Enernoc (ENOC) 10-Q 2014 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2014

or

¨ 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 Incorporation or Organization)	(IRS Employer Identification No.)

One Marina Park Drive Suite 400 Boston, Massachusetts	02210
(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  x    No  ¨

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  x    No  ¨

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	¨	Accelerated filer	x
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

There were 30,346,946 shares of the registrant’s common stock, $0.001 par value per share, outstanding as of May 5, 2014.

EnerNOC, Inc.

Index to Form 10-Q

			Page
Part I - Financial Information
Item 1.		Financial Statements
		Unaudited Condensed Consolidated Balance Sheets at March 31, 2014 and December 31, 2013		3
		Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2014 and 2013		4
		Unaudited Condensed Consolidated Statements of Comprehensive Loss for the three months ended March 31, 2014 and 2013		5
		Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2014 and 2013		6
		Notes to Unaudited Condensed Consolidated Financial Statements		7
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
Item 3.		Quantitative and Qualitative Disclosures About Market Risk		57
Item 4.		Controls and Procedures		58
Part II - Other Information
Item 1.		Legal Proceedings		58
Item 1A	��	Risk Factors		59
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds		59
Item 6.		Exhibits		60
		Exhibit Index		60
		Signatures		61

2

EnerNOC, Inc.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except par value and share data)

	March 31, 2014			December 31, 2013
ASSETS
Current assets
Cash and cash equivalents	$	103,698		$	149,189
Restricted cash		1,197			1,834
Trade accounts receivable, net of allowance for doubtful accounts of $462 and $454 at March 31, 2014 and December 31, 2013, respectively		46,528			35,933
Unbilled revenue		27,507			66,675
Capitalized incremental direct customer contract costs		16,267			9,509
Deposits		263			252
Prepaid expenses, deposits and other current assets		9,920			6,610
Assets held for sale		681			681
Total current assets		206,061			270,683
Property and equipment, net of accumulated depreciation of $80,238 and $75,810 at March 31, 2014 and December 31, 2013, respectively		48,425			47,419
Goodwill		94,969			77,104
Customer relationship intangible assets, net		19,482			14,247
Other definite-lived intangible assets, net		5,702			2,939
Capitalized incremental direct customer contract costs, long-term		1,910			1,995
Deposits and other assets		2,794			1,568
Total assets	$	379,343		$	415,955
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	1,532		$	2,031
Accrued capacity payments		58,497			76,676
Accrued payroll and related expenses		10,978			13,370
Accrued expenses and other current liabilities		13,871			10,145
Accrued performance adjustments		539			1,720
Deferred revenue		29,281			20,625
Liabilities held for sale		521			521
Total current liabilities		115,219			125,088
Deferred acquisition consideration		572			566
Accrued acquisition contingent consideration		399			—
Deferred tax liability		6,938			6,211
Deferred revenue		7,997			6,819
Other liabilities		7,431			7,776
Commitments and contingencies (Note 10)		—			—
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, 30,249,264 and 29,920,807 shares issued and outstanding at March 31, 2014 and December 31, 2013, respectively		30			30
Additional paid-in capital		354,140			353,354
Accumulated other comprehensive loss		(1,987	)		(2,535	)
Accumulated deficit		(111,767	)		(81,354	)
Total EnerNOC, Inc. stockholders’ equity		240,416			269,495
Noncontrolling interest		371			—
Total stockholders’ equity		240,787			269,495
Total liabilities and stockholders’ equity	$	379,343		$	415,955

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

3

EnerNOC, Inc.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share and per share data)

	Three Months Ended March 31,
	2014			2013
Revenues:
Grid operator	$	35,770		$	15,063
Utility		10,309			11,769
Enterprise		6,429			6,018
Total revenues		52,508			32,850
Cost of revenues		36,139			22,197
Gross profit		16,369			10,653
Operating expenses:
Selling and marketing		18,499			15,653
General and administrative		23,677			20,121
Research and development		5,175			4,820
Total operating expenses		47,351			40,594
Loss from operations		(30,982	)		(29,941	)
Other income, net		574			67
Interest expense		(450	)		(313	)
Loss before income tax		(30,858	)		(30,187	)
Benefit from (provision for) income tax		425			(350	)
Net loss		(30,433	)		(30,537	)
Net loss attributable to noncontrolling interest		(20	)		—
Net loss attributable to EnerNOC, Inc.	$	(30,413	)	$	(30,537	)
Net loss per common share attributable to EnerNOC, Inc. (basic and diluted)	$	(1.09	)	$	(1.12	)
Weighted average number of common shares used in computing basic and diluted net loss per common share		27,923,861			27,366,612

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

4

EnerNOC, Inc.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(in thousands)

	Three Months Ended March 31,
	2014			2013
Net loss	$	(30,433	)	$	(30,537	)
Foreign currency translation adjustments		547			(24	)
Comprehensive loss		(29,886	)		(30,561	)
Comprehensive loss attributable to noncontrolling interest		(21	)		—
Comprehensive loss attributable to EnerNOC, Inc.	$	(29,865	)	$	(30,561	)

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

5

EnerNOC, Inc.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

		Three Months Ended March 31,
		2014			2013
Cash flows from operating activities	��
Net loss		$	(30,433	)	$	(30,537	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depreciation			5,482			4,936
Amortization of acquired intangible assets			1,883			1,794
Stock-based compensation expense			4,227			4,704
Impairment of equipment			95			142
Impairment of definite lived assets			163			—
Unrealized foreign exchange transaction gain			(404	)		(32	)
Deferred taxes			208			372
Non-cash interest expense			116			71
Accretion of fair value of deferred purchase price and accrued contingent purchase price consideration related to acquisitions			6			30
Other, net			(174	)		77
Changes in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable, trade			(10,332	)		8,123
Unbilled revenue			39,198			26,578
Prepaid expenses and other current assets			(3,126	)		(2,153	)
Capitalized incremental direct customer contract costs			(6,254	)		(5,033	)
Other assets			328			82
Other noncurrent liabilities			(345	)		3,357
Deferred revenue			9,341			11,004
Accrued capacity payments			(18,338	)		(17,073	)
Accrued payroll and related expenses			(3,426	)		(1,086	)
Accounts payable, accrued performance adjustments and accrued expenses and other current liabilities			219			1,424
Net cash (used in) provided by operating activities			(11,566	)		6,780
Cash flows from investing activities
Purchases of property and equipment			(6,113	)		(8,938	)
Payments made for acquisitions, net of cash acquired			(24,085	)		—
Payments made for cost method investment			(1,000	)		—
Change in restricted cash and deposits			651			1,564
Payments made for acquisition of customer contract			(403	)		—
Net cash used in investing activities			(30,950	)		(7,374	)
Cash flows from financing activities
Proceeds from exercises of stock options			525			489
Payments related to employee restricted stock minimum tax withholdings			(3,644	)		—
Net cash (used in) provided by financing activities			(3,119	)		489
Effects of exchange rate changes on cash and cash equivalents			144			(109	)
Net change in cash and cash equivalents			(45,491	)		(214	)
Cash and cash equivalents at beginning of period			149,189			115,041
Cash and cash equivalents at end of period		$	103,698		$	114,827
Non-cash financing and investing activities
Issuance of common stock in satisfaction of bonuses		$	145		$	154

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

6

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 leading provider of energy intelligence software (EIS) and related solutions. The Company unlocks the full value of energy management for commercial, institutional and industrial end-users of energy, which it refers to as its C&I or enterprise customers, and its electric power grid operator and utility customers by delivering a comprehensive suite of demand-side management solutions. These solutions allow customers to make better and more strategic decisions about how and when they use electricity.

The Company believes that it is the world’s leading provider of demand response applications and solutions. Demand response is an alternative to traditional electric 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.

The Company provides its utility and grid operator customers with two demand response solutions: EnerNOC Demand Resource and EnerNOC Demand Manager, which it collectively refers to as EnerNOC DemandSMART.

When the Company enters into an EnerNOC Demand Resource contract, it matches obligation, in the form of megawatts (MWs) that it agrees to deliver to its utility and electric power grid operator customers, with supply, in the form of MW that it is able to curtail from the electric power grid through its arrangements with C&I customers. The Company deploys a sales team to contract with its C&I customers and installs its advanced metering equipment at these customers’ sites to connect them to its network, resulting in an increased ability to curtail demand from the electric power grid. When the Company is called upon by its utility or electric power grid operator customers to deliver its contracted capacity, the Company uses its Network Operations Center (NOC) to remotely manage and reduce electricity consumption across its 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. The Company receives recurring payments from electric power grid operators and utilities for providing its EnerNOC Demand Resource solution and it shares these recurring payments with its C&I customers in exchange for those C&I customers reducing their power consumption when called upon by the Company to do so. The Company occasionally reallocates and realigns its capacity supply and obligation through open market bidding programs, supplemental demand response programs, auctions or other similar capacity arrangements and bilateral contracts to account for changes in supply and demand forecasts, as well as changes in programs and market rules in order to achieve more favorable pricing opportunities. The Company refers to the above activities as managing its portfolio of demand response capacity.

EnerNOC’s Demand Manager solution consists of long-term contracts with a utility customer for a Software-as-a-Service solution that allows utilities to manage demand response capacity in utility-sponsored demand response programs. The Company’s EnerNOC Demand Manager solution provides its utility customers with real-time load monitoring, dispatching applications, customizable reports, measurement and verification, and other professional services.

The Company builds on its position as a leading demand response provider by using its NOC and energy intelligence software (EIS) platform to deliver a portfolio of additional EIS and solutions to new and existing C&I, electric power grid operator and utility customers. These additional EIS and solutions include the Company’s EfficiencySMART and SupplySMART applications and solutions, and certain wireless energy management products. EfficiencySMART is the Company’s data-driven energy efficiency suite that includes energy efficiency planning, audits, assessments, commissioning and retro-commissioning authority services, and a cloud-based energy analytics application used for managing energy across a C&I customer’s portfolio of sites. The cloud-based energy analytics application also includes the ability to integrate with a C&I customer’s existing energy management system, provide utility bill management and tools for measurement, tracking, analysis, reporting and management of greenhouse gas emissions. SupplySMART is the Company’s energy price and risk management application and solution 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 management. The Company’s wireless energy management products are designed to ensure that its C&I customers can connect their equipment remotely and access meter data securely, and include both cellular modems and an agricultural specific wireless technology solution.

7

Reclassifications

The Company has reclassified certain amounts in its unaudited condensed consolidated statements of operations for the three month period ended March 31, 2013, to conform to the 2014 presentation. The reclassifications made related to the presentation of the Company’s revenues from DemandSMART revenues and EfficiencySMART, SupplySMART and other revenues to revenues from grid operators, revenues from utilities, and revenues from enterprise customers and was done in order to provide the users of its consolidated financial statements with additional insight into how the Company and its management views and evaluates its revenues and related growth. This reclassification within the unaudited condensed consolidated statements of operations for the three month period ended March 31, 2013 had no impact on previously reported total consolidated revenues or consolidated results of operations.

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) and variable interest entities (VIE) in which the Company has variable interests are consolidated where the Company is the primary beneficiary and thus controls the VIE. Intercompany transactions and balances are eliminated upon consolidation.

On February 13, 2014, the Company acquired all of the outstanding capital stock of Entelios AG (Entelios) and all of the outstanding capital stock of Activation Energy DSU Limited (Activation) in separate purchase business combinations. Accordingly, the results of operations of Entelios and Activation 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.

Liquidity Changes

In May 2014, the Company was required to provide incremental financial assurance in connection with its capacity bid in a certain open market bidding program. The Company has provided this financial assurance utilizing a $22,000 letter of credit issued under its $70,000 senior secured revolving credit facility with the several lenders from time to time party thereto and Silicon Valley Bank (SVB), as administrative agent, swingline lender, issuing lender, lead arranger and book manager (SVB and together with the other lenders, and referred to herein as the lenders), which was subsequently amended in August 2013, December 2013 and January 2014 (2013 credit facility) and additionally, utilized $4,500 of its available unrestricted cash on hand. 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 letter of credit and cash during the three month period ending June 30, 2014.

8

Acquisition of Entech Utility Service Bureau, Inc. and Entech Utility Service Bureau Ltd.

On April 17, 2014, the Company and two of its subsidiaries completed acquisitions of all of the outstanding stock of Entech Utility Service Bureau, Inc. (Entech US) and Entech Utility Service Bureau Ltd. (Entech UK) (collectively, Entech), privately-held companies headquartered in the United States and the United Kingdom, respectively, that are leading providers of global utility bill management (UBM) software, which is currently deployed in over 100 countries, including many of the world’s fastest growing economies, such as China, India, and Brazil. The Company concluded that these acquisitions represented business combinations and, therefore, will account for them as such. The Company believes that the combination of Entech’s software and technology, including real-time energy data, tariffs, and monthly utility bill data on the Company’s EIS platform will now enable real-time visibility and forecasting of energy costs and empower better energy management across global enterprises.

The Company concluded that these acquisitions represented business combinations under ASC 805, but has concluded that they did not represent material business combinations and therefore, no pro forma financial information will be required.

Entech US and Entech UK were not entities under common control and the Company separately negotiated the acquisitions, including purchase price, with each of the entity’s stockholders. The Company acquired Entech US for an aggregate purchase price of $6,796 all of which was cash paid at closing with $60 paid to the stockholders’ consultants to settle transactional fees due to these consultants. There are no earn-out or other additional contingent purchase price arrangements related to the acquisition of Entech US. The Company acquired Entech UK for an aggregate purchase price of $3,154 all of which was cash paid at closing with $18 paid to the stockholders’ consultants to settle the stockholders’ fees due to these consultants. There are no earn-out or other additional contingent purchase price arrangements related to the acquisition of Entech UK.

Transaction costs related to this business combination have been expensed as incurred and are included in general and administrative expenses in the accompanying condensed consolidated statements of operations. The Company’s consolidated financial statements will reflect Entech’s results of operations from April 17, 2014 forward.

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

There were no other material recognizable subsequent events recorded or requiring disclosure in the March 31, 2014 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 thereto have been

9

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, 2013, and include all adjustments (consisting of normal, recurring adjustments) necessary for the fair presentation of the Company’s financial position at March 31, 2014 and statements of operations, statements of comprehensive loss and statements of cash flows for the three month periods ended March 31, 2014 and 2013. Operating results for the three month period ended March 31, 2014 are not necessarily indicative of the results to be expected for any other interim period or the entire fiscal year ending December 31, 2014 (fiscal 2014).

The preparation of these unaudited condensed consolidated financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, the Company evaluates its estimates, including those related to revenue recognition, allowance for doubtful accounts, valuations and purchase price allocations related to business combinations, fair value of deferred acquisition consideration, fair value of accrued acquisition contingent consideration, expected future cash flows including growth rates, discount rates, terminal values and other assumptions and estimates used to evaluate the recoverability of long-lived assets and goodwill, estimated fair values of intangible assets and goodwill, amortization methods and periods, certain accrued expenses and other related charges, stock-based compensation, contingent liabilities, fair value of asset retirement obligations, tax reserves and recoverability of the Company’s net deferred tax assets 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 of its industry, including, but not limited to, rapid technological changes, competition from similar energy management applications, services and products provided by 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 ASC 605,Revenue Recognition (ASC 605). 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 the following criteria:

• 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 significant 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 fees to be fixed or determinable unless the fees are subject to refund or adjustment or are 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 the Company offers payment terms significantly in excess of its normal terms, it 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 maintains a reserve for customer adjustments and allowances as a reduction in revenues. In determining the Company’s revenue reserve estimate, and in accordance with company policy, the Company relies on historical data and known performance adjustments. These factors, and unanticipated changes in the economic and industry environment, could cause the

10

Company’s reserve estimates to differ from actual results. The Company records a provision for estimated customer adjustments and allowances in the same period as the related revenues are recorded. These estimates are based on the specific facts and circumstances of a particular program, analysis of credit memo data, historical customer adjustments, and other known factors. If the data the Company uses to calculate these estimates does not properly reflect reserve requirements, then a change in the allowances would be made in the period in which such a determination is made and revenues in that period could be affected. As of March 31, 2014 and December 31, 2013, the Company’s revenue reserves were $475. During the three month period ended March 31, 2013, the Company recorded an increase to the revenue reserve of $50. There was no change to the revenue reserve for the three month period ended March 31, 2014.

Revenues from grid operators and revenues from utilities principally represent demand response revenues. During the three month period ended March 31, 2014, revenues from grid operators and revenues from utilities were comprised of $44,100 of demand response revenues and $1,979 of enterprise EIS and solutions revenues. During the three month periods ended March 31, 2013, revenues from grid operators and revenues from utilities were comprised of $24,482 of demand response revenues and $2,350 of enterprise EIS and solutions revenues.

All revenues from enterprise customers for the three month periods ended March 31, 2014 and 2013 were derived from enterprise EIS and solutions.

Demand Response Revenues

The Company enters into contracts and open market bidding programs with utilities and electric power grid operators to provide demand response applications and services. Currently the Company has two principal service offerings under which it provides demand response applications and services: (1) full-service turnkey offering to utilities under which it manages all aspects of demand response program delivery to deliver a firm capacity resource (Demand Resource) and (2) utility partnership offering under which utilities can utilize software through a software as a service offering, integrated metering hardware, and professional services to support their tariff-based C&I demand response programs on a service-level agreement basis (Demand Manager).

The Company has evaluated the factors within ASC 605 regarding gross versus net revenue reporting for its demand response revenues and its payments to C&I customers. Based on the evaluation of the factors within ASC 605, the Company has determined that all of the applicable indicators of gross revenue reporting were met. The applicable indicators of gross revenue reporting included, but were not limited to, the following:

• The Company is the primary obligor in its arrangements with electric power grid operators and utility customers because the Company provides its demand response services directly to electric power grid operators and utilities under long-term contracts or pursuant to open market programs and contracts separately with C&I customers to deliver such services. The Company manages all interactions with the electric power grid operators and utilities, while C&I customers do not interact with the electric power grid operators and utilities. In addition, the Company assumes the entire performance risk under its arrangements with electric power grid operators and utility customers, including the posting of financial assurance to assure timely delivery of committed capacity with no corresponding financial assurance received from its C&I customers. In the event of a shortfall in delivered committed capacity, the Company is responsible for all penalties assessed by the electric power grid operators and utilities without regard for any recourse the Company may have with its C&I customers.

• The Company has latitude in establishing pricing, as the pricing under its arrangements with electric power grid operators and utilities is negotiated through a contract proposal and contracting process or determined through a capacity auction. The Company then separately negotiates payment to C&I customers and has complete discretion in the contracting process with the C&I customers.

• The Company has complete discretion in determining which suppliers (C&I customers) will provide the demand response services, provided that the C&I customer is located in the same region as the applicable electric power grid operator or utility.

• The Company is involved in both the determination of service specifications and performs part of the services, including the installation of metering and other equipment for the monitoring, data gathering and measurement of performance, as well as, in certain circumstances, the remote control of C&I customer loads.

