ENERNOC INC - FORM 10-Q

Attached files

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EX-2.1 - EX-2.1 - ENERNOC INC	b83961exv2w1.htm
EX-10.1 - EX-10.1 - ENERNOC INC	b83961exv10w1.htm
EX-32.1 - EX-32.1 - ENERNOC INC	b83961exv32w1.htm
EX-31.1 - EX-31.1 - ENERNOC INC	b83961exv31w1.htm
EX-31.2 - EX-31.2 - ENERNOC INC	b83961exv31w2.htm
EXCEL - IDEA: XBRL DOCUMENT - ENERNOC INC	Financial_Report.xls

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 March 31, 2011


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. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§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). Yes þ No o

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

Large accelerated filer þ

Accelerated filer o

Non-accelerated filer o
(Do not check if a smaller reporting company)

Smaller reporting company o

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

There were 26,393,957 shares of the registrant’s common stock, $0.001 par value per share, outstanding as of May 1, 2011.

EnerNOC, Inc.

Index to Form 10-Q


		Page

Part I — Financial Information

Item 1.	Financial Statements

	Unaudited Condensed Consolidated Balance Sheets at March 31, 2011 and December 31, 2010		3

	Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2011 and 2010		4

	Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 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		26

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		44

Item 4.	Controls and Procedures		44

Part II — Other Information

Item 1.	Legal Proceedings		44

Item 1A	Risk Factors		44

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		45

Item 6.	Exhibits		46

	Signatures		47
	Exhibit Index		48
EX-2.1
EX-10.1
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

EnerNOC, Inc.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except par value and share data)


	March 31, 2011			December 31, 2010
ASSETS
Current assets
Cash and cash equivalents	$	102,642		$	153,416
Restricted cash		277			1,537
Trade accounts receivable, net of allowance for doubtful accounts of $150 at March 31, 2011 and December 31, 2010		27,502			22,137
Unbilled revenue		30,122			73,144
Inventory		357			—
Prepaid expenses, deposits and other current assets		11,004			6,707

Total current assets		171,904			256,941
Property and equipment, net of accumulated depreciation of $39,808 and $36,309 at March 31, 2011 and December 31, 2010, respectively		34,896			34,690
Goodwill		64,885			24,653
Definite-lived intangible assets, net		24,897			5,823
Indefinite-lived intangible assets		920			920
Deposits and other assets		3,592			2,872

Total assets	$	301,094		$	325,899

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	410		$	111
Accrued capacity payments		40,925			65,792
Accrued payroll and related expenses		7,424			11,135
Accrued expenses and other current liabilities		7,876			9,307
Accrued acquisition contingent consideration		—			1,500
Deferred revenue		9,196			5,540
Current portion of long-term debt		27			37

Total current liabilities		65,858			93,422
Long-term liabilities
Deferred acquisition consideration		3,998			—
Deferred tax liability		1,476			1,141
Deferred revenue, long-term		2,314			4,696
Other liabilities		500			514

Total long-term liabilities		8,288			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, 26,397,332 and 25,155,067 shares issued and outstanding at March 31, 2011 and December 31, 2010, respectively		26			25
Additional paid-in capital		314,034			293,942
Accumulated other comprehensive loss		(74	)		(75	)
Accumulated deficit		(87,038	)		(67,766	)

Total stockholders’ equity		226,948			226,126

Total liabilities and stockholders’ equity	$	301,094		$	325,899

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

EnerNOC, Inc.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share and per share data)


	Three Months Ended March 31,
	2011			2010
Revenues	$	31,762		$	28,121
Cost of revenues		19,201			18,546

Gross profit		12,561			9,575
Operating expenses:
Selling and marketing		11,587			9,114
General and administrative		16,313			13,749
Research and development		3,232			2,057

Total operating expenses		31,132			24,920

Loss from operations		(18,571	)		(15,345	)
Other income		128			3
Interest expense		(163	)		(25	)

Loss before income tax		(18,606	)		(15,367	)
(Provision for) benefit from income tax		(666	)		1,167

Net loss	$	(19,272	)	$	(14,200	)


Loss per common share
Basic	$	(0.76	)	$	(0.59	)
Diluted	$	(0.76	)	$	(0.59	)

Weighted average number of common shares outstanding
Basic		25,248,650			24,051,114
Diluted		25,248,650			24,051,114

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

EnerNOC, Inc.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Three Months Ended March 31,
	2011			2010
Cash flows from operating activities
Net loss	$	(19,272	)	$	(14,200	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depreciation		3,625			3,231
Amortization of acquired intangible assets		1,152			388
Stock-based compensation expense		3,482			4,346
Impairment of property and equipment		110			—
Unrealized foreign exchange transaction loss (gain)		132			(13	)
Deferred taxes		335			(441	)
Non-cash interest expense		9			15
Other, net		79			(21	)
Changes in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable, trade		(2,920	)		1,253
Unbilled revenue		43,021			24,014
Prepaid expenses and other current assets		(3,524	)		(624	)
Inventory		80			—
Other assets		22			12
Other noncurrent liabilities		(13	)		(16	)
Deferred revenue		1,134			614
Accrued capacity payments		(24,897	)		(13,008	)
Accrued payroll and related expenses		(3,278	)		(2,324	)
Accounts payable and accrued expenses		(4,965	)		(104	)

Net cash (used in) provided by operating activities		(5,688	)		3,122

Cash flows from investing activities
Payments made for acquisitions, net of cash acquired		(41,047	)		—
Payments made for contingent consideration related to acquisitions		(1,500	)		(1,100	)
Purchases of property and equipment		(3,464	)		(5,596	)
Change in restricted cash and deposits		(5	)		(282	)

Net cash used in investing activities		(46,016	)		(6,978	)

Cash flows from financing activities
Proceeds from exercises of stock options		1,040			1,515
Repayment of borrowings and payments under capital leases		(10	)		(9	)

Net cash provided by financing activities		1,030			1,506
Effects of exchange rate changes on cash		(100	)		(5	)

Net change in cash and cash equivalents		(50,774	)		(2,355	)
Cash and cash equivalents at beginning of period		153,416			119,739

Cash and cash equivalents at end of period	$	102,642		$	117,384


Non-cash financing and investing activities
Issuance of common stock in connection with acquisitions	$	15,132		$	260

Issuance of common stock in satisfaction of bonuses	$	440		$	775

Increase in deferred acquisition consideration	$	3,925		$	—

Increase in accrued contingent consideration related to acquisitions	$	—		$	1,667

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

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 totaling $737 previously included in selling and marketing expenses in its unaudited condensed consolidated statements of operations for the three months ended March 31, 2010 as general and administrative expenses for the three months ended March 31, 2010 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.

