are available for future grant under the 2007 Plan up to a maximum of 1,000,000 shares. The 2007 Plan provides for an annual increase to the shares issuable under the 2007 Plan by an amount equal to the lesser of 520,000 shares or an amount determined by the Company’s board of directors. This annual increase is effective on the first day of each fiscal year through 2017. During the six months ended June 30, 2011 and 2010, the Company issued 18,211 shares of its common stock and 24,681 shares of its common stock, respectively, to certain executives to satisfy a portion of the Company’s compensation obligations to those individuals. As of June 30, 2011, 2,078,154 shares were available for future grant under the 2007 Plan.

     For stock options granted prior to January 1, 2009, the fair value of each option was estimated at the date of grant using a Black-Scholes option-pricing model. For stock options granted on or after January 1, 2009, the fair value of each option has been and will be estimated on the date of grant using a lattice valuation model. The lattice valuation model considers characteristics of fair value option pricing that are not available under the Black-Scholes option pricing model. Similar to the Black-Scholes option pricing model, the lattice valuation model takes into account variables such as expected volatility, dividend yield rate, and risk free interest rate. However, in addition, the lattice valuation model considers the probability that the option will be exercised prior to the end of its contractual life and the probability of termination or retirement of the option holder in computing the value of the option. For these reasons, the Company believes that the lattice model provides a fair value that is more representative of actual experience and future expected experience than that value calculated using the Black-Scholes option pricing model.

     The fair value of options granted was estimated at the date of grant using the following weighted average assumptions:

	Six Months Ended June 30,
	2011			2010
Risk-free interest rate		3.3	%		3.6	%
Vesting term, in years		2.22			2.16
Expected annual volatility		79	%		86	%
Expected dividend yield		—	%		—	%
Exit rate pre-vesting		7.3	%		5.94	%
Exit rate post-vesting		14.06	%		10.89	%

     Volatility measures the amount that a stock price has fluctuated or is expected to fluctuate during a period. As there was no public market for the Company’s common stock prior to the effective date of the IPO, the Company determined the volatility 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 through September 30, 2010 was determined using an average of the historical volatility measures of this peer group of companies. During the three months ended September 30, 2010, the Company determined that it had sufficient history to utilize Company-specific volatility in accordance with ASC 718,Stock Compensation(ASC 718) and is now calculating volatility using a component of implied volatility and historical volatility to determine the value of share-based payments. The risk-free interest rate is the rate available as of the option date on zero-coupon United States government issues with a term equal to the expected life of the option. During the three months ended March 31, 2010, the Company changed its vesting for new grants of stock options and restricted stock to a 25% cliff vest after one year of grant and quarterly thereafter for three years as compared to its primary vesting for historical grants of 25% cliff vest after one year of grant and monthly thereafter for three years. The change in vesting resulted in the vesting term changing in 2010 for new grants awarded with this new vesting. The Company has not paid dividends on its common stock in the past and does not plan to pay any dividends in the foreseeable future. In addition, the terms of the 2011 credit facility preclude the Company from paying dividends. During the three months ended June 30, 2011, the Company updated its estimated exit rate pre-vesting and post-vesting applied to options, restricted stock and restricted stock units based on an evaluation of demographics of its

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employee groups and historical forfeitures for these groups in order to determine its option valuations as well as its stock-based compensation expense. The changes in estimate of the volatility, exit rate pre-vesting and exit rate post-vesting did not have a material impact on the Company’s stock-based compensation expense recorded in the accompanying unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2011.

     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 measurable.

The components of stock-based compensation expense are disclosed below:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
Stock options	$	1,364	$	2,371	$	3,145	$	4,676
Restricted stock and restricted stock units		2,421		1,287		4,122		3,328
Total	$	3,785	$	3,658	$	7,267	$	8,004

     Stock-based compensation is recorded in the accompanying unaudited condensed consolidated statements of operations, as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
Selling and marketing expenses	$	1,255	$	1,141	$	2,298	$	2,189
General and administrative expenses		2,212		2,319		4,380		5,450
Research and development expenses		318		198		589		365
Total	$	3,785	$	3,658	$	7,267	$	8,004

     The Company recognized no material income tax benefit from stock-based compensation arrangements during the three and six months ended June 30, 2011 and 2010. In addition, no material compensation cost was capitalized during the three and six months ended June 30, 2011 and 2010.

     The following is a summary of the Company’s stock option activity during the six months ended June 30, 2011:

	Six Months Ended June 30, 2011
	Number of					Weighted-
	Shares			Exercise		Average		Aggregate
	Underlying			Price Per		Exercise Price		Intrinsic
	Options			Share		Per Share		Value
Outstanding at December 31, 2010		2,112,359		$	0.17 - $48.06	$	14.38	$	23,948	(2)
Granted		39,950					19.43
Exercised		(236,352	)				7.35	$	2,789	(3)
Cancelled		(158,066	)				15.55
Outstanding at June 30, 2011		1,757,891		$	0.17 - $48.06		15.33	$	9,413	(4)
Weighted average remaining contractual life in years: 5.3
Exercisable at end of period		1,234,183		$	0.17 - $48.06	$	11.94	$	8,754	(4)
Weighted average remaining contractual life in years: 5.0
Vested or expected to vest at June 30, 2011 (1)		1,724,392		$	0.17 - $48.06	$	15.13	$	9,399	(4)

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(1)	This represents the number of vested options as of June 30, 2011 plus the number of unvested options expected to vest as of June 30, 2011 based on the unvested options outstanding at June 30, 2011, adjusted for the estimated forfeiture rate of 7.3%.
(2)	The aggregate intrinsic value was calculated based on the positive difference between the estimated fair value of the Company’s common stock on December 31, 2010 of $23.91 and the exercise price of the underlying options.
(3)	The aggregate intrinsic value was calculated based on the positive difference between the fair value of the Company’s common stock on the applicable exercise dates and the exercise price of the underlying options.
(4)	The aggregate intrinsic value was calculated based on the positive difference between the estimated fair value of the Company’s common stock on June 30, 2011 of $15.74 and the exercise price of the underlying options.

Additional Information About Stock Options

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
	In thousands, except share and				In thousands, except share and
	per share amounts				per share amounts
Total number of options granted during the period		23,600		71,500		39,950		251,275
Weighted-average fair value per share of options granted	$	11.03	$	19.45	$	11.96	$	18.66
Total intrinsic value of options exercised(1)	$	528	$	4,108	$	2,789	$	9,961

(1) Represents the difference between the market price at exercise and the price paid to exercise the options.

     Of the stock options outstanding as of June 30, 2011, 1,743,898 options were held by employees and directors of the Company and 13,993 options were held by non-employees. For outstanding unvested stock options related to employees as of June 30, 2011, the Company had $7,023 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 2.2 years. There were no material unvested non-employee options as of June 30, 2011.

Restricted Stock and Restricted Stock Units

     For non-vested restricted stock and restricted stock units outstanding as of June 30, 2011, the Company had $16,595 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 2.5 years.

Restricted Stock

     The following table summarizes the Company’s restricted stock activity during the six months ended June 30, 2011:

					Weighted Average
	Number of				Grant Date Fair
	Shares				Value Per Share
Nonvested at December 31, 2010		254,896			$	30.03
Granted		454,381				19.68
Vested		(46,122	)			25.32
Cancelled		(20,443	)			29.31
Nonvested at June 30, 2011		642,712		��	$	23.08

     All shares underlying awards of restricted stock are restricted in that they are not transferable until they vest. Restricted stock typically vests ratably over a four-year period from the date of issuance, with certain exceptions. Included in the above table are 2,000 shares of restricted stock granted to certain non-executive employees and 16,000 shares of restricted stock granted to the Company’s board of directors during the six months ended June 30, 2011 that were immediately vested. The fair value of the restricted stock is expensed ratably over the vesting period. The Company records any proceeds received for unvested shares of restricted stock in accrued expenses and the amount is amortized into additional paid-in capital as the shares vest. If the employee who received the restricted stock leaves the Company prior to the vesting date for any reason, the shares of restricted stock will be forfeited and returned to the Company.

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Additional Information about Restricted Stock

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
	in thousands, except share and per
	share amounts
Total number of shares of restricted stock granted during the period		79,600		39,542		454,381		84,792
Weighted average fair value per share of restricted stock granted	$	17.86	$	30.02	$	19.68	$	29.59
Total number of shares of restricted stock vested during the period		15,214		23,866		46,122		87,327
Total fair value of shares of restricted stock vested during the period	$	263	$	697	$	886	$	2,551

Restricted Stock Units

     The following table summarizes the Company’s restricted stock unit activity during the six months ended June 30, 2011:

				Weighted Average
	Number of			Grant Date Fair
	Shares			Value Per Share
Nonvested at December 31, 2010		388,124		$	26.11
Granted		—			—
Vested		(81,709	)		26.46
Cancelled		(54,562	)		25.60
Nonvested at June 30, 2011		251,853		$	26.10

     The total fair value of restricted stock units that vested during the six months ended June 30, 2011 was $1,466. The weighted average grant date fair value of restricted stock units granted during the six months ended June 30, 2010 was $28.60 per share.

10. Income Taxes

     The Company accounts for income taxes in accordance with ASC 740,Income Taxes(ASC 740), which is the asset and liability method for accounting and reporting income taxes. Under ASC 740, deferred tax assets and liabilities are recognized based on temporary differences between the financial reporting and income tax bases of assets and liabilities using statutory rates. In addition, ASC 740 requires a valuation allowance against net deferred tax assets if, based upon the available evidence, it is more likely than not that some or all of the deferred tax assets will not be realized.

     ASC 740 also provides criteria for the recognition, measurement, presentation and disclosures of uncertain tax positions. A tax benefit from an uncertain tax position may be recognized if it is “more likely than not” that the position is sustainable based solely on its technical merits. As of June 30, 2011 and December 31, 2010, the Company had no material unrecognized tax benefits.

     In accordance with ASC 740, each interim period is considered an integral part of the annual period and tax expense is measured using an estimated annual effective tax rate. An enterprise is required, at the end of each interim reporting period, to make its best estimate of the annual effective tax rate for the full fiscal year and use that rate to provide for income taxes on a current year-to-date basis. Generally, if an enterprise has an ordinary loss for the year to date at the end of an interim period and anticipates ordinary income for the fiscal year, the enterprise will record an interim period tax benefit based on applying the estimated annual effective tax rate to the ordinary loss as long as the tax benefits are realized during the year or recognizable as a deferred tax asset as of the end of the year. However, if an enterprise is unable to make a reliable estimate of its annual effective tax rate then the actual effective tax rate for the year-to-date may be the best estimate of the annual effective tax rate. The Company has determined that it is currently unable to make a reliable estimate of its annual effective tax rate as of June 30, 2011 due to unusual sensitivity to the rate as

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it relates to the current forecasted fiscal 2011 U.S. ordinary income. As a result, the Company recorded a tax provision for the six months ended June 30, 2011 based on its actual effective tax rate for six months ended June 30, 2011. The tax provision recorded for the three and six months ended June 30, 2011 was $101 and $767, respectively, and represented the following:

• estimated foreign taxes resulting from guaranteed profit allocable to certain of the Company’s foreign subsidiaries, which have been determined to be limited-risk service providers acting on behalf of the U.S. parent for tax purposes, for which there are no tax net operating loss carryforwards; and

• amortization of tax deductible goodwill, which generates a deferred tax liability that cannot be offset by net operating losses or other deferred tax assets since its reversal is considered indefinite in nature.

     If the Company is able to make a reliable estimate of its annual effective tax rate as of September 30, 2011 and if the Company is still anticipating U.S. ordinary income for fiscal 2011, then as required by ASC 740, the Company will utilize that rate to provide for income taxes on a current year-to-date basis, which could result in a significant provision from income taxes being recorded during the three months ended September 30, 2011, which would be predominantly offset by a significant benefit recorded during the three months ending December 31, 2011. If the Company continues to be unable to make a reliable estimate of its annual effective tax rate as of September 30, 2011, the Company expects to follow a consistent methodology as applied for the three and six months ended June 30, 2011.

     The Company reviews all available evidence to evaluate the recovery of deferred tax assets, including the recent history of accumulated losses in all tax jurisdictions over the last three years, as well as its ability to generate income in future periods. As of June 30, 2011, due to the uncertainty related to the ultimate use of the Company’s deferred income tax assets, the Company provided a full valuation allowance on all of its U.S. deferred tax assets.

11. Concentrations of Credit Risk

     The following table presents the Company’s significant customers. With respect to PJM Interconnection (PJM) and ISO-New England, Inc. (ISO-NE), these customers are regional electric power grid operator customers, which are comprised of multiple utilities and were formed to control the operation of a regional power system, coordinate the supply of electricity, and establish fair and efficient markets.