11

As a result, the Company determined that it earns revenue (as a principal) from the delivery of demand response services to electric power grid operators and utility customers and records the amounts billed to the electric power grid operators and utility customers as gross demand response revenues and the amounts paid to C&I customers as cost of revenues.

EnerNOC Demand Resource Solution

The majority of the Company’s demand response revenues are generated from the EnerNOC Demand Resource solution. Demand response revenues consist of two elements: revenue earned from 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 from 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 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.

Commencing in fiscal 2012, all demand response capacity revenues related to the Company’s participation in the PJM open market program are being recognized at the end of the four-month delivery period of June through September, or during the three month period ended September 30^th of each year. Because the period during which the Company is required to perform (June through September) is shorter than the period over which payments are received under the program (June through May), a portion of the revenues that have been earned are recorded and accrued as unbilled revenue. Substantially all revenues related to the PJM open market program for the year ended September 30, 2013 were recognized during the three month period ended September 30, 2013 and as a result of the billing period not coinciding with the revenue recognition period, the Company had $26,465, and $64,643 in unbilled revenues from PJM at March 31, 2014 and December 31, 2013, respectively.

Energy event revenues are recognized when earned. Energy event revenue is deemed to be substantive and represents the culmination of a separate earnings process and is recognized when the energy event is initiated by the electric power grid operator or utility customer and the Company has responded under the terms of the contract or open market program. During the three month periods ended March 31, 2014 and 2013, the Company recognized $20,570 and $1,935, respectively, of energy event revenues.

The Company has evaluated the forward capacity programs in which the Company participates and has determined that its contractual obligations in these programs do not currently meet the definition of derivative contracts under ASC 815,Derivatives and Hedging(ASC 815).

EnerNOC Demand Manager Solution

Under the Company’s EnerNOC Demand Manager solution, the Company generally receives an ongoing fee for overall management of the utility demand response program based on enrolled capacity or enrolled C&I customers, which is not subject to adjustment based on performance during a demand response dispatch. The Company recognizes revenues from these fees ratably over the applicable service delivery period commencing upon when the C&I customers have been enrolled and the contracted services have been delivered. In addition, under this offering, the Company may receive additional fees for program start-up, as well as, for C&I customer installations. The Company has determined that these fees do not have stand-alone value due to that such services do not have value without the ongoing services related to the overall management of the utility demand response program and therefore, the Company recognizes these fees over the estimated customer relationship period, which is generally the greater of 3 years or the contract period, commencing upon the enrollment of the C&I customers and delivery of the contracted services. Through March 31, 2014, revenues from EnerNOC Demand Manager have not been material to the Company’s consolidated results of operations.

Enterprise EIS and Solutions

With respect to the Company’s enterprise EIS and solutions revenues, which represent the Company’s EfficiencySMART, SupplySMART and other revenues, these generally represent ongoing service arrangements where the revenues are recognized ratably

12

over the service period commencing upon delivery of the contracted service with the customer. Under certain of the Company’s arrangements, in particular certain EfficiencySMART arrangements with utilities, a portion of the fees received may be subject to adjustment or refund based on the validation of the energy savings delivered after the implementation is complete. As a result, the Company defers the portion of the fees that are subject to adjustment or refund until such time as the right of adjustment or refund lapses, which is generally upon completion and validation of the implementation. In addition, under certain other of the Company’s arrangements, the Company sells proprietary equipment to C&I customers 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 revenues associated with the equipment and the Company begins recognizing such revenue ratably over the expected C&I customer relationship period (generally 3 years), once the C&I customer is receiving the ongoing services from the Company. 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.

The Company follows the provisions of ASC Update No. 2009-13,Multiple-Deliverable Revenue Arrangements(ASU 2009-13). The Company typically determines the selling price of its services based on vendor specific objective evidence (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 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. Third Party Evidence (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. Management’s best estimate of selling price (ESP) is established in those instances where neither VSOE nor TPE are available, by 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.

Foreign Currency Translation

Foreign currency translation adjustments are recorded as a component of other comprehensive loss and included in accumulated other comprehensive loss within stockholders’ equity. Gains arising from transactions denominated in foreign currencies and the re-measurement of certain intercompany receivables and payables are included in other income, net in the unaudited condensed consolidated statements of operations and were $387 and $16 for the three month periods ended March 31, 2014 and 2013, respectively. Foreign currency exchange gains (losses) resulted primarily from foreign denominated intercompany receivables held by the Company from one of its Australian subsidiaries which mainly resulted from funding provided to complete the acquisition of Energy Response Holdings Pty Ltd (Energy Response) and fluctuations in the Australian dollar exchange rate and U.S. dollar denominated intercompany payables from one of the Company’s German subsidiaries to the Company which mainly resulted from funding provided to complete the acquisition of Entelios.

During the three month period ended March 31, 2014, there were no material settlements of foreign denominated receivables or payables and therefore, there were no material realized gains (losses) during the three month period ended March 31, 2014. During the three month period ended March 31, 2013, $10,266 ($9,921 Australian) of the intercompany receivable from the Company’s Australian subsidiary was settled resulting in a realized loss of $280. As of March 31, 2014, the Company had an intercompany receivable from its Australian subsidiary that is denominated in Australian dollars and not deemed to be of a “long-term investment” nature totaling $10,951 at March 31, 2014 exchange rates ($11,844 Australian) and two of its German subsidiaries had an intercompany payable to the Company that is denominated in U.S. dollars and not deemed to be of a “long-term investment” nature totaling $18,059 at March 31, 2014. The increase in the Australian intercompany receivable from December 31, 2013 was primarily due to royalties and other support charges due to the U.S. parent for services and technology provided by the U.S. parent during the three month period ended March 31, 2014. Subsequent to March 31, 2014, the Company settled $5,627 ($5,977 Australian) of the intercompany receivable from the Company’s Australian subsidiary resulting in a realized loss of $387.

13

In addition, a portion of the funding provided by the Company to one of its Australian subsidiaries to complete the acquisition of Energy Response was deemed to be of a “long-term investment nature” and therefore, the resulting translation adjustments are being recorded as a component of stockholders’ equity within accumulated other comprehensive loss. As of March 31, 2014, the intercompany funding that is denominated in Australian dollars and deemed to be of a “long-term investment” nature totaled $18,829 at March 31, 2014 exchange rates ($20,364 Australian) and during the three month period ended March 31, 2014, the Company recorded translation adjustments of $654 related to this intercompany funding within accumulated other comprehensive loss.

Comprehensive (Loss) Income

Comprehensive (loss) income is defined as the change in equity of a business enterprise during a period resulting from transactions and other events and circumstances from non-owner sources. As of March 31, 2014 and December 31, 2013, 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.

Software Development Costs

Software development costs, including license fees and external consulting costs, of $1,398 and $2,631 for the three month periods ended March 31, 2014 and 2013, respectively, have been capitalized in accordance with Accounting Standard Codification (ASC) 350-40, Internal-Use Software(ASC 350-40). The capitalized amount was included as software in property and equipment at March 31, 2014 and December 31, 2013. Amortization of capitalized internal use software costs was $1,530 and $1,308 for the three month periods ended March 31, 2014 and 2013, respectively. Accumulated amortization of capitalized internal use software costs was $22,971 and $21,441 as of March 31, 2014 and December 31, 2013, respectively.

Impairment of Property and Equipment

During the three month period ended March 31, 2014, as a result of the removal of certain demand response equipment from service, the Company concluded that there were no expected future direct cash flows associated with this demand response equipment and therefore, an impairment indicator existed. The Company determined that the residual value of this demand response equipment was nominal and as a result, recorded an impairment charge during the three month period ended March 31, 2014 of $95, to reduce the carrying value of such equipment to zero. During the three month period ended March 31, 2013, the Company recognized impairment charges of $142.

Industry Segment Information

The Company operates in the following major geographic areas as noted in the below chart. The “All other” designation includes Australia, Germany, Japan, Ireland, New Zealand and the United Kingdom. Revenues are based upon customer location and internationally totaled $9,180 and $8,087 for the three month periods ended March 31, 2014 and 2013, respectively.

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

	Three Months Ended March 31,
	2014			2013
United States		83	%		75	%
Canada		11			15
All other		6			10
Total		100	%		100	%

As of March 31, 2014 and December 31, 2013, 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.

14

2. Acquisitions

Entelios AG

On February 13, 2014, the Company and one of its subsidiaries completed an acquisition of all of the outstanding stock of Entelios, a privately-held company headquartered in Germany that is a leading provider of demand response in Europe. This acquisition accelerates the Company’s entry into continental Europe with Entelios’ strong team and existing relationships with leading grid operators, utilities, retailers, and commercial, institutional, and industrial customers.

The Company concluded that this acquisition represented a business combination under ASC 805 and has also concluded that it did not represent a material business combination and therefore, no pro forma financial information is required to be presented. Subsequent to the acquisition date, the Company’s results of operations include the results of operations of Entelios.

The Company acquired Entelios for an aggregate purchase price, exclusive of potential contingent consideration, of $21,784 (16,000 Euros translated based on the exchange rate on the closing date of the acquisition), all of which was paid in cash. Of the consideration paid at closing, $6,884 (5,056 Euros) was paid as consideration to allow Entelios to settle its outstanding debt and related tax obligations. In addition to the amounts paid at closing, the Company may be obligated to pay additional contingent purchase price consideration related to an earn-out amount up to a maximum of $2,042 (1,500 Euros). The earn-out payment, if any, will be based on the achievement of certain minimum defined profit metrics for the years ending December 31, 2014 and 2015, respectively. Of the $2,042 (1,500 Euros) maximum earn-out payment, up to $817 (600 Euros) and $1,225 (900 Euros) relate to the achievement of the defined profit metrics for the years ending December 31, 2014 and 2015, respectively. If the minimum defined profit metrics are not achieved, there will be no partial payment, however, the amount of the earn-out payment can vary based on the amount that profits exceed the minimum defined profit metrics. The Company determined that the initial fair value of the earn-out payment as of the acquisition date was $95. This fair value was included as a component of the purchase price resulting in an aggregate purchase price of $21,879. Any changes in fair value will be recorded in the Company’s consolidated statements of operations. The Company recorded its estimate of the fair value of the contingent consideration based on the evaluation of the likelihood of the achievement of the contractual conditions that would result in the payment of the contingent consideration and weighted probability assumptions of these outcomes. This fair value measurement was determined utilizing a Monte Carlo simulation and 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, 2014, there were no changes in the probability of the earn-out payment. This liability has been discounted to reflect the time value of money and therefore, as the milestone date approaches, the fair value of this liability will increase. This increase in fair value will be recorded to cost of revenues in the Company’s consolidated statements of operations. During the three months ended March 31, 2014, the change in fair value due to the accretion of the time value of money discount was not material. At March 31, 2014, the liability was recorded at $96 after adjusting for changes in exchange rates.

Transaction costs related to this business combination have been expensed as incurred and are included in general and administrative expenses in the Company’s unaudited condensed consolidated statements of operations. Transaction costs incurred related to this transaction were approximately $511.

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

Net tangible liabilities assumed as of February 13, 2014	$	(50	)
Customer relationships		4,084
Non-compete agreements		204
Developed technology		1,770
Trade name		218
Deferred income tax asset		2,070
Deferred income tax liability		(2,070	)
Goodwill		15,653
Total	$	21,879

The deferred income tax liability recorded in connection with the preliminary allocation of purchase price relates to the book and tax basis difference related to the acquired definite-lived intangible assets for which the book amortization expense for such assets will not be deductible for tax purposes. Due to the fact that this deferred income tax liability represents a potential source of income as defined in ASC 740,Income Taxes(ASC 740), the Company determined that it was more likely than not that a portion of the

15

deferred tax assets acquired in the business combination, which relate to tax net operating loss carry forwards, were realizable. As a result, the Company recorded a corresponding deferred income tax asset that would be utilized to offset this potential source of taxable income. As the deferred income tax liability and deferred income tax asset are both long-term and relate to the same jurisdiction, these amounts are netted in the Company’s unaudited condensed consolidated balance sheet.

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

Cash	$	1,564
Accounts receivable		19
Capitalized incremental direct customer contract costs		36
Prepaid expenses and other current assets		148
Property and equipment		377
Other assets		72
Accounts payable		(178	)
Accrued payroll and related expenses		(970	)
Accrued expenses and other liabilities		(1,098	)
Deferred revenues		(20	)
Total	$	(50	)

Identifiable Intangible Assets

As part of the preliminary purchase price allocation, the Company determined that Entelios’s separately identifiable intangible assets were its customer relationships, non-compete agreements, developed technology, and trade name. Developed technology represented internally developed software that supports the management of demand response dispatches, including fast-response dispatches, as well as, assists with the performance calculations and related settlements. 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 acquired customer relationships, non-compete agreements, and trade name definite-lived intangible assets. 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 12% and 17%, 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 Company used the cost approach to value the acquired developed technology definite-lived intangible asset, as the Company determined that a market participant would be expected to have similar offerings and capabilities to build a replacement version of the software. Furthermore, it is expected that the software will be migrated over time or potentially replaced by the Company’s existing software platform and this expectation is consistent with that of a market participant. The cost approach calculates fair value by calculating the reproduction cost of an exact replica of the subject intangible asset. The Company calculated the replacement cost based on the estimated hours and costs incurred to develop.

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 include 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 amortizes its 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 concluded that the cash flows were not reliably determinable, on a straight-line basis.

16

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

Activation Energy DSU Limited

On February13, 2014, the Company and one of its subsidiaries completed an acquisition of all of the outstanding stock of Activation, a privately-held company headquartered in Ireland that is the leading provider of demand response software and services in Ireland. This acquisition gives the Company an immediate presence in the Irish capacity market and further strengthens the Company’s ability to deliver its full suite of EIS and solutions throughout Europe.

The Company concluded that this acquisition represented a business combination under ASC 805 and has also concluded that it did not represent a material business combination and therefore, no pro forma financial information will be required to be presented. Subsequent to the acquisition date, the Company’s results of operations include the results of operations of Activation.

The Company acquired Activation for an aggregate purchase price of $3,844 (2,823 Euros translated based on the exchange rate on the date of the acquisition close), plus an additional $732 (538 Euros) paid as working capital and other adjustments, all of which was paid in cash. In addition to the amounts paid at closing, the Company may be obligated to pay additional contingent purchase price consideration related to an earn-out amount up to a maximum of $1,398 (1,027 Euros). The earn-out payment, if any, will be based on the achievement of certain minimum defined MW enrollment, as well as, profit metrics for the years ending December 31, 2014 and 2015, respectively. Of the $1,398 (1,027 Euros) maximum earn-out payment, up to $350 (257 Euros) and $1,048 (770 Euros) relate to the achievement of the defined profit metrics for the years ending December 31, 2014 and 2015, respectively. If the minimum defined profit metrics are not achieved, there will be no partial payment, however, the amount of the earn-out payment can vary based on the amount that profits exceed the minimum defined profit metrics. The Company determined that the initial fair value of the earn-out payment as of the acquisition date was $300. This fair value was included as a component of the purchase price resulting in an aggregate purchase price of $4,876. Any changes in fair value will be recorded in the Company’s consolidated statements of operations. The Company recorded its estimate of the fair value of the contingent consideration based on the evaluation of the likelihood of the achievement of the contractual conditions that would result in the payment of the contingent consideration and weighted probability assumptions of these outcomes. This fair value measurement was determined utilizing a Monte Carlo simulation and was based on significant inputs not observable in the market and therefore, represented a Level 3 measurement as defined in ASC 820. As of March 31, 2014, there were no changes in the probability of the earn-out payment. This liability has been discounted to reflect the time value of money and therefore, as the milestone date approaches, the fair value of this liability will increase. This increase in fair value will be recorded to cost of revenues in the Company’s consolidated statements of operations. During the three month period ended March 31, 2014, the change in fair value due to the accretion of the time value of money discount was not material. At March 31, 2014, the liability was recorded at $303 after adjusting for changes in exchange rates.

Transaction costs related to this business combination have been expensed as incurred and are included in general and administrative expenses in the Company’s unaudited condensed consolidated statements of operations. Transaction costs incurred related to this transaction were approximately $159.

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

Net tangible assets acquired as of February 13, 2014	$	752
Customer relationships		2,042
Non-compete agreements		220
Developed technology		545
Trade name		82
Deferred income tax liability		(361	)
Goodwill		1,596
Total	$	4,876

17

The deferred income tax liability recorded in connection with the preliminary allocation of purchase price relates to the book and tax basis difference related to the acquired definite-lived intangible assets where the book amortization expense for such assets will not be deductible for tax purposes.

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

Cash	$	711
Accounts receivable		472
Prepaid expenses and other current assets		27
Property and equipment		92
Accounts payable		(45	)
Accrued expenses and other current liabilities		(55	)
Accrued capacity payments		(450	)
Total	$	752

Identifiable Intangible Assets

As part of the preliminary purchase price allocation, the Company determined that Activation’s separately identifiable intangible assets were its customer relationships, non-compete agreements, developed technology, and trade name. Developed technology represented internally developed software that facilitates customer transactions and provides analytical capabilities. 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 acquired customer relationships, non-compete agreements, and trade name definite-lived intangible assets. 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 17% and 20%, 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 Company used the cost approach to value the acquired developed technology definite-lived intangible asset, as the Company determined that a market participant would be expected to have similar offerings and capabilities to build a replacement version of the software. Furthermore, it is expected that the software will be migrated over time or potentially replaced by the Company’s existing software platform and this expectation is consistent with that of a market participant. The cost approach calculates fair value by calculating the reproduction cost of an exact replica of the subject intangible asset. The Company calculated the replacement cost based on the estimated hours and costs incurred to develop.

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 include 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 amortizes its 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 concluded that the cash flows were not reliably determinable, on a straight-line basis.

18

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

3. Japan Joint Venture

On December 10, 2013, the Company entered into a joint venture with Marubeni Corporation to provide demand response applications and solutions in Japan. The new company was formed in January 2014 and named EnerNOC Japan K.K., which will have an exclusive license to market DemandSMART throughout Japan. The Company and Marubeni Corporation contributed initial capital funding in the form of common stock totaling $580 and $392, respectively. The Company is the majority-owner and owns 60% of EnerNOC Japan K.K. The Company has evaluated its accounting for its ownership interest in EnerNOC Japan K.K. in accordance with ASC 810,Consolidation (ASC 810) and has concluded that it is required to consolidate this entity. As a result, the Company will consolidate the results of this entity, which commenced during the three month period ended March 31, 2014, in accordance with ASC 810. During the three month period ended March 31, 2014, the revenues and pre-tax loss derived from EnerNOC Japan K.K. were not material to the Company’s consolidated results of operations.