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.

In April 2011, the Company and one of its subsidiaries entered into a $75,000 senior secured revolving credit facility pursuant to a credit agreement (2011 credit facility), with several banks and other financial institutions or entities from time to time party to the credit agreement and Silicon Valley Bank (SVB), as administrative agent, issuing lender and swingline lender (SVB and together with the other lenders, the Lenders). The 2011 credit facility replaces the credit facility with SVB, dated as of August 5, 2008, as amended (2008 credit facility), which existed as of March 31, 2011. Refer to Note 7 for further discussion.

In April 2011, the Company and one of its U.S. subsidiaries entered into a guarantee and collateral agreement with SVB for the benefit of the Lenders. Refer to Note 7 for further discussion.

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. Based on the Company’s prior experience with this certain open market bidding program, the Company currently expects that it will recover a portion of this cash and these letters of credit during the second quarter of 2011.

There were no other material recognizable subsequent events recorded or requiring disclosure in the March 31, 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 March 31, 2011 and statements of operations and statements of cash flows for the three months ended March 31, 2011 and 2010. Operating results for the three months ended March 31, 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, 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 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 from larger companies, customer concentration, government regulations, market or program rule changes, protection of proprietary rights and dependence on key individuals.

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 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 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.

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 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 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.

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 utility contracts, 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 utility 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.

•

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, the Company adopted this new accounting guidance at the beginning of its first quarter of 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 in the first quarter of fiscal 2011, and if they were applied in the same manner to fiscal 2010 would not have had a material impact to revenue for the first quarter of fiscal 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 (i.e. vendors). 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 future impact of this change 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

Comprehensive loss 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 is composed of net loss and foreign currency translation adjustments. As of March 31, 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, net of related tax effects, which have not been material to date.

Comprehensive loss for the three months ended March 31, 2011 and 2010 was as follows:


	Three months ended March 31,
	2011			2010
Net loss	$	(19,272	)	$	(14,200	)
Foreign currency translation adjustments		1			(48	)

Total comprehensive loss	$	(19,271	)	$	(14,248	)

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

Software development costs of $837 and $1,244 for the three months ended March 31, 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 March 31, 2011 and December 31, 2010. The Company capitalized $13 and $578 during the three months ended March 31, 2011 and 2010, respectively, related to a company-wide enterprise resource planning systems implementation project. Amortization of capitalized internal use software costs was $842 and $698 for the three months ended March 31, 2011 and 2010, respectively. Accumulated amortization of capitalized internal use software costs was $7,976 and $7,134 as of March 31, 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 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 March 31, 2011, approximately $1,949 of the Company’s generation equipment is utilized in open market demand response 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.

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 March 31, 2011, the Company had $357 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 following major geographic areas as noted in the below chart. The “All other” designation includes other international operations. Revenues are based upon customer location, and internationally totaled $4,858 and $13 for the three months ended March 31, 2011 and 2010, respectively.

Revenues by geography as a percentage of total revenues are as follows:


	Three Months Ended March 31,
	2011			2010
United States		85	%		100	%
Canada		15			—
All other		*			*

Total		100	%		100	%


*		Represents less than 1% of total revenues.

As of March 31, 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.

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 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.

The allocation of the purchase price is based upon preliminary estimates of the fair value of assets acquired and liabilities assumed as of January 3, 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 initial allocation of the purchase price consists of the following approximate amounts:

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


Net tangible assets acquired as of January 3, 2011	$	588
Customer relationships		6,430
Non-compete agreements		420
Developed technology		50
Trade name		260
Goodwill		18,910

Total	$	26,658

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


Cash	$	273
Accounts receivable		999
Prepaids and other assets		35
Property and equipment		183
Accounts payable		(196	)
Accrued expenses and other liabilities		(706	)

Total	$	588

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 350-30-35 General 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. 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 an Arrangement and Plan of Merger, 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 energy management and 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 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 March 31, 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 months ended March 31, 2011, the Company recorded a charge of $73, of which $35 was recorded to cost of revenues and $38 was recorded to general and administrative expenses. At March 31, 2011, the liability is recorded at $3,998. This acquisition had no contingent consideration or earn-out payments.

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 initial allocation of the purchase price consist of the following approximate amounts:


Net tangible assets acquired as of January 25, 2011	$	1,148
Customer relationships		4,800
Non-compete agreements		280
Developed technology		3,000
Trade name		400
Goodwill		20,243

Total	$	29,871

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 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 that 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 and other energy management 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 March 31, 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.

The components and initial 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.

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.

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 March 31, 2011 and December 31, 2010:


			As of March 31, 2011					As of December 31, 2010
	Weighted Average		Gross					Gross
	Amortization		Carrying		Accumulated			Carrying		Accumulated
	Period (in years)		Amount		Amortization			Amount		Amortization
Customer contracts		6.02	$	4,217	$	(1,696	)	$	4,217	$	(1,593	)
Employment agreements and non-compete agreements		2.90		1,492		(390	)		772		(309	)
Software		1.23		120		(73	)		120		(63	)
Developed technology		3.79		3,050		(131	)		—		—
Customer relationships		5.05		19,256		(1,803	)		3,510		(1,016	)
Trade name		3.13		825		(150	)		115		(115	)
Patents		8.94		200		(20	)		200		(15	)

Total			$	29,160	$	(4,263	)	$	8,934	$	(3,111	)

The increase in intangibles assets from December 31, 2010 to March 31, 2011 was due to the allocation of purchase price related to the acquisitions in the three months ended March 31, 2011. Amortization expense related to intangible assets amounted to $1,152 and $388 for three months ended March 31, 2011 and 2010, respectively. Amortization expense for developed technology, which was $131 for the three months ended March 31, 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 4.9 years at March 31, 2011. Estimated amortization is $5,252, $5,427, $5,365, $4,842, $2,662 and $2,501 for 2011, 2012, 2013, 2014, 2015 and thereafter, respectively.

Indefinite-Lived Intangible Assets

In connection with the Company’s acquisition of Smallfoot and Zox, the Company acquired certain in-process research and development projects that had a fair value of $920 at March 31, 2011 and December 31, 2010. These projects are still in-process and no interim impairment indicators have been identified as of March 31, 2011. The estimated cost to complete the in-process research and development projects in the aggregate as of March 31, 2011 was approximately $595.