	Three Months Ended June 30,
	2011					2010
			% of Total					% of Total
	Revenues		Revenues			Revenues		Revenues
PJM Interconnection	$	30,756		52	%	$	38,784		58	%
ISO-New England, Inc.		8,406		14			14,830		22
Total	$	39,162		66	%	$	53,614		80	%

	Six Months Ended June 30,
	2011					2010
			% of Total					% of Total
	Revenues		Revenues			Revenues		Revenues
PJM Interconnection	$	31,373		35	%	$	39,100		41	%
ISO-New England, Inc.		20,123		22			32,250		34
Total	$	51,496		57	%	$	71,350		75	%

     Accounts receivable from PJM was approximately $7,417 and $7,848 at June 30, 2011 and December 31, 2010, respectively. Accounts receivable from ISO-NE was approximately $2,486 and $3,351 at June 30, 2011 and December 31, 2010, respectively.

     No additional customers provided 10% of more of the accounts receivable balance at June 30, 2011. Southern California Edison Company was the only additional customer that provided 10% or more of the accounts receivable balance at December 31, 2010 at 15% of the accounts receivable balance. Unbilled revenue related to PJM was $16,907 and $72,887 at June 30, 2011 and December 31, 2010, respectively. There was no significant unbilled revenue for any other customers at June 30, 2011 and December 31, 2010.

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12. Legal Proceedings

     The Company is subject to legal proceedings, claims and litigation arising in the ordinary course of business. The Company does not expect the ultimate costs to resolve these matters to have a material adverse effect on its consolidated financial condition, results of operations or cash flows.

13. Recent Accounting Pronouncements

Business Combinations

     In December 2010, the FASB issued Accounting Standards Update No. 2010-29,Business Combinations — Disclosure of Supplementary Pro Forma Information for Business Combinations(ASU 2010-29). ASU 2010-29 requires a public entity to disclose revenue and earnings of the combined entity as though the business combination that occurred during the current year had occurred as of the beginning of the prior year. It also requires a description of the nature and amount of material, nonrecurring adjustments directly attributable to the business combination included in the reported revenue and earnings. The new disclosure was effective for the Company’s first quarter of fiscal 2011. The adoption of ASU 2010-29 will require additional disclosure in the event of a business combination but will not have a material impact on the Company’s financial condition and results of operations during the three and six months ended June 30, 2011. As a result of the acquisition of Energy Response in July 2011, the Company will be required to meet certain disclosure requirements and provide pro-forma financial information. Refer to Note 1 for further information on the acquisition of Energy Response.

Intangibles — Goodwill and Other

     In December 2010, the FASB issued ASU 2010-28,Intangibles- Goodwill and Other(ASU 2010-28). ASU 2010-28 modifies Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist. ASU 2010-28 is effective for fiscal years that begin after December 15, 2010, which is fiscal 2011 for the Company. The adoption of this standard did not have a material impact on the Company’s results from operations and financial condition.

Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS

     In May 2011, the FASB issued ASU 2011-04,Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS, which amends its accounting guidance related to fair value measurements in order to more closely align its disclosure requirements with those in International Financial Reporting Standards. This guidance clarifies the application of existing fair value measurement and disclosure requirements and also changes certain principles or requirements for measuring fair value or for disclosing information about fair value measurements. The guidance is effective for interim and annual periods beginning after December 15, 2011. The adoption of this guidance is not expected to have a material effect on the Company’s financial position or results of operations.

Presentation of Comprehensive Income

     In June 2011, the FASB issued ASU 2011-05,Presentation of Comprehensive Income,which represents new accounting guidance related to the presentation of other comprehensive income (OCI). This guidance eliminates the option to present components of OCI as part of the statement of changes in shareholders’ equity, which is the option that the Company currently uses to present OCI. The guidance allows for a one-statement or two-statement approach, outlined as follows:

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• One-statement approach: Present the components of net income and total net income, the components of OCI and a total for OCI, along with the total of comprehensive income in a single continuous statement.

• Two-statement approach: Present the components of net income and total net income in the statement of net income. A statement of OCI would immediately follow the statement of net income and include the components of OCI and a total for OCI, along with the total of comprehensive income.

     The guidance also requires an entity to present on the face of the financial statements any reclassification adjustments for items that are reclassified from OCI to net income. The guidance is effective for interim and annual periods beginning after December 15, 2011. The adoption of this guidance will not have an effect on the Company’s financial position or results of operations, but will only impact how certain information related to OCI is presented in the Company’s consolidated financial statements.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

     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 onForm 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 onForm 10-K for the fiscal year ended December 31, 2010, as filed with the Securities and Exchange Commission, or the SEC, on March 1, 2011. This Quarterly Report onForm 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 onForm 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 onForm 10-Q, as well as in our Annual Report onForm 10-K for the fiscal year ended December 31, 2010. 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 management applications and services for the smart grid, which include comprehensive demand response, data-driven energy efficiency, energy price and risk management, and enterprise carbon management applications and services. Our energy management applications and services enable cost effective energy management strategies for commercial, institutional and industrial end-users of energy, which we refer to as our C&I customers, and our electric power grid operator and utility customers by reducing real-time demand for electricity, increasing energy efficiency, improving energy supply transparency, and mitigating emissions.

     We believe that we are the largest demand response service provider to C&I customers in the United States. As of June 30, 2011, we managed approximately 6,650 megawatts, or MW, of demand response capacity across a C&I customer base of approximately 4,500 accounts and 10,700 sites throughout multiple electric power grids. Demand response is an alternative to traditional power generation and transmission infrastructure projects that enables electric power 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 or during periods when energy prices are high. We use our Network Operations Center, or NOC, and comprehensive demand response application, DemandSMART, to remotely manage and reduce electricity consumption across a growing network of C&I customer sites, making demand response capacity available to electric power grid operators and utilities on demand while helping C&I customers achieve energy savings, improved financial results and environmental benefits. To date, we have received substantially all of our revenues from electric power grid operators and utilities, who make recurring payments to us for managing demand response capacity that we share with our C&I customers in exchange for those C&I customers reducing their power consumption when called upon.

     We build on our position as a leading demand response services provider by using our NOC and energy management application platform to deliver a portfolio of additional energy management applications and services to new and existing C&I, electric power grid operator and utility customers. These additional energy management applications and services include our EfficiencySMART, SupplySMART and CarbonSMART applications and services. EfficiencySMART is our data-driven energy efficiency suite that includes commissioning and retro-commissioning authority services, energy consulting and engineering services, a persistent commissioning application and an enterprise energy management application for managing energy across a portfolio of sites. SupplySMART is our energy price and risk management application that provides our C&I 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, budget forecasting, and utility bill management. CarbonSMART is our enterprise carbon management application that supports and manages the measurement, tracking, analysis, reporting and management of greenhouse gas emissions.

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     Since inception, our business has grown substantially. We began by providing demand response services in one state in 2003 and had expanded to providing our portfolio of energy management applications and services in several regions throughout the United States, as well as internationally in Australia, Canada and the United Kingdom, by June 30, 2011.

Significant Recent Developments

     In July 2011, we completed our acquisition of all of the outstanding stock of Energy Response Holdings Pty Ltd, or Energy Response, pursuant to a stock purchase agreement dated July 1, 2011. Energy Response specializes in demand response and other energy management services in Australia and New Zealand. The total purchase price paid by us at closing was A$27.9 million, of which A$2.5 million was paid in shares of our common stock and the balance of which was paid in cash. The actual number of shares of our common stock issued in the transaction was based upon the average of the per share last sale price for our common stock on The NASDAQ Global Market for the thirty trading day period ending three trading days prior to the closing. In addition, the former stockholders of Energy Response may be entitled to an additional earn-out payment of A$10.0 million, of which A$3.3 million will be paid in shares of our common stock and the balance of which will be paid in cash, upon the development of a demand response reserve capacity market in the National Electricity Market in Australia by December 31, 2013 that meets certain market size and price per megawatt conditions. The Australian dollar to United States dollar conversion rate on July 1, 2011 was 1.0718 to 1.

Revenues and Expense Components

Revenues

     We derive recurring revenues from the sale of our energy management applications and services. We do not recognize any revenues until persuasive evidence of an arrangement exists, delivery has occurred, the fee is fixed or determinable, and we deem collection to be reasonably assured.

     Our revenues from our demand response services primarily consist of capacity and energy payments, including ancillary services payments. We derive revenues from demand response capacity that we make available in open market programs and pursuant to contracts that we enter into with electric power grid operators and utilities. In certain markets, we enter into contracts with electric power grid operators and utilities, generally ranging from three to 10 years in duration, to deploy our demand response services. We refer to these contracts as utility contracts.

     Where we operate in open market programs, our revenues from demand response capacity payments may vary month-to-month based upon our enrolled capacity and the market payment rate. Where we have a utility contract, we receive periodic capacity payments, which may vary monthly or seasonally, based upon enrolled capacity and predetermined payment rates. Under both open market programs and utility contracts, 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 measurement and verification 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 refer to this as an energy payment.

     As program rules may differ for each open market program in which we participate and for each utility contract, 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 capacity revenues when we have provided verification to the electric power grid operator or utility of our ability to deliver the committed capacity under the open market program or utility 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 revenues are recognized and future revenues become fixed or determinable and are recognized monthly over the performance period until the next demand response event or measurement and verification test. In subsequent demand response events or measurement and verification tests, if our verified capacity is below the previously verified amount, the electric power grid operator or utility customer will reduce future payments based on the adjusted verified capacity amounts. Under certain utility contracts and open market program participation rules, our performance and related fees are measured and determined over a period of time. If we

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can reliably estimate our performance for the applicable performance period, we will reserve the entire amount of estimated penalties that will be incurred, if any, as a result of estimated underperformance prior to the commencement of revenue recognition. If we are unable to reliably estimate the performance and any related penalties, we defer the recognition of revenues until the fee is fixed or determinable. Any changes to our original estimates of net revenues are recognized as a change in accounting estimate in the earliest reporting period that such a change is determined.

     We defer incremental direct costs incurred related to the acquisition or origination of a utility contract or open market program in a transaction that results in the deferral or delay of revenue recognition. As of June 30, 2011 and December 31, 2010, the incremental direct costs deferred were approximately $1.4 million and $0.9 million, respectively. These deferred expenses would not have been incurred without our participation in a certain open market program and will be expensed in proportion to the related revenue being recognized. During the three and six months ended June 30, 2011 and 2010, we did not defer any contract origination costs. In addition, we capitalize the costs of our production and generation equipment utilized in the delivery of our demand response services and expense this equipment over the lesser of its useful life or the term of the contractual arrangement. During the three months ended June 30, 2011 and 2010, we capitalized $4.7 million and $2.8 million, respectively, of production and generation equipment costs. During the six months ended June 30, 2011 and 2010, we capitalized $6.6 million and $4.0 million, respectively, of production and generation equipment costs. We believe that this accounting treatment appropriately matches expenses with the associated revenue.

     As of June 30, 2011, we had approximately 6,650 MW under management in our demand response network, meaning that we had entered into definitive contracts with our C&I customers representing approximately 6,650 MW of demand response capacity. In determining our MW under management in the seasonal demand response programs in which we participate, we typically count the maximum demand response capacity for a C&I customer site over a trailing twelve-month period as the MW under management for that C&I customer site, although the trailing period could be longer in certain programs under which significant rule changes have occurred. 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. The most significant exception is the PJM Interconnection, or PJM, forward capacity market, which is a market from which we derive a substantial portion of our revenues. 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 C&I customer portfolio from the point in time when we consider a MW to be under management to when we earn revenues from that MW. Certain other markets in which we currently participate, such as the ISO-New England, Inc., or ISO-NE, market, or choose to participate in the future operate or may operate in a manner that could create a delay in recognizing revenue from the MW that we enable in those markets. Additionally, not all of our MW under management may be enrolled in a demand response program or may earn revenue in a given program period or year based on the way that we manage our portfolio of demand response capacity.

     Under certain utility contracts and open market programs, such as PJM’s Emergency Load Response Program, the period during which we are required to perform may be shorter than the period over which we receive payments under that contract or program. In these cases, we record revenue, net of reserves for estimated penalties related to potential delivered capacity shortfalls, over the mandatory performance obligation period, and a portion of the revenues that have been earned is recorded and accrued as unbilled revenue. Our unbilled revenue related to PJM of $16.9 million as of June 30, 2011 will be billed and collected through May 31, 2012. Due to the lower pricing that will take effect in the PJM market in 2011 and 2012, as well as the discontinuance of PJM’s Interruptible Load for Reliability program, or the ILR program, beginning in 2012 and an expected decrease in MW enrolled in the PJM market in 2012 as compared to 2011, we currently expect that our revenues derived from the PJM market will significantly decrease as a percentage of our total annual revenues in 2011 and 2012 as compared to prior years, and that our ability to grow our overall revenues in 2011 and 2012 at levels consistent with prior years will be negatively impacted.