4. Equity Investment and License

In February 2014, the Company purchased Series A Preferred Stock (preferred stock) in a privately-held company that licenses its developed software technology for managing electricity tariff rates and related subject matters to allow third parties a central repository to obtain this information and to convert energy usage data into financial costs and savings for a purchase price of $1,000. Based on other recent financings completed by this privately-held company, the Company concluded that the $1,000 represented the fair value of its investment. The Company notes that its preferred stock investment has a substantive liquidation preference and therefore, does not represent in-substance common stock. As a result, the Company concluded that such investment should be accounted for as a cost method investment under ASC 325-20,Cost Method Investments(ASC 325-20). Under ASC 325-20, cost method investments are recorded as long-term assets initially at historical cost and are assessed for other-than-temporary impairments under the provisions of ASC 320 and are adjusted accordingly. Based on the Company’s assessment as of March 31, 2014, the Company did not identify any other-than-temporary impairment indicators. Since the inputs utilized for the Company’s periodic impairment assessment are not based on observable market data, this cost method investment is classified within Level 3 of the fair value hierarchy. To determine the fair value of this investment, the Company utilized available financial information related to the entity, including information based on recent or pending third-party equity investments in this entity. A cost method investment’s fair value is not estimated as there are no identified events or changes in circumstances that may have a significant adverse effect on the fair value of the investment and to do so would be impractical.

In addition to the above equity investment, the Company also entered into a license agreement to obtain a perpetual license to the developed software technology and other rights for $2,000. In accordance with the terms of the license agreement, the Company has a perpetual license to the developed software technology, including any future updates and enhancements, as well as, in certain instances has the right to acquire ownership of the technology. The Company concluded that the $2,000 represents the fair value of the license obtained and has capitalized this amount as a component of property and equipment in its unaudited condensed consolidated balance sheets. The Company is depreciating this asset over its estimated useful life of three years with depreciation expense being recorded as a component of cost of revenues. For the three month period ended March 31, 2014, the Company recorded depreciation expense of $111. The Company also has the ability to earn a royalty of certain future revenues that may be generated from the licensing of the developed software technology up to a maximum of $2,000. The Company concluded that these potential royalties represent a potential contingent income stream and will record such royalties, if any, as a component of other income in its consolidated statements of operations upon cash receipt. Through March 31, 2014, the Company had not received any such royalty payments.

19

5. Intangible Assets and Goodwill

Definite-Lived Intangible Assets

The following table provides the gross carrying amount and related accumulated amortization of intangible assets as of March 31, 2014 and December 31, 2013:

			As of March 31, 2014					As of December 31, 2013
	Weighted Average Amortization Period (in years)		Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Customer relationships		3.63	$	35,573	$	(16,091	)	$	29,663	$	(15,416	)
Customer contracts		2.81		5,152		(3,074	)		4,887		(2,900	)
Employment agreements and non-compete agreements		1.09		1,988		(1,422	)		1,676		(1,475	)
Software				120		(120	)		120		(120	)
Developed technology		1.24		4,623		(2,048	)		2,277		(1,758	)
Trade name		1.03		878		(503	)		575		(455	)
Patents		5.90		180		(72	)		180		(68	)
Total other definite-lived intangible assets				12,941		(7,239	)		9,715		(6,776	)
Total			$	48,514	$	(23,330	)	$	39,378	$	(22,192	)

The increase in the gross carrying amount of definite-lived intangible assets from December 31, 2013 to March 31, 2014 was primarily due to definite-lived intangible assets acquired in connection with the Company’s acquisitions of Entelios and Activation. Refer to Note 2 for further discussion. In addition, the increase to the gross carrying amount of the definite-lived customer contract intangible assets was due to the acquisition of certain C&I contractual arrangements acquired during the three month period ended March 31, 2014 for a purchase price of $403 to help fulfill its contractual obligations and overall performance requirements in connection with one of its bilateral demand response arrangements with an utility. The acquisition of this intangible asset did not meet the definition of a business, as defined in ASC 805,due to the fact that neither processes nor the additional inputs required to combine with this intangible asset in order to be capable of producing outputs were acquired. Therefore, the acquisition of this intangible asset was accounted for as an asset acquisition based on the principles described in ASC 850-50, and as there was only a single asset acquired, the entire purchase price was allocated to this single intangible asset. Based on the evaluation of the expected direct cash flows to be received from this acquired intangible asset, the Company determined that the cost exceeded the fair value of the acquired intangible asset and as a result, recorded an impairment charge of $163. The remaining value of this intangible asset of $240 is being amortized to cost of revenues over the contractual term of the acquired arrangements which expires on December 31, 2014.

Amortization expense related to intangible assets amounted to $1,883 and $1,794 for the three month periods ended March 31, 2014 and 2013, respectively. Amortization expense for developed technology, which was $351 and $139 for the three months ended March 31, 2014 and 2013, respectively, 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 3.2 years at March 31, 2014. Estimated amortization is expected to be $6,879, $6,793, $5,023, $3,405, $996 and $2,088 for the nine month period ending December 31, 2014, and years ending 2015, 2016, 2017, 2018 and thereafter, respectively.

Goodwill

In accordance with ASC 350,Intangibles - Goodwill and Other(ASC 350), the Company tests goodwill at the reporting unit level for impairment on an annual basis and between annual tests if events and circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying value. The Company’s annual impairment test date is November 30 (Impairment Test Date). During the three months ended March 31, 2014, there were no potential impairment indicators identified that required an interim impairment test of goodwill. The Company’s market capitalization as of March 31, 2014 exceeded the book value of its consolidated net assets by more than 100%. In addition, as of November 30, 2013 (last Impairment Test Date), the fair value of both the Company’s consolidated Australian reporting unit and the Company’s all other operations reporting unit exceeded each of their respective carrying values by more than 50%.

The following table shows the change of the carrying amount of goodwill from December 31, 2013 to March 31, 2014:

Balance at December 31, 2013	$	77,104
Acquisitions (Note 2)		17,249
Foreign currency translation		616
Balance at March 31, 2014	$	94,969

20

6. Net Loss Per Share

A reconciliation of basic and diluted share amounts for the three month periods ended March 31, 2014 and 2013 are as follows (in thousands):

	Three Months Ended March 31,
	2014		2013
Basic weighted average common shares outstanding		27,924		27,367
Weighted average common stock equivalents		—		—
Diluted weighted average common shares outstanding		27,924		27,367
Weighted average anti-dilutive shares related to:
Stock options		895		1,250
Nonvested restricted shares		2,138		2,189
Restricted stock units		18		81
Escrow shares		—		64

In reporting periods in which the Company reports a net loss, anti-dilutive shares consist of 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 have been anti-dilutive had the Company had net income. In those reporting periods in which the Company reports net income, anti-dilutive shares consist of those common stock equivalents that have either an exercise price above the average stock price for the period or the common stock equivalents’ related average unrecognized stock compensation expense is sufficient to “buy back” the entire amount of shares.

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, with respect to restricted stock awards that vest based on achievement of performance conditions, because performance conditions are considered contingencies under ASC 260,Earnings per Share(ASC 260) the criteria for contingent shares must first be applied before determining the dilutive effect of these types of share-based payments. Prior to the end of the contingency period (i.e., before the performance conditions have been satisfied), the number of contingently issuable common shares to be included in diluted weighted average common shares outstanding should be based on the number of common shares, if any, that would be issuable under the terms of the arrangement if the end of the reporting period were the end of the contingency period (e.g., the number of shares that would be issuable based on current performance criteria) assuming the result would be dilutive.

In connection with certain of the Company’s business combinations, the Company issued common 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. As of March 31, 2014, the Company had no shares of common stock held in escrow.

The 254,654 shares related to a component of the deferred purchase price consideration from the acquisition of M2M Communications Corporation (M2M), which are not subject to adjustment as the issuance of such shares is not subject to any contingency, are included in both the basic and diluted weighted average common shares outstanding amounts.

7. Disclosure of Fair Value of Financial Instruments

The Company’s financial instruments mainly consist of cash and cash equivalents, restricted cash, cost-method investment, accounts receivable and accounts payable. 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. Refer to Note 4 for discussion of cost-method investment.

21

8. Fair Value Measurements

The table below presents the balances of assets and liabilities measured at fair value on a recurring basis at March 31, 2014:

	Fair Value Measurement at March 31, 2014 Using
	Totals		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Unobservable Inputs (Level 3)
Assets:
Money market funds (1)	$	88,611	$	88,611	$	—	$	—
Liabilities:
Accrued contingent purchase price consideration (2)	$	399	$	—	$	—	$	399
Deferred acquisition consideration (2)	$	572	$	—	$	—	$	572

(1) Total of $88,431 included in cash and cash equivalents and $180 included in restricted cash in the accompanying unaudited condensed consolidated balance sheets and represents the only asset that the Company measures and records at fair value on a recurring basis. These money market funds represent excess operating cash that is invested daily into an overnight investment account. The decrease from December 31, 2013 was primarily due to cash used in operations and cash utilized for the Company’s acquisitions of Entelios and Activation during the three month period ended March 31, 2014.

(2) Accrued contingent purchase price consideration, which resulted from the Company’s acquisitions of Energy Response, Entelios and Activation, and deferred acquisition consideration, which is a result of the Company’s acquisition of M2M, represent the only assets or liabilities that the Company measures and records at fair value on a recurring basis using significant unobservable inputs (Level 3). The aggregate increase in fair value of liabilities for the three month period ended March 31, 2014 of $10 was due to the increase in the liabilities as a result of the amortization of the applicable discounts related to the time value of money of $6 and changes in exchange rates. There were no changes to the probability or timing of payment during the three month period ended March 31, 2014.

With respect to assets measured at fair value on a non-recurring basis, these represent impaired long-lived assets (refer to Note 1 for discussion of the determination of fair value of these assets), impaired definite-lived intangible assets (refer to Note 2 for discussion of the determination of fair value of these assets) and cost method investments (refer to Note 4 for discussion of the determination of fair value of these assets).

The table below presents the balances of assets and liabilities measured at fair value on a recurring basis at December 31, 2013:

	Fair Value Measurement at December 31, 2013 Using
	Totals		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Unobservable Inputs (Level 3)
Assets:
Money market funds (1)	$	146,626	$	146,626	$	—	$	—
Liabilities:
Deferred acquisition consideration (2)	$	566	$	—	$	—	$	566

(1) Total of $145,076 included in cash and cash equivalents and $1,550 included in restricted cash in the accompanying unaudited condensed consolidated balance sheets and represents the only assets that the Company measures and records at fair value on a recurring basis. These money market funds represent excess operating cash that is invested daily into an overnight investment account.

(2) Deferred acquisition consideration which is a liability and was the result of the Company’s acquisition of M2M represents the only liability that the Company measures and records at fair value on a recurring basis using significant unobservable inputs (Level 3). The aggregate increase in fair value of this liability for the year ended December 31, 2013 of $33 was due to the increase in the liability as a result of the amortization of the discount related to the time value of money. There were no changes with respect to the timing of payment subsequent to December 31, 2013.

22

9. Financing Arrangements

In March 2012, the Company and one of its subsidiaries entered into a $50,000 credit facility with Silicon Valley Bank (SVB), which was subsequently amended in June 2012 and April 2013 (the 2012 credit facility). On April 12, 2013, the Company, one its subsidiaries and SVB entered into an amendment to the 2012 credit facility to extend the termination date from April 15, 2013 to April 30, 2013. On April 18, 2013, the Company, one of its subsidiaries and SVB terminated the 2012 credit facility.

On April 18, 2013, the Company entered into the 2013 credit facility. The 2013 credit facility replaced the 2012 credit facility

The 2013 credit facility provides for a two year revolving line of credit in the aggregate amount of $70,000, subject to increase from time to time up to an aggregate amount of $100,000 with an additional commitment from the lenders or new commitments from new financial institutions.

Subject to continued compliance with the covenants contained in the 2013 credit facility, the full amount of the 2013 credit facility may be available for issuances of letters of credit and up to $5,000 may be available for swing line loans. The interest on revolving loans under the 2013 credit facility will accrue, at the Company’s election, at either (i) the Eurodollar Rate with respect to the relevant interest period plus 2.00% per annum or (ii) the ABR (defined as the highest of (x) the “prime rate” as quoted in theWall Street Journal, and (y) the Federal Funds Effective Rate plus 0.50%) plus 1.00% per annum. The letter of credit fee charged under the 2013 credit facility is 2.00% per annum. The Company expenses the interest and letter of credit fees under the 2013 credit facility, as applicable, in the period incurred. The obligations under the 2013 credit facility are secured by all domestic assets of the Company and several of its domestic subsidiaries. The 2013 credit facility terminates on April 18, 2015 and all amounts outstanding thereunder will become due and payable in full and the Company would be required to collateralize with cash any outstanding letters of credit under the 2013 credit facility up to 105% of the amounts outstanding. In connection with the 2013 credit facility and related amendments, the Company incurred financing costs of approximately $859 which have been deferred and are being amortized to interest expense over the term of the 2013 credit facility, or through April 18, 2015.

The 2013 credit facility contains customary terms and conditions for credit facilities of this type, including, among other things, restrictions on the ability of the Company and its subsidiaries to incur additional indebtedness, create liens, enter into transactions with affiliates, transfer assets, make certain acquisitions, pay dividends or make distributions on, or repurchase, the Company’s common stock, consolidate or merge with other entities, or undergo a change in control. In addition and as described above, the Company is required to meet certain monthly and quarterly financial covenants customary for this type of credit facility, including maintaining a minimum specified level of free cash flow, a minimum specified unrestricted cash balance and a minimum specified ratio of current assets to current liabilities.

The 2013 credit facility contains customary events of default, including 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, SVB may accelerate the Company’s obligations under the 2013 credit facility. If the Company is determined to be in default then any amounts outstanding under the 2013 credit facility would become immediately due and payable and the Company would be required to collateralize with cash any outstanding letters of credit up to 105% of the amounts outstanding.

As of March 31, 2014, the Company was in compliance with all of its covenants under the 2013 credit facility. The Company believes that it is reasonably assured that it will comply with the covenants of the 2013 credit facility for the foreseeable future.

As of March 31, 2014, the Company had no borrowings, but had outstanding letters of credit totaling $46,213, under the 2013 credit facility. The decrease in the amount of outstanding letters of credit from December 31, 2013 to March 31, 2014 is primarily the result of fewer outstanding letters of credit as collateral for demand response arrangements and obligations. As of March 31, 2014, the Company had $23,787 available under the 2013 credit facility for future borrowings or issuances of additional letters of credit.

In May 2014, the Company was required to provide incremental financial assurance in connection with its capacity bid in a certain open market bidding program. The Company has provided this financial assurance utilizing a $22,000 letter of credit issued under the 2013 credit facility and additionally, utilized $4,500 of its available unrestricted cash on hand. 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 letter of credit and cash during the three month period ending June 30, 2014.

23

10. Commitments and Contingencies

In July 2012, the Company entered into a lease for its new principal executive offices at One Marina Park Drive, Floors 4-6, Boston, Massachusetts. The lease term is through July 2020 and the lease contains both a rent holiday period and escalating rental payments over the lease term. The lease requires payments for additional expenses such as taxes, maintenance, and utilities and contains a fair value renewal option. The Company began occupying the space during the second quarter of fiscal 2013. In accordance with the terms of the lease, the landlord provided certain lease incentives with respect to the leasehold improvements. In accordance with ASC 840, Leases(ASC 840), the Company recorded the incentives as deferred rent and will reflect these amounts as reductions of lease expense over the lease term. Although lease payments under this arrangement did not commence until August 2013, as the Company had the right to use and controlled physical access to the space, it determined that the lease term commenced in July 2012 and, as a result, began recording rent expense on this lease arrangement at that time on a straight-line basis. The lease also contains certain provisions requiring the Company to restore certain aspects of the leased space to its initial condition. The Company has determined that these provisions represent asset retirement obligations and recorded the estimated fair value of these obligations as the related leasehold improvements were incurred. The Company will accrete the liability to fair value over the life of the lease as a component of operating expenses. As of March 31, 2014, the Company recorded an asset retirement obligation of $410.

In March 2014, the Company entered into a lease for its California operations. The lease term runs through September 2019 and the lease contains both a rent holiday period and escalating rental payments over the lease term. The lease requires payments for additional expenses such as taxes, maintenance, and utilities and contains a fair value renewal option. The lease commences on April 1, 2014.

As of March 31, 2014, future minimum lease payments for operating leases with non-cancelable terms of more than one year were as follows:

	Operating Leases
Remainder of 2014	$	4,205
2015		5,622
2016		5,445
2017		5,437
2018		5,569
Thereafter		7,517
Total minimum lease payments (not reduced by sublease rentals of $191)	$	33,795

As of March 31, 2014 and December 31, 2013, the Company had a deferred rent liability representing rent expense recorded on a straight-line basis in excess of contractual lease payments of $6,343 and $6,729, respectively, which is included in other liabilities in the accompanying unaudited condensed consolidated balance sheets.

As of March 31, 2014, the Company was contingently liable under outstanding letters of credit for $46,213. As of March 31, 2014 and December 31, 2013, the Company had restricted cash balances of $1,197 and $1,834, respectively. The restricted cash balances as of March 31, 2014 and December 31, 2013 primarily relate to cash utilized to collateralize certain demand response programs.

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, which may be secured by cash or letters of credit. Performance guarantees as of March 31, 2014 were $46,512 and included deposits held by certain customers of $119 and certain restricted cash utilized to collateralize certain demand response programs of $180 at March 31, 2014. 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 deposits 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, 2014, the Company had

24

$2,593 in deferred fees for these arrangements which were included in deferred revenues as of March 31, 2014. As of March 31, 2014, the maximum termination penalty to which the Company could be subject under these arrangements, which the Company has deemed not probable of being incurred, was approximately $7,967.

As of March 31, 2014 and December 31, 2013, the Company accrued in the accompanying unaudited condensed consolidated balance sheets $539 and $1,720, respectively, of performance adjustments related to fees received for its participation in a certain demand response program. The decrease in the accrual from December 31, 2013 was a result of the Company repaying $1,370 to the electric power grid operator during the three month period ended March 31, 2014 since the Company did not deliver all of its MW obligations under this demand response program offset by an increase in additional performance adjustments.

The Company believes that it is probable that these performance adjustments will need to be re-paid to the electric power grid operator and since the electric power grid operator has the right to require repayment at any point at its discretion, the amounts have been classified as a current liability.

In 2012, the Company decided to net settle a portion of its future contractual delivery obligations in a certain open market bidding program. As of March 31, 2014, the Company entered into transactions to net settle a significant portion of its future delivery obligations and these transactions have been approved by the customer. As a result, as long as the other criteria for revenue recognition are met, the Company will recognize these fees from the net settlement transactions as revenues as they become due and payable with such fees being recorded as a component of DemandSMART revenues. During the three month period ended March 31, 2014, the Company recognized revenues of $3,771 related to these net settlement transactions.

The Company typically grants customers a limited warranty that guarantees that its hardware will substantially conform to current specifications for one year from the delivery date. Based on the Company’s operating history, the liability associated with product warranties has been determined to be nominal.