Goodwill

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


Balance at December 31, 2010	$	24,653
Acquisitions		40,195
Foreign currency translation impact		37

Balance at March 31, 2011	$	64,885

4. Net Loss Per Share

A reconciliation of basic and diluted share amounts for the three months ended March 31, 2011 and 2010 are as follows (in thousands):


	Three Months Ended March 31,
	2011		2010
Basic weighted average common shares outstanding		25,249		24,051
Weighted average common stock equivalents	—		—

Diluted weighted average common shares outstanding		25,249		24,051


Weighted average anti-dilutive shares related to:
Stock options		2,018		3,113
Nonvested restricted shares		412		178
Restricted stock units		324		236
Escrow shares		280		150

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 March 31, 2011, the Company had no borrowings and letters of credit totalling $36,775 outstanding under the 2008 credit facility. At December 31, 2010, the Company had no borrowings and letters of credit totalling $36,561 outstanding under the 2008 credit facility. For additional information regarding the 2008 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.

The table below presents the balances of assets and liabilities measured at fair value on a recurring basis at March 31, 2011:


	Fair Value Measurement at March 31, 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)	$	83,570	$	83,570	$	—	$	—
Deferred acquisition consideration (2)	$	3,998		—		—	$	3,998


(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 months ended March 31, 2011 of $73 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 March 31, 2011, the Company had restricted cash of approximately $277 of cash 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.

The carrying amounts of cash and cash equivalents, restricted cash, trade accounts receivable, accounts payable and accrued expenses included in the consolidated balance sheets approximate fair value given the short-term nature of these financial instruments.

7. Financing Arrangements

Pursuant to the terms of the 2008 credit facility, SVB will, among other things, make revolving credit and term loan advances and issue letters of credit for the Company’s account. The interest on loans under the 2008 credit facility accrues at interest rates based upon either SVB’s prime rate or the 30, 60 or 90-day LIBOR plus 2.25%, at the Company’s election. The interest on term loans accrues at SVB’s prime rate plus 0.50% or the 30, 60 or 90-day LIBOR plus 2.75%, at the Company’s election. The term advance is payable in thirty-six consecutive equal monthly installments of principal, calculated by SVB, based upon the amount of the term advance and an amortization schedule equal to thirty-six months. All unpaid principal and accrued interest was due and payable in full on March 31, 2011, which was the maturity date. 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 1.25%. The Company expenses the interest and letter of credit fees, as applicable, in the period incurred. As of March 31, 2011, the Company was not in compliance with the minimum specified tangible net worth covenant of the 2008 credit facility and obtained a waiver of this covenant default from SVB.

The Company was in compliance with all financial covenants under the 2008 credit facility at December 31, 2010. The 2011 credit facility does not contain a minimum specified tangible net worth financial covenant and the Company is currently in compliance with the covenants under 2011 credit facility. At March 31, 2011, the Company had no borrowings and letters of credit totaling $36,775 outstanding under the 2008 credit facility.

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 credit agreement 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 the Wall 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 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 agreement, 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 replaces the 2008 credit facility which existed as of March 31, 2011.

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.

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 March 31, 2011 and December 31, 2010. Restricted cash to secure certain other commitments was $277 and $237 at March 31, 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 $3,940 and $3,467, respectively, at March 31, 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 March 31, 2011, the Company has deferred fees totaling approximately $1,800, which are included in deferred revenue, long-term in the accompanying consolidated balance sheets. As of March 31, 2011, the maximum termination penalty that the Company is subject to under these arrangements, which the Company has not deemed probable of incurring, is approximately $5,700.

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.

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 three months ended March 31, 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 March 31, 2011, 2,122,478 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:


	Three Months Ended March 31,
	2011			2010
Risk-free interest rate		3.4	%		3.7	%
Vesting term, in years		2.22			2.16
Expected annual volatility		80	%		86	%
Expected dividend yield		—	%		—	%
Exit rate pre-vesting		7.3	%		4.88	%
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 Credit Facility preclude the Company from paying dividends. During the three months ended March 31, 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 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 months ended March 31, 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 March 31,
	2011		2010
Stock option expense	$	1,781	$	2,305
Restricted stock and restricted stock units		1,701		2,041

Total	$	3,482	$	4,346

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


	Three Months Ended March 31,
	2011		2010
Selling and marketing expenses	$	1,043	$	1,016
General and administrative expenses		2,168		3,163
Research and development expenses		271		167

Total	$	3,482	$	4,346

The Company recognized no material income tax benefit from share-based compensation arrangements during the three months ended March 31, 2011 and 2010. In addition, no material compensation cost was capitalized during the three months ended March 31, 2011 and 2010.

The following is a summary of the Company’s stock option activity during the three months ended March 31, 2011:


	Three Months Ended March 31, 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		16,350					21.50
Exercised		(165,566	)				6.28	$	2,261	(3)
Cancelled		(111,766	)				14.22

Outstanding at March 31, 2011		1,851,377		$	0.17 - $48.06		15.17	$	13,931	(4)

Weighted average remaining contractual life in years: 5.6
Exercisable at end of period		1,230,766		$	0.17 - $48.06	$	11.34	$	12,249	(4)

Weighted average remaining contractual life in years: 5.3
Vested or expected to vest at March 31, 2011 (1)		1,812,244		$	0.17 - $48.06	$	14.94	$	13,887	(4)


(1)		This represents the number of vested options as of March 31, 2011 plus the number of unvested options expected to vest as of March 31, 2011 based on the unvested options outstanding at March 31, 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 March 31, 2011 of $19.11 and the exercise price of the underlying options.

Additional Information About Stock Options


	Three Months Ended March 31,
	2011		2010
	In thousands, except share and
	per share amounts
Total number of options granted during the period		16,350		179,775
Weighted-average fair value per share of options granted	$	13.30	$	18.35
Total intrinsic value of options exercised(1)	$	2,261	$	5,769


(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 March 31, 2011, 1,837,384 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 March 31, 2011, the Company had $8,564 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 2.3 years. There were no material unvested non-employee options as of March 31, 2011.

Restricted Stock and Restricted Stock Units

For non-vested restricted stock and restricted stock units outstanding as of March 31, 2011, the Company had $17,875 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 2.9 years.

Restricted Stock

The following table summarizes the Company’s restricted stock activity during the three months ended March 31, 2011:


				Weighted Average
	Number of			Grant Date Fair
	Shares			Value Per Share
Nonvested at December 31, 2010		254,896		$	30.03
Granted		374,781			20.07
Vested		(30,908	)		23.76
Cancelled		(7,867	)		31.19

Nonvested at March 31, 2011		590,902		$	24.02

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 1,000 shares of restricted stock granted to certain non-executive employees and 16,000 shares of restricted stock granted to our board of directors during the three months ended March 31, 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.