     In February 2011, PJM and Monitoring Analytics, LLC, the PJM market monitor, issued a joint statement concerning settlements in PJM’s capacity market for participants using a certain baseline methodology for the measurement and verification of demand response. We refer to this as the PJM statement. The PJM statement, among other things, asserted that certain market practices in the PJM capacity market were no longer appropriate or acceptable and unilaterally implied that compensation should no longer be determined by actual measured reductions in C&I customers’ electrical load, unless the reductions are below such C&I customer’s peak demand for electricity in the prior year. We filed for and were granted expedited declaratory relief with the Federal Energy Regulatory Commission, or FERC, which clarified that we may continue to manage our portfolio of demand response capacity in PJM as we have in the past and continue to receive settlement in accordance with the current PJM market rules approved by FERC. However, PJM continues to take steps to modify the market rules according to the PJM statement, including by filing proposed tariff changes with FERC. In the event that PJM is successful at modifying the market rules in the future to reflect its position as set forth in the PJM statement, our revenues for 2011 and beyond could be significantly reduced. Furthermore, the attention of our management and other personnel has been, and may continue to be, diverted as we defend our position with respect to the PJM statement, which has had, and may continue to have, a negative impact on our sales efforts in, and revenues derived from, the PJM region as well as our other operating regions.

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     Revenues generated from open market sales to PJM accounted for 52% and 58%, respectively, of our total revenues for the three months ended June 30, 2011 and 2010 and 35% and 41%, respectively, of our total revenues for the six months ended June 30, 2011 and 2010.

     Revenues generated from open market sales to ISO-NE accounted for 14% and 22%, respectively, of our total revenues for the three months ended June 30, 2011 and 2010 and 22% and 34%, respectively, of our total revenues for the six months ended June 30, 2011 and 2010.

     In addition to demand response revenues, we generally receive either a subscription-based fee, consulting fee or a percentage savings fee for arrangements under which we provide our other energy management applications and services, specifically our EfficiencySMART, SupplySMART and CarbonSMART applications and services. Revenues derived from these applications and services were $6.3 million and $3.1 million, respectively, for the three months ended June 30, 2011 and 2010 and $12.3 million and $6.5 million, respectively, for the six months ended June 30, 2011 and 2010.

     Our revenues have historically been higher in our second and third fiscal quarters compared to other quarters in our fiscal year due to seasonality related to the demand response market.

Cost of Revenues

     Cost of revenues for our demand response services consists primarily of amounts owed to our C&I customers for their participation in our demand response network and are generally recognized over the same performance period as the corresponding revenue. We enter into contracts with our C&I 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 C&I customer reduces consumption of energy from the electric power grid during a demand response event. The equipment and installation costs for our devices located at our C&I customer sites, which monitor energy usage, communicate with C&I customer sites and, in certain instances, remotely control energy usage to achieve committed capacity are capitalized and depreciated over the lesser of the remaining estimated customer relationship period or the estimated useful life of the equipment, and this depreciation is reflected in cost of revenues. We also include in cost of revenues our amortization of acquired developed technology, amortization of capitalized internal-use software costs related to our DemandSMART application, the monthly telecommunications and data costs we incur as a result of being connected to C&I customer sites and our internal payroll and related costs allocated to a C&I customer site. Certain costs such as equipment depreciation and telecommunications and data costs are fixed and do not vary based on revenues recognized. These fixed costs could impact our gross margin trends described below during interim periods. Cost of revenues for our EfficiencySMART, SupplySMART and CarbonSMART applications and services include our amortization of capitalized internal-use software costs related to those applications and services, third party services, equipment costs, 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 energy management applications and services, (b) the selling price of our energy management applications and services, (c) our cost of revenues, (d) the way in which we manage, or are permitted to manage by the relevant electric power grid operator or utility, our portfolio of demand response capacity, (e) the introduction of new clean and intelligent energy management applications and services, (f) our demand response event performance and (g) our ability to open and enter new markets and regions and expand deeper into markets we already serve. Our outcomes in negotiating favorable contracts with our C&I customers, as well as with our electric power grid operator and utility customers, the effective management of our portfolio of demand response capacity and our demand response event performance are the primary determinants of our gross profit and gross margin.

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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 462 full-time employees at June 30, 2010 to 554 full-time employees at June 30, 2011. 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. We expect our overall operating expenses to increase in absolute dollar terms for the foreseeable future and to increase as a percentage of total annual revenues in the near term as we continue to invest in our business and employee base in order to capitalize on emerging opportunities, expand the development of our energy management applications and services, and grow our MW under management. In addition, amortization expense from intangible assets acquired in future acquisitions will increase our operating expenses in future periods.

Selling and Marketing

     Selling and marketing expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards, related to our sales and marketing organization, (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 our selling and marketing expenses to continue to increase in absolute dollar terms for the foreseeable future and to slightly increase as a percentage of total annual revenues in the near term as we further increase the number of our sales professionals.

General and Administrative

     General and administrative expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards and bonuses, 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 and to slightly increase as a percentage of total annual revenues in the near term as we further invest in our infrastructure and employee base to support our continued growth.

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 research and development organization, (b) payments to suppliers for design and consulting services, (c) costs relating to the design and development of new energy management applications and services and enhancement of existing energy management applications and services, (d) quality assurance and testing and (e) other related overhead. During the three and six months ended June 30, 2011, we capitalized software development costs of $2.3 million and $3.1 million, respectively, and the amount is included as software in property and equipment at June 30, 2011. During the three and six months ended June 30, 2010, we capitalized software development costs of $2.8 million and $4.0 million, respectively, and the amount is included as software in property and equipment at June 30, 2010. We capitalized $0 and $0.4 million during the three months ended June 30, 2011 and 2010, respectively, and $13,000 and $1.0 million during the six months ended June 30, 2011 and 2010, respectively, related to a company-wide enterprise resource planning systems implementation project, which was put into production in June 2011 and is being amortized over a five year useful life. We expect research and development expenses to increase in absolute dollar terms for the foreseeable future and to slightly increase as a percentage of total annual revenues in the near term as we develop new technologies and further invest in our research and development organization.

Stock-Based Compensation

     We account for stock-based compensation in accordance with Accounting Standards Codification, or ASC, 718,Stock Compensation. As such, all share-based payments to employees, including grants of stock options, restricted stock and restricted stock units, are recognized in the statement of operations based on their fair values as of the date of grant. 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 lattice valuation model. For the three months ended June 30, 2011 and 2010, we recorded expenses of approximately $3.8 million and $3.7 million, respectively, in connection with share-based payment awards to employees and non-employees. For the six months ended June 30, 2011 and 2010, we recorded expenses of approximately $7.3 million and $8.0 million, respectively, in connection with share-based payment awards to employees and non-employees. With respect to option grants through June 30, 2011, a future expense of non-vested options of approximately $7.0 million is expected to be recognized over a weighted average period of 2.2 years. With respect to restricted stock and restricted stock units issued through June 30, 2011, a future expense of unvested restricted stock and restricted stock unit awards of approximately $16.6 million is expected to be recognized over a weighted average period of 2.5 years.

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Other Income and Expense, Net

     Other income and expense consist primarily of interest income earned on cash balances, gain or loss on transactions designated in currencies other than our or our subsidiaries’ functional currency 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.

Interest Expense

     Interest expense consists of interest on our capital lease obligations, fees associated with the credit facility that we entered into with Silicon Valley Bank, or SVB, in August 2008, which we refer to as the 2008 credit facility, fees associated with the $75.0 million senior secured revolving credit facility that we entered into with SVB and certain other lenders in April 2011, which we refer to as the 2011 credit facility, and fees associated with issuing letters of credit and other financial assurances.

Consolidated Results of Operations

Three and Six Months Ended June 30, 2011 Compared to the Three and Six Months Ended June 30, 2010

Revenues

     The following table summarizes our revenues for the three and six months ended June 30, 2011 and 2010 (dollars in thousands):

	Three Months Ended June 30,				Dollar			Percentage
	2011		2010		Change			Change
Revenues:
DemandSMART	$	52,578	$	63,420	$	(10,842	)		(17.1	)%
EfficiencySMART, SupplySMART and CarbonSMART		6,326		3,128		3,198			102.2
Total	$	58,904	$	66,548	$	(7,644	)		(11.5	)%

	Six Months Ended June 30,				Dollar			Percentage
	2011		2010		Change			Change
Revenues:
DemandSMART	$	78,394	$	88,147	$	(9,753	)		(11.1	)%
EfficiencySMART, SupplySMART and CarbonSMART		12,272		6,522		5,750			88.2
Total	$	90,666	$	94,669	$	(4,003	)		(4.2	)%

     For the three months ended June 30, 2011, our DemandSMART revenues decreased by $10.8 million, or 17%, as compared to the three months ended June 30, 2010. For the six months ended June 30, 2011, our DemandSMART revenues decreased by $9.8 million, or 11%, as compared to the six months ended June 30, 2010. The decrease in our DemandSMART revenues was primarily attributable to changes in the following existing operating areas (dollars in thousands):

	Revenue (Decrease) Increase:			Revenue (Decrease) Increase:
	Three Months Ended			Six Months Ended
	June 30, 2010 to			June 30, 2010 to
	June 30, 2011			June 30, 2011
PJM	$	(8,028	)	$	(7,727	)
ERCOT		181			1,784
New England		(6,424	)		(12,127	)
Ontario Power Authority		1,907			6,590
New York		(295	)		(922	)
California		369			776
Other (1)		1,448			1,873
Total increased DemandSMART response revenues	$	(10,842	)	$	(9,753	)

(1) The amounts included in this category relate to increases in various demand response programs, none of which are individually material.

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     The decrease in DemandSMART revenues during the three and six months ended June 30, 2011 as compared to the same periods in 2010 was primarily due to less favorable pricing in PJM, as well as an increase in the estimated reserve for potential performance adjustments recorded in the three months ended June 30, 2011. The decrease in DemandSMART revenues during the three and six months ended June 30, 2011 was also attributable to the commencement of an ISO-NE program in which we currently participate, which started on June 1, 2010, under which we enrolled fewer MW at lower pricing compared to a prior, similar ISO-NE program in which we participated. In addition, the pricing of this new ISO-NE program was lower for June 2011 compared to June 2010. The decrease in our DemandSMART revenues was also attributable to less favorable pricing in New York during the three and six months ended June 30, 2011.

     The decrease in our DemandSMART revenues during the three and six months ended June 30, 2011 was offset in part by an increase in revenues recognized in Canada under our utility contract with Ontario Power Authority, or the OPA contract. As a result of an amendment to certain refund provisions under the OPA contract entered into during the three months ended March 31, 2011, we concluded that we can reliably estimate the fees potentially subject to refund as of March 31, 2011 and therefore, we recorded revenues under the OPA contract for which the corresponding cost of revenues were recorded in prior periods. Prior to March 31, 2011, we had not recognized any revenues related to the OPA contract. In addition, we recognized revenues related to fees received based on the finalization of performance related to a certain California demand response program for which we had earned additional revenues related to our performance during the year ended December 31, 2010 and for which the corresponding cost of revenues were recorded in 2010. An increase in our MW under management in certain of our demand response programs, specifically ERCOT, also offset the decrease in our DemandSMART revenues. With respect to ERCOT, the increase in revenues for the three months ended June 30, 2011 was lower than the increase in revenues for the three months ended March 31, 2011 as a result of an increase in MW under management being offset by a reduction in fees due to underperformance.

     For the three and six months ended June 30, 2011, our EfficiencySMART, SupplySMART and CarbonSMART applications and services revenues increased by $3.2 million and $5.8 million, respectively, as compared to the same periods in 2010 primarily due to our acquisition of Global Energy Partners, Inc, or Global Energy, a company specializing in the design and implementation of utility energy efficiency and demand response programs, which occurred in January 2011.

     We currently expect our total revenues to increase slightly for the year ending December 31, 2011 as compared to 2010. Although our MW under management have increased in the PJM market in 2011 as compared to 2010, until PJM prices return in 2013 to more historical levels, we expect our revenues derived from the PJM market to decrease as a percentage of total annual revenues in 2011 and 2012 as significantly lower capacity prices in this market take effect for those years. These lower prices in PJM will negatively impact our ability to grow our overall revenues in 2011 and 2012 at levels consistent with prior years.

     In addition, the discontinuance of the ILR program by PJM beginning in 2012 will reduce the flexibility that we currently have to manage our portfolio of demand response capacity in the PJM market and will negatively impact our future revenues. We also expect a decrease in MW enrolled in the PJM market in 2012 as compared to 2011, which will also negatively impact our revenues in 2012. In connection with the PJM statement, we filed for and were granted expedited declaratory relief with FERC, which clarified that we may continue to manage our portfolio of demand response capacity in PJM as we have in the past and continue to receive settlement in accordance with the current PJM market rules approved by FERC. However, PJM continues to take steps to modify the market rules according to the PJM statement, including by filing proposed tariff changes with FERC. In the event that PJM is successful at modifying the market rules in the future to reflect its position as set forth in the PJM statement, our revenues for 2011 and beyond could be significantly reduced. Furthermore, the attention of our management and other personnel has been, and may continue to be, diverted as we defend our position with respect to the PJM statement, which has had, and may continue to have, a negative impact on our sales efforts in, and revenues derived from, the PJM region as well as our other operating regions.