In connection with the Company’s agreement for its employee health insurance plan, the Company could be subject to an additional payment if the agreement is terminated. The Company has not elected to terminate this agreement nor does the Company believe that termination is probable for the foreseeable future. As a result, the Company has determined that it is not probable that a loss is likely to occur and no amounts have been accrued related to this potential payment upon termination. As of March 31, 2014, the payment due upon termination would be $1,026.

11. Stockholders’ Equity

Share Repurchase Program

On August 6, 2013, the Company’s Board of Directors authorized the repurchase of up to $30,000 of the Company’s common stock during the period from August 6, 2013 through August 6, 2014, unless earlier terminated by the Board of Directors. During the three month period ended March 31, 2014, there were no repurchases of the Company’s common stock pursuant to its publicly announced share repurchase program, and as of March 31, 2014, $20,545 was available for repurchase under the Plan. The Company repurchased 169,176 shares of its common stock during the three month period ended March 31, 2014 to cover employee minimum statutory income tax withholding obligations in connection with the vesting of restricted stock under its equity incentive plans, which the Company pays in cash to the appropriate taxing authorities on behalf of its employees. All shares were retired upon repurchase.

Stock-Based Compensation

During the three month periods ended March 31, 2014 and 2013, the Company issued 6,632 shares and 8,920 shares of its common stock, respectively, to certain executives to satisfy a portion of the Company’s bonus obligation to these individuals. Historically, the Company’s Amended and Restated 2007 Employee, Director and Consultant Stock Plan (the 2007 Plan) contained an “evergreen” provision, which provided 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. The last annual increase to the 2007 Plan of 520,000 shares occurred during the three month period ended March 31, 2013. On May 28, 2013, the Company’s shareholders approved an amendment and restatement of the 2007 Plan to, among other things, increase the number of shares of common stock authorized for issuance under the 2007 Plan by 2,500,000 shares and eliminate the evergreen provision. As of March 31, 2014, 2,329,080 shares were available for future grant under the 2007 Plan, as amended and restated.

25

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

	Three Months Ended March 31,
	2014			2013
Risk-free interest rate		2.67	%		1.90	%
Vesting term, in years		2.22			2.22
Expected annual volatility		72	%		75	%
Expected dividend yield		—	%		—	%
Exit rate pre-vesting		7.8	%		7.7	%
Exit rate post-vesting		14.06	%		14.06	%

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. Volatility measures the amount that a stock price has fluctuated or is expected to fluctuate during a period. The Company calculates volatility using a component of implied volatility and historical volatility to determine the value of share-based payments. 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 2013 credit facility preclude the Company from paying dividends. During the three month period ended March 31, 2014, the Company updated its estimated pre-vesting and post-vesting exit rates 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 noting no change in the exit-rate post vesting and no material changes in the expected annual volatility or exit rate pre-vesting. The changes in estimates of the volatility and exit rate pre-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 month period ended March 31, 2014.

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

	Three Months Ended March 31,
	2014			2013
Stock options	$	186		$	399
Restricted stock and restricted stock units		4,041	(1)		4,305
Total	$	4,227		$	4,704

(1) Due to the fact that the Company’s chief executive officer is required to receive his 2014 performance based bonus, if achieved, in shares of common stock of the Company determined based on the cash value of such bonus divided by the fair market value of the Company’s common stock on the date that the Company’s Compensation Committee validates the achievement of the performance bonus metrics, in accordance with the Company’s policy, the Company is recording this amount as stock-based compensation expense ratably over the applicable performance and service period in accordance with ASC 718, Stock Compensation (ASC 718). During the three month period ended March 31, 2014, the Company recorded $125 of stock-based compensation expense.

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

	Three Months Ended March 31,
	2014		2013
Selling and marketing expenses	$	1,193	$	1,390
General and administrative expenses		2,696		2,952
Research and development expenses		338		362
Total	$	4,227	$	4,704

The Company recognized no material income tax benefit from share-based compensation arrangements during the three month periods ended March 31, 2014 and 2013, respectively. No material compensation cost was capitalized during the three month periods ended March 31, 2014 and 2013.

26

The following is a summary of the Company’s stock option activity during the three month period ended March 31, 2014:

	Three Months Ended March 31, 2014
	Number of Shares Underlying Options			Exercise Price Per Share	Weighted- Average Exercise Price Per Share		Aggregate Intrinsic Value
Outstanding at December 31, 2013		960,742		$0.17 - $48.06	$	17.87	$	4,691	(2)
Granted		1,809				21.09
Exercised		(51,237	)			10.26	$	592	(3)
Cancelled		(74,309	)			29.47
Outstanding at March 31, 2014		837,005		$0.35 - $48.06		17.32	$	6,817	(4)
Weighted average remaining contractual life in years: 3.1
Exercisable at end of period		814,852		$0.35 - $48.06	$	17.28	$	6,695	(4)
Weighted average remaining contractual life in years: 3.0
Vested or expected to vest at March 31, 2014 (1)		835,658		$0.35 - $48.06	$	17.32	$	6,807	(4)

(1) This represents the number of vested options as of March 31, 2014 plus the number of unvested options expected to vest as of March 31, 2014 based on the unvested options outstanding at March 31, 2014, adjusted for the estimated forfeiture rate of 7.8%.

(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, 2013 of $17.21 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, 2014 of $22.28 and the exercise price of the underlying options.

Additional Information About Stock Options

	Three Months Ended March 31,
	2014		2013
Total number of options granted during the period		1,809		1,000
Weighted-average fair value per share of options granted	$	11.69	$	10.08
Total intrinsic value of options exercised (1)	$	592	$	553

(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, 2014, 828,512 options were held by employees and directors of the Company and 8,493 options were held by non-employees. For outstanding unvested stock options related to employees and directors of the Company as of March 31, 2014, the Company had $195 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 1.3 years. There were no unvested non-employee stock options as of March 31, 2014.

Restricted Stock and Restricted Stock Units

For non-vested restricted stock and restricted stock units subject to service-based vesting conditions outstanding as of March 31, 2014, the Company had $15,266 of unrecognized stock-based compensation expense, which is expected to be recognized over a

27

weighted average period of 2.8 years. For non-vested restricted stock subject to performance-based vesting conditions outstanding that were probable of vesting as of March 31, 2014, the Company had $10,773 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 2.0 years. There were no non-vested restricted stock awards outstanding subject to performance-based vesting conditions that were not probable of vesting as of March 31, 2014.

Restricted Stock

The following table summarizes the Company’s restricted stock activity during the three month period ended March 31, 2014:

	Number of Shares			Weighted Average Grant Date Fair Value Per Share
Nonvested at December 31, 2013		2,395,322		$	13.48
Granted		491,899			20.94
Vested		(694,401	)		13.64
Cancelled		(86,385	)		10.01
Nonvested at March 31, 2014		2,106,435		$	15.84

28

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 25% cliff vesting after one year and the remaining 75% vesting ratably quarterly thereafter, with certain exceptions. Included in the above table are 4,500 shares of restricted stock granted to certain non-executive employees and 31,365 shares of restricted stock granted to members of the Company’s board of directors during the three month period ended March 31, 2014 that immediately vested. Also included in the table above are shares of restricted stock granted to non-employee advisory board members. In fiscal 2013, the Company granted 33,000 shares of restricted stock to non-employee advisory board members. Of the 33,000 shares of restricted stock granted, 22,000 shares vest ratably on a quarterly basis over four years and 11,000 shares of restricted stock vest in equal annual tranches on July 1, 2014 and July 1, 2015, as long as the individuals continue to serve as advisory board members through the date of the applicable vesting. The Company will account for these share-based awards in accordance with ASC 505-50, Equity Based Payments to Non-Employees(ASC 505-50), which will result in the Company continuing to re-measure the fair value of the share-based awards until such time as the awards vest. During the three month period ended March 31, 2014, the Company recorded stock-based compensation expense related to these awards of $88. As of March 31, 2014, 28,875 shares were unvested and had a fair value of $643.

The fair value of restricted stock upon which vesting is solely service-based is expensed ratably over the vesting period. With respect to restricted stock where vesting contains certain performance-based vesting conditions, the fair value is expensed based on the accelerated attribution method as prescribed by ASC 718, over the vesting period. With the exception of certain executives whose employment agreements provide for continued vesting in certain circumstances upon departure, 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. During the three month period ended March 31, 2014, the Company granted 388,034 shares of nonvested restricted stock to certain executives that contain performance-based vesting conditions. Of these shares, 25% vest in 2015 if the performance criteria related to certain 2014 operating results are achieved and the executive is still employed as of the vesting date and the remaining 75% of the shares vest quarterly over a three year period thereafter as long as the executive is still employed as of the vesting date. If the performance criteria related to certain 2014 operating results are not achieved, 100% of the shares are forfeited.

During the three month period ended March 31, 2014, there were no changes to probabilities of vesting of performance-based stock awards which had a material impact on stock-based compensation expense or amounts expected to be recognized.

Additional Information About Restricted Stock

	Three Months Ended March 31,
	2014		2013
	In thousands, except share and per
	share amounts
Total number of shares of restricted stock granted during the period		491,899		981,841
Weighted average fair value per share of restricted stock granted	$	20.94	$	16.71
Total number of shares of restricted stock vested during the period		694,401		577,293
Total fair value of shares of restricted stock vested during the period	$	15,103	$	5,706

Restricted Stock Units

The following table summarizes the Company’s restricted stock unit activity during the three month period ended March 31, 2014:

	Number of Shares			Weighted Average Grant Date Fair Value Per Share
Nonvested at December 31, 2013		34,250		$	28.59
Granted		—			—
Vested		(34,250	)		28.59
Cancelled		—			—
Nonvested at March 31, 2014		—		$	—

29

Additional Information About Restricted Stock Units

	Three Months Ended March 31,
	2014		2013
	In thousands, except share amounts
Total number of shares of restricted stock units vested during the period		34,250		53,478
Total fair value of shares of restricted stock units vested during the period	$	772	$	911

12. Income Taxes

The Company accounts for income taxes in accordance with the liability method of ASC 740, Income Taxes(ASC 740). Deferred tax assets and liabilities are recognized based on the differences between the financial reporting and income tax bases of assets and liabilities using statutory rates. A valuation allowance must be provided against 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. During the three month period ended March 31, 2014, there were no material changes in the Company’s uncertain tax positions.

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 effective tax rate for the full fiscal year and use that rate to provide for income taxes on a current year-to-date basis. However, if an enterprise is unable to make a reliable estimate of its annual effective tax rate, the actual effective tax rate for the year-to-date period may be the best estimate of the annual effective tax rate. The Company is able to reliably estimate the annual effective tax rate on its foreign earnings, but is unable to reliably estimate the annual effective tax rate on U.S. earnings due to the potential volatility related to forecasted U.S. earnings and the fact that the majority of the U.S. tax provision is fixed due to the deferred tax expense related to tax deductible goodwill. As a result, the Company has provided a $425 worldwide tax benefit for the three month period ended March 31, 2014. The provision is comprised of a tax benefit on its foreign loss for the three month period ended where the Company expects to realize such benefit during fiscal 2014 plus a U.S. tax expense related to tax deductible goodwill that generates a deferred tax liability that cannot be used as a source of income against which deferred tax assets may be realized.

If the Company is able to make a reliable estimate of its worldwide annual effective tax rate as of June 30, 2014, 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 month period ending June 30, 2014 since the majority of the year-to-date loss will be related to the U.S. If the Company continues to be unable to make a reliable estimate of its annual effective tax rate as of June 30, 2014, the Company expects to follow a consistent methodology as was applied for the three month period ended March 31, 2014 and record a provision for income taxes in the U.S. for the three month period ending June 30, 2014 consistent with the three month period ending March 31, 2014 resulting in an overall income tax benefit for the three month period ending June 30, 2014 consistent with the three month period ended March 31, 2014, excluding the discrete tax provision that would be recorded upon the completion of a sale of the Company’s service line as further discussed in Note 14.

The Company reviews all available evidence to evaluate the recovery of deferred tax assets, including the recent history of losses in all tax jurisdictions, as well as its ability to generate income in future periods. As of March 31, 2014, due to the uncertainty related to the ultimate use of the Company’s deferred income tax assets, the Company has provided a valuation allowance on all of its U.S., Germany, Japan, and U.K deferred tax assets and a partial valuation on its Australia deferred tax assets.

30

13. Concentrations of Credit Risk

The following table presents the Company’s significant customers. PJM Interconnection (PJM), ISO-New England, Inc. (ISO-NE) and Tennessee Valley Authority (TVA) are regional electric power grid operator customers in the mid-Atlantic, New England and Southeast regions, respectively, that are comprised of multiple utilities and were formed to control the operation of the regional power system, coordinate the supply of electricity, and establish fair and efficient markets. No other customers comprised more than 10% of consolidated revenues during the three month periods ended March 31, 2014 and 2013.

	Three Months Ended March 31,
	2014						2013
	Revenues			% of Total Revenues			Revenues			% of Total Revenues
PJM		18,218			35	%			*			*%
ISO-NE			*			*%		4,761			14	%
TVA			*			*%		3,416			10	%

* Represented less than 10% of consolidated revenues.

PJM was the only customer that comprised 10% or more of the Company’s accounts receivable balance at March 31, 2014, representing 51% of the balance. PJM and Southern California Edison Company were the only customers that each comprised 10% or more of the Company’s accounts receivable balance at December 31, 2013, representing 39% and 18%, respectively, of such balance.

Unbilled revenue related to PJM was $26,465 and $64,643 at March 31, 2014 and December 31, 2013, respectively. There was no significant unbilled revenue for any other customers at March 31, 2014 and December 31, 2013.

Deposits and restricted cash include 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 $119 and $128 at March 31, 2014 and December 31, 2013, respectively.

14. 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.

On May 3, 2013, a purported shareholder of the Company (the Plaintiff) filed a derivative and class action complaint in the United States District Court for the District of Delaware (the Court) against certain officers and directors of the Company as well as the Company as a nominal defendant (the Defendants). The complaint asserts derivative claims, purportedly brought on behalf of the Company, for breach of fiduciary duty, waste of corporate assets, and unjust enrichment in connection with certain equity grants (awarded in 2010, 2012, and 2013) that allegedly exceeded an annual limit on per-employee equity grants purported to be contained in the 2007 Plan. The complaint also asserts a direct claim, brought on behalf of the plaintiff and a proposed class of the Company’s shareholders, alleging the Company’s proxy statement filed on April 26, 2013 was false and misleading because it failed to disclose that the equity grants were improper. The plaintiff seeks, among other relief, rescission of the equity grants, unspecified damages, injunctive relief, disgorgement, attorneys’ fees, and such other relief as the Court may deem proper.

Defendants filed a motion to dismiss on August 30, 2013. Plaintiff responded to the motion on October 18, 2013 and Defendants replied on November 22, 2013. No hearing date has been set.

The Company continues to believe that the Company and the other defendants have substantial legal and factual defenses to the claims and allegations contained in the complaint, and continues to pursue these defenses vigorously. The Company continues to believe that it is neither remote nor probable that the Company will incur a loss related to this matter. There can be no assurance, however, that the Company’s defense of this matter will be successful. The Company carries insurance for these types of claims and currently believes that a resolution to this claim, in excess of the deductible, would be covered by its insurance. Therefore, the Company does not currently believe that it is reasonably possible that the potential magnitude of the range of any loss would be material to the Company’s consolidated financial conditions, results of operations or cash flows. However, there is no guarantee that

31

this claim will be covered by the Company’s insurer. A denial of the claim by the insurance provider or a judgment significantly in excess of the Company’s insurance coverage could materially and adversely affect its consolidated financial condition, results of operations and cash flows. In addition, regardless of the outcome of this matter, the matter may divert financial and management resources and result in general business disruption, including that the Company may suffer from adverse publicity that could harm its reputation and negatively impact its stock price.

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.

15. Assets and Liabilities Held for Sale

During the three month period ended December 31, 2013, the Company committed to a plan to sell a component of the business that the Company acquired in connection with its acquisition of Global Energy Partners, Inc. (Global Energy) in January 2011 related to consulting and engineering support services to the global electric utility industry, with a particular focus on providing consulting services to utilities (Utility Solutions Consulting). The Company engaged a third party consultant to assist the Company in actively marketing this service line for sale and identify a buyer. Based on the Company’s evaluation of the assets held for sale criteria under ASC 360-10,Impairment and Disposal of Long-Lived Assets, it concluded all of the criteria were met and that the assets and liabilities of Utility Solutions Consulting that are expected to be sold should be classified as held for sale. The assets held for sale relate to separately identifiable intangible assets, including customer relationships and certain non-compete agreements that were acquired in connection with the Global Energy acquisition and specifically relate to Utility Solutions Consulting. Due to the fact that the Company has concluded that Utility Solutions Consulting meets the definition of a business in accordance with ASC 805, also included in assets held for sale is the goodwill of the Company’s All Other reporting unit which has been allocated to Utility Solutions Consulting, which is a component of this reporting unit. The amount of goodwill allocated to Utility Solutions Consulting was based on the relative fair values of this business and the portion of the reporting unit that will be retained. The liabilities held for sale relate to the portion of the Company’s deferred tax liability related to the goodwill that has been allocated to Utility Solutions Consulting. The following table summarizes the assets and liabilities held for sale as of March 31, 2014:

	March 31, 2014
Customer relationship intangible assets, net	$	153
Other definite-lived intangible assets, net		39
Goodwill		489
Total Assets Held for Sale		681
Deferred tax liability		521
Total Liabilities Held for Sale	$	521

The Company has concluded that the Utility Solutions Consulting disposal group meets the criteria of discontinued operations under ASC 205-20,Discontinued Operations (ASC 205-20). However, the Company has determined that the operations of Utility Solutions Consulting are neither quantitatively or qualitatively material to the Company’s consolidated operations for the three month periods ended March 31, 2014 or 2013, respectively, and therefore, the results of operations of Utility Solutions Consulting have not been presented as discontinued operations in the Company’s accompanying consolidated statements of operations for the three month periods ended March 31, 2014 and 2013.

32

On April 16, 2014, the Company entered into an agreement with a third party to sell the Utility Solutions Consulting services line for up to $4,750 subject to satisfaction of certain conditions and representations. The Company anticipates this transaction will close during the three month period ending June 30, 2014 and result in a potential gain upon sale of up to $2,275, net of tax effects and other costs and expenses related to the sale. Up to $500 of this potential gain may be either reduced or deferred depending on the timing of the Company’s fulfillment of certain obligations under the agreement.

16. Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (FASB) issued ASU No. 2014-08,Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (ASU 2014-08). ASU 2014-08 amends the definition of discontinued operations under ASC 205-20 to only those disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity’s operations and financial results will be reported as discontinued operations in the financial statements. This guidance is effective for all disposals (or classifications as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance. The Company has early adopted this guidance as of January 1, 2014. The adoption of this guidance had no impact on the Company’s consolidated financial statements.

