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UNITED STATES


SECURITIES AND EXCHANGE COMMISSION


Washington, DC 20549





FORM 10-Q/A


Amendment No. 1





(Mark One)


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


For the quarterly period ended


June 30, 2015


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)








Delaware87-0698303(State or Other Jurisdiction ofIncorporation or Organization)(IRS EmployerIdentification No.)





One Marina Park DriveSuite 400Boston, Massachusetts02210(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 ý 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 ý No  ̈




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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 filerýNon-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 ý


There were 30,841,383 shares of the registrant’s common stock, $0.001 par value per share, outstanding as of August 3, 2015.











EXPLANATORY NOTE





This Amendment No. 1 on Form 10-Q/A (this “Amendment No. 1”) is being filed to amend our Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2015 (the “Original Filing”), filed with the U.S. Securities and Exchange Commission on August 6, 2015. The sole purpose of this Amendment No. 1 is to correct a typographical error contained in the certification of the chief executive officer and chief operating officer and chief financial officer 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 (the “906 Certification”).  As amended, “for the quarter ended March 31, 2015” has been replaced in the 906 Certification with “for the quarter ended June 30, 2015.”





Other than described above, no other modifications or changes have been made to the Original Filing. This Amendment No. 1 does not reflect events occurring after the date of the Original Filing or modify or update those disclosures made pursuant to subsequent events.

















EnerNOC, Inc.


Index to Form 10-Q





PagePart I - Financial InformationItem 1.Financial StatementsUnaudited Condensed Consolidated Balance Sheets at June 30, 2015 and December 31, 20143Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2015 and 20144Unaudited Condensed Consolidated Statements of Comprehensive Loss for the three and six months ended June 30, 2015 and 20145Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2015 and 20146Notes to Unaudited Condensed Consolidated Financial Statements7Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations30Item 3.Quantitative and Qualitative Disclosures About Market Risk50Item 4.Controls and Procedures51Part II - Other InformationItem 1.Legal Proceedings52Item 1ARisk Factors52Item 2.Unregistered Sales of Equity Securities and Use of Proceeds54Item 6.Exhibits55Signatures56







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EnerNOC, Inc.


UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS


(in thousands, except par value and share data)


June 30, 2015December 31, 2014ASSETSCurrent assetsCash and cash equivalents$143,555$254,351Restricted cash288813Trade accounts receivable, net of allowance for doubtful accounts of $948 and $679 at June 30, 2015 and December 31, 2014, respectively38,72940,875Unbilled revenue19,13197,512Capitalized incremental direct customer contract costs19,3567,633Deferred tax assets6,8926,524Prepaid expenses and other current assets16,42612,613Assets held for sale848—Total current assets245,225420,321Property and equipment, net of accumulated depreciation of $103,359 and $94,976 at June 30, 2015 and December 31, 2014, respectively49,65650,458Goodwill150,305114,939Intangible assets, net62,99931,111Capitalized incremental direct customer contract costs, net of current portion440982Deferred tax assets766680Deposits and other assets7,1716,211Total assets$516,562$624,702LIABILITIES AND STOCKHOLDERS’ EQUITYCurrent liabilitiesAccounts payable$2,255$9,250Accrued capacity payments46,24392,332Accrued payroll and related expenses20,68518,446Accrued expenses and other current liabilities25,19728,724Deferred revenue22,91913,738Liabilities held for sale48—Total current liabilities117,347162,490Accrued acquisition consideration1,1011,198Convertible senior notes140,928138,908Deferred tax liability16,85716,449Deferred revenue6,2795,816Other liabilities7,8707,721Commitments and contingencies (Note 8)——Stockholders’ equityUndesignated 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, 30,871,330 and 29,833,578 shares issued and outstanding at June 30, 2015 and December 31, 2014, respectively3130Additional paid-in capital371,665365,855Accumulated other comprehensive loss(7,402)(4,752)Accumulated deficit(138,342)(69,260)Total EnerNOC, Inc. stockholders’ equity225,952291,873Noncontrolling interest228247Total stockholders’ equity226,180292,120Total liabilities and stockholders’ equity$516,562$624,702


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


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EnerNOC, Inc.


UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


(in thousands, except share and per share data)


Three Months EndedSix Months EndedJune 30,June 30,2015201420152014Revenues:Grid operator$41,545$22,974$65,258$58,744Utility12,55711,96123,33822,270Enterprise18,3989,12034,45515,549Total revenues72,50044,055123,05196,563Cost of revenues33,54327,80265,49963,941Gross profit38,95716,25357,55232,622Operating expenses:Selling and marketing23,67019,52652,16638,025General and administrative28,45324,19156,74347,868Research and development7,7354,99715,18610,172Gain on sale of service line (Note 13)—(3,378)—(3,378)Gain on the sale of assets (Note 14)(2,991)(2,171)(2,991)(2,171)Total operating expenses56,86743,165121,10490,516Loss from operations(17,910)(26,912)(63,552)(57,894)Other income (expense), net1,705374(2,952)948Interest expense(2,240)(603)(4,532)(1,053)Loss before income tax(18,445)(27,141)(71,036)(57,999)(Provision for) benefit from income tax(345)(264)1,940161Net loss(18,790)(27,405)(69,096)(57,838)Net loss attributable to noncontrolling interest(10)(20)(14)(40)Net loss attributable to EnerNOC, Inc.$(18,780)$(27,385)$(69,082)$(57,798)Net loss per common shareBasic and diluted$(0.66)$(0.96)$(2.45)$(2.05)Weighted average number of common shares used in computing net loss per common shareBasic and diluted28,327,86728,461,11128,172,39828,225,518


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





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EnerNOC, Inc.


UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS


(in thousands)


Three Months EndedSix Months EndedJune 30,June 30,2015201420152014Net loss$(18,790)$(27,405)$(69,096)$(57,838)Foreign currency translation adjustments(108)347(2,650)894Comprehensive loss(18,898)(27,058)(71,746)(56,944)Comprehensive loss attributable to noncontrolling interest(15)(13)(19)(34)Comprehensive loss attributable to EnerNOC, Inc.$(18,883)$(27,045)$(71,727)$(56,910)


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





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EnerNOC, Inc.


UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


(in thousands)


Six Months EndedJune 30,20152014Cash flows from operating activitiesNet loss$(69,096)$(57,838)Adjustments to reconcile net loss to net cash (used in) provided by operating activities:Depreciation11,80310,845Amortization of acquired intangible assets7,9454,362Fair value adjustment of contingent purchase price409120Stock-based compensation expense7,2378,026Gain on sale of service line—(3,378)Gain on sale of assets(2,991)(2,171)Impairment of equipment and definite lived intangible assets480675Unrealized foreign exchange translation loss (gain)3,344(79)Deferred income taxes(2,123)627Non-cash interest expense2,540245Other, net356(63)Changes in operating assets and liabilities, net of effects of acquisitions:Trade accounts receivable10,70312,628Unbilled revenue78,30865,560Prepaid expenses and other current assets(5,820)(4,040)Capitalized incremental direct customer contract costs(11,200)(33,759)Other assets(887)290Other noncurrent liabilities167(488)Deferred revenue9,63629,936Accrued capacity payments(45,553)(38,656)Accrued payroll and related expenses(775)579Accounts payable, accrued expenses and other current liabilities(18,151)12,305Net cash (used in) provided by operating activities(23,668)5,726Cash flows from investing activitiesPurchases of property and equipment(11,290)(12,586)Payments made for acquisitions, net of cash acquired(77,559)(35,010)Payments made for investments—(1,000)Proceeds from sale of service line—4,275Proceeds from sale of assets2,9912,171Change in restricted cash and deposits2,323689Payments made for acquisition of customer contract—(403)Net cash used in investing activities(83,535)(41,864)Cash flows from financing activitiesProceeds from exercises of stock options1,017603Payments made for employee restricted stock minimum tax withholdings(3,147)(5,051)Net cash used in financing activities(2,130)(4,448)Effects of exchange rate changes on cash and cash equivalents(1,463)300Net change in cash and cash equivalents(110,796)(40,286)Cash and cash equivalents at beginning of period254,351149,189Cash and cash equivalents at end of period$143,555$108,903Supplemental disclosure of cash flow informationCash paid for interest$1,992$723Cash paid for income taxes$3,902$1,632Non-cash financing and investing activitiesIssuance of common stock in connection with acquisitions$103$—Issuance of common stock in satisfaction of bonuses$865$145


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


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EnerNOC, Inc.


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


(in thousands, except share and per share data)


1. Description of Business, Basis of Presentation and Summary of Significant Accounting Policies


Description of Business


EnerNOC, Inc. (the Company) is the leading provider of energy intelligence software (EIS) and related solutions. The Company’s enterprise customers use the Company's software to transform how they manage and control energy spend for their organizations, while utilities leverage the Company's software to better engage their customers and meet their demand-side management goals and objectives.


The Company’s EIS and related solutions provide its enterprise customers with a Software-as-a-Service (SaaS), solution to manage:


• energy supplier selection, procurement and implementation;


• energy budget forecasting;


• utility bills and payment;


• facility optimization, including the measurement, tracking, analysis and reporting on greenhouse gas emissions;


• project tracking;


• demand response, both in open and vertically-integrated markets; and


• peak demand and the related cost impact.