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Gross Profit and Gross Margin

     The following table summarizes our gross profit and gross margin percentages for our energy management applications and services for the three and six months ended June 30, 2011 and 2010 (dollars in thousands):

Three Months Ended June 30,
2011				2010
Gross Profit	Gross Margin			Gross Profit		Gross Margin
$                                     20,377		34.6	%	$	28,992		43.6	%
Six Months Ended June 30,
2011				2010
Gross Profit	Gross Margin			Gross Profit		Gross Margin
$                                     32,938		36.3	%	$	38,567		40.7	%

     The decrease in gross profit during the three and six months ended June 30, 2011 as compared to the same periods in 2010 was primarily due to less favorable pricing in PJM and ISO-NE. Additionally, gross profit decreased as a result of an increase in the estimated reserve for potential performance adjustments in PJM recorded in the three months ended June 30, 2011. The decrease in gross profit was offset in part by the recognition of revenues in connection with the OPA contract pursuant to which we recognized the cost of such revenues in previous periods. The decrease in gross profit was also offset by our strong demand response event performance, particularly in the ISO-NE region, which resulted in higher energy payments for the six months ended June 30, 2011 as compared to the same period in 2010, as well as an increase in gross profit due to certain acquisitions that we recently completed.

     Our gross margin decreased during the three and six months ended June 30, 2011 as compared to the same periods in 2010 primarily due to less favorable pricing in PJM and ISO-NE, which were not entirely offset by lower payments to our C&I customers. Our gross margins were also impacted by an increase in the estimated reserve for potential performance adjustments in PJM recorded in the three months ended June 30, 2011. Additionally, our gross margin was also impacted by deferring certain revenues related to Global Energy and M2M for which the corresponding cost of revenues was recorded in the three and six months ended June 30, 2011. This decrease was offset in part by the recognition of revenues in connection with the OPA contract and a California demand response program in which we participate, pursuant to which we recognized the cost of such revenues in previous periods.

     We currently expect that our gross margin for the year ending December 31, 2011 will be slightly above our gross margin for the year ended December 31, 2010 of 42.9%, and that our gross margin for the three months ending September 30, 2011 will be the highest gross margin among our four quarterly reporting periods in 2011, consistent with our gross margin pattern in 2010, due to seasonality related to the demand response market. In addition, until the prices in the PJM market improve in 2013, we expect the lower capacity prices that will take effect in the PJM market in 2011 and 2012 to negatively impact our ability to grow our overall gross profits and gross margins in 2011 and 2012 at levels consistent with prior years. Moreover, the discontinuance of the ILR program by PJM beginning in 2012 will reduce the flexibility that we currently have to manage our portfolio of demand response capacity in the PJM market and will negatively impact our future gross profits and gross margins. We also expect a decrease in MW enrolled in the PJM market in 2012 as compared to 2011, which will also negatively impact our gross profits and gross margins in 2012. In addition, in connection with the PJM statement or otherwise, in the event that PJM is successful at modifying the market rules in the future or the attention of our management and other personnel continues to be diverted, our gross profits for 2011 and beyond could be further reduced and our gross margins for the same period could be negatively impacted.

Operating Expenses

     The following table summarizes our operating expenses for the three and six months ended June 30, 2011 and 2010 (dollars in thousands):

	Three Months Ended June 30,				Percentage
	2011		2010		Change
Operating Expenses:
Selling and marketing	$	13,620	$	11,531		18.1	%
General and administrative		15,899		13,152		20.9	%
Research and development		3,350		2,494		34.3	%
Total	$	32,869	$	27,177		20.9	%

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	Six Months Ended June 30,				Percentage
	2011		2010		Change
Operating Expenses:
Selling and marketing	$	25,207	$	20,645		22.1	%
General and administrative		32,212		26,901		19.7	%
Research and development		6,582		4,551		44.6	%
Total	$	64,001	$	52,097		22.8	%

     In certain forward capacity markets in which we choose to participate, such as PJM, we may enable our C&I customers, meaning we may install our equipment at a C&I customer site to allow for the curtailment of MW from the electric power grid, up to twelve months in advance of enrolling the C&I customer in a particular program. This market feature creates a longer average revenue recognition lag time across our C&I customer portfolio from the point in time when we consider a MW to be under management to when we earn revenues from that MW. Because we incur operational expenses, including salaries and related personnel costs, at the time of enablement, there has been a trend of incurring operating expenses associated with enabling our C&I customers in advance of recognizing the corresponding revenues.

     Selling and Marketing Expenses

	Three Months Ended June 30,				Percentage
	2011		2010		Change
Payroll and related costs	$	9,417	$	7,998		17.7	%
Stock-based compensation		1,255		1,108		13.3	%
Other		2,948		2,425		21.6	%
Total	$	13,620	$	11,531		18.1	%

	Six Months Ended June 30,				Percentage
	2011		2010		Change
Payroll and related costs	$	17,066	$	13,801		23.7	%
Stock-based compensation		2,298		2,124		8.2	%
Other		5,843		4,720		23.8	%
Total	$	25,207	$	20,645		22.1	%

     The increase in selling and marketing expenses for the three and six months ended June 30, 2011 compared to the same periods in 2010 was primarily due to an increase in payroll and related costs associated with an increase in the number of selling and marketing full-time employees from 174 at June 30, 2010 to 209 at June 30, 2011.

     The increase in payroll and related costs for the three months ended June 30, 2011 compared to the same period in 2010 was also attributable to an increase in sales commissions payable to members of our sales organization of $0.2 million, as well as the timing associated with our hiring new full-time employees during 2011 as compared to 2010. These increases were offset by a slight decrease in salary rates per full-time employee. The increase in payroll and related costs for the six months ended June 30, 2011 compared to the same period in 2010 was also primarily attributable to an increase in sales commissions payable to members of our sales organization of $0.8 million, as well as the timing associated with our hiring new full-time employees during 2011 as compared to 2010 and an increase in salary rates per full-time employee.

     The increase in stock-based compensation for the three and six months ended June 30, 2011 compared to the same periods in 2010 was primarily due to annual stock-based awards granted to certain of our officers and costs related to equity awards granted to certain of our employees, offset in part by significant stock-based awards granted in 2006 that became fully expensed.

     The increase in other selling and marketing expenses for the three months ended June 30, 2011 compared to the same period in 2010 was attributable to us allocating company-wide costs to selling and marketing expenses based on headcount, which

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resulted in an increase in facility costs of $0.9 million due to the expansion of our office space as a result of recent acquisitions and an increase of $0.1 million due to technology and communication costs. This increase was offset in part by a decrease in marketing costs of $0.5 million due to decreases in costs associated with third-party marketing personnel, employee attendance at conferences and seminars, and costs associated with rebranding efforts in 2010. The increase in other selling and marketing expenses for the six months ended June 30, 2011 compared to the same period in 2010 was attributable to us allocating company-wide costs to selling and marketing expenses based on headcount, which resulted in an increase in facility costs of $1.4 million due to the expansion of our office space as a result of recent acquisitions. This increase was also attributable to increases in professional services of $0.1 million, primarily due to increased legal fees. This increase was offset in part by decreases in marketing costs of $0.4 million due to decreases in costs associated with third-party marketing personnel, employee attendance at conferences and seminars, and costs associated with rebranding efforts in 2010.

     General and Administrative Expenses

	Three Months Ended June 30,				Percentage
	2011		2010		Change
Payroll and related costs	$	8,540	$	7,109		20.1	%
Stock-based compensation		2,212		2,352		(6.0	)%
Other		5,147		3,691		39.4	%
Total	$	15,899	$	13,152		20.9	%

	Six Months Ended June 30,				Percentage
	2011		2010		Change
Payroll and related costs	$	18,057	$	14,104		28.0	%
Stock-based compensation		4,380		5,515		(20.6	)%
Other		9,775		7,282		34.2	%
Total	$	32,212	$	26,901		19.7	%

     The increase in general and administrative expenses for the three and six months ended June 30, 2011 compared to the same periods in 2010 was primarily due to an increase in payroll and related costs due to an increase in executive compensation and severance. The increase in payroll and related costs for the three and six months ended June 30, 2011 compared to the same periods in 2010 was also attributable to an increase in full-time employees from 232 at June 30, 2010 to 278 at June 30, 2011.

     The decrease in stock-based compensation for the three and six months ended June 30, 2011 compared to the same periods in 2010 was primarily due to a fully-vested stock award granted to an executive in the six months ended June 30, 2010 compared with no such award granted in the six months ended June 30, 2011, as well as fully-vested stock awards granted to our board of directors with a lesser grant-date fair value in the six months ended June 30, 2011 than the same amount of stock-based awards granted during the same period in 2010. Additionally, we recognized a reversal of stock-based compensation expense related to the forfeiture of stock-based awards that were granted to our former senior vice president and chief operating officer, who terminated employment with us in February 2011 prior to the vesting of these awards.

     The increase in other general and administrative expenses for the three months ended June 30, 2011 compared to the same period in 2010 was attributable to an increase in professional services fees of $0.9 million primarily due to increased accounting, consulting and legal fees as a result of recent acquisitions, and an increase in technology and communication costs of $0.3 million. Additionally, we allocated company-wide costs to general and administrative expenses based on headcount, which resulted in a $0.3 million increase of facility costs related to increased rent expense due to the expansion of our office space.

     The increase in other general and administrative expenses for the six months ended June 30, 2011 compared to the same period in 2010 was attributable to an increase in professional services fees of $1.1 million primarily due to increased accounting, consulting and legal fees as a result of our acquisitions. The increase was also attributable to miscellaneous expenses, including finance charges and other taxes, of $0.5 million due to the growth of our business. Additionally, the increase was due to technology and communication costs of $0.5 million. We also allocated company-wide costs to general and administrative expenses based on headcount, which resulted in a $0.4 million increase of facility costs related to increased rent expense due to the expansion of our office space.

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     Research and Development Expenses

	Three Months Ended June 30,				Percentage
	2011		2010		Change
Payroll and related costs	$	1,917	$	1,582		21.2	%
Stock-based compensation		318		198		60.6	%
Other		1,115		714		56.2	%
Total	$	3,350	$	2,494		34.3	%

	Six Months Ended June 30,				Percentage
	2011		2010		Change
Payroll and related costs	$	3,672	$	2,773		32.4	%
Stock-based compensation		589		365		61.4	%
Other		2,321		1,413		64.3	%
Total	$	6,582	$	4,551		44.6	%

     The increase in research and development expenses for the three and six months ended June 30, 2011 compared to the same periods in 2010 was primarily driven by the costs associated with an increase in the number of research and development full-time employees from 56 at June 30, 2010 to 67 at June 30, 2011, as well as an increase in salary rates per full-time employee. The increase in research and development expenses for the three and six months ended June 30, 2011 compared to the same periods in 2010 was also attributable to lower capitalized internal payroll and related costs of $0.2 million and $0.4 million, respectively.

     The increase in stock-based compensation for the three and six months ended June 30, 2011 compared to the same periods in 2010 was primarily due to stock-based awards granted to certain employees in connection with our acquisition of SmallFoot LLC, or Smallfoot, and ZOX, LLC, or Zox, in March 2010, as well as costs related to equity awards granted to certain of our employees.

     The increase in other research and development expenses for the three months ended June 30, 2011 compared to the same period in 2010 was primarily related to a $0.3 million increase in technology and communications related to software licenses and fees used in the development of our energy management applications and $0.1 million related to professional services fees for consulting services associated with the development of our energy management applications. The increase in other research and development expenses for the six months ended June 30, 2011 compared to the same period in 2010 was primarily related to a $0.5 million increase in technology and communications related to software licenses and fees used in the development of our energy management applications and $0.3 million related to professional services fees for consulting services associated with the development of our energy management applications. We also allocated company-wide costs to research and development expenses based on headcount, which resulted in a $0.1 million increase of facility costs related to increased rent expense due to the expansion of our office space.

Other Expense, Net

     Other expense, net for the three and six months ended June 30, 2011 and the three and six months ended June 30, 2010 was primarily comprised of a nominal amount of interest income offset by a nominal amount of foreign currency losses related to certain receivables denominated in foreign currencies.

Interest Expense

     Interest expense for the three and six months ended June 30, 2011 includes interest on our outstanding capital leases and letters of credit origination fees. The decrease in interest expense for the three and six months ended June 30, 2011 compared to the same periods in 2010 was due to lower fees incurred in connection with outstanding letters of credit.

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Income Taxes

     The tax provision recorded for the three and six months ended June 30, 2011 was $0.1 million and $0.8 million, respectively, and represented the following:

• estimated foreign taxes resulting from guaranteed profit allocable to our foreign subsidiaries, which have been determined to be limited-risk service providers acting on behalf of the U.S. parent for tax purposes, for which there are no tax net operating loss carryforwards; and

• amortization of tax deductible goodwill, which generates a deferred tax liability that cannot be offset by net operating losses or other deferred tax assets since its reversal is considered indefinite in nature.