33

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, 2013, as filed with the Securities and Exchange Commission, or the SEC, on March 7, 2014, or our 2013 Form 10-K. 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 2013 Form 10-K. 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 energy intelligence software, or EIS, and related solutions. We unlock the full value of energy management for commercial, institutional and industrial end-users of energy, which we refer to as our C&I or enterprise customers, and our electric power grid operator and utility customers by delivering a comprehensive suite of demand-side management solutions. These solutions allow our customers to make better and more strategic decisions about how and when they use electricity.

We believe that we are the world’s leading provider of demand response applications and solutions. Demand response is an alternative to traditional electric 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 provide our utility and grid operator customers with two demand response solutions: EnerNOC Demand Resource and EnerNOC Demand Manager, which we collectively refer to as EnerNOC DemandSMART.

When we enter into an EnerNOC Demand Resource contract, we match obligation, in the form of megawatts, or MW, that we agree to deliver to our utility and electric power grid operator customers, with supply, in the form of MW that we are able to curtail from the electric power grid through our arrangements with C&I customers. We deploy a sales team to contract with our C&I customers and install our advanced metering equipment at these customers’ sites to connect them to our network, resulting in an increased ability to curtail demand from the electric power grid. When we are called upon by our utility or electric power grid operator customers to deliver our contracted capacity, we use our Network Operations Center, or NOC, to remotely manage and reduce electricity consumption across our 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. We receive recurring payments from electric power grid operators and utilities for providing our EnerNOC Demand Resource solution and we share these recurring payments with our C&I customers in exchange for those C&I customers reducing their power consumption when called upon by us to do so. We occasionally reallocate and realign our capacity supply and obligation through open market bidding programs, supplemental demand response programs, auctions or other similar capacity arrangements and bilateral contracts to account for changes in supply and demand forecasts, as well as changes in programs and market rules in order to achieve more favorable pricing opportunities. We refer to the above activities as managing our portfolio of demand response capacity.

EnerNOC’s Demand Manager solution consists of long-term contracts with a utility customer for a Software-as-a-Service solution that allows utilities to manage demand response capacity in utility-sponsored demand response programs. Our EnerNOC Demand Manager solution provides our utility customers with real-time load monitoring, dispatching applications, customizable reports, measurement and verification, and other professional services.

34

We build on our position as a leading demand response provider by using our NOC and EIS platform to deliver a portfolio of additional energy intelligence software and solutions to new and existing C&I, electric power grid operator and utility customers. These additional EIS and solutions include our EfficiencySMART and SupplySMART applications and solutions, and certain wireless energy management products. EfficiencySMART is our data-driven energy efficiency suite that includes energy efficiency planning, audits, assessments, commissioning and retro-commissioning authority services, and a cloud-based energy analytics application used for managing energy across a C&I customer’s portfolio of sites. The cloud-based energy analytics application also includes the ability to integrate with a C&I customer’s existing energy management system, provide utility bill management and tools for measurement, tracking, analysis, reporting and management of greenhouse gas emissions. SupplySMART is our energy price and risk management application and solution 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. Our wireless energy management products are designed to ensure that our C&I customers can connect their equipment remotely and access meter data securely, and include both cellular modems and an agricultural specific wireless technology solution.

Significant Recent Developments

On April 14, 2014, we announced that Neil Moses, our Chief Financial Officer and Treasurer, was appointed as our Chief Operating Officer. Mr. Moses will continue to serve in the capacity of Chief Financial Officer, Treasurer, principal financial officer and principal accounting officer.

Use of Non-Financial Business and Operational Data

We utilize certain non-financial business and operational data to provide additional insight into factors and opportunities relevant to our business. This non-financial business and operational data is not utilized to either manage the business or make resource allocation decisions, and therefore does not necessarily have any direct correlation to our financial performance. However, the non-financial business and operational data may provide observations as to the scope of our operations and therefore, we believe the utilization of such data can provide insights into certain aspects of our business, such as market share and penetration and customer composition and depth. Commencing with this Quarterly Report on Form 10-Q, we began to disclose two additional non-financial business and operating statistics entitled “Utility Customers” and “Grid Operator Customers”. Neither of these two statistics is utilized to manage the business or make resource allocation decisions, and therefore do not necessarily have any direct correlation to our financial performance. They may however provide observations as to the scope of our operations growth of our demand response business and overall market penetration.

The following table outlines certain non-financial business and operational data utilized as of March 31, 2014 and December 31, 2013 (amounts rounded to nearest hundred):

	December 31, 2013		March 31, 2014
Utility Customers(1)		36		43
Grid Operator Customers(2)		8		13
C&I Customers Participating in Demand Response (3)		5,800		5,800
C&I Sites Participating in Demand Response(3)		13,900		14,300
C&I Customers with Enterprise Revenue(4)		600		800
C&I Sites with Enterprise Revenue(4)		2,800		3,000

(1) The term “Utility Customers” describes the number of our electric utility customers that have a contract with us for demand response or energy services. We enter into contractual commitments with certain of these utility customers through bilateral contractual arrangements for the express purpose of reducing load on their grid when called upon, or

35

dispatched, to do so. For certain of these utility customers we provide energy efficiency and consulting services. This measure does not have any direct correlation to our financial performance but may provide observations as to the progress of our sales and marketing efforts aimed at utility customers and our ability to recruit and maintain such customers with a need to curtail demand for electricity.

(2) The term “Grid Operator Customers” describes the number of our grid operator customers that have a contract with us and actively rely on our demand response programs to manage load on their grid. We enter into contractual commitments with these grid operator customers through participation in open market auctions, as well as, bilateral contractual arrangements for the express purpose of optimizing load on their grid when called upon, or dispatched, to do so. This measure does not have any direct correlation to our financial performance but may provide observations as to the progress of our sales and marketing efforts aimed at grid operator customers and our ability to recruit and maintain such customers with a need to curtail demand for electricity.

(3) The term “C&I Customers Participating in Demand Response” describes the number of our commercial, industrial and institutional customers under contract to actively participate in our demand response programs. By extension, the term “C&I Sites Participating in Demand Response” describes the number of sites across our commercial, industrial and institutional customer base under contract to actively participate in our demand response programs. Certain of these customers and sites may additionally use our energy intelligence software and solutions to gain control of how and when they consume electricity. These two measures do not have any direct correlation to our financial performance but may provide observations as to the progress of our sales and marketing efforts and our ability to recruit and maintain customers with curtailable demand for electricity.

(4) The term “C&I Customers with Enterprise Revenue” describes the number of our enterprise customers that separately purchase our energy intelligence software and solutions to gain control of how and when they consume electricity. By extension, the term “C&I Sites with Enterprise Revenue” describes the number of sites across our enterprise customer base that separately purchase our EIS and solutions. These two measures do not have any direct correlation to our financial performance but may provide observations as the progress of our sales and marketing efforts and our ability to recruit and maintain enterprise customers. Both C&I Customers with Enterprise Revenue and C&I Sites with Enterprise Revenue include SupplySMART contract data.

The number of utility customers that have contracts with us and actively rely on our demand response solutions to reduce the load on their grid at March 31, 2014 was 43 compared to 36 at December 31, 2013. The number of utility customers that have contracts with us and actively rely on our demand response solutions to reduce the load on their grid is one measure of the relative success that our utility selling team has in signing up new utility customers for whom we agree to reduce load when called upon to do so. We generally receive recurring cash payments from each utility customer in exchange for the capacity we commit to reduce for them. In addition, we receive additional cash payments in the form of energy payments from utility customers when we are actually called upon to reduce load and subsequently deliver on that commitment. The increase in the number of utility customers that have contracts with us and actively rely on our demand response solutions to reduce the load on their grid at March 31, 2014 as compared to December 31, 2013 primarily reflects the addition of new customers from our recent acquisitions of Entelios AG, or Entelios, and Activation Energy DSU Ltd, or Activation. In general, we expect that the number of utility customers that have contracts with us and actively rely on our demand response solutions to reduce the load on their grid will increase over time.

The number of grid operator customers that have contracts with us and actively rely on our demand response solutions to reduce the load on their grid at March 31, 2014 was 13 compared to eight at December 31, 2013. The number of grid operator customers that have contracts with us and actively rely on our demand response solutions to reduce the load on their grid is one measure of the relative success that our grid operator selling team has in signing up new grid operator customers for whom we agree to reduce load when called upon to do so. We generally receive recurring cash payments from each grid operator customer in exchange for the capacity we commit to reduce for them. In addition, we receive additional cash payments in the form of energy payments from grid operator customers when we are actually called upon to reduce load and subsequently deliver on that commitment. The increase in the number of grid operator customers that have contracts with us and actively rely on our demand response solutions to reduce the load on their grid at March 31, 2014 as compared to December 31, 2013 primarily reflects the addition of new customers from our recent acquisitions of Entelios and Activation. In general, we expect that the number of grid operator customers that have contracts with us and actively rely on our demand response solutions to reduce the load on their grid will increase over time.

The number of C&I customers participating in demand response was approximately 5,800 at March 31, 2014 and December 31, 2013. The number of C&I customers participating in demand response is one measure of the relative success that our C&I selling team has in signing up new customers to whom we deliver recurring cash payments in exchange for the capacity they commit to make available in support of the commitments that we enter into with electric power grid operators and utilities. The number of C&I

36

customer sites participating in demand response at March 31, 2014 was approximately 14,300 as compared to approximately 13,900 at December 31, 2013. In general, we expect that the number of C&I customers participating in demand response to increase or decrease in tandem with the number of C&I sites participating in demand response. Exceptions to this expected trend may occur if we are successful in further penetrating existing C&I customers so as to add additional sites without adding additional customers. The number of C&I customers participating in demand response programs and the number of C&I customer sites participating in demand response programs are not necessarily correlated and may increase or decrease in future periods if we choose to participate in additional or different markets in the future.

The number of C&I Customers with Enterprise Revenue that have deployed our EIS and solutions at March 31, 2014 was approximately 800 compared to approximately 600 at December 31, 2013. This increase of approximately 200 reflects our increased efforts to develop our enterprise selling team, the relative success that our enterprise selling team has had in penetrating the market for EIS and solutions, and the growing need for our solutions with enterprise customers who are increasingly turning to energy intelligence software and solutions to make strategic decisions about the how and when they use electricity. The number of C&I Sites with Enterprise Revenue that are under the management of our enterprise energy intelligence software and solutions at March 31, 2014 was approximately 3,000 compared to approximately 2,800 at December 31, 2013. The number of C&I Sites with Enterprise Revenue that are under the management of our enterprise energy intelligence software and solutions has increased in tandem with the increase in C&I Customers with Enterprise Revenue. We expect that the number of C&I Customers with Enterprise Revenue and C&I Sites with Enterprise Revenue that use or are managed by our EIS and solutions will continue to increase in the future as the market for these solutions continues to grow.

We continually evaluate the non-financial business and operational data that we review and the relevance of this data as our business continues to evolve and such data and information may change over time.

Revenues and Expense Components

Revenues

We derive recurring revenues from the sale of our EIS and related solutions. 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 customers include grid operators, utilities and enterprises.

Our grid operator revenues and utility revenues primarily reflect the sale of our demand response solutions. The revenues primarily consist of capacity and energy payments, including ancillary services payments, as well as payments derived from the effective management of our portfolio, including our participation in capacity auctions and bilateral contracts and ongoing fixed fees for the overall management of utility-sponsored demand response programs. We derive revenues from our EnerNOC Demand Resource solution by making demand response capacity 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 ten years in duration, to deploy our EnerNOC Demand Resource solution. 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 when 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 energy event revenues.

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 related to our EnerNOC Demand Resource solution, 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

37

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 related to our EnerNOC Demand Resource solution 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 generally begin earning revenues from our MW within approximately one to three months 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. Certain other markets in which we currently participate, such as the Western Australia market, or may 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.

In the PJM open market program in which we participate, the program year operates on a June to May basis and performance is measured based on the aggregate performance during the months of June through September. As a result, fees received for the month of June could potentially be subject to adjustment or refund based on performance during the months of July through September. Based on changes to certain PJM program rules during the year ended December 31, 2012, we concluded that we no longer had the ability to reliably estimate the amount of fees potentially subject to adjustment or refund until the performance period ends on September 30^th of each year. Therefore, commencing in fiscal 2012, all demand response capacity revenues related to our participation in the PJM open market program are being recognized at the end of the performance period, or during the three month period ended September 30^thof each year. As a result of the fact that the period during which we are required to perform (June through September) is shorter than the period over which we receive payments under the program (June through May), a portion of the revenues that have been earned will be recorded and accrued as unbilled revenue.

Our revenues have historically been higher in the second and third quarters of our fiscal year due to seasonality related to the demand response market. We expect, based on the fact that we recognize demand response capacity revenue related to our participation in the PJM open market program and the Western Australia, or WA, demand response program governed by the Independent Market Organization, or IMO, which we refer to as the WA demand response program, during the three month period ended September 30^thof each year, that our revenues will typically be higher in the third quarter as compared to any other quarter in our fiscal year. However, the introduction in the PJM market of the summer-only, extended-summer and annual demand response products beginning in the 2014/2015 delivery year could adversely impact our ability to successfully manage our portfolio of demand response capacity in that program and could negatively impact our results of operations and financial condition.

Fees received from the reallocation or realignment of our capacity supply and obligation through auctions or other similar capacity arrangements and bilateral contracts are recognized as revenues as they become due and payable and are recorded as a component of DemandSMART revenues.

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 of $26.5 million from PJM at March 31, 2014, will be billed and collected during the second quarter of 2014.

Revenues generated from PJM accounted for approximately 35% of our total revenues for the three month period ended March 31, 2014. Revenues generated from open market sales to ISO New England, Inc., or ISO-NE, accounted for approximately 14% of our total revenues for the three month period ended March 31, 2013, and revenues generated from our utility contract with Tennessee Valley Authority, or TVA, accounted for approximately 10% of our total revenues for the three month period ended March 31, 2013. Other than PJM, ISO-NE and TVA, no individual electric power grid operator or utility customer accounted for more than 10% of our total revenues for the three month periods ended March 31, 2014 and 2013. If we choose to participate in additional or different markets in the future, the contribution of our current electric power grid operator and utility customers to total revenues will change.

With respect to EnerNOC Demand Manager, we generally receive an ongoing fee for overall management of the utility demand response program based on enrolled capacity or enrolled C&I customers, which is not subject to adjustment based on performance during a demand response dispatch. We recognize revenues from these fees ratably over the applicable service delivery period commencing upon when the C&I customers have been enrolled and the contracted services have been delivered. In addition, under this offering, we may receive additional fees for program start-up, as well as, for C&I customer installations. We have determined that

38

these fees do not have stand-alone value due to the fact that such services do not have value without the ongoing services related to the overall management of the utility demand response program and therefore, we recognize these fees over the estimated customer relationship period, which is generally the greater of three years or the contract period, commencing upon the enrollment of the C&I customers and delivery of the contracted services.

Our enterprise revenues reflect the sales of our EIS and solutions to large C&I customers that seek to gain control of how and when they consume electricity. Enterprise revenue primarily reflects the sale of our EfficiencySMART and SupplySMART applications and solutions and generally represents ongoing arrangements where the revenues are recognized ratably over the service period commencing upon delivery of the contracted solutions to the customer. Under certain of our arrangements, in particular certain EfficiencySMART, a portion of the fees received may be subject to adjustment or refund based on the validation of the energy savings delivered after the implementation is complete. As a result, we defer the portion of the fees that are subject to adjustment or refund until such time as the right of adjustment or refund lapses, which is generally upon completion and validation of the implementation. In addition, under certain of our other arrangements, in particular those arrangements entered into by our wholly-owned subsidiary, M2M, we sell proprietary equipment to customers that is utilized to provide the ongoing solutions 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 begin recognizing those fees ratably over the expected customer relationship period (generally three years), once the customer is receiving from us the ongoing services. In addition, we capitalize the associated direct and incremental costs, which primarily represent the equipment and third-party installation costs, and recognize such costs over the expected customer relationship period.

Cost of Revenues

Cost of revenues for our demand response services primarily consists 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 energy 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 during interim periods as described elsewhere in this Quarterly Report on Form 10-Q. Cost of revenues for our EfficiencySMART and SupplySMART applications and services, and certain other wireless energy management products include our amortization of capitalized internal-use software costs related to those applications, services and products, 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.

We defer incremental direct costs 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, 2014 and December 31, 2013, we had no deferred incremental direct costs related to the acquisition or origination of a utility contract or open market program and during the three month periods ended March 31, 2014 and 2013, no contract origination costs were deferred. In addition, we defer incremental direct costs incurred related to customer contracts where the associated revenues have been deferred as long as the deferred incremental direct costs are deemed realizable. During the three month periods ended March 31, 2014 and 2013, we deferred $7.9 million and $6.3 million, respectively, of incremental direct costs associated with customer contracts. These deferred expenses will be expensed in proportion to the related revenue being recognized. During the three month periods ended March 31, 2014 and 2013, we expensed $1.3 million and $1.1 million, respectively, of deferred incremental direct costs to cost of revenues. As of March 31, 2014, there were no material realizability issues related to deferred incremental direct costs. We also 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 estimated useful life or the term of the contractual arrangement. During the three month periods ended March 31, 2014 and 2013, we capitalized $1.8 million and $2.4 million, respectively, of production and generation equipment costs. We believe that the above accounting treatments appropriately match expenses with the associated revenues.

Gross Profit and Gross Margin

Gross profit consists of our total revenues less our cost of revenues. Our gross profit has been, and will continue to be, affected by many factors, including (a) the demand for our energy management applications, services and products, (b) the selling price of our energy management applications, services and products, (c) our cost of revenues, (d) the way in which we manage, or are permitted to

39

manage by the relevant electric power grid operator or utility, our portfolio of demand response capacity, (e) the introduction of new energy management applications, services and products, (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. The effective management of our portfolio of demand response capacity, including our outcomes in negotiating favorable contracts with our customers and our participation in capacity auctions and bilateral contracts, 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 717 full-time employees at March 31, 2013 to 756 full-time employees at March 31, 2014 primarily as a result of our overall growth and expansion into new markets over the past year, including an increase of 25 full-time employees from our acquisitions of Entelios and Activation. We expect to continue to hire employees to support our growth for the foreseeable future. In addition, we incur significant up-front costs associated with the expansion of the number of contractual MW, which we expect to continue for the foreseeable future. We expect our overall operating expenses to increase marginally in absolute dollar terms for the foreseeable future as we continue to enable new C&I customer sites and expand the development of our energy management applications, services and products. In addition, amortization expense from intangible assets acquired in possible 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 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 an increase in selling and marketing expenses in absolute dollar terms through at least the end of fiscal 2014 as we invest in infrastructure to support our continued growth; however, we expect that selling and marketing expenses as a percentage of revenues will decrease for fiscal 2014.