Additional Information About Restricted Stock


	Three Months Ended March 31,
	2011		2010
	In thousands, except share and per
	share amounts
Total number of shares of restricted stock granted during the period		374,781		45,250
Weighted average fair value per share of restricted stock granted	$	20.07	$	29.20
Total number of shares of restricted stock vested during the period		30,908		63,461
Total fair value of shares of restricted stock vested during the period	$	623	$	1,854

Restricted Stock Units

The following table summarizes the Company’s restricted stock unit activity during the three months ended March 31, 2011:


				Weighted Average
	Number of			Grant Date Fair
	Shares			Value Per Share
Nonvested at December 31, 2010		388,124		$	26.11
Granted		—			—
Vested		(64,728	)		26.99
Cancelled		(54,562	)		25.60

Nonvested at March 31, 2011		268,834		$	26.00

The total fair value of restricted stock units that vested during the three months ended March 31, 2011 was $1,178. The weighted average grant date fair value of restricted stock granted during the three months ended March 31, 2010 was $28.59 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 March 31, 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 March 31, 2011 due to unusual sensitivity to the rate as it relates to the current forecasted fiscal 2011 U.S. ordinary income. As a result, the Company recorded a tax provision for the three months ended March 31, 2011 based on its actual effective tax rate for three months ended March 31, 2011. The tax provision recorded for the three months ended March 31, 2011 was $666 and represented the following:

	•		estimated foreign taxes resulting from guaranteed profit allocable to 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;

	•		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 June 30, 2011 and if the Company is still anticipating 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 benefit from income taxes being recorded during the three months ended June 30, 2011. If the Company continues to be unable to make a reliable estimate of its annual effective tax rate as of June 30, 2011, the Company expects to follow a consistent methodology as applied for the three months ended March 31, 2011 and record a provision for income taxes for the three 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 March 31, 2011, due to the uncertainty related to the ultimate use of the Company’s deferred income tax assets, the Company has 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 ISO-New England, Inc. (ISO-NE) and Ontario Power Authority (OPA), 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 March 31,
	2011					2010
			% of Total					% of Total
	Revenues		Revenues			Revenues		Revenues
ISO-New England, Inc.		11,673		37	%		17,420		62	%
Ontario Power Authority		4,683		15	%		—		—	%

Total	$	16,356		52	%	$	17,420		62	%

Accounts receivable from ISO-NE was approximately $2,797 and $3,351 at March 31, 2011 and December 31, 2010, respectively. Accounts receivable from OPA was approximately $1,288 and $0 at March 31, 2011 and December 31, 2010, respectively.

PJM and Southern California Edison Company were the only additional customers that provided 10% or more of the accounts receivable balance at March 31, 2011 at 25% and 15% of accounts receivable balance, respectively. PJM and Southern California Edison Company were the only additional customers that provided 10% or more of the accounts receivable balance at December 31, 2010 at 36% and 15% of accounts receivable balance, respectively. Unbilled revenue related to PJM was $29,993 and $72,887 at March 31, 2011 and December 31, 2010, respectively. There was no significant unbilled revenue for any other customers at March 31, 2011 and December 31, 2010.

Deposits and restricted cash consist of funds to secure performance under certain contracts and open market bidding programs with electric power grid operator and utility customers. Deposits held by these customers were $3,940 and $3,467 at March 31, 2011 and December 31, 2010, respectively. Restricted cash to secure letters of credit was $0 and $1,300 at March 31, 2011 and December 31, 2010, respectively. Restricted cash to secure certain other commitments was $277 and $237 at March 31, 2011 and December 31, 2010, respectively.

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.


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 on Form 10-Q, as well as our audited financial statements and notes thereto and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010, as filed with the Securities and Exchange Commission, or the SEC, on March 1, 2011. This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Without limiting the foregoing, the words “may,” “will,” “should,” “could,” “expect,” “plan,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “continue,” “target” and variations of those terms or the negatives of those terms and similar expressions are intended to identify forward-looking statements. All forward-looking statements included in this Quarterly Report on Form 10-Q are based on current expectations, estimates, forecasts and projections and the beliefs and assumptions of our management including, without limitation, our expectations regarding our results of operations, operating expenses and the sufficiency of our cash for future operations. We assume no obligation to revise or update any such forward-looking statements. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of certain important factors, including those set forth below under this Item 2 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Part II, Item 1A — “Risk Factors” and elsewhere in this Quarterly Report on Form 10-Q, as well as in our Annual Report on Form 10-K for the fiscal year ended December 31, 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 March 31, 2011, we managed approximately 6,300 megawatts, or MW, of demand response capacity across a C&I customer base of approximately 3,900 accounts and 10,100 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.

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 Canada and the United Kingdom, by March 31, 2011.

Significant Recent Developments

In April 2011, we and one of our subsidiaries entered into a $75.0 million senior secured revolving credit facility pursuant to a credit agreement, which we refer to as the 2011 credit facility, with the several banks and other financial institutions or entities from time to time party to the credit agreement and Silicon Valley Bank, or SVB, as administrative agent, issuing lender and swingline lender. The 2011 credit facility replaces the credit facility with SVB, dated as of August 5, 2008, as amended , which we refer to as the 2008 credit facility, which was in place as of March 31, 2011.

In April 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.

In February 2011, we and Darren Brady, our then-current senior vice president and chief operating officer, agreed that Mr. Brady would resign as senior vice president and chief operating officer effective February 11, 2011.

In January 2011, we acquired M2M Communications Corporation, or M2M, pursuant to an agreement and plan of merger, which we refer to as the M2M merger agreement. M2M is a leading provider of wireless technology solutions for energy management and demand response. The total merger consideration paid by us at closing was $30.0 million, plus an additional $3.3 million paid as a result of M2M having a positive capitalization amount at closing, of which $15.0 million was paid in shares of our common stock and the balance of which was paid in cash. An aggregate of $7.0 million of the merger consideration, consisting of cash and shares of our common stock, was retained by us and will be paid to the stockholders of M2M upon the satisfaction of certain conditions contained in the M2M merger agreement.

In January 2011, we also acquired all of the outstanding capital stock of Global Energy Partners, Inc., or Global Energy, a provider of energy efficiency and demand response programmatic solutions and innovative technology applications. The total purchase price paid by us at closing was $26.5 million, of which $6.6 million was paid in shares of our common stock and the balance of which was paid in cash.