     In accordance with ASC 740,Income Taxes,or ASC 740, each interim period is considered an integral part of the annual period and tax expense is measured using an estimated annual effective tax rate. An enterprise is required, at the end of each interim reporting period, to make its best estimate of the annual effective tax rate for the full fiscal year and use that rate to provide for income taxes on a current year-to-date basis. Generally, if an enterprise has an ordinary loss for the year to date at the end of an interim period and anticipates ordinary income for the fiscal year, the enterprise will record an interim period tax benefit based on applying the estimated annual effective tax rate to the ordinary loss as long as the tax benefits are realized during the year or recognizable as a deferred tax asset as of the end of the year. However, if an enterprise is unable to make a reliable estimate of its annual effective tax rate, then actual effective tax rate for the year-to-date may be the best estimate of the annual effective tax rate. We have determined that we are currently unable to make a reliable estimate of our annual effective tax rate as of June 30, 2011 due to unusual sensitivity to the rate as it relates to the current forecasted U.S. ordinary income for the fiscal year ending December 31, 2011, or fiscal 2011. As a result, we recorded a tax provision for the three and six months ended June 30, 2011 based on our actual effective tax rate for the six months ended June 30, 2011.

     If we are able to make a reliable estimate of our annual effective tax rate as of September 30, 2011 and if we are still anticipating U.S. ordinary income for fiscal 2011, then as required by ASC 740, we will utilize that rate to provide for income taxes on a current year-to-date basis, which could result in a significant provision from income taxes being recorded during the three months ending September 30, 2011, which would be predominantly offset by a significant benefit recorded during the three months ending December 31, 2011. If we continue to be unable to make a reliable estimate of our annual effective tax rate as of September 30, 2011, we expect to follow a consistent methodology as applied for the three and six months ended June 30, 2011.

     We reviewed all available evidence to evaluate the recovery of deferred tax assets, including the recent history of accumulated losses in all tax jurisdictions over the last three years, as well as our ability to generate income in future periods. As of June 30, 2011, due to the uncertainty related to the ultimate use of our deferred income tax assets, we have provided a full valuation allowance on all of our U.S. deferred tax assets.

     For the three months ended June 30, 2010, we recorded a provision for income taxes of $0.3 million. For the six months ended June 30, 2010, we recorded a benefit from income taxes of $0.9 million.

Liquidity and Capital Resources

     Overview

     Since inception, we have generated significant cumulative losses. As of June 30, 2011, we had an accumulated deficit of $100.0 million. As of June 30, 2011, our principal sources of liquidity were cash and cash equivalents totalling $79.2 million, a decrease of $74.2 million from the December 31, 2010 balance of $153.4 million. As of June 30, 2011, we were contingently liable for $43.5 million in connection with outstanding letters of credit under the 2011 credit facility. As of June 30, 2011 and December 31, 2010, we had restricted cash balances of $0.1 million and $1.5 million, respectively, which relate to amounts to collateralize unused outstanding letters of credit and cover financial assurance requirements in certain of the programs in which we participate and certain other commitments. At June 30, 2011 and December 31, 2010, our excess cash was primarily invested in money market funds.

     We believe our existing cash and cash equivalents at June 30, 2011, amounts available under the 2011 credit facility and our anticipated net cash flows from operating activities will be sufficient to meet our anticipated cash needs, including investing activities, for at least the next 12 months. Our future working capital requirements will depend on many factors, including, without limitation, the rate at which we sell certain of our energy management applications and services to electric power grid operators and utilities and the increasing rate at which letters of credit or security deposits are required by those electric power grid operators and utilities, the introduction and market acceptance of

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new energy management applications and services, the expansion of our sales and marketing and research and development activities, and the geographic expansion of our business operations. To the extent that our cash and cash equivalents, amounts available under the 2011 credit facility and our anticipated cash flows from operating activities are insufficient to fund our future activities or planned future acquisitions, we may be required to raise additional funds through bank credit arrangements or public or private equity or debt financings. We also may raise additional funds in the event we determine in the future to effect one or more acquisitions of businesses, technologies or products. In addition, we may elect to raise additional funds even before we need them if the conditions for raising capital are favorable. Accordingly, we have filed a shelf registration statement with the SEC to register shares of our common stock and other securities for sale, giving us the opportunity to raise funding when needed or otherwise considered appropriate at prices and on terms to be determined at the time of any such offerings. We currently have the ability to sell approximately $62.1 million of our securities under the shelf registration statement. Any equity or equity-linked financing could be dilutive to existing stockholders. In the event we require additional cash resources, we may not be able to obtain bank credit arrangements or effect any equity or debt financing on terms acceptable to us or at all.

     Cash Flows

     The following table summarizes our cash flows for the six months ended June 30, 2011 and 2010 (dollars in thousands):

	Six Months Ended June 30,
	2011			2010
Cash flows provided by operating activities	$	8,052		$	10,976
Cash flows used in investing activities		(83,887	)		(14,647	)
Cash flows provided by financing activities		1,717			2,455
Effects of exchange rate changes on cash		(62	)		(12	)
Net change in cash and cash equivalents	$	(74,180	)	$	(1,228	)

     Cash Flows Provided by Operating Activities

     Cash provided by operating activities primarily consists of net 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 provided by operating activities for the six months ended June 30, 2011 was $8.1 million and consisted of $21.7 million of net cash provided by working capital and other activities and $18.6 million of non-cash expense items, primarily consisting of depreciation and amortization, deferred taxes, stock-based compensation charges and impairment charges of property and equipment, offset by a net loss of $32.2 million.

     Cash provided by working capital and other activities consisted of a decrease of $56.1 million in unbilled revenues relating to the PJM demand response market, a decrease of $0.1 million in inventory, an increase of $3.9 million in deferred revenue and an increase of $1.1 million in accrued payroll and related expenses. These amounts were offset by cash used in working capital and other activities consisting of an increase of $8.8 million in accounts receivable due to the timing of cash receipts under the programs in which we participate, an increase in prepaid expenses and other assets of $5.3 million, a decrease of accrued capacity payments of $23.3 million, the majority of which was related to the PJM demand response market, and a decrease of $2.1 million in accounts payable and accrued expenses and other current liabilities due to the timing of payments.

     Cash provided by operating activities for the six months ended June 30, 2010 was $11.0 million and consisted of a net loss of $13.1 million offset by $8.2 million of net cash provided by working capital and other activities and $15.9 million of non-cash items, primarily consisting of depreciation and amortization, deferred taxes, stock-based compensation charges and impairment of property and equipment. Cash provided by working capital and other activities consisted of a decrease of $10.6 million in unbilled revenues relating to the PJM demand response market, a $2.9 million increase in deferred revenue, an increase in other non-current liabilities of $1.2 million, an increase of $4.7 million in accounts payable and accrued expenses due to the timing of C&I customer payments, and an increase of $0.3 million in accrued payroll and related expenses. These amounts were partially offset by cash used in working capital and other activities, which reflected an increase in prepaid expenses and other assets of $5.1 million, an increase in accounts receivable of $6.1 million due to the timing of cash receipts under the demand response programs in which we participate and a $0.3 million decrease in accrued capacity payments, the majority of which was related to the PJM demand response market.

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     Cash Flows Used in Investing Activities

     Cash used in investing activities was $83.9 million for the six months ended June 30, 2011. During the six months ended June 30, 2011, we acquired Global Energy for a purchase price of $26.7 million, of which $19.9 million was paid in cash, and M2M Communications Corporation, or M2M, for a purchase price of $29.9 million, of which $17.6 million was paid in cash. During the six months ended June 30, 2011, we also completed an immaterial acquisition for a purchase price of $5.2 million, of which $3.9 million was paid in cash. Additionally, our cash investments included the cash portion of the acquisition contingent consideration for Cogent Energy, Inc., or Cogent, of $1.5 million. During the six months ended June 30, 2011, a portion of our cash totaling $28.1 million was transferred to a third party agent at the end of June 2011 in anticipation of the potential acquisition of Energy Response. On July 1, 2011, we completed the Energy Response acquisition for $27.3 million and the excess cash held by the third party was returned to us in July 2011. Our principal cash investments during the six months ended June 30, 2011 related to capitalizing internal use software costs used to build out and expand our energy management applications and services and purchases of property and equipment. During the six months ended June 30, 2011, we also incurred $12.1 million in capital expenditures primarily related to the purchase of office equipment and demand response equipment and other miscellaneous expenditures.

     Cash used in investing activities was $14.6 million for the six months ended June 30, 2010. Our principal cash investments during the six months ended June 30, 2010 related to capitalizing internal use software costs used to build out and expand our demand response and other energy management applications and services and purchases of property and equipment. During the six months ended June 30, 2010, we acquired Smallfoot and Zox for a purchase price of $1.4 million, of which $1.1 million was paid in cash. Additionally, our cash investments included the cash portion of the earn-out payment due in connection with our acquisition of South River Consulting, LLC, or SRC, of $0.9 million. We had an increase in restricted cash and deposits resulting in a reduction of cash of $0.6 million primarily as a result of our cash deposits made in connection with demand response programs in which we participate. During the six months ended June 30, 2010, we also incurred $12.0 million in capital expenditures primarily related to the purchase of office equipment and demand response equipment and other miscellaneous expenditures.

     Cash Flows Provided by Financing Activities

     Cash provided by financing activities was $1.7 million and $2.5 million for the six months ended June 30, 2011 and 2010, respectively, and consisted primarily of proceeds that we received from exercises of options to purchase shares of our common stock during the six months ended June 30, 2011 and 2010.

     Credit Facility Borrowings

     In April 2011, we and one of our subsidiaries entered into the 2011 credit facility. Subject to continued covenant compliance, the 2011 credit facility provides for a two-year revolving line of credit in the aggregate amount of $75.0 million, the full amount of which may be available for issuances of letters of credit and up to $5.0 million of which may be available for swing line loans. The revolving line of credit is subject to increase from time to time up to an aggregate amount of $100.0 million with additional commitments from the lenders or new commitments from financial institutions acceptable to SVB. The interest on revolving loans under the 2011 credit facility will accrue, at our election, at either (i) the Eurodollar Rate with respect to the relevant interest period plus 2.00% or (ii) the ABR (defined as the highest of (x) the “prime rate” as quoted in theWall Street Journal, (y) the Federal Funds Effective Rate plus 0.50% and (z) the Eurodollar Rate for a one-month interest period plus 1.00%) plus 1.00%. In connection with the issuance or renewal of letters of credit for our account, we are charged a letter of credit fee of 2.125% pursuant to the 2011 credit facility. We expense the interest and letter of credit fees, as applicable, in the period incurred. The 2011 credit facility terminates and all amounts outstanding thereunder are due and payable in full on April 15, 2013. As of June 30, 2011, we were not in compliance with one covenant under the 2011 credit facility as a result of the transfer of cash to fund the acquisition of Energy Response and obtained a waiver of this covenant default from SVB. At June 30, 2011, we had no borrowings and letters of credit totaling $43.5 million outstanding under the 2011 credit facility.

     The 2011 credit facility contains customary terms and conditions for credit facilities of this type, including restrictions on the ability of us and our subsidiaries to incur additional indebtedness, create liens, enter into transactions with affiliates, transfer assets, pay dividends or make distributions on, or repurchase our common stock, consolidate or merge with other entities, or suffer a change in control. In addition, we are required to meet certain financial covenants customary with this type of credit facility, including maintaining a minimum specified tangible net worth and a minimum specified ratio of current assets to current liabilities.

     The 2011 credit facility contains customary events of default, including for payment defaults, breaches of representations, breaches of affirmative or negative covenants, cross defaults to other material indebtedness, bankruptcy and failure to discharge certain judgments. If a default occurs and is not cured within any applicable cure period or is not waived, the lenders may accelerate our obligations under the 2011 credit facility. The 2011 credit facility replaces the 2008 credit facility, which was in place as of March 31, 2011.

     On April 15, 2011, we and one of our subsidiaries entered into a guarantee and collateral agreement with SVB for the benefit of the lenders under the 2011 credit facility. The guarantee and collateral agreement provides that the obligations under the 2011 credit facility are secured by all domestic assets of us and several of our subsidiaries, excluding our foreign subsidiaries.

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     We incurred financing costs of $0.5 million in connection with the 2011 credit facility, which were deferred and are being amortized to interest expense over the life of the 2011 credit facility, which matures on April 15, 2013.

     In April 2011, we were required to provide financial assurance in connection with our capacity bid in a certain open market bidding program. We provided this financial assurance utilizing approximately $56.0 million of our available cash on hand and a $39.0 million letter of credit issued under the 2011 credit facility. In May 2011, based on the capacity that we cleared in this open market bidding program and the required post-auction financial assurance requirements, we recovered all the $56.0 million of our available cash that we had provided as financial assurance prior to the auction and were able to reduce the $39.0 million letter of credit to $13.5 million.

     In June 2011, we and one of our subsidiaries entered into an amendment to the 2011 credit facility, which modified certain of our covenant requirements.

Contingent Earn-Out Payments

     In connection with our acquisition of Cogent, we agreed to make a single contingent earn-out payment of $1.5 million in cash, to be paid based on the achievement of a certain minimum revenue-based milestone and a certain earnings-based milestone of Cogent for the year ended December 31, 2010. Both of these milestones needed to be achieved in order for the earn-out payment to occur, and there would be no partial payment if the milestones were not fully achieved. As we believed that it was remote that the earn-out payment would not be made, we determined the fair value of the earn-out payment based on the present value of the $1.5 million and recorded this in connection with our purchase accounting for the acquisition of Cogent. The milestones were achieved and we paid the earn-out payment in January 2011.