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 an increase in general and administrative expenses in absolute dollar terms through at least the end of fiscal 2014 as we invest in infrastructure to support our continued growth; however, we expect that general and administrative expenses as a percentage of revenues will decrease for fiscal 2014.

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, solutions and products and enhancement of existing energy management applications, solutions and products, (d) quality assurance and testing and (e) other related overhead. During the three month periods ended March 31, 2014 and 2013, we capitalized software development costs, including software license fees and external consulting costs, of $1.4 million and $2.6 million, respectively, which are included as software in property and equipment at March 31, 2014. We expect an increase in research and development expenses in absolute dollar terms through at least the end of fiscal 2014 as we develop new technologies and enhance our existing technologies to support our continued growth; however, we expect that research and development expenses as a percentage of revenues will decrease for fiscal 2014.

Stock-Based Compensation

We account for stock-based compensation in accordance with Accounting Standards Codification, or ASC, 718Stock Compensation, or ASC 718. 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. During the three month period ended March 31, 2014, we granted 388,034 shares of non-vested restricted stock to certain executive employees. Of these shares, 25% vest in 2015 if the performance criteria related to certain 2014 operating results are achieved and the executive is still employed as of the vesting date and the remaining 75% of the shares vest quarterly over a three year period thereafter as long as the executive is still employed as of the vesting date. If the performance criteria related to certain 2014 operating results are not

40

achieved, 100% of the shares are forfeited. As a result of these grants of non-vested restricted stock, additional stock grants related to our expanding employee base and the overall increase in our stock price, we anticipate that, on a per employee basis, stock-based compensation expense will increase for the year ending December 31, 2014 as compared to the year ended December 31, 2013.

For the three month periods ended March 31, 2014 and 2013, we recorded expenses of approximately $4.2 million and $4.7 million, respectively, in connection with share-based payment awards to employees and non-employees. The slight decrease in stock-based compensation expense for the three month period ended March 31, 2014 as compared to the same period in 2013 was due to stock-based compensation expense during the three month period ended March 31, 2013 related to restricted stock grants that had been granted in lieu of fiscal 2013 cash bonuses. This decrease was partially offset by additional stock grants related to our expanding employee base and the overall increase in our stock price. With respect to stock option grants through March 31, 2014, a future expense of non-vested stock options of approximately $0.2 million is expected to be recognized over a weighted average period of 1.3 years. For outstanding non-vested restricted stock awards and restricted stock units subject to service-based vesting conditions as of March 31, 2014, we had $15.3 million of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 2.8 years. For outstanding non-vested restricted stock awards subject to performance-based vesting conditions, and that were probable of vesting as of March 31, 2014, we had $10.8 million of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 2.0 years. There were no non-vested restricted stock awards outstanding subject to performance-based vesting conditions that were not probable of vesting as of March 31, 2014.

Interest Expense and Other Income, Net

In March 2012, we entered into a $50.0 million credit facility with Silicon Valley Bank, or SVB, which was subsequently amended in June 2012 and April 2013, which we refer to as the 2012 credit facility. In April 2013, we entered into a $70.0 million senior secured revolving credit facility with the several lenders from time to time party thereto and SVB, as administrative agent, swingline lender, issuing lender, lead arranger and book manager, which was subsequently amended in August 2013, December 2013 and January 2014, which we refer to as the 2013 credit facility. The 2013 credit facility replaced the 2012 credit facility. Interest expense primarily consists of fees associated with the 2012 credit facility and the 2013 credit facility. Interest expense also consists of fees associated with issuing letters of credit and other financial assurances. Other income and expense consist primarily of gains or losses on transactions denominated in currencies other than our or our subsidiaries’ functional currency, interest income earned on cash balances, and other non-operating income and expense.

Consolidated Results of Operations

Three Month Period Ended March 31, 2014 Compared to the Three Month Period Ended March 31, 2013

Revenues

The following table summarizes our revenues for the three month periods ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31,				Dollar			Percentage
	2014		2013		Change			Change
Revenues:
Grid operator	$	35,770	$	15,063	$	20,707			137.5	%
Utility		10,309		11,769		(1,460	)		(12.4	)%
Enterprise		6,429		6,018		411			6.8	%
Total	$	52,508	$	32,850	$	19,658			59.8	%

41

For the three month period ended March 31, 2014, our revenues from grid operators increased by $20.7 million, or 137.5% as compared to the three month period ended March 31, 2013. The increase in our revenues from grid operators was primarily attributable to changes in the following operating areas (dollars in thousands):

	Revenue Increase (Decrease)
	March 31, 2013 to March 31, 2014
PJM	$	17,395
Alberta, Canada		1,670
New York Independent System Operator (New York ISO)		966
Other (1)		676
Total increased grid operator revenues	$	20,707

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

The increase in revenues from grid operators during the three month period ended March 31, 2014 as compared to the same period in 2013 was primarily due to an increase in PJM energy revenues resulting from a significant number of demand response event dispatches and overall MW dispatched as compared to the three month period ended March 31, 2013 where there were no PJM emergency event dispatches. In addition, the increase in revenues for the three month period ended March 31, 2014 as compared to the same period in 2013 resulted from an ancillary demand response program in which we participate where the MW enrolled increased during the three month period ended March 31, 2014 as compared to the same period in 2013. The increase was also due to revenues recognized from our participation in certain demand response programs in Alberta, Canada, driven by an increase in enrolled MW, as well as, revenues recognized from this grid operator under an ancillary demand response program in which we did not start participating until the three month period ended September 30, 2013. Additionally, this increase was also attributable to an increase in revenues from our New York ISO demand response program due to an increase in our MW delivery and more favorable pricing, as well as revenues recognized from our acquisition of Activation during the three month period ended March 31, 2014.

For the three month period ended March 31, 2014, our revenues from utilities decreased by $1.5 million, or 12.4% as compared to the three month period ended March 31, 2013. The decrease in our revenues from utilities was primarily attributable to changes in the following operating areas (dollars in thousands):

	Revenue Increase (Decrease)
	March 31, 2013 to March 31, 2014
National Electricity Market (NEM) - Australia	$	(1,010	)
TVA		(514	)
Other (1)		64
Total decreased utility revenues	$	(1,460	)

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

The decrease in revenues from utilities during the three month period ended March 31, 2014 as compared to the same period in 2013 was primarily due to a decrease in revenues from our NEM demand response programs in Australia, largely due to a certain program which ended in the second quarter of 2013 and was not renewed. Additionally, this decrease was also attributable to a decrease in revenues from TVA, resulting from a temporary decrease in enrolled MW due to underperformance in a certain demand response event during the three month period ended March 31, 2014. These decreases in revenues from utilities for the three month period ended March 31, 2014 as compared to the same period in 2013 were partially offset by an increase in enrolled MW in certain of our domestic demand response programs.

For the three month period ended March 31, 2014, our revenues from Enterprise customers increased by $0.4 million, or 6.8%, as compared to the same period in 2013 primarily due to an increase in both the number of customers and overall consulting engagements.

42

Gross Profit and Gross Margin

The following table summarizes our gross profit and gross margin percentages for our energy management applications, solutions and products for the three month periods ended March 31, 2014 and 2013 (dollars in thousands):

Three Months Ended March 31,
2014					2013
Gross Profit		Gross Margin			Gross Profit		Gross Margin
$	16,369		31.2	%	$	10,653		32.4	%

The increase in gross profit during the three month period ended March 31, 2014 as compared to the same period in 2013 was due to the increase in PJM demand response energy event revenues resulting from a significant number of demand response event dispatches and overall MW dispatched as compared to the three month period ended March 31, 2013 where there were no PJM emergency event dispatches. In addition, the increase in gross profits for the three month period March 31, 2014 as compared to the same period in 2013 was due to an ancillary demand response program in which we participate in PJM where the MW enrolled increased during the three month period ended March 31, 2014 as compared to the same period in 2013. The increase in gross profit during the three month period ended March 31, 2014, as compared to the same period in 2013 was also due to an increase in revenues resulting from increased participation in our international demand response programs in Alberta, Canada and New Zealand. Additionally, this increase in gross profit was also attributable to an increase in revenues from our New York ISO demand response program due to an increase in our MW delivery and more favorable pricing, as well as revenues recognized from our acquisition of Activation during the three month period ended March 31, 2014. The increase in gross profit during the three month period ended March 31, 2014 compared to the same period in 2013 was partially offset by a decrease in revenues from utilities due to a decrease in revenues from a demand response program in Australia, which ended in the second quarter of 2013 and was not renewed, as well as, a decrease in revenues from TVA, resulting from a temporary decrease in enrolled MW.

Our gross margin during the three month period ended March 31, 2014 decreased compared to the same period in 2013, primarily due to a significant increase in PJM energy event revenues which historically yield a lower gross margin. These decreases in gross margin were partially offset by revenues related to our participation in international demand response programs, which are higher margin demand response programs, improved management of our portfolio of demand response capacity and lower installed costs associated with our C&I contracts.

We continue to expect our gross margins for the year ending December 31, 2014, or fiscal 2014, to return to more historic levels in the mid 40% range. The expected decrease in gross margin compared to fiscal 2013 is expected to result primarily from continued changes in fiscal 2014 in the management of our portfolio of demand response capacity in the PJM demand response program, including an expected decrease in the percentage of higher margin revenues recognized as a result of the adjustment of our zonal capacity obligations through our participation in the PJM incremental auctions and bilateral contracts. In addition, this expected decrease in gross margin in fiscal 2014 as compared to fiscal 2013 is expected to result from an increase in lower margin energy revenues resulting from a potential increase in both the number of demand response event dispatches and number of MW expected to be dispatched in fiscal 2014 as compared to fiscal 2013 based on current trends.

Operating Expenses

The following table summarizes our operating expenses for the three month periods ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31,				Percentage Change
	2014		2013
Operating Expenses:
Selling and marketing	$	18,499	$	15,653		18.2	%
General and administrative		23,677		20,121		17.7	%
Research and development		5,175		4,820		7.4	%
Total	$	47,351	$	40,594		16.6	%

In certain forward capacity markets in which we participate, such as PJM, we may install our equipment at a C&I customer site to allow for the curtailment of MW from the electric power grid, which we refer to as enablement, up to twelve months in advance of enrolling the C&I customer in a particular program. As a result, there has been a trend of incurring operating expenses at the time of enablement, including salaries and related personnel costs, associated with enabling certain of our C&I customers in advance of recognizing the corresponding revenues.

43

Selling and Marketing Expenses

	Three Months Ended March 31,				Percentage Change
	2014		2013
Payroll and related costs	$	12,107	$	9,598		26.1	%
Stock-based compensation		1,193		1,390		(14.2	)%
Other		5,199		4,665		11.4	%
Total	$	18,499	$	15,653		18.2	%

The increase in payroll and related costs for the three month period ended March 31, 2014 compared to the same period in 2013 was primarily due to an increase in bonus expense during the three month period ended March 31, 2014, as a portion of the fiscal 2012 and fiscal 2013 bonuses were settled in shares of our common stock and therefore recorded in stock-based compensation expense during fiscal 2012 and fiscal 2013, as well as, an increase in commissions. The increase in payroll and related costs for the three month period ended March 31, 2014 as compared to the same period in 2013 was also due to an increase in the number of selling and marketing full-time employees from 228 at March 31, 2013 to 244 at March 31, 2014.

The decrease in stock-based compensation for the three month period ended March 31, 2014 compared to the same period in 2013 resulted primarily from a greater percentage of stock-based compensation expense being recognized in fiscal 2012 and fiscal 2013 as compared to 2014 as a result of a portion of the fiscal 2012 and fiscal 2013 bonuses being settled in shares of our common stock and therefore recorded in stock-based compensation expense. This decrease was partially offset by an increase in the grant date fair value of stock-based awards granted subsequent to the three month period ended March 31, 2013.

The increase in other selling and marketing expenses for the three month period ended March 31, 2014 compared to the same period in 2013 was primarily attributable to higher costs associated with various marketing initiatives and higher professional fees of $0.4 million and $0.2 million, respectively.

General and Administrative Expenses

	Three Months Ended March 31,				Percentage Change
	2014		2013
Payroll and related costs	$	13,446	$	11,042		21.8	%
Stock-based compensation		2,696		2,952		(8.7	)%
Other		7,535		6,127		23.0	%
Total	$	23,677	$	20,121		17.7	%

The increase in payroll and related costs for the three month period ended March 31, 2014 compared to the same period in 2013 was primarily attributable to an increase in bonus expense during the three month period ended March 31, 2014, as a portion of the fiscal 2012 and fiscal 2013 bonuses were settled in shares of our common stock and therefore recorded in stock-based compensation expense, as well as, an increase in the number of general and administrative full-time employees from 387 at March 31, 2013 to 403 at March 31, 2014. In addition, the increase in payroll and related costs for the three month period ended March 31, 2014 as compared to the same period in 2013 was also due to an increase in the Company’s payroll tax liability as a result of vesting of a significant number of shares of restricted stock combined with an increase in the Company’s stock price during the three month period ended March 31, 2014.

The decrease in stock-based compensation for the three month period ended March 31, 2014 compared to the same period in 2013 was due primarily to a greater percentage of stock-based compensation expense being recognized in fiscal 2012 and fiscal 2013 as compared to 2014 as a portion of the fiscal 2012 and fiscal 2013 bonuses being settled in shares of our common stock and therefore recorded in stock-based compensation expense. The decrease in stock-based compensation expense for the three month period ended March 31, 2014 was partially offset by an increase in the grant date fair value of stock-based awards granted subsequent to the three month period ended March 31, 2013 as a result of the increase in our stock price, which includes fully-vested awards that were granted to our board of directors during the three month period ended March 31, 2014.

The increase in other general and administrative expenses for the three month period ended March 31, 2014 compared to the same period in 2013 was primarily attributable to an increase in professional services fees of $1.5 million due to increased accounting,

44

consulting and legal fees incurred primarily related to our recent acquisitions. The increase was also due to higher depreciation expense of $0.5 million as a result of the capital expenditures we incurred to build-out the new lease for our principal executive offices. We commenced depreciation expense upon occupying the facility in June 2013. In addition, we incurred higher software licenses and fees of $0.3 million. The increases in other general and administrative expenses for the three month period ended March 31, 2014 compared to the same period in 2013 were partially offset by a $0.7 million decrease in rent expense, as during the three month period ended March 31, 2013 we incurred rent expense for both our prior and current principal executive office leases, as well as decreases in technology and communication expenses and other taxes of $0.1 million and $0.1 million, respectively.

Research and Development Expenses

	Three Months Ended March 31,				Percentage Change
	2014		2013
Payroll and related costs	$	3,154	$	2,387		32.1	%
Stock-based compensation		338		362		(6.6	)%
Other		1,683		2,071		(18.7	)%
Total	$	5,175	$	4,820		7.4	%

The increase in payroll and related costs for the three month period ended March 31, 2014 compared to the same period in 2013 was primarily driven by an increase in the number of research and development full-time employees from 102 at March 31, 2013 to 109 at March 31, 2014, as well an increase in bonus expense during the three month period ended March 31, 2014, as a portion of the fiscal 2012 and fiscal 2013 bonuses were settled in shares of our common stock and therefore recorded in stock-based compensation expense.

The decrease in stock-based compensation for the three month period ended March 31, 2014 compared to the same period in 2013 primarily resulted from a greater percentage of stock-based compensation expense being recognized in fiscal 2012 and fiscal 2013 as compared to 2014 as a result of a portion of the fiscal 2012 and fiscal 2013 bonuses being settled in shares of our common stock and therefore recorded in stock-based compensation expense. The decrease in stock-based compensation expense for the three month period ended March 31, 2014 was partially offset by an increase in the grant date fair value of stock-based awards granted subsequent to the three month period ended March 31, 2013 as a result of the increase in our stock price.

The decrease in other research and development expenses for the three month period ended March 31, 2014 compared to the same period in 2013 was primarily due to a decrease of $0.4 million in consulting and professional fees and a decrease of $0.2 million in software licenses and fees used in the development of our energy management applications, services and products. These decreases were partially offset by an increase of $0.2 million in technology and communication expenses.

Interest Expense and Other Income, Net

The increase in interest expense of approximately $0.1 million for the three month period ended March 31, 2014 compared to the same period in 2013 was primarily attributable to higher amortization expense of our deferred financing costs and higher average outstanding letter of credit balances during the three month period ended March 31, 2014 as compared to the same period in 2013.

Other income, net for the three month period ended March 31, 2014 was $0.6 million compared to $0.1 million for the three month period ended March 31, 2013. Other income, net was comprised primarily of net foreign currency gains and interest income. Foreign currency exchange gains resulted primarily from foreign denominated intercompany receivables held by us from one of our Australian subsidiaries which mainly resulted from funding provided to complete the acquisition of Energy Response Holdings Pty Ltd (Energy Response) and fluctuations in the Australian dollar exchange rate, and U.S. dollar denominated intercompany payables from one of our German subsidiaries to us which mainly resulted from funding provided to complete the acquisition of Entelios. Other income, net for the three month period ended March 31, 2014 was also comprised of $0.1 million of fees received from participants for a conference we held during this period, as well as, $0.1 million of interest income primarily related to foreign invested cash.

During the three month periods ended March 31, 2014 and 2013, we incurred no material realized foreign currency gains (losses). We currently do not hedge any of our foreign currency transactions.

Income Taxes

The tax benefit recorded for the three month period ended March 31, 2014 was $0.4 million and was comprised of a tax benefit on our foreign loss for the three month period ended March 31, 2014 partially offset by a U.S. tax expense related to tax deductible goodwill that generates a deferred tax liability that cannot be used as a source of income against which deferred tax assets may be realized.

45

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 effective tax rate for the full fiscal year and use that rate to provide for income taxes on a current year-to-date basis. However, if an enterprise is unable to make a reliable estimate of its annual effective tax rate, the actual effective tax rate for the year-to-date period may be the best estimate of the annual effective tax rate. We are able to reliably estimate the annual effective tax rate on our foreign earnings, but are unable to reliably estimate the annual effective tax rate on U.S. earnings.

We review all available evidence to evaluate the recovery of deferred tax assets, including the recent history of losses in all tax jurisdictions, as well as our ability to generate income in future periods. As of March 31, 2014, due to the uncertainty related to the ultimate use of our deferred income tax assets, we have provided a valuation allowance on all of our U.S., Germany, Japan, and U.K. deferred tax assets and a partial valuation on our Australia deferred tax assets.

For the three month period ended March 31, 2013, due to the fact that we could also not make a reliable estimate of our U.S. annual effective rate at March 31, 2013, we recorded an income tax provision of $0.4 million related to a U.S. tax expense related to tax deductible goodwill which generates a deferred tax liability that cannot be used as a source of income against which deferred tax assets may be realized, partially offset by a tax benefit on our foreign loss for the three month period ended March 31, 2013.