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 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 March 31, 2011 and December 31, 2010, the incremental direct costs deferred were approximately $0.9 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 months ended March 31, 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 March 31, 2011 and 2010, we capitalized $1.9 million and $1.9 million, respectively, of production and generation equipment costs. We believe that this accounting treatment appropriately matches expenses with the associated revenue.

As of March 31, 2011, we had approximately 6,300 MW under management in our demand response network, meaning that we had entered into definitive contracts with our C&I customers representing approximately 6,300 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. 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-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 $30.0 million as of March 31, 2011 will be billed and collected through May 31, 2011. Due to the lower pricing that will take effect in the PJM market in 2011 and 2012, as well as the discontinuance of 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. Had the lower pricing that will take effect in the PJM market beginning in 2011 been in effect during the year ended December 31, 2010, our revenues for that period would have been lower by approximately $50.0 million to $55.0 million.

In February 2011, PJM and Monitoring Analytics, LLC, the PJM market monitor, issued a joint statement concerning settlements in PJM’s demand response programs for participants using a certain baseline method of measurement and verification for 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 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. In the event that PJM is successful in 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 by amounts, currently estimated by us to be in the range of $15.0 million to $32.0 million; however, the ultimate financial impact could deviate from this range and will depend on numerous factors, including the details of any PJM tarriff amendments or business rule changes and the associated timing and market impact of any such modifications, many of which are beyond our control.

Revenues generated from open market sales to ISO-NE accounted for 37% and 62%, respectively, of our total revenues for the three months ended March 31, 2011 and 2010. Revenues generated from open market sales to OPA accounted for 15% and 0%, respectively, of our total revenues for the three months ended March 31, 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 $5.9 million and $3.5 million, respectively, for the three months ended March 31, 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.

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 427 full-time employees at March 31, 2010 to 570 full-time employees at March 31, 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. Although we expect our overall operating expenses to increase in absolute dollar terms for the foreseeable future as we grow our MW under management and expand the development of our energy management applications and services, we expect our overall annual operating expenses to decrease as a percentage of total annual revenues as we leverage our existing employee base and continue generating revenues from our energy management applications and services. However, amortization expense from intangible assets acquired in future acquisitions could potentially 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 remain relatively flat in absolute dollar terms for the foreseeable future and to decrease as a percentage of total annual revenues as we leverage our current sales and marketing personnel.

General and Administrative

General and administrative expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards 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 as we invest in infrastructure to support our continued growth. We expect general and administrative expenses to decrease as a percentage of total annual revenues as we leverage our current infrastructure and employee base.

Research and Development

Research and development expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards, related to our 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 months ended March 31, 2011 and 2010, we capitalized software development costs of $0.8 million and $1.2 million, respectively, and the amount is included as software in property and equipment at March 31, 2011. We capitalized $13,000 and $0.6 million during the three months ended March 31, 2011 and 2010, respectively, related to a company-wide enterprise resource planning systems implementation project. We expect research and development expenses to increase in absolute dollar terms for the foreseeable future as we develop new technologies and to decrease as a percentage of total revenues in the long term as we leverage our existing technology.

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 March 31, 2011 and 2010, we recorded expenses of approximately $3.5 million and $4.3 million, respectively, in connection with share-based payment awards to employees and non-employees. With respect to option grants through March 31, 2011, a future expense of non-vested options of approximately $8.6 million is expected to be recognized over a weighted average period of 2.3 years. With respect to restricted stock and restricted stock units issued through March 31, 2011, a future expense of unvested restricted stock and restricted stock unit awards of approximately $17.9 million is expected to be recognized over a weighted average period of 2.9 years.

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. We do not currently hold any auction rate securities.

Interest Expense

Interest expense consists of interest on our capital lease obligations, fees associated with the 2008 credit facility and fees associated with issuing letters of credit and other financial assurances.

Consolidated Results of Operations

Three Months Ended March 31, 2011 Compared to the Three Months Ended March 31, 2010

Revenues

The following table summarizes our revenues for the three months ended March 31, 2011 and 2010 (dollars in thousands):


	Three Months Ended March 31,				Dollar		Percentage
	2011		2010		Change		Change
Revenues:
Demand response	$	25,816	$	24,666	$	1,150		4.7	%
EfficiencySMART, SupplySMART and CarbonSMART		5,946		3,455		2,491		72.1	%

Total	$	31,762	$	28,121	$	3,641		12.9	%

For the three months ended March 31, 2011, our demand response revenues increased by $1.2 million, or 5%, as compared to the three months ended March 31, 2010. The increase in our demand response revenues was primarily attributable to changes in the following existing operating areas (dollars in thousands):


	Revenue Increase
	(Decrease):
	March 31, 2010 to
	March 31, 2011
PJM	$	422
ERCOT		1,603
New England		(5,747	)
Ontario Power Authority		4,683
Other (1)		189

Total increased demand response revenues	$	1,150


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

The increase in demand response revenues during the three months ended March 31, 2011 as compared to the same period in 2010 was primarily due to 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 the OPA contract entered into during the three months ended March 31, 2011, which amended certain refund provisions, 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 the three months ended March 31, 2011, we had not recognized any revenues related to the OPA contract. In addition, the increase in demand response revenues was also attributable to 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 contributed to the increase in our demand response revenues.

The increase in our demand response revenues was offset by the commencement of a new ISO-NE program, which started on June 1, 2010, under which we enrolled fewer MW with lower pricing compared to a prior, similar ISO-NE program in which we participated. In addition, lower market pricing in the New York demand response program in which we participate resulted in a decrease in demand response revenues for the three months ended March 31, 2011.

For the three months ended March 31, 2011, our EfficiencySMART, SupplySMART and CarbonSMART applications and services revenues increased by $2.5 million as compared to the same period in 2010 primarily due to our acquisition of Global Energy, which occurred in January 2011.

We currently expect our revenues to increase slightly for the year ending December 31, 2011 as compared to the same period in 2010 as we further increase our MW under management in all operating regions, enroll new C&I customers in our demand response programs, expand the sales of our EfficiencySMART, SupplySMART and CarbonSMART applications and services to our new and existing C&I customers and pursue more favorable pricing opportunities with our C&I customers. 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. For example, had the lower pricing that will take effect in the PJM market beginning in 2011 been in effect during the year ended December 31, 2010, our revenues for that period would have been lower by approximately $50.0 million to $55.0 million.