Capital Spending

     We have made capital expenditures primarily for general corporate purposes to support our growth and for equipment installation related to our business. Our capital expenditures totaled $12.1 million and $12.0 million during the six months ended June 30, 2011 and 2010, respectively. As we continue to grow, we expect our capital expenditures for 2011 to increase as compared to 2010.

Contractual Obligations

     As of June 30, 2011, the contractual obligations disclosure contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010, which we filed with the SEC on March 1, 2011, has not materially changed.

Off-Balance Sheet Arrangements

     As of June 30, 2011, we did not have any off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K, that have or are reasonably likely to have a current or future effect on our financial condition, changes in our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. We have issued letters of credit in the ordinary course of our business in order to participate in certain demand response programs. As of June 30, 2011, we had outstanding letters of credit totaling $43.5 million. For information on these commitments and contingent obligations, see “Liquidity and Capital Resources — Credit Facility Borrowings” above and Note 8 to our unaudited condensed consolidated financial statements contained herein.

Critical Accounting Policies and Use of Estimates

     The discussion and analysis of our financial condition and results of operations are based upon our interim unaudited condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates, including those related to revenue recognition for multiple element arrangements, allowance for doubtful accounts, valuations and purchase price allocations related to business combinations, expected future cash flows including growth rates, discount rates, terminal values and other assumptions and estimates used to evaluate the recoverability of long-lived assets and goodwill, estimated fair values of intangible assets and goodwill, amortization methods and periods, certain accrued expenses and other related charges, stock-based compensation, contingent liabilities, tax reserves and recoverability of our net deferred tax assets and related valuation allowance. We

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base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates if past experience or other assumptions do not turn out to be substantially accurate. Any differences may have a material impact on our financial condition and results of operations.

     The critical accounting estimates used in the preparation of our financial statements that we believe affect our more significant judgments and estimates used in the preparation of our interim condensed consolidated financial statements presented in this Quarterly Report on Form 10-Q are described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in the notes to the consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2010, which we filed with the SEC on March 1, 2011. Except as disclosed herein, there have been no material changes to our critical accounting policies or estimates during the three and six months ended June 30, 2011.

Revenue Recognition

     We recognize revenues in accordance with ASC 605,Revenue Recognition. 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 reasonably assured. In making these judgments, we evaluate these criteria as follows:

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

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

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

• Collection is reasonably assured.We conduct a credit review at the inception of an arrangement to determine the creditworthiness of the customer. Collection is reasonably assured if, based upon 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 reasonably assured, revenues are deferred and recognized upon the receipt of cash.

     We enter into utility contracts and open market bidding programs to provide demand response applications and services. Demand response revenues consist of two elements: revenue earned based on our ability to deliver committed capacity to our electric power grid operator and utility customers, which we refer to as capacity revenue; and revenue earned based on additional payments made to us for the amount of energy usage actually curtailed from the grid during a demand response event, which we refer to as energy event revenue.

     We recognize demand response revenue when we have provided verification to the electric power grid operator or utility of our ability to deliver the committed capacity which entitles us to payments under the utility contract or open market program. Committed capacity is generally 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 electric power grid operator or utility customer will reduce future payments based on the adjusted verified capacity amounts. 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 and the amount of refund cannot be reliably estimated, the revenue is deferred until the right of refund lapses.

     With respect to one of the open market programs in which we participate, performance is measured based on the aggregate performance during the months of June through September. June is the commencement of the program year. As a result, fees received for the month of June could potentially be subject to adjustment or refund based on performance during the months of July through September. We have concluded that we can reliably estimate the amount of fees potentially subject to adjustment or refund and record a reserve for this amount in the month of June. As of June 30, 2011, we recorded an estimated reserve of $9.3 million related to potential subsequent performance adjustments. The fees under this program are fixed as of September 30 and we will record any change in estimate based on final performance during the three months ending September 30, 2011. Historically, the changes in estimate have not been material.

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     As a result of a contractual amendment entered into during the three months ended March 31, 2011 to amend certain refund provisions included in one of our utility contracts, we concluded that we could reliably estimate the fees potentially subject to refund as of March 31, 2011 and therefore, the fees under this arrangement were fixed or determinable. As a result, during the three months ended March 31, 2011, we recognized as revenues $3.0 million of fees that had been previously deferred as of December 31, 2010.

     Certain of the forward capacity programs in which we participate may be deemed derivative contracts under ASC 815,Derivatives and Hedging(ASC 815). In such situations, we believe we meet the scope exception under ASC 815 as a normal purchase, normal sale as that term is defined in ASC 815 and, accordingly, the arrangement is not treated as a derivative contract.

     Energy event revenues are 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 electric power grid operator or utility customer and we have responded under the terms of the utility contract or open market program.

     Under certain of our arrangements, in particular those arrangements entered into by M2M, we sell equipment to the C&I customer that is utilized to provide the ongoing services that we deliver. Currently, this equipment has been determined to not have stand-alone value. As a result, we defer the fees associated with the equipment and, once the C&I customer is receiving the ongoing services from us, recognizes those fees ratably over the expected C&I customer relationship period, which is generally three years. In addition, we capitalize the direct and incremental costs, which primarily represent the equipment and third-party installation costs, and recognize such costs over the expected C&I customer relationship period.

     In September 2009, the Financial Accounting Standards Board, or FASB, ratified ASC Update No. 2009-13,Multiple-Deliverable Revenue Arrangements, or ASU 2009-13. ASU 2009-13 amends existing revenue recognition accounting pronouncements that are currently within the scope of ASC Subtopic 605-25, which is the revenue recognition guidance for multiple-element arrangements. ASU 2009-13 provides for three significant changes to the existing multiple element revenue recognition guidance as follows:

• deletes the requirement to have objective and reliable evidence of fair value for undelivered elements in an arrangement. This may result in more deliverables being treated as separate units of accounting;

• modifies the manner in which the arrangement consideration is allocated to the separately identified deliverables. ASU 2009-13 requires an entity to allocate revenue in an arrangement using its best estimate of selling prices, or ESP, of deliverables if a vendor does not have vendor-specific objective evidence of selling price, or VSOE, or third-party evidence of selling price, or TPE, if VSOE is not available. Each separate unit of accounting must have a selling price, which can be based on management’s estimate when there is no other means (VSOE or TPE) to determine the selling price of that deliverable. The arrangement consideration is allocated based on the elements’ relative selling prices; and

• eliminates use of the residual method and requires an entity to allocate revenue using the relative selling price method, which results in the discount in the transaction being evenly allocated to the separate units of accounting.

     As required, we adopted ASU 2009-13 at the beginning of our first quarter of fiscal 2011 on a prospective basis for transactions originating or materially modified on or after January 1, 2011. ASU 2009-13 generally does not change the units of accounting for our revenue transactions. The impact of adopting ASU 2009-13 was not material to our financial statements during the six months ended June 30, 2011, and if they were applied in the same manner to fiscal 2010 would not have had a material impact to revenue for the six months ended June 30, 2010. We do not expect the adoption of ASU 2009-13 to have a significant impact on the timing and pattern of revenue recognition in the future due to the limited number of multiple element arrangements. The key impact that we expect the adoption of ASU 2009-13 to have relates to certain EfficiencySMART service arrangements with C&I customers who also provide curtailment of capacity as part of our demand response arrangements. Historically, we had recorded the fees recognized under these arrangements as a reduction of cost of revenues as evidence of fair value did not exist for persistent commissioning services due to limited history of selling separately and no available TPE. As previously stated, the impact of ASU 2009-13 has not been and is not expected to be material.

     We typically determine the selling price of its services based on VSOE. Consistent with our methodology under previous accounting guidance, we determine VSOE based on our normal pricing and discounting practices for the specific service when sold on a stand-alone basis. In determining VSOE, our policy is to require a substantial majority of selling prices for a product or service to be within a reasonably narrow range. We also consider the class of customer, method of distribution, and the geographies into which our products and services are sold into when determining VSOE. We typically have had VSOE for our products and services.

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     In certain circumstances, we are not able to establish VSOE for all deliverables in a multiple element arrangement. This may be due to the infrequent occurrence of stand-alone sales for an element, a limited sales history for new services or pricing within a broader range than permissible by our policy to establish VSOE. In those circumstances, we proceed to the alternative levels in the hierarchy of determining selling price. TPE of selling price is established by evaluating largely similar and interchangeable competitor products or services in stand-alone sales to similarly situated customers. We are typically not able to determine TPE and we have not used this measure since we are unable to reliably verify stand-alone prices of competitive solutions. ESP is established in those instances where neither VSOE nor TPE are available, considering internal factors such as margin objectives, pricing practices and controls, customer segment pricing strategies and the product life cycle. Consideration is also given to market conditions such as competitor pricing strategies information gathered from experience in customer negotiations, market research and information, recent technological trends, competitive landscape and geographies. Use of ESP is limited to a very small portion of our services, principally certain EfficiencySMART services.

Recent Accounting Pronouncements

Business Combinations

     In December 2010, the FASB issued Accounting Standards Update No. 2010-29,Business Combinations — Disclosure of Supplementary Pro Forma Information for Business Combinations, or ASU 2010-29. ASU 2010-29 requires a public entity to disclose revenue and earnings of the combined entity as though the business combination that occurred during the current year had occurred as of the beginning of the prior year. It also requires a description of the nature and amount of material, nonrecurring adjustments directly attributable to the business combination included in the reported revenue and earnings. The new disclosure was effective for our first quarter of fiscal 2011. The adoption of ASU 2010-29 will require additional disclosure in the event of a business combination but will not have a material impact on our financial condition and results of operations during the three and six months ended June 30, 2011. As a result of the acquisition of Energy Response in July 2011, we will be required to meet certain disclosure requirements and provide pro-forma financial information.

Intangibles — Goodwill and Other

     In December 2010, the FASB issued ASU 2010-28,Intangibles- Goodwill and Other, or ASU 2010-28. ASU 2010-28 modifies Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist. ASU 2010-28 is effective for fiscal years that begin after December 15, 2010, which is fiscal 2011 for us. The adoption of this standard did not have a material impact on our results from operations and financial condition.

Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS

     In May 2011, the FASB issued ASU 2011-04,Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS, which amends its accounting guidance related to fair value measurements in order to more closely align its disclosure requirements with those in International Financial Reporting Standards. This guidance clarifies the application of existing fair value measurement and disclosure requirements and also changes certain principles or requirements for measuring fair value or for disclosing information about fair value measurements. The guidance is effective for interim and annual periods beginning after December 15, 2011. The adoption of this guidance is not expected to have a material effect on our financial position or results of operations.

Presentation of Comprehensive Income

     In June 2011, the FASB issued ASU 2011-05,Presentation of Comprehensive Income,which represents new accounting guidance related to the presentation of other comprehensive income, or OCI. This guidance eliminates the option to present components of OCI as part of the statement of changes in shareholders’ equity, which is the option that we currently use to present OCI. The guidance allows for a one-statement or two-statement approach, outlined as follows:

• One-statement approach: Present the components of net income and total net income, the components of OCI and a total for OCI, along with the total of comprehensive income in a single continuous statement.

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• Two-statement approach: Present the components of net income and total net income in the statement of net income. A statement of OCI would immediately follow the statement of net income and include the components of OCI and a total for OCI, along with the total of comprehensive income.

     The guidance also requires an entity to present on the face of the financial statements any reclassification adjustments for items that are reclassified from OCI to net income. The guidance is effective for interim and annual periods beginning after December 15, 2011. The adoption of this guidance will not have an effect on our financial position or results of operations, but will only impact how certain information related to OCI is presented in our consolidated financial statements.

Additional Information

Non-GAAP Financial Measures

     To supplement our consolidated financial statements presented on a GAAP basis, we disclose certain non-GAAP measures that exclude certain amounts, including non-GAAP net income (loss), non-GAAP net income (loss) per share, adjusted EBITDA and free cash flow. These non-GAAP measures are not in accordance with, or an alternative for, generally accepted accounting principles in the United States.

     The GAAP measure most comparable to non-GAAP net income (loss) is GAAP net income (loss); the GAAP measure most comparable to non-GAAP net income (loss) per share is GAAP net income (loss) per share; the GAAP measure most comparable to adjusted EBITDA is GAAP net income (loss); and the GAAP measure most comparable to free cash flow is cash flows from operating activities. Reconciliations of each of these non-GAAP financial measures to the corresponding GAAP measure are included below.

Use and Economic Substance of Non-GAAP Financial Measures Used by EnerNOC

     Management uses these non-GAAP measures when evaluating our operating performance and for internal planning and forecasting purposes. Management believes that such measures help indicate underlying trends in our business, are important in comparing current results with prior period results, and are useful to investors and financial analysts in assessing our operating performance. For example, management considers non-GAAP net income (loss) to be an important indicator of the overall performance because it eliminates the effects of events that are either not part of our core operations or are non-cash compensation expenses. In addition, management considers adjusted EBITDA to be an important indicator of our operational strength and performance of our business and a good measure of our historical operating trend. Moreover, management considers free cash flow to be an indicator of our operating trend and performance of our business.