Liquidity and Capital Resources

Overview

We have generated significant cumulative losses since inception. As of March 31, 2014, we had an accumulated deficit of $111.8 million. As of March 31, 2014, our principal sources of liquidity were cash and cash equivalents totaling $103.7 million, a decrease of $45.5 million from our December 31, 2013 balance of $149.2 million, and amounts available under the 2013 credit facility. At March 31, 2014 and December 31, 2013, our excess cash was primarily invested in money market funds.

We believe our existing cash and cash equivalents at March 31, 2014, amounts available under the 2013 credit facility and our anticipated net cash flows from operating activities will be sufficient to meet our anticipated cash needs, including investing activities, for at least the next 12 months. We are utilizing a portion of our existing cash and cash equivalents and amounts available under the 2013 credit facility to provide financial assurance in connection with our participation in a certain open market bidding program in May 2014. Based upon our prior experience with this certain open market bidding program we expect that we will recover a portion of the cash and letter of credit related to this financial assurance by the end of the second quarter of 2014. Our future working capital requirements will depend on many factors, including, without limitation, the rate at which we sell our energy management applications, solutions and products to customers and the increasing rate at which letters of credit or security deposits are required by electric power grid operators and utilities, the introduction and market acceptance of new energy management applications, services and products, the expansion of our sales and marketing and research and development activities, and the geographic expansion of our business operations. To the extent that our cash and cash equivalents, amounts available under the 2013 credit facility and our anticipated cash flows from operating activities are insufficient to fund our future activities or planned future acquisitions, we may be required to raise additional funds through bank credit arrangements or public or private equity or debt financings. We also may raise additional funds in the event we determine in the future to effect one or more acquisitions of businesses, technologies or products. In addition, we may elect to raise additional funds even before we need them if the conditions for raising capital are favorable. 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 complete 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 month periods ended March 31, 2014 and 2013 (dollars in thousands):

	Three Months Ended March 31,
	2014			2013
Cash flows (used in) provided by operating activities	$	(11,566	)	$	6,780
Cash flows used in investing activities		(30,950	)		(7,374	)
Cash flows (used in) provided by financing activities		(3,119	)		489
Effects of exchange rate changes on cash		144			(109	)
Net change in cash and cash equivalents	$	(45,491	)	$	(214	)

46

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 month period ended March 31, 2014 was $11.6 million and consisted of a net loss of $30.4 million offset by $11.5 million of noncash items, consisting primarily of depreciation and amortization, stock-based compensation charges, impairment charges of equipment, and deferred taxes, and by $7.3 million of net cash provided by working capital and other activities. Cash provided by working capital and other activities consisted of a decrease of $39.2 million in unbilled revenues, most of which related to the PJM demand response market, a decrease of $9.3 million in deferred revenue primarily related to the Western Australia demand response program and a decrease of $0.2 million in accounts payable, accrued performance adjustments and accrued expenses primarily due to the timing of payments. These amounts were offset by cash used in working capital and other activities consisting of an increase of 10.3 million in accounts receivable due to the timing of cash receipts under the demand response programs in which we participate, an increase in capitalized incremental direct customer contract costs of $6.3 million, an increase in prepaid expenses and other assets of $2.8 million, a decrease of $0.3 million in other noncurrent liabilities, a decrease of $18.3 million in accrued capacity payments and a decrease in accrued payroll and related expenses of $3.4 million.

Cash provided by operating activities for the three month period ended March 31, 2013 was $6.8 million and consisted of a net loss of $30.5 million offset by $12.1 million of noncash items, consisting primarily of depreciation and amortization, stock-based compensation charges, impairment charges of equipment, and deferred taxes, and by $25.2 million of net cash provided by working capital and other activities. Cash provided by working capital and other activities consisted of a decrease of $8.1 million in accounts receivable due to the timing of cash receipts under the demand response programs in which we participate, a decrease of $26.6 million in unbilled revenues, most of which related to the PJM demand response market, an increase of $3.4 million in other noncurrent liabilities, an increase of $11.0 million in deferred revenue primarily related to the Western Australia demand response program, and an increase of $1.4 million in accounts payable, accrued performance adjustments and accrued expenses primarily due to the timing of payments. These amounts were offset by cash used in working capital and other activities consisting of an increase in prepaid expenses and other assets of $2.2 million, an increase in capitalized incremental direct customer contract costs of $5.0 million, a decrease of $17.1 million in accrued capacity payments and a decrease in accrued payroll and related expenses of $1.1 million.

Cash Flows Used in Investing Activities

Cash used in investing activities was $30.9 million for the three month period ended March 31, 2014. During the three month period ended March 31, 2014, we made payments, net of cash acquired, of $3.9 million and $20.2 million, respectively, for the acquisitions of Entelios and Activation. In addition, we made a payment of $1.0 million to acquire a cost method investment. We also incurred $6.1 million in capital expenditures primarily related to $3.4 million in software additions, including capitalized software, to further expand the functionality of our software and solutions, as well as, increased demand response equipment related to an increased installed base. We also made payments of $0.4 million for the acquisition of a customer contract. In addition, our restricted cash and deposits increased by $0.7 million due to an increase in deposits principally related to the financial assurance requirements for demand response programs in which we participate.

Cash used in investing activities was $7.4 million for the three month period ended March 31, 2013. During the three month period ended March 31, 2013, we incurred $8.9 million in capital expenditures primarily related to capital expenditures for our new corporate headquarters, as well as capitalized internal use software costs as we continue our investment to further develop and enhance our software. In addition, during the three month period ended March 31, 2013, our restricted cash and deposits decreased by $1.6 million due to a decrease in deposits principally related to the financial assurance requirements for demand response programs in which we participate, as these deposits were replaced with letters of credit.

47

Cash Flows (Used in) Provided by Financing Activities

Cash used in financing activities was $3.1 million for the three month period ended March 31, 2014 and consisted primarily of payments made for employee restricted stock minimum tax withholdings, partially offset by proceeds that we received from exercises of options to purchase shares of our common stock. Cash provided by financing activities was $0.5 million for the three month period ended March 31, 2013 and consisted primarily of proceeds that we received from exercises of options to purchase shares of our common stock.

Credit Facility Borrowings

In March 2012, we and one of our subsidiaries entered into the 2012 credit facility. On April 12, 2013, we, one of our subsidiaries and SVB entered into an amendment to the 2012 credit facility to extend the termination date from April 15, 2013 to April 30, 2013. On April 18, 2013, in connection with the 2013 credit facility described below, the 2012 credit facility was terminated.

On April 18, 2013, we entered into the 2013 credit facility. The 2013 credit facility replaced the 2012 credit facility. The 2013 credit facility provides for a two year revolving line of credit in the aggregate amount of $70 million, subject to increase from time to time up to an aggregate amount of $100 million with an additional commitment from the lenders or new commitments from new financial institutions.

Subject to continued compliance with the covenants contained in the 2013 credit facility, the full amount of the 2013 credit facility may be available for issuances of letters of credit and up to $5 million may be available for swing line loans. The interest on revolving loans under the 2013 credit facility will accrue, at our election, at either (i) the Eurodollar Rate with respect to the relevant interest period plus 2.00% or (ii) the ABR (defined as the highest of (x) the “prime rate” as quoted in the Wall Street Journal, and (y) the Federal Funds Effective Rate plus 0.50%) plus 1.00%. The letter of credit fee charged under the 2013 credit facility is consistent with the 2012 credit facility letter of credit fee of 2.00%. We expense the interest and letter of credit fees under the 2013 credit facility, as applicable, in the period incurred. The obligations under the 2013 credit facility are secured by all of our domestic assets and the assets of several of our domestic subsidiaries. The 2013 credit facility terminates on April 18, 2015 and all amounts outstanding thereunder will become due and payable in full and we would be required to collateralize with cash any outstanding letter of credit under the 2013 credit facility up to 105% of the amounts outstanding. In connection with the 2013 credit facility and related amendments we incurred financing costs of approximately $0.9 million which were deferred and are being amortized to interest expense over the term of the 2013 credit facility, or through April 18, 2015.

The 2013 credit facility contains customary terms and conditions for credit facilities of this type, including, among other things, restrictions on our and our subsidiaries ability to incur additional indebtedness, create liens, enter into transactions with affiliates, transfer assets, make certain acquisitions, pay dividends or make distributions on, or repurchase, our common stock, consolidate or merge with other entities, or undergo a change in control. In addition, we are required to meet certain monthly and quarterly financial covenants customary with this type of credit facility, as described above, including maintaining a minimum specified level of free cash flow, a minimum specified unrestricted cash balance and a minimum specified ratio of current assets to current liabilities.

The 2013 credit facility contains customary events of default, including 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, SVB may accelerate our obligations under the 2013 credit facility. If we are determined to be in default then any amounts outstanding under the 2013 credit facility would become immediately due and payable and we would be required to collateralize with cash any outstanding letters of credit up to 105% of the amounts outstanding.

As of March 31, 2014, we were in compliance with all of our covenants under the 2013 credit facility. We believe that it is reasonably assured that we will comply with the covenants of the 2013 credit facility for the foreseeable future.

As of March 31, 2014, we had no borrowings, but had outstanding letters of credit totaling $46.2 million under the 2013 credit facility. The decrease in the amount of outstanding letters of credit from December 31, 2013 to March 31, 2014 is primarily the result of fewer letters of credit issued as collateral for demand response arrangements and obligations. As of March 31, 2014, we had $23.8 million available under the 2013 credit facility for future borrowings or issuances of additional letters of credit.

In May 2014, we were required to provide financial assurance in connection with our capacity bid in a certain open market bidding program. We have provided this financial assurance utilizing a $22.0 million letter of credit issued under the 2013 credit facility and additionally, utilized $4.5 million of our available unrestricted cash on hand. Based on our prior experience with this certain open market bidding program, we currently expect that we will recover a portion of this letter of credit and cash during the three month period ending June 30, 2014.

48

Contingent Earn-Out Payments

As discussed in Note 2 of our unaudited condensed consolidated financial statements contained herein, in connection with our acquisitions of Entelios and Activation, we may be obligated to pay additional contingent purchase price consideration related to earn-out payments of $2.0 million (1.5 million Euros) and $1.4 million ($1.0 million Euros), respectively, based on the applicable exchange rates as of the closing date of each respective transaction.

The earn-out payment for Entelios, if any, will be based on the achievement of certain minimum defined profit metrics for the years ending December 31, 2014 and 2015, respectively. Of the $2.0 million (1.5 million Euros) maximum earn-out payment, up to $0.8 million (0.6 million Euros) and $1.2 million (0.9 million Euros) relate to the achievement of the defined profit metrics for the years ending December 31, 2014 and 2015, respectively. If the minimum defined profit metrics are not achieved, there will be no partial payment if the milestone is not fully achieved, however, the amount of the earn-out payment can vary based on the amount that profits exceed the minimum defined profit metrics. We determined that the initial fair value of the earn-out payment as of the acquisition date was $0.1 million. We recorded our estimate of the fair value of the contingent consideration based on the evaluation of the likelihood of the achievement of the contractual conditions that would result in the payment of the contingent consideration and weighted probability assumptions of these outcomes. This fair value measurement was determined utilizing a Monte Carlo simulation and was based on significant inputs not observable in the market and therefore, represented a Level 3 measurement as defined in ASC 820. Any changes in fair value will be recorded in our consolidated statements of operations. As of March 31, 2014, there were no changes in the probability of the earn-out payment. This liability has been discounted to reflect the time value of money and therefore, as the milestone date approaches, the fair value of this liability will increase. This increase in fair value is recorded to cost of revenues in our accompanying unaudited condensed consolidated statements of operations. During the three month period ended March 31, 2014, the change in fair value due to the accretion of the time value of money discount was not material. At March 31, 2014, the liability was recorded at $0.1 million after adjusting for changes in exchange rates.

The earn-out payment for Activation, if any, will be based on the achievement of certain minimum defined megawatt enrollment, as well as, profit metrics for the years ending December 31, 2014 and 2015, respectively. Of the $1.4 million (1.0 million Euros) maximum earn-out payment, up to $0.4 million (0.3 million Euros) and $1.0 million (0.7 million Euros) relate to the achievement of the defined profit metrics for the years ending December 31, 2014 and 2015, respectively. If the minimum defined profit metrics are not achieved, there will be no partial payment if the milestone is not fully achieved, however, the amount of the earn-out payment can vary based on the amount that profits exceed the minimum defined profit metrics. We determined that the initial fair value of the earn-out payment as of the acquisition date was $0.3 million. We recorded our estimate of the fair value of the contingent consideration based on the evaluation of the likelihood of the achievement of the contractual conditions that would result in the payment of the contingent consideration and weighted probability assumptions of these outcomes. This fair value measurement was determined utilizing a Monte Carlo simulation and was based on significant inputs not observable in the market and therefore, represented a Level 3 measurement as defined in ASC 820. Any changes in fair value will be recorded in our consolidated statements of operations. As of March 31, 2014, there were no changes in the probability of the earn-out payment. This liability has been discounted to reflect the time value of money and therefore, as the milestone date approaches, the fair value of this liability will increase. This increase in fair value is recorded to cost of revenues in our accompanying unaudited condensed consolidated statements of operations. During the three month period ended March 31, 2014, the change in fair value due to the accretion of the time value of money discount was not material. At March 31, 2014, the liability was recorded at $0.3 million after adjusting for changes in exchange rates.

As discussed in Note 1 of our unaudited condensed consolidated financial statements contained herein, in connection with our acquisition of a foreign entity, we may be obligated to pay additional contingent purchase price consideration related to certain earn-out amounts up to a maximum of $1.8 million). The earn-out payments, if any, will be based on the achievement of certain defined market legislation and certain operational metrics. Up to $1.5 million of the earn-out payments are also only payable to those stockholders of the acquired entity who are employees as of the time of achievement. Therefore, we have concluded that these earn-out payments should be accounted for as compensation arrangements and not a component of purchase price and we will evaluate the probability of achievement and record expense ratably over the applicable estimated service period as compensation expense for the amount, if any, deemed probable of achievement. With respect to the other potential earn-out payment of $0.3 million, we are still gathering information in order to determine the fair value of the contingent purchase price consideration as of the acquisition date. Any changes in fair value after the completion of this fair value analysis will be recorded to our consolidated statements of operations.

Capital Spending

We have made capital expenditures primarily related to $3.4 million in software additions, including capitalized software, to further expand the functionality of our software and solutions, as well as, increased demand response equipment related to an

49

increased installed base. Our capital expenditures totaled $6.1 million and $8.9 million during the three month periods ended March 31, 2014 and 2013, respectively. We expect capital expenditures to decrease for fiscal 2014 as compared to fiscal 2013 due to the capital expenditures incurred in 2013 related to our new corporate headquarters.

Contractual Obligations

As of March 31, 2014, the contractual obligations disclosure contained in our 2013 Form 10-K has not materially changed except as disclosed herein:

In March 2014, we entered into a lease for our California operations. The lease term is through September 2019 and the lease contains both a rent holiday period and escalating rental payments over the lease term. The lease requires payments for additional expenses such as taxes, maintenance, and utilities and contains a fair value renewal option. The lease commences on April 1, 2014.

Information regarding our significant contractual obligations of the types described below is set forth in the following table and includes the operating lease arrangement described above. Payments due by period have been presented based on payments due subsequent to March 31, 2014. For example, the payments due in less than one year represent contractual obligations that will be settled by March 31, 2015.

	Payments Due By Period (in thousands)
Contractual Obligations	Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		More than 5 Years
Operating lease obligations (not reduced by sublease rentals of $191)	$	33,795	$	5,611	$	5,622	$	16,435	$	6,127
Total	$	33,795	$	5,611	$	5,622	$	16,435	$	6,127

Off-Balance Sheet Arrangements

As of March 31, 2014, 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, 2014, we had outstanding letters of credit totaling $46.2 million under the 2013 credit facility. 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.

50

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 unaudited 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 2013 Form 10-K. Except as disclosed herein, there have been no material changes to our critical accounting policies or estimates during the three month period ended March 31, 2014.

Revenue Recognition

We recognize revenues in accordance with Accounting Standards Codification 605,Revenue Recognition (ASC 605). In all of the our arrangements, we do 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, we evaluate the following criteria:

• 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 significant 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 we offer payment terms significantly in excess of our 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 maintain a reserve for customer adjustments and allowances as a reduction in revenues. In determining our revenue reserve estimate, and in accordance with company policy, we rely on historical data and known performance adjustments. These factors, and unanticipated changes in the economic and industry environment, could cause our reserve estimates to differ from actual results. We record a provision for estimated customer adjustments and allowances in the same period as the related revenues are recorded. These estimates are based on the specific facts and circumstances of a particular program, analysis of credit memo data, historical customer adjustments, and other known factors. If the data we use to calculate these estimates does not properly reflect reserve requirements, then a change in the allowances would be made in the period in which such a determination is made and revenues in that period could be affected. As of March 31, 2014 and December 31, 2013, our revenue reserves were $0.5 million. During the three month period ended March 31, 2013, we recorded an increase to the revenue reserve of $0.1 million. There was no change to the revenue reserve for the three month period ended March 31, 2014.

Revenues from grid operators and revenues from utilities principally represent demand response revenues. During the three month period ended March 31, 2014, revenues from grid operators and revenues from utilities were comprised of $44.1 million of demand response revenues and $2.0 million of enterprise EIS and solutions revenues. During the three month period ended March 31, 2013, revenues from grid operators and revenues from utilities were comprised of $24.5 million of demand response revenues and $2.4 million of enterprise EIS and solutions revenues.

All revenues from enterprise customers for the three month periods ended March 31, 2014 and 2013 were derived from enterprise EIS and solutions.

Demand Response Revenues

We enter into contracts and open market bidding programs with utilities and electric power grid operators to provide demand response applications and services. Currently we have two principal service offerings under which it provides demand response

51

applications and services: (1) full-service turnkey offering to utilities under which it manages all aspects of demand response program delivery to deliver a firm capacity resource (Demand Resource) and (2) utility partnership offering under which utilities can utilize software through a software as a service offering, integrated metering hardware, and professional services to support their tariff-based C&I demand response programs on a service-level agreement basis (Demand Manager).

We have evaluated the factors within ASC 605 regarding gross versus net revenue reporting for our demand response revenues and our payments to C&I customers. Based on the evaluation of the factors within ASC 605, we have determined that all of the applicable indicators of gross revenue reporting were met. The applicable indicators of gross revenue reporting included, but were not limited to, the following:

• We are the primary obligor in our arrangements with electric power grid operators and utility customers because we provide our demand response services directly to electric power grid operators and utilities under long-term contracts or pursuant to open market programs and contracts separately with C&I customers to deliver such services. We manage all interactions with the electric power grid operators and utilities, while C&I customers do not interact with the electric power grid operators and utilities. In addition, we assume the entire performance risk under our arrangements with electric power grid operators and utility customers, including the posting of financial assurance to assure timely delivery of committed capacity with no corresponding financial assurance received from our C&I customers. In the event of a shortfall in delivered committed capacity, we are responsible for all penalties assessed by the electric power grid operators and utilities without regard for any recourse we may have with our C&I customers.