In addition, the discontinuance of the Interruptible Load for Reliability program, or 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 could 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. In the event that PJM is successful in 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 by amounts currently estimated by us, based on our understanding of the proposals in the PJM statement and our estimates of how such proposals would apply, to be in the range of $15.0 million to $32.0 million; however, the ultimate financial impact could deviate from this range and will depend on numerous factors, including the details of any PJM tarriff amendments or business rule changes and the associated timing and market impact of any such modifications, many of which are beyond our control.

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 months ended March 31, 2011 and 2010 (dollars in thousands):


Three Months Ended March 31,
	2011				2010
Gross Profit		Gross Margin			Gross Profit		Gross Margin
$	12,561		39.5	%	$	9,575		34.0	%

Our gross profit increased during the three months ended March 31, 2011 as compared to the same period in 2010 primarily due to the increase in our revenues driven by the recognition of revenues in connection with the OPA contract pursuant to which we recognized the cost of such revenues in previous periods. Additionally, we had strong demand response event performance, particularly in the ISO-NE region, resulting in higher energy payments for the three months ended March 31, 2011 as compared to the same period in 2010, which was partially offset by a decrease in ISO-NE capacity revenue.

Our gross margin increased during the three months ended March 31, 2011 as compared to the same period in 2010 primarily due to 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. This increase was partially offset by increasing indirect costs of revenues, including cost of services for which we recorded no associated revenues during the three months ended March 31, 2011.

We currently expect that our gross margin for the year ending December 31, 2011 will be similar to our gross margin for the year ended December 31, 2010, 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 could 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 in modifying the market rules in the future, 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 months ended March 31, 2011 and 2010 (dollars in thousands):


	Three Months Ended March 31,				Percentage
	2011		2010		Change
Operating Expenses:
Selling and marketing	$	11,587	$	9,114		27.1	%
General and administrative		16,313		13,749		18.6	%
Research and development		3,232		2,057		57.1	%

Total	$	31,132	$	24,920		24.9	%

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 March 31,				Percentage
	2011		2010		Change

Payroll and related costs	$	7,649	$	5,803		31.8	%
Stock-based compensation		1,043		1,016		2.7	%
Other		2,895		2,295		26.1	%

Total	$	11,587	$	9,114		27.1	%

The increase in selling and marketing expenses for the three months ended March 31, 2011 compared to the same period in 2010 was primarily driven by the payroll and related costs associated with an increase in the number of selling and marketing full-time employees from 160 at March 31, 2010 to 214 at March 31, 2011. The increase in payroll and related costs for the three months ended March 31, 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 $0.5 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 stock-based compensation for the three months ended March 31, 2011 compared to the same period 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 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 March 31, 2011 as compared to the same period in 2010 was attributable to increases in professional services and marketing costs of $0.1 million due to employee attendance at conferences and seminars and costs associated with third-party marketing personnel. Additionally, we allocated company-wide costs to selling and marketing expenses based on headcount, which resulted in an increase in facility costs of $0.5 million due to the expansion of our office space.

General and Administrative Expenses


	Three Months Ended March 31,				Percentage
	2011		2010		Change

Payroll and related costs	$	9,517	$	6,996		36.0	%
Stock-based compensation		2,168		3,163		(31.5	)%
Other		4,628		3,590		28.9	%

Total	$	16,313	$	13,749		18.6	%

The increase in general and administrative expenses for the three months ended March 31, 2011 compared to the same period in 2010 was primarily driven by payroll and related costs due to an increase in executive compensation and severance. The increase in payroll and related costs for the three months ended March 31, 2011 compared to the same period in 2010 was also attributable to an increase in full-time employees from 216 at March 31, 2010 to 283 at March 31, 2011. The decrease in stock-based compensation for the three months ended March 31, 2011 compared to the same period in 2010 was primarily due to a fully-vested stock award granted to a certain executive in the three months ended March 31, 2010 compared with no such award granted in the three months ended March 31, 2011, as well as fully-vested stock awards granted to our board of directors with a lesser grant-date fair value in the three months ended March 31, 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 March 31, 2011 compared to the same period in 2010 was attributable to miscellaneous expenses, including finance charges and other taxes, of $0.5 million due to the growth of our business. Additionally, there was an increase in professional services fees of $0.2 million primarily due to increased consulting fees, and an increase in technology and communication costs of $0.1 million. Additionally, we allocated company-wide costs to general and administrative expenses based on headcount, which resulted in a $0.2 million increase of facility costs related to increased rent expense due to the expansion of our office space.

Research and Development Expenses


	Three Months Ended March 31,				Percentage
	2011		2010		Change

Payroll and related costs	$	1,755	$	1,191		47.4	%
Stock-based compensation		271		167		62.3	%
Other		1,206		699		72.5	%

Total	$	3,232	$	2,057		57.1	%

The increase in research and development expenses for the three months ended March 31, 2011 compared to the same period in 2010 was primarily driven by the costs associated with an increase in the number of research and development full-time employees from 51 at March 31, 2010 to 73 at March 31, 2011. The increase in research and development expenses for the three months ended March 31, 2011 compared to the same period in 2010 was also attributable to lower capitalized internal payroll and related costs of $0.2 million. The increase in stock-based compensation for the three months ended March 31, 2011 compared to the same period 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 March 31, 2011 compared to the same period in 2010 was primarily related to a $0.2 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.

Other Income, Net

Other income, net for the three months ended March 31, 2011 was $0.1 million as compared to other income, net of $3,000 for the three months ended March 31, 2010. Other income, net for the three months ended March 31, 2011 and 2010 was comprised of a nominal amount of interest income, as well as net nominal foreign currency gains.

Income Taxes

The tax provision recorded for the three months ended March 31, 2011 was $0.7 million 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 March 31, 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 months ended March 31, 2011 based on our actual effective tax rate for the three months ended March 31, 2011.

If we are able to make a reliable estimate of our annual effective tax rate as of June 30, 2011and if we are still anticipating 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 benefit from income taxes being recorded during the three months ended June 30, 2011. If we continue to be unable to make a reliable estimate of our annual effective tax rate as of June 30, 2011, we expect to follow a consistent methodology as applied for the three months ended March 31, 2011 and record a provision for income taxes for the three 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 March 31, 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 March 31, 2010, we recorded an income tax benefit of $1.2 million based on the reliably estimated annual effective tax rate on the loss before income taxes for the three months ended March 31, 2010. This tax benefit related principally to losses incurred from operations in the United States, which we realized in 2010 based on forecasted pre-tax income for the fiscal year ended December 31, 2010, partially offset by losses from foreign operations for which no tax benefit can be recognized.