     The following is an explanation of the non-GAAP measures that we utilize, including the adjustments that management excluded as part of the non-GAAP measures for the three and six months ended June 30, 2011 and 2010, respectively, as well as reasons for excluding these individual items:

• Management defines non-GAAP net income (loss) as net income (loss) before expenses related to stock-based compensation and amortization expenses related to acquisition-related intangible assets, net of related tax effects.

• Management defines adjusted EBITDA as net income (loss), excluding depreciation, amortization, stock-based compensation, interest, income taxes and other income (expense). Adjusted EBITDA eliminates items that are either not part of our core operations or do not require a cash outlay, such as stock-based compensation. Adjusted EBITDA also excludes depreciation and amortization expense, which is based on our estimate of the useful life of tangible and intangible assets. These estimates could vary from actual performance of the asset, are based on historic cost incurred to build out our deployed network and may not be indicative of current or future capital expenditures.

• Management defines free cash flow as net cash provided by (used in) operating activities less capital expenditures. Management defines capital expenditures as purchases of property and equipment, which includes capitalization of internal-use software development costs.

Material Limitations Associated with the Use of Non-GAAP Financial Measures

     Non-GAAP net income (loss), non-GAAP net income (loss) per share, adjusted EBITDA and free cash flow may have limitations as analytical tools. The non-GAAP financial information presented here should be considered in conjunction with, and not as a substitute for or superior to, the financial information presented in accordance with GAAP and should not be considered measures of our liquidity. There are significant limitations associated with the use of non-GAAP financial measures. Further, these measures may differ from the non-GAAP information, even where similarly titled, used by other companies and therefore should not be used to compare our performance to that of other companies.

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Non-GAAP Net Loss and Non-GAAP Net Loss per Share

     Net loss for the three months ended June 30, 2011 was $13.0 million, or $0.51 per basic and diluted share, compared to a net income of $1.1 million, or $0.04 per basic and diluted share, for the three months ended June 30, 2010. Net loss for the six months ended June 30, 2011 was $32.2 million, or $1.27 per basic and diluted share, compared to a net loss of $13.1 million, or $0.54 per basic and diluted share, for the six months ended June 30, 2010. Excluding stock-based compensation charges and amortization of expenses related to acquisition-related assets, net of tax effects, non-GAAP net loss for the three months ended June 30, 2011 was $7.8 million, or $0.31 per basic and diluted share, compared to a non-GAAP net income of $4.3 million, or $0.18 per basic share and $0.17 per diluted share, for the three months ended June 30, 2010. Excluding stock-based compensation charges and amortization of expenses related to acquisition-related assets, net of tax effects, non-GAAP net loss for the six months ended June 30, 2011 was $22.5 million, or $0.88 per basic and diluted share, compared to a non-GAAP net loss of $4.9 million, or $0.20 per basic and diluted share, for the six months ended June 30, 2010. The reconciliation of non-GAAP net loss to GAAP net loss is set forth below:

	Three Months Ended June 30,
	2011			2010
	(In thousands, except share and per share data)
GAAP net (loss) income	$	(12,973	)	$	1,078
ADD: Stock-based compensation		3,785			3,658
ADD: Amortization expense of acquired intangible assets		1,373			368
LESS: Income tax effect on Non-GAAP adjustments(1)		—			(775	)
Non-GAAP net (loss) income	$	(7,815	)	$	4,329
GAAP net (loss) income per basic share	$	(0.51	)	$	0.04
ADD: Stock-based compensation		0.15			0.15
ADD: Amortization expense of acquired intangible assets		0.05			0.02
LESS: Income tax effect on Non-GAAP adjustments(1)		—			(0.03	)
Non-GAAP net (loss) income per basic share	$	(0.31	)	$	0.18
GAAP net (loss) income per diluted share	$	(0.51	)	$	0.04
ADD: Stock-based compensation		0.15			0.14
ADD: Amortization expense of acquired intangible assets		0.05			0.02
LESS: Income tax effect on Non-GAAP adjustments(1)		—			(0.03	)
Non-GAAP net (loss) income per diluted share	$	(0.31	)	$	0.17
Weighted average number of common shares outstanding
Basic		25,537,483			24,371,125
Diluted		25,537,483			25,861,957

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	Six Months Ended June 30,
	2011			2010
	(In thousands, except share and per share data)
GAAP net loss	$	(32,245	)	$	(13,122	)
ADD: Stock-based compensation		7,267			8,004
ADD: Amortization expense of acquired intangible assets		2,525			756
LESS: Income tax effect on Non-GAAP adjustments(2)		—			(568	)
Non-GAAP net loss	$	(22,453	)	$	(4,930	)
GAAP net loss per basic share	$	(1.27	)	$	(0.54	)
ADD: Stock-based compensation		0.29			0.33
ADD: Amortization expense of acquired intangible assets		0.10			0.03
LESS: Income tax effect on Non-GAAP adjustments(2)		—			(0.02	)
Non-GAAP net loss per basic share	$	(0.88	)	$	(0.20	)
GAAP net loss per diluted share	$	(1.27	)	$	(0.54	)
ADD: Stock-based compensation		0.29			0.33
ADD: Amortization expense of acquired intangible assets		0.10			0.03
LESS: Income tax effect on Non-GAAP adjustments(2)		—			(0.02	)
Non-GAAP net loss per diluted share	$	(0.88	)	$	(0.20	)
Weighted average number of common shares outstanding
Basic		25,393,864			24,212,004
Diluted		25,393,864			24,212,004

(1)	Represents the increase in the income tax provision recorded for the three months ended June 30, 2010 based on our effective tax rate for the three months ended June 30, 2010. The non-GAAP adjustments would have no impact on the provision for income taxes recorded for the three months ended June 30, 2011.
(2)	Represents the reduction in the income tax benefit recorded for the six months ended June 30, 2010 based on the effective tax rate for the six months ended June 30, 2010. The non-GAAP adjustments would have no impact on the provision for income taxes recorded for the six months ended June 30, 2011.

Adjusted EBITDA

     Adjusted EBITDA was negative $3.5 million and positive $9.2 million for the three months ended June 30, 2011 and 2010, respectively. Adjusted EBITDA was negative $13.8 million and positive $1.8 million for the six months ended June 30, 2011 and 2010, respectively.

     The reconciliation of adjusted EBITDA to net (loss) income is set forth below:

	Three Months Ended June 30,					Six Months Ended June 30,
	2011			2010		2011			2010
Net (loss) income	$	(12,973	)	$	1,078	$	(32,245	)	$	(13,122	)
Add back:
Depreciation and amortization		5,187			3,711		9,964			7,330
Stock-based compensation expense		3,785			3,658		7,267			8,004
Other expense		142			14		14			11
Interest expense		238			466		401			491
Provision for (benefit from) income tax		101			257		767			(910	)
Adjusted EBITDA	$	(3,520	)	$	9,184	$	(13,832	)	$	1,804

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Free Cash Flow

     Cash flow provided by operating activities was $13.7 million and $8.1 million for the three and six months ended June 30, 2011, respectively. Cash flow provided by operating activities was $7.9 million and $11.0 million for the three and six months ended June 30, 2010, respectively. We incurred positive free cash flows of $5.1 million and $1.4 million for the three months ended June 30, 2011 and 2010, respectively. We incurred negative free cash flows of $4.1 million and $1.1 million for the six months ended June 30, 2011 and 2010, respectively. The reconciliation of free cash flow to cash flow from operating activities is set forth below:

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Net cash provided by operating activities	$	13,740		$	7,854		$	8,052		$	10,976
Subtract:
Purchases of property and equipment		(8,680	)		(6,443	)		(12,144	)		(12,039	)
Free cash flow	$	5,060		$	1,411		$	(4,092	)	$	(1,063	)

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     At June 30, 2011, there had not been a material change in the interest rate risk information and foreign exchange risk information disclosed in the “Quantitative and Qualitative Disclosures About Market Risk” subsection of the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010, which we filed with the SEC on March 1, 2011.

Item 4. Controls and Procedures

Disclosure Controls and Procedures.

     Our principal executive officer and principal financial officer, after evaluating the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this Quarterly Report on Form 10-Q, have concluded that, based on such evaluation, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to our management, including our principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Internal Control over Financial Reporting.

     No change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the fiscal quarter ended June 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. 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 condition, results of operations or cash flows.

Item 1A. Risk Factors

     We operate in a rapidly changing environment that involves a number of risks that could materially affect our business, financial condition or future results, some of which are beyond our control. In addition to the other information set forth in this Quarterly Report on Form 10-Q, the risks and uncertainties that we believe are most important for you to consider are discussed in Part I — Item 1A under the heading “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010, or our 2010 Form 10-K, which we filed with the SEC on March 1, 2011. During the three months ended June 30, 2011, there were no material changes to the risk factors that were disclosed in Part I — Item 1A under the heading “Risk Factors” in our 2010 Form 10-K, other than as set forth below:

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          The risk factor titled “We are exposed to potential risks and will continue to incur significant costs as a result of the internal control testing and evaluation process mandated by Section 404 of the Sarbanes-Oxley Act of 2002” is deleted in its entirety from the risk factors set forth in our 2010 Form 10-K.

          The following risk factors replace and supersede the corresponding risk factors set forth in our 2010 Form 10-K:

Our future profitability may fluctuate, and we expect to incur net losses in the near term.

          As of June 30, 2011, we had an accumulated deficit of $100.0 million. Although we achieved profitability for the year ended December 31, 2010 with net income of $9.6 million, our net losses for the six months ended June 30, 2011 were $32.2 million, our net losses for the years ended December 31, 2009 and 2008 were $6.8 million and $36.7 million, respectively, and we expect to incur additional operating losses in the near term. Our operating losses have historically been driven by start-up costs, costs of developing our technology, and operating expenses related to increased headcount and the expansion of the number of MW under our management. As we seek to grow our revenues and customer base, we plan to continue to invest in our business and employee base in order to capitalize on emerging opportunities and expand our energy management applications and services, which will require increased operating expenses. We expect these increased operating expenses, as well as other factors, to cause us to incur net losses in the near term, and there can be no assurance that we will be able to grow our revenues at rates that will allow us to maintain profitability in the long term.

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

     During the years ended December 31, 2010, 2009 and 2008, revenues generated from open market sales to PJM, an electric power grid operator customer, accounted for 60%, 52% and 28%, respectively, of our total revenues. During the six months ended June 30, 2011, revenues generated from open market sales to PJM accounted for 35% of our total revenues. The modification or termination of our sales relationship with PJM, or the modification or termination of any of PJM’s open market programs in which we participate, could significantly reduce our future revenues and profit margins and have a material adverse effect on our results of operations and financial condition. For example, beginning in June 2012, PJM will discontinue the ILR program, which is a program in which we have historically been an active participant. The discontinuance of the ILR program by PJM will reduce the flexibility that we currently have to manage our portfolio of demand response capacity in the PJM market and will negatively impact our future revenues and profit margins. In addition, in February 2011, PJM and Monitoring Analytics, LLC, the PJM market monitor, issued the PJM statement. The PJM statement, among other things, asserted that certain market practices in the PJM capacity market were no longer appropriate or acceptable and unilaterally implied that compensation should no longer be determined by actual measured reductions in C&I customers’ electrical load, unless the reductions are below such C&I customers’ peak demand for electricity in the prior year. We filed for and were granted expedited declaratory relief with FERC, which clarified that we may continue to manage our portfolio of demand response capacity in PJM as we have in the past and continue to receive settlement in accordance with the current PJM market rules approved by FERC. However, PJM continues to take steps to modify the market rules according to the PJM statement, including by filing proposed tariff changes with FERC. In the event that PJM is successful at modifying the market rules in the future, our ability to manage our portfolio of demand response capacity in the PJM market would be harmed, which will significantly reduce our future revenues and profit margins and which may have a material adverse effect on our results of operations and financial condition. Furthermore, the attention of our management and other personnel has been, and may continue to be, diverted as we defend our position with respect to the PJM statement, which has had, and may continue to have, a negative impact on our sales efforts in, and revenues and gross profits derived from, the PJM region as well as our other operating regions.

     In addition, revenues generated from two fixed price contracts with, and open market sales to ISO-NE, an electric power grid operator customer, accounted for 18%, 29% and 36%, respectively, of our total revenues for the years ended December 31, 2010, 2009 and 2008. During the six months ended June 30, 2011, revenues generated from open market sales to ISO-NE accounted for 22% of our total revenues. The modification or termination of our sales relationship with ISO-NE, or the modification or termination of any of ISO-NE’s open market programs in which we participate, could significantly reduce our future revenues and profit margins and have a material adverse effect on our results of operations and financial condition.