• We have latitude in establishing pricing, as the pricing under our arrangements with electric power grid operators and utilities is negotiated through a contract proposal and contracting process or determined through a capacity auction. We then separately negotiate payment to C&I customers and have complete discretion in the contracting process with the C&I customers.

• We have complete discretion in determining which suppliers (C&I customers) will provide the demand response services, provided that the C&I customer is located in the same region as the applicable electric power grid operator or utility.

• We are involved in both the determination of service specifications and perform part of the services, including the installation of metering and other equipment for the monitoring, data gathering and measurement of performance, as well as, in certain circumstances, the remote control of C&I customer loads.

As a result, we determined that we earn revenue (as a principal) from the delivery of demand response services to electric power grid operators and utility customers and record the amounts billed to the electric power grid operators and utility customers as gross demand response revenues and the amounts paid to C&I customers as cost of revenues.

EnerNOC Demand Resource Solution

The majority of our demand response revenues are generated from the EnerNOC Demand Resource solution. Demand response revenues consist of two elements: revenue earned based on our ability to deliver committed capacity to our electric power grid operator and utility customers, which we refer to as capacity revenue; and revenue earned based on additional payments made to us for the amount of energy usage actually curtailed from the grid during a demand response event, which we refer to as energy event revenue.

We recognize demand response revenue when we have provided verification to the electric power grid operator or utility of our ability to deliver the committed capacity which entitles us to payments under the 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.

52

Commencing in fiscal 2012, all demand response capacity revenues related to our participation in the PJM open market program are being recognized at the end of the four-month delivery period of June through September, or during the three month period ended September 30^th of each year. Because the period during which we are required to perform (June through September) is shorter than the period over which payments are received under the program (June through May), a portion of the revenues that have been earned are recorded and accrued as unbilled revenue. Substantially all revenues related to the PJM open market program year ended September 30, 2013 were recognized during the three month period ended September 30, 2013 and as a result of the billing period not coinciding with the revenue recognition period, we had $26.5 million and $64.7 million in unbilled revenues from PJM at March 31, 2014 and December 31, 2013, respectively.

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 contract or open market program. During the three month periods ended March 31, 2014 and 2013, we recognized $20.6 million and $2.0 million, respectively, of energy event revenues.

We have evaluated the forward capacity programs in which we participate and have determined that our contractual obligations in these programs do not currently meet the definition of derivative contracts under ASC 815,Derivatives and Hedging(ASC 815).

EnerNOC Demand Manager Solution

Under our EnerNOC Demand Manager solution, we generally receive an ongoing fee for overall management of the utility demand response program based on enrolled capacity or enrolled C&I customers, which is not subject to adjustment based on performance during a demand response dispatch. We recognize revenues from these fees ratably over the applicable service delivery period commencing upon when the C&I customers have been enrolled and the contracted services have been delivered. In addition, under this offering, we may receive additional fees for program start-up, as well as, for C&I customer installations. We have determined that these fees do not have stand-alone value due to that such services do not have value without the ongoing services related to the overall management of the utility demand response program and therefore, we recognize these fees over the estimated customer relationship period, which is generally the greater of three years or the contract period, commencing upon the enrollment of the C&I customers and delivery of the contracted services. Through March 31, 2014, revenues from EnerNOC Demand Manager have not been material to our consolidated results of operations.

Enterprise EIS and Solutions

With respect to our enterprise EIS and solutions revenues, which represent our EfficiencySMART, SupplySMART and other revenues, these generally represent ongoing service arrangements where the revenues are recognized ratably over the service period commencing upon delivery of the contracted service with the customer. Under certain of our arrangements, in particular certain EfficiencySMART arrangements with utilities, a portion of the fees received may be subject to adjustment or refund based on the validation of the energy savings delivered after the implementation is complete. As a result, we defer the portion of the fees that are subject to adjustment or refund until such time as the right of adjustment or refund lapses, which is generally upon completion and validation of the implementation. In addition, under certain other of our arrangements, we sell proprietary equipment to C&I customers 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 revenues associated with the equipment and we begin recognizing such revenue ratably over the expected C&I customer relationship period (generally 3 years), once the C&I customer is receiving the ongoing services from the Company. In addition, we capitalize 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.

We follow the provisions of ASC Update No. 2009-13,Multiple-Deliverable Revenue Arrangements(ASU 2009-13). We typically determine the selling price of our services based on vendor specific objective evidence (VSOE). Consistent with our methodology under previous accounting guidance, we determine VSOE based on our normal pricing and discounting practices for the specific service when sold on a stand-alone basis. In determining VSOE, our policy is to require a substantial majority of selling prices for a product or service to be within a reasonably narrow range. We also consider the class of customer, method of distribution, and the geographies into which our products and services are sold 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

53

hierarchy of determining selling price. Third Party Evidence (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 have not used this measure since we have been unable to reliably verify standalone prices of competitive solutions. Our best estimate of selling price (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 our services, principally certain EfficiencySMART services.

Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (FASB) issued ASU No. 2014-08,Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (ASU 2014-08). ASU 2014-08 amends the definition of discontinued operations under ASC 205-20 to only those disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity’s operations and financial results will be reported as discontinued operations in the financial statements. This guidance is effective for all disposals (or classifications as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance. We have early adopted this guidance as of January 1, 2014. The adoption of this guidance had no impact on our consolidated financial statements.

Additional Information

Non-GAAP Financial Measures

To supplement our consolidated financial statements presented on a GAAP basis, we disclose certain non-GAAP measures that exclude certain amounts, including non-GAAP net loss attributable to EnerNOC, Inc., non-GAAP net loss per share attributable to EnerNOC, Inc., 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 loss attributable to EnerNOC, Inc. is GAAP net loss attributable to EnerNOC, Inc.; the GAAP measure most comparable to non-GAAP net loss per share attributable to EnerNOC, Inc. is GAAP net loss per share attributable to EnerNOC, Inc.; the GAAP measure most comparable to adjusted EBITDA is GAAP net loss attributable to EnerNOC, Inc.; and the GAAP measure most comparable to free cash flow is cash flows (used in) provided by operating activities. Reconciliations of each of these non-GAAP financial measures to the corresponding GAAP measures are included below.

Use and Economic Substance of Non-GAAP Financial Measures

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) attributable to EnerNOC, Inc. 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 month periods ended March 31, 2014 and 2013, respectively, as well as reasons for excluding these individual items:

• Management defines non-GAAP net income (loss) attributable to EnerNOC, Inc. as net income (loss) attributable to EnerNOC, Inc. 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) attributable to EnerNOC, Inc., excluding depreciation, amortization, stock-based compensation, direct and incremental expenses related to acquisitions or divestitures, interest,

54

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) attributable to EnerNOC, Inc., non-GAAP net income (loss) per share attributable to EnerNOC, Inc., 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 attributable to EnerNOC, Inc. and Non-GAAP Net Loss per Share attributable to EnerNOC, Inc.

Net loss attributable to EnerNOC, Inc. for the three month period ended March 31, 2014 was $30.4 million, or $1.09 per basic and diluted share, compared to net loss attributable to EnerNOC, Inc. of $30.5 million, or $1.12 per basic and diluted share, for the three month period ended March 31, 2013. Excluding stock-based compensation charges and amortization of expenses related to acquisition-related assets, net of tax effects, non-GAAP net loss attributable to EnerNOC, Inc. for the three month period ended March 31, 2014 was $24.3 million, or $0.87 per basic and diluted share, compared to non-GAAP net loss attributable to EnerNOC, Inc. of $24.0 million, or $0.88 per basic and diluted share, for the three month period ended March 31, 2013.

	Three Months Ended March 31,
	2014			2013
	(In thousands, except share and per share data)
GAAP net loss attributable to EnerNOC, Inc.	$	(30,413	)	$	(30,537	)
ADD: Stock-based compensation		4,227			4,704
ADD: Amortization expense of acquired intangible assets		1,883			1,794
LESS: Income tax effect on Non-GAAP adjustments (1)		—			—
Non-GAAP net loss attributable to EnerNOC, Inc.	$	(24,303	)	$	(24,039	)
GAAP net loss per basic and diluted share attributable to EnerNOC, Inc.	$	(1.09	)	$	(1.12	)
ADD: Stock-based compensation		0.15			0.17
ADD: Amortization expense of acquired intangible assets		0.07			0.07
LESS: Income tax effect on Non-GAAP adjustments (1)		—			—
Non-GAAP net loss per basic and diluted share attributable to EnerNOC, Inc.	$	(0.87	)	$	(0.88	)
Weighted average number of common shares outstanding
Basic		27,923,861			27,366,612
Diluted		27,923,861			27,366,612

(1) The non-GAAP adjustments would have no impact on the provision for income taxes recorded for the three month periods ended March 31, 2014 or 2013, respectively.

55

Adjusted EBITDA

Adjusted EBITDA was negative $18.4 million and negative $18.5 million for the three months ended March 31, 2014 and 2013, respectively.

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

	Three Months Ended March 31,
	2014			2013
Net loss attributable to EnerNOC, Inc.	$	(30,413	)	$	(30,537	)
Add back:
Depreciation and amortization		7,365			6,730
Stock-based compensation expense		4,227			4,704
Direct and incremental expenses related to acquisitions or divestitures		946			—
Other income		(574	)		(67	)
Interest expense		450			313
(Benefit from) provision for income tax		(425	)		350
Adjusted EBITDA	$	(18,424	)	$	(18,507	)

56

Free Cash Flow

Cash flows (used in) provided by operating activities were $(11.6) million and $6.8 million for the three month periods ended March 31, 2014 and 2013, respectively. We had negative free cash flows of $17.7 million and $2.2 million for the three month periods ended March 31, 2014 and 2013, respectively. The reconciliation of cash flows from operating activities to free cash flow is set forth below:

	Three Months Ended March 31,
	2014			2013
Net cash provided by (used in) operating activities	$	(11,566	)	$	6,780
Subtract:
Purchases of property and equipment		(6,113	)		(8,938	)
Free cash flow	$	(17,679	)	$	(2,158	)

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Except as disclosed herein, there have been no material changes during the three month period ended March 31, 2014 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 2013 Form 10-K.

Foreign Currency Exchange Risk

Our international business is subject to risks, including, but not limited to unique economic conditions, changes in political climate, differing tax structures, other regulations and restrictions, and foreign exchange rate volatility. Accordingly, our future results could be materially adversely impacted by changes in these or other factors.

A substantial majority of our foreign expense and sales activities are transacted in local currencies, including Australian dollars, British pounds, Canadian dollars and New Zealand dollars. In addition, our foreign sales are denominated in local currencies. Fluctuations in the foreign currency rates could affect our sales, cost of revenues and profit margins and could result in exchange losses. In addition, currency devaluations can result in a loss if we maintain deposits in a foreign currency. During the three month period ended March 31, 2014, approximately 17% of our consolidated sales were generated outside the United States, and we anticipate that sales generated outside the United States will continue to represent greater than 10% of our consolidated sales for fiscal 2014 and will continue to grow in subsequent fiscal years.

We believe that the operating expenses of our international subsidiaries that are incurred in local currencies will not have a material adverse effect on our business, results of operations or financial condition for fiscal 2014. Our operating results and certain assets and liabilities that are denominated in foreign currencies are affected by changes in the relative strength of the U.S. dollar against the applicable foreign currency. Our expenses denominated in foreign currencies are positively affected when the U.S. dollar strengthens against the applicable foreign currency and adversely affected when the U.S. dollar weakens.

During the three month periods ended March 31, 2014 and 2013, we incurred net foreign exchange gains totaling $0.4 million and less than $0.1 million, respectively. During the three month period ended March 31, 2014, we had no material realized gains (losses) related to the settlement of transactions denominated in foreign currencies. During the three month period ended March 31, 2013, we realized losses of ($0.3) million related to the settlement of transactions denominated in foreign currencies. As of March 31, 2014, we had an intercompany receivable from our Australian subsidiary that is denominated in Australian dollars and not deemed to be of a “long-term investment” nature totaling $11.0 million at March 31, 2014 exchange rates ($11.8 million Australian) and two of our German subsidiaries had an intercompany payable to us that are denominated in U.S. dollars and not deemed to be of a “long-term investment” nature totaling $18.1 million at March 31, 2014 exchange rates.

A hypothetical 10% increase or decrease in foreign currencies in which we transact would not have a material adverse effect on our financial condition or results of operations other than the impact on the unrealized gain (loss) on the intercompany receivable held by us from our Australian subsidiary that is denominated in Australian dollars, and for which a hypothetical 10% increase or decrease in the foreign currency would result in an incremental $2.9 million gain or loss.

57

We currently do not have a program in place that is designed to mitigate our exposure to changes in foreign currency exchange rates. We frequently evaluate certain potential programs, including the use of derivative financial instruments, to reduce our exposure to foreign exchange gains and losses, and the volatility of future cash flows caused by changes in currency exchange rates. The utilization of forward foreign currency contracts would reduce, but would not eliminate, the impact of currency exchange rate movements.

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.

As a result of our recent acquisitions, we have begun to integrate certain business processes and systems. Accordingly, certain changes have been made and will continue to be made to our internal controls over financial reporting until such time as these integrations are complete. There have been no other changes in our internal control over financial reporting that occurred during the period covered by this report that have materially affected, or are 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.

On May 3, 2013, a purported shareholder of the Company (the Plaintiff) filed a derivative and class action complaint in the United States District Court for the District of Delaware (the Court) against certain of our officers and directors as well as the Company as a nominal defendant (the Defendants). The complaint asserts derivative claims, purportedly brought on behalf of the Company, for breach of fiduciary duty, waste of corporate assets, and unjust enrichment in connection with certain equity grants (awarded in 2010, 2012, and 2013) that allegedly exceeded an annual limit on per-employee equity grants purported to be contained in the 2007 Plan. The complaint also asserts a direct claim, brought on behalf of the Plaintiff and a proposed class of our shareholders, alleging our proxy statement filed on April 26, 2013 was false and misleading because it failed to disclose that the equity grants were improper. The plaintiff seeks, among other relief, rescission of the equity grants, unspecified damages, injunctive relief, disgorgement, attorneys’ fees, and such other relief as the Court may deem proper.

Defendants filed a motion to dismiss on August 30, 2013. Plaintiff responded to the motion on October 18, 2013 and Defendants replied on November 22, 2013. No hearing date has been set.

We continue to believe that we and the other defendants have substantial legal and factual defenses to the claims and allegations contained in the complaint, and continue to pursue these defenses vigorously. We continue to believe that it is neither remote nor probable that we will incur a loss related to this matter. There can be no assurance, however, that our defense of this matter will be successful. We carry insurance for these types of claims and currently believe that a resolution to this claim, in excess of the deductible, would be covered by our insurance. Therefore, we do not currently believe that it is reasonably possible that the potential magnitude of the range of any loss would be material to our consolidated financial conditions, results of operations or cash flows. However, there is no guarantee that this claim will be covered by our insurer. A denial of the claim by the insurance provider or a judgment significantly in excess of our insurance coverage could materially and adversely affect our consolidated financial condition, results of operations and cash flows. In addition, regardless of the outcome of this matter, the matter may divert financial and management resources and result in general business disruption, including that we may suffer from adverse publicity that could harm our reputation and negatively impact our stock price.

58

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 2013 Form 10-K. During the three months ended March 31, 2014, there were no material changes to the risk factors that were disclosed in Part I - Item 1A under the heading “Risk Factors” in our 2013 Form 10-K.

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

The following table provides information about our purchases of our common stock during the first quarter of fiscal 2014:

Fiscal Period	Total Number of Shares Purchased (1)		Average Price Paid per Share (2)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (3)		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (3)
Through December 31, 2013		—	$	—		—	$	20,545,298
January 1, 2014 - January 31, 2014		17,907		18.46		—		20,545,298
February 1, 2014 - February 28, 2014		36,339		22.30		—		20,545,298
March 1, 2014 - March 31, 2014		114,930		21.78		—		20,545,298
Total for the first quarter of 2014		169,176	$	21.54		—	$	20,545,298

(1) We repurchased 169,176 shares of our common stock in the first quarter of fiscal 2014 related to repurchases of our common stock to cover employee minimum statutory income tax withholding obligations in connection with the vesting of restricted stock under our equity incentive plans, which we pay in cash to the appropriate taxing authorities on behalf of our employees.

(2) Average price paid per share is calculated based on the average price per share related to repurchases of our common stock to cover employee minimum statutory income tax withholding obligations in connection with the vesting of restricted stock under our equity incentive plans which we pay in cash to the appropriate taxing authorities on behalf of our employees. Amounts disclosed are rounded to the nearest two decimal places.

(3) On August 6, 2013, our board of directors authorized and we announced the repurchase of up to $30 million of our common stock during the twelve month period ending August 6, 2014, unless earlier terminated by the board of directors. In the fourth quarter of 2013, we repurchased 274,663 shares of our common stock at an average price of $16.25 under the $30 million share repurchase plan. There were no repurchases of our common stock in the first quarter of fiscal 2014 pursuant to our share repurchase program, which we publicly announced in August 2013.

59

Item 6. Exhibits.

3.1	Second Amended and Restated Bylaws of EnerNOC, Inc. (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed February 12, 2014 (File No. 001-33471) and incorporated herein by reference).
10.1*@	Offer Letter, dated June 6, 2013 by and between EnerNOC, Inc. and Matthew Cushing.
10.2*@	Severance Agreement, dated as of June 11, 2013, by and between EnerNOC, Inc. and Matthew Cushing.
10.3#	Second Amendment to Credit Agreement among EnerNOC, Inc. and Silicon Valley Bank, dated as of December 3, 2013 (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed January 23, 2014 (File No. 001-33471) and incorporated herein by reference).
10.4	Third Amendment to Credit Agreement among EnerNOC, Inc. and Silicon Valley Bank, dated as of January 16, 2014 (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed January 23, 2014 (File No. 001-33471) and incorporated herein by reference).
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 Operating Officer and 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 Operating Officer and Chief Financial Officer of EnerNOC, Inc. pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*	The following materials from EnerNOC, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, formatted in XBRL (Extensible Business Reporting Language): (i) the Unaudited Condensed Consolidated Balance Sheets, (ii) the Unaudited Condensed Consolidated Statements of Income, (iii) the Unaudited Condensed Consolidated Statements of Comprehensive Income, (iv) the Unaudited Condensed Consolidated Statements of Cash Flows, and (v) Notes to Unaudited Condensed Consolidated Financial Statements.

* Filed herewith

@ Management contract, compensatory plan or arrangement

# Confidential treatment has been granted by the Securities and Exchange Commission as to certain portions of this Exhibit, which have been omitted and filed separately with the Securities and Exchange Commission

60

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 8, 2014	By:	/s/ Timothy G. Healy
		Timothy G. Healy
		Chief Executive Officer
Date: May 8, 2014	By:	/s/ Neil Moses
		Neil Moses
		Chief Operating Officer and Chief Financial Officer

61