Liquidity and Capital Resources

Overview

Since inception, we have generated significant cumulative losses. As of March 31, 2011, we had an accumulated deficit of $87.0 million. As of March 31, 2011, our principal sources of liquidity were cash and cash equivalents totalling $102.6 million, a decrease of $50.8 million from the December 31, 2010 balance of $153.4 million. As of March 31, 2011, we were contingently liable for $36.8 million in connection with outstanding letters of credit under the 2008 credit facility. As of March 31, 2011 and December 31, 2010, we had restricted cash balances of $0.3 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. At March 31, 2011 and December 31, 2010, our excess cash was primarily invested in money market funds.

We believe our existing cash and cash equivalents at March 31, 2011 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 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 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 three months ended March 31, 2011 and 2010 (dollars in thousands):


	Three Months Ended March 31,
	2011			2010
Cash flows (used in) provided by operating activities	$	(5,688	)	$	3,122
Cash flows used in investing activities		(46,016	)		(6,978	)
Cash flows provided by financing activities		1,030			1,506
Effects of exchange rate changes on cash		(100	)		(5	)

Net change in cash and cash equivalents	$	(50,774	)	$	(2,355	)

Cash Flows (Used in) Provided by Operating Activities

Cash (used in) 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 used in operating activities for the three months ended March 31, 2011 was $5.7 million and consisted of net loss of $19.3 million, offset by $8.9 million of non-cash items, primarily consisting of depreciation and amortization, deferred taxes, stock-based compensation charges and impairment of property and equipment, as well as $4.7 million of net cash provided by working capital and other activities. Cash provided by working capital and other activities consisted of an increase of $1.1 million in deferred revenue and a decrease of $43.0 million in unbilled revenues relating to the PJM demand response market. These amounts were offset by cash used in working capital and other activities consisting of a decrease of $3.3 million in accrued payroll and related expenses, a decrease of $5.0 million in accounts payable and accrued expenses due to the timing of payments, a decrease of accrued capacity payments of $24.9 million, the majority of which was related to the PJM demand response market, an increase in prepaid expenses and other assets of $3.3 million and an increase of $2.9 million in accounts receivable due to the timing of cash receipts under the programs in which we participate.

Cash provided by operating activities for the three months ended March 31, 2010 was $3.1 million and consisted of a net loss of $14.2 million offset by $9.8 million of net cash provided by working capital and other activities and $7.5 million of non-cash items, primarily consisting of depreciation and amortization, deferred tax benefit and stock-based compensation charges. Cash provided by working capital and other activities consisted of a decrease of $24.0 million in unbilled revenues relating to the PJM demand response market, a decrease in accounts receivable of $1.3 million due to the timing of cash receipts under the demand response programs in which we participate, and a $0.5 million increase in deferred revenue. These amounts were partially offset by cash used from working capital and other activities, which reflected an increase in prepaid expenses and other assets of $0.6 million, a decrease of $0.1 million in accounts payable and accrued expenses due to the timing of payments, a $13.0 million decrease in accrued capacity payments, the majority of which was related to the PJM demand response market, and a $2.3 million decrease in accrued payroll and related expenses.

Cash Flows Used in Investing Activities

Cash used in investing activities was $46.0 million for the three months ended March 31, 2011. During the three months ended March 31, 2011, we acquired Global Energy for a purchase price of $26.7 million, of which $19.9 million was paid in cash, M2M for a purchase price of $29.9 million, of which $17.6 million was paid in cash and DMT 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. Our principal cash investments during the three months ended

March 31, 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 three months ended March 31, 2011, we also incurred $3.5 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 $7.0 million for the three months ended March 31, 2010. Our principal cash investments during the three months ended March 31, 2010 related to installation services used to build out and expand our energy management applications and services and purchases of property and equipment. During the three months ended March 31, 2010, we acquired Smallfoot and Zox for a purchase price of $1.4 million, of which $1.1 million was paid in cash. We had an increase in restricted cash and deposits resulting in a reduction of cash of $0.3 million primarily as a result of our cash deposits made in connection with demand response programs in which we participate. During the three months ended March 31, 2010, we also incurred $5.6 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 $1.0 million and $1.5 million for the three months ended March 31, 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 three months ended March 31, 2011 and 2010.

Credit Facility Borrowings

Pursuant to the terms of the 2008 credit facility, SVB will, among other things, make revolving credit and term loan advances and issue letters of credit for our account. The interest on loans under the 2008 credit facility accrues at interest rates based upon either SVB’s prime rate or the 30, 60 or 90-day LIBOR plus 2.25%, at our election. The interest on term loans accrues at SVB’s prime rate plus 0.50% or the 30, 60 or 90-day LIBOR plus 2.75%, at our election. The term advance is payable in thirty-six consecutive equal monthly installments of principal, calculated by SVB, based upon the amount of the term advance and an amortization schedule equal to thirty-six months. All unpaid principal and accrued interest was due and payable in full on March 31, 2011, which was the maturity date. In connection with the issuance or renewal of letters of credit for our account, we are charged a letter of credit fee of 1.25%. We expense the interest and letter of credit fees, as applicable, in the period incurred. We were not in compliance with the minimum specified tangible net worth covenant of the 2008 credit facility as of March 31, 2011 and obtained a waiver of this covenant default from SVB. We were in compliance with all financial covenants under the 2008 credit facility at December 31, 2010. The 2011 credit facility does not contain a minimum specified tangible net worth financial covenant and we are currently in compliance with the covenants under 2011 credit facility. At March 31, 2011, we had no borrowings and letters of credit totaling $36.8 million outstanding under the 2008 SVB credit facility.

In April 2011, we and one of our subsidiaries entered into the 2011 credit facility. Subject to continued covenant compliance, the 2011credit 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 credit agreement 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 the Wall 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. 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 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 agreement, 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.

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. Based on our prior experience with this certain open market bidding program, we currently expect that we will recover a portion of this cash and these letters of credit during the second quarter of 2011.

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 $3.5 million and $5.6 million during the three months ended March 31, 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 March 31, 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 March 31, 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 March 31, 2011, we had outstanding letters of credit totaling $36.8 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 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 months ended March 31, 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 its 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.

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 $3,025 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 3 years. In addition, we capitalize the 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, or 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, 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.

	•		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 this new accounting guidance at the beginning of its first quarter of 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 our revenue transactions. The impact of adopting this new accounting guidance was not material to our financial statements in the first quarter of fiscal 2011, and if they were applied in the same manner to fiscal 2010 would not have had a material impact to revenue for the first quarter of fiscal 2010. We do 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 limited number of multiple element arrangements. The key impact that we expect 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 our demand response arrangements (i.e. vendors). 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 future impact of this change is not expected to be material.