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

     Unfavorable regulatory decisions in markets where we currently operate could also significantly and negatively affect our business. For example, in connection with the PJM statement, in the event that FERC approves the proposed tariff changes filed by PJM with FERC and modifies the PJM market rules accordingly, or to the extent PJM is otherwise successful at modifying the market rules in the future, our future revenues and profit margins will be significantly reduced and our future results of operations and financial condition will be negatively impacted. Regulators could also 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 demand response capacity reductions we aggregate from C&I customers willing to reduce consumption from the electric power 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 C&I customers willing to reduce load by curtailing consumption rather than by generating electricity themselves. Market rules could also be modified to change the design of a particular demand response program, which may adversely affect our participation in that program, or a demand response program in which we currently participate could be eliminated in its entirety. Any elimination or change in the design of a demand response program, including any supplemental program, in which we participate, especially in the PJM or ISO-NE markets, could adversely impact our ability to successfully provide our demand response application and services or manage our portfolio of demand response capacity in that program.

     In addition, a buildup of new electric generation facilities or reduced demand for electric capacity could result in excess electric generation capacity in certain regional electric 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 energy management applications and services 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 C&I customers in demand response programs. Further, some markets 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.

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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:

• an acquisition may involve unexpected costs or liabilities, may cause us to fail to meet our previously stated financial guidance, or the effects of purchase accounting may be different from our expectations;

• problems may arise with our ability to successfully integrate the acquired businesses, which may result in us not operating as effectively and efficiently as expected, and may include:

• diversion of management time, as well as a shift of focus from operating the businesses to issues related to integration and administration or inadequate management resources available for integration activity and oversight;

• failure to retain and motivate key employees;

• failure to successfully manage relationships with customers and suppliers;

• failure of customers to accept our new energy management applications and services;

• failure to effectively coordinate sales and marketing efforts;

• failure to combine service offerings quickly and effectively;

• failure to effectively enhance acquired technology, applications and services or develop new applications and services relating to the acquired businesses;

• difficulties and inefficiencies in managing and operating businesses in multiple locations or operating businesses in which we have either limited or no direct experience;

• difficulties integrating financial reporting systems;

• difficulties in the timely filing of required reports with the SEC; and

• difficulties in implementing controls, procedures and policies, including disclosure controls and procedures and internal controls over financial reporting, appropriate for a larger public company at companies that, prior to their acquisition, lacked such controls, procedures and policies, which may result in ineffective disclosure controls and procedures or material weaknesses in internal controls over financial reporting;

• we may not be able to achieve the expected synergies from an acquisition, or it may take longer than expected to achieve those synergies;

• an acquisition may result in future impairment charges related to diminished fair value of businesses acquired as compared to the price we paid for them;

• an acquisition may involve restructuring operations or reductions in workforce, which may result in substantial charges to our operations; and

• future acquisitions could result in potentially dilutive issuances of equity securities, the incurrence of debt, or contingent liabilities, which could harm our financial condition.

     In January 2011, we acquired Global Energy, M2M and DMT, and in July 2011 we acquired Energy Response. There can be no assurance that we will be able to successfully integrate these companies or any other companies, products or technologies that we acquire.

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

     Our future success depends on commercial acceptance of our clean and intelligent energy management applications and services and our ability to enter into additional utility contracts and new open market bidding programs. We anticipate that revenues related to our demand response application and services will constitute a substantial majority of our revenues for the foreseeable future. The market for clean and intelligent energy management applications and services in general is relatively new. If we are unable to educate our potential customers about the advantages of our energy management applications and services over competing products and services, or our existing customers no longer rely on our energy management applications and services, our ability to sell our energy management applications and services will be limited. In addition, because the clean and intelligent energy management applications and services 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 management applications and services that address those needs. Further, we are subject to the risk that the current global economic and market conditions will result in lower overall demand for electricity in the United States and other markets that we are seeking to penetrate over the next few years. Such a reduction in the demand for electricity could create a corresponding reduction in both supply- and demand-side resources being implemented by electric power grid operators and utilities. If the market for our energy management applications and services does not continue to develop, our ability to grow our business could be limited and we may not be able to operate profitably.

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An increased rate of terminations by our C&I customers, or their failure to renew contracts when they expire, would negatively impact our business by reducing our revenues and requiring us to spend more money to maintain and grow our C&I customer base.

     Our ability to provide demand response capacity under our utility contracts and in open market bidding programs depends on the amount of MW that we manage across C&I customers who enter into contracts with us to reduce electricity consumption on demand. If our existing C&I customers do not renew their contracts as they expire, we will need to acquire MW from additional C&I customers or expand our relationships with existing C&I customers in order to maintain our revenues and grow our business. The loss of revenues resulting from C&I customer contract terminations could be significant, and limiting C&I customer terminations is an important factor in our ability to return to profitability in future periods. If we are unsuccessful in limiting our C&I customer terminations, we may be unable to acquire a sufficient amount of MW or we may incur significant costs to replace MW in our portfolio, which could cause our revenues to decrease and our cost of revenues to increase.

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

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

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

     We allocate our operations, sales and marketing, research and development, general and administrative, and financial resources based on our business plan, which includes assumptions about current and future utility contracts and open market programs with grid operator and utility customers, current and future contracts with C&I customers, variable prices in open market programs 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 energy management applications and services. However, these factors are uncertain. If our assumptions regarding these factors prove to be incorrect or if alternatives to those offered by our energy management applications and services gain further acceptance, then actual demand for our energy management applications and services could be significantly less than the demand we anticipate and we may not be able to sustain our revenue growth or return to profitability in future periods.

The 2011 credit facility contains financial and operating restrictions that may limit our access to credit. If we fail to comply with covenants in the 2011 credit facility, we may be required to repay our indebtedness thereunder, which may have an adverse effect on our liquidity.

     Provisions in the 2011 credit facility impose restrictions on our ability to, among other things:

• incur additional indebtedness;

• create liens;

• enter into transactions with affiliates;

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• transfer assets;

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

• merge or consolidate.

     In addition, we are required to meet certain financial covenants customary with this type of credit facility, including maintaining a minimum specified tangible net worth and a minimum specified ratio of current assets to current liabilities. The 2011 credit facility 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 the 2011 credit facility. In addition to preventing additional borrowings under the 2011 credit facility, an event of default, if not cured or waived, may result in the acceleration of the maturity of indebtedness outstanding under the 2011 credit facility, which would require us to pay all amounts outstanding. In addition, in the event that we default under the 2011 credit facility while we have letters of credit outstanding, we will be required to post up to 105% of the value of the letters of credit in cash with SVB to collateralize those letters of credit. As of June 30, 2011, we were contingently liable for $43.5 million in connection with outstanding letters of credit under the 2011 credit facility. 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.

We expect our quarterly revenues and operating results to fluctuate. If we fail in future periods to meet our publicly announced financial guidance or 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. We provide public guidance on our expected results of operations for future periods. This guidance is comprised of forward-looking statements subject to risks and uncertainties, including the risks and uncertainties described in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the fiscal year ended December 31, 2010 and in our other public filings and public statements, and is based necessarily on assumptions we make at the time we provide such guidance. Our revenues and operating results may fail to meet our previously stated financial guidance or the expectations of securities analysts or investors in some quarter or quarters. Our failure to meet such expectations or our financial guidance 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 management applications and services;

• the seasonality of our demand response business in certain of the markets in which we operate, where revenues recognized under certain utility contracts and pursuant to certain open market bidding programs can be higher or concentrated in particular seasons and months;

• changes in open market bidding program rules and reductions in pricing for demand response capacity;

• delays in the implementation and delivery of our clean and intelligent energy management applications and services, which may impact the timing of our recognition of revenues;

• delays or reductions in spending for clean and intelligent energy management applications and services by our electric power grid operator or utility customers and potential customers;

• the long lead time associated with securing new customer contracts;

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

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

• the termination or expiration of existing contracts with electric power grid operator and utility customers and C&I customers;

• the potential interruptions of our customers’ operations;

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

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

• the imposition of penalties or the reversal of deferred revenue due to our failure to meet a capacity commitment;

• flaws in the design or the elimination or modification of any demand response program in which we participate;

• global economic and credit market conditions; and

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

Our stock price has been and is likely to continue to be volatile and the market price of our common stock may fluctuate substantially.

     Prior to our IPO, there was not a public market for our common stock. There is a limited history on which to gauge the volatility of our stock price; however, since our common stock began trading on The NASDAQ Global Market, or NASDAQ, on May 18, 2007 through December 31, 2010, our stock price has fluctuated from a low of $4.80 to a high of $50.50. Furthermore, the stock market has recently experienced significant volatility. The volatility of stocks for companies in the energy and technology industry often does not relate to the operating performance of the companies represented by the stock. Some of the factors that may cause the market price of our common stock to fluctuate include:

• demand for and acceptance of our clean and intelligent energy management applications and services;

• our ability to develop new relationships and maintain and enhance existing relationships with customers and strategic partners;

• changes in open market bidding program rules and reductions in pricing for demand response capacity;

• the termination or expiration of existing contracts with electric power grid operator and utility customers and C&I customers;

• general market conditions and overall fluctuations in equity markets in the United States;

• flaws in the design or the elimination or modification of any demand response program in which we participate;

• introduction of technological innovations or new energy management applications or services by us or our competitors;

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• actual or anticipated variations in quarterly revenues and operating results;

• the financial guidance we may provide to the public, any changes in such guidance or our failure to meet such guidance;

• changes in estimates or recommendations by securities analysts that cover our common stock;

• delays in the implementation and delivery of our clean and intelligent energy management applications and services, which may impact the timing of our recognition of revenues;

• litigation or regulatory enforcement actions;

• changes in the regulations affecting our industry in the United States and internationally;

• the way in which we recognize revenues and the timing associated with our recognition of revenues;

• developments or disputes concerning patents or other proprietary rights;

• period-to-period fluctuations in our financial results;

• the potential interruptions of our customers’ operations;

• the seasonality of our demand response business in certain of the markets in which we operate;

• failure to secure adequate capital to fund our operations, or the future sale or issuance of equity securities at prices below fair market price or in general; and

• economic and other external factors or other disasters or crises.

     These and other external factors may cause the market price and demand for our common stock to fluctuate substantially, which may limit or prevent investors from readily selling their shares of common stock and may otherwise negatively affect the liquidity of our common stock. In addition, in the past, when the market price of a stock has been volatile, holders of that stock have instituted securities class action litigation against the company that issued the stock. Our stock price has been particularly volatile recently, we believe due in large part to the PJM statement. Although as of the date of filing of this Annual Report on Form 10-K we have not received notice of any lawsuit brought against us by any of our stockholders, we are aware that several plantiffs’ law firms have announced that they are investigating securities claims against us. While we would vigorously defend any such lawsuit, we could incur substantial costs defending any such lawsuit. Such a lawsuit could also divert the time and attention of our management.

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Item 6. Exhibits.

10.1	Credit Agreement among EnerNOC, Inc., ENOC Securities Corporation, Silicon Valley Bank and T.D. Bank, N.A., dated as of April 15, 2011, as amended by the First Amendment to Credit Agreement, dated as of June 30, 2011.
10.2	Guarantee and Collateral Agreement made by EnerNOC, Inc. and ENOC Securities Corporation in favor of Silicon Valley Bank, dated as of April 15, 2011.
31.1	Certification of Chief Executive Officer of EnerNOC, Inc. pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2	Certification of Chief Financial Officer of EnerNOC, Inc. pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1	Certification of the Chief Executive Officer and Chief Financial Officer of EnerNOC, Inc. pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101@	The following materials from EnerNOC, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, formatted in XBRL (Extensible Business Reporting Language): (i) the Unaudited Condensed Consolidated Balance Sheets, (ii) the Unaudited Condensed Consolidated Statements of Operations, (iii) the Unaudited Condensed Consolidated Statements of Cash Flows, and (iv) Notes to Unaudited Condensed Consolidated Financial Statements.

^@ Users of the XBRL data are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

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SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	EnerNOC, Inc.
Date: August 9, 2011	By:	/s/ Timothy G. Healy
		Timothy G. Healy
		Chief Executive Officer (principal executive officer)
Date: August 9, 2011	By:	/s/ Timothy Weller
		Timothy Weller
		Chief Financial Officer and Treasurer (principal financial officer)

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Exhibit Index

Number	Exhibit Title
10.1	Credit Agreement among EnerNOC, Inc., ENOC Securities Corporation, Silicon Valley Bank and T.D. Bank, N.A., dated as of April 15, 2011, as amended by the First Amendment to Credit Agreement, dated as of June 30, 2011.
10.2	Guarantee and Collateral Agreement made by EnerNOC, Inc. and ENOC Securities Corporation in favor of Silicon Valley Bank, dated as of April 15, 2011.
31.1	Certification of Chief Executive Officer of EnerNOC, Inc. pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2	Certification of Chief Financial Officer of EnerNOC, Inc. pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1	Certification of the Chief Executive Officer and Chief Financial Officer of EnerNOC, Inc. pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101@	The following materials from EnerNOC, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, formatted in XBRL (Extensible Business Reporting Language): (i) the Unaudited Condensed Consolidated Balance Sheets, (ii) the Unaudited Condensed Consolidated Statements of Operations, (iii) the Unaudited Condensed Consolidated Statements of Cash Flows, and (iv) Notes to Unaudited Condensed Consolidated Financial Statements.

^@ Users of the XBRL data are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

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