We typically determine the selling price of its services based on VSOE. Consistent with its 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 its products and services are sold into when determining VSOE. We typically have had VSOE for our products and services.

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.

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 months ended March 31, 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.

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

Net loss for the three months ended March 31, 2011 was $19.3 million, or $0.76 per basic and diluted share, compared to a net loss of $14.2 million, or $0.59 per basic and diluted share, for the three months ended March 31, 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 March 31, 2011 was $14.6 million, or $0.58 per basic and diluted share, compared to a non-GAAP net loss of $9.8 million, or $0.41 per basic and diluted share, for the three months ended March 31, 2010. The reconciliation of non-GAAP net loss to GAAP net loss is set forth below:


	Three Months Ended March 31,
	2011			2010
	(In thousands, except share and per share data)

GAAP net loss	$	(19,272	)	$	(14,200	)
ADD: Stock-based compensation		3,482			4,346
ADD: Amortization expense of acquired intangible assets		1,152			388
LESS: Income tax effect on Non-GAAP adjustments(1)		—			(360	)

Non-GAAP net loss	$	(14,638	)	$	(9,826	)


GAAP net loss per basic share	$	(0.76	)	$	(0.59	)
ADD: Stock-based compensation		0.14			0.18
ADD: Amortization expense of acquired intangible assets		0.04			0.01
LESS: Income tax effect on Non-GAAP adjustments(1)		—			(0.01	)

Non-GAAP net loss per basic share	$	(0.58	)	$	(0.41	)


GAAP net loss per diluted share	$	(0.76	)	$	(0.59	)
ADD: Stock-based compensation		0.14			0.18
ADD: Amortization expense of acquired intangible assets		0.04			0.01
LESS: Income tax effect on Non-GAAP adjustments(1)		—			(0.01	)

Non-GAAP net loss per diluted share	$	(0.58	)	$	(0.41	)


Weighted average number of common shares outstanding
Basic		25,248,650			24,051,114
Diluted		25,248,650			24,051,114


(1)		Represents the reduction in the income tax benefit recorded for the three months ended March 31, 2010 based on our effective tax rate for the three months ended March 31, 2010. The non-GAAP adjustments would have no impact on the provision for income taxes recorded for the three months ended March 31, 2011.

Adjusted EBITDA

Adjusted EBITDA was negative $10.3 million and negative $7.4 million for the three months ended March 31, 2011 and 2010, respectively. The reconciliation of adjusted EBITDA to net loss is set forth below:


	Three Months Ended March 31,
	2011			2010
Net loss	$	(19,272	)	$	(14,200	)
Add back:
Depreciation and amortization		4,777			3,619
Stock-based compensation expense		3,482			4,346
Other income		(128	)		(3	)
Interest expense		163			25
Provision for (benefit from) income tax.		666			(1,167	)

Adjusted EBITDA	$	(10,312	)	$	(7,380	)

Free Cash Flow

Cash flow (used in) provided by operating activities was $(5.7) million and $3.1 million for the three months ended March 31, 2011 and 2010, respectively. We incurred negative free cash flows of $9.2 million and $2.5 million for the three months ended March 31, 2011 and 2010, respectively. The reconciliation of free cash flow to cash flow from operating activities is set forth below:


	Three Months Ended March 31,
	2011			2010
Net cash (used in) provided by operating activities	$	(5,688	)	$	3,122
Subtract:
Purchases of property and equipment		(3,464	)		(5,596	)

Free cash flow	$	(9,152	)	$	(2,474	)

Item 3. Quantitative and Qualitative Disclosures About Market Risk

At March 31, 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 March 31, 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, which we filed with the SEC on March 1, 2011. During the three months ended March 31, 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 Annual Report on Form 10-K for the fiscal year ended December 31, 2010, except that the following risk factor replaces and supersedes the corresponding risk factor set forth in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010:

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. 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 its Interruptible Load for Reliability program, or 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 a joint statement concerning settlements in PJM’s demand response programs for participants using a certain baseline method of measurement and verification for 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 customers’ peak demand for 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. In the event that PJM is successful in 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.

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. 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.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

(a) Unregistered Sales of Equity Securities

We offered, issued and/or sold the following unregistered securities during the three months ended March 31, 2011: on January 3, 2011, in connection with our acquisition of Global Energy, we issued 275,181 shares of our common stock, and on January 25, 2011, in connection with our acquisition of M2M, we issued 351,665 shares of our common stock.

The issuance of the securities described above was deemed to be exempt from registration under the Securities Act in reliance on Section 4(2) of the Securities Act as transactions by an issuer not involving any public offering. The recipients of these securities in such transaction represented their intention to acquire the securities for investment only and not with a view to or for sale in connection with any distribution thereof. Such recipients received written disclosures that the securities have not been registered under the Securities Act and that any resale must be made pursuant to a registration or an available exemption from such registration. All of these securities are deemed restricted securities for the purposes of the Securities Act. The sales of these securities were made without general solicitation or advertising.

Item 6. Exhibits.


2.1*		Agreement and Plan of Merger, dated as of January 21, 2011, by and among EnerNOC, Inc., M2M Communications Corporation, M2M Merger Sub, Inc., Steve Hodges, in his capacity as stockholder representative, and certain individuals named herein.

10.1*@		Separation Agreement with Darren Brady

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 three months ended March 31, 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, tagged as blocks of text.


@		Management contract, compensatory plan or arrangement.

*		Filed herewith.

**		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.

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: May 5, 2011	By:	/s/ Timothy G. Healy
		Timothy G. Healy
		Chief Executive Officer (principal executive officer)


Date: May 5, 2011	By:	/s/ Timothy Weller
		Timothy Weller
		Chief Financial Officer and Treasurer (principal financial officer)

Exhibit Index


Number		Exhibit Title
2.1*		Agreement and Plan of Merger, dated as of January 21, 2011, by and among EnerNOC, Inc., M2M Communications Corporation, M2M Merger Sub, Inc., Steve Hodges, in his capacity as stockholder representative, and certain individuals named herein.

10.1*@		Separation agreement with Darren Brady

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 three months ended March 31, 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, tagged as blocks of text.


@		Management contract, compensatory plan or arrangement.

*		Filed herewith.

**		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.

ENERNOC INC - FORM 10-Q - May 5, 2011

Attached files

ENERNOC INC Reports

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