The Company’s EIS and related solutions provide its enterprise customers the visibility they need to prioritize resources against the activities that will deliver the highest return on investment. The Company offers its EIS and related solutions to its enterprise customers at four subscription levels: basic, standard, professional, and industrial. The Company delivers its SaaS solutions on all of the major Internet browsers and on leading mobile device operating systems. In addition to its EIS packages, the Company sells two categories of premium professional services, which it refers to as Software Enhancement Services and Energy & Procurement Services. The Company’s Software Enhancement Services help its enterprise customers set their energy management strategy and enhance the effectiveness of EIS deployment. The Company’s Energy and Procurement Services consist of audits, retro-commissioning, and supply procurement consulting. The Company’s target enterprise customers for its EIS and related solutions are organizations that spend approximately $100 /year or more per site on energy, and the Company sells to these customers primarily through its direct salesforce.


The Company’s EIS for utilities is a SaaS solution that provides utilities with customer engagement, energy efficiency and demand response applications, while improving operational effectiveness. The Company delivers shared value for both the utility and its customers by combining its deep expertise with enterprise customers with energy data analytics, machine learning, and predictive algorithms to deliver segmentation and targeting capabilities that enable utilities to serve their most complex market segments, including commercial, institutional and industrial end-users of energy, and small or medium-sized enterprises. The Company’s EIS and related solutions provide its utility customers with a cost-effective and holistic solution that improves customer satisfaction ratings, delivers savings and consumption reductions to help achieve energy efficiency mandates, manages system peaks and grid constraints, and increases demand for utility-provided products and services.


The Company’s EIS and related solutions for utilities customers and electric power grid operators also include the demand response solutions and applications, EnerNOC Demand ManagerTM and EnerNOC Demand ResourceTM. EnerNOC Demand Manager is a SaaS application that provides utilities with the underlying technology to manage their demand response programs and secure reliable demand-side resources. The Company’s EnerNOC Demand Manager product consists of long-term contracts with a utility customer for a SaaS solution that allows utilities to manage demand response capacity in utility-sponsored demand response programs. This product provides its utility customers with real-time load monitoring, dispatching applications, customizable reports, measurement and verification, and other professional services. The Company’s EnerNOC Demand Resource is a turnkey demand response resource where it matches obligation, in the form of megawatts (MW) that it agrees to deliver to the Company’s utility customers and electric power grid operators, with supply, in the form of MW that it is able to curtail from the electric power grid through its arrangements with its enterprise customers. When the Company is called upon by its utility customers and electric power grid operators 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 enterprise customer sites, making demand response capacity available to its utility customers and electric power grid operators on demand while helping its enterprise customers achieve energy savings, improve financial results and realize environmental benefits. The Company receives recurring payments from its utility customers and electric power grid operators for providing its EnerNOC Demand Resource and the Company shares these recurring payments with its enterprise customers in exchange for those enterprise customers reducing their power consumption when called upon by the Company to do so. The Company


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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 third-party 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.


Since inception, the Company’s business has grown substantially. The Company began by providing its demand response solutions in one state in the United States in 2003 and has expanded to providing its EIS and related solutions throughout the United States, as well as internationally in Australia, Brazil, Canada, China, Germany, India, Ireland, Japan, New Zealand, South Korea, Switzerland and the United Kingdom.





Basis of Consolidation


The unaudited condensed consolidated financial statements of the Company include the accounts of its wholly-owned subsidiaries and have been prepared in conformity with accounting principles generally accepted in the United States (GAAP). Intercompany transactions and balances are eliminated upon consolidation. The Company owns 60% of EnerNOC Japan K.K, for which it consolidates the operations in accordance with Accounting Standards Codification (ASC) 810, Consolidation (ASC 810). The remaining 40% represents non-controlling interest in the accompanying unaudited condensed consolidated balance sheets and 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.





Use of Estimates in Preparation of Financial Statements


The 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 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, 2014 , as filed with the SEC on March 12, 2015, and as amended on March 13, 2015 on Form 10-K/A, and include all adjustments (consisting of normal, recurring adjustments) necessary for the fair presentation of the Company’s financial position at June 30, 2015 and statements of operations and statements of comprehensive loss for the three and six months ended June 30, 2015 and 2014 and the statements of cash flows for the six months ended June 30, 2015 and 2014. Operating results for the three and six months ended June 30, 2015 are not necessarily indicative of the results to be expected for any other interim period or the entire fiscal year ending December 31, 2015 (fiscal 2015 ).


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 accrued acquisition consideration, expected future cash flows including growth rates, discount rates, terminal values and other assumptions and estimates used to evaluate the recoverability of long-lived assets and goodwill, estimated fair values of intangible assets and goodwill, amortization methods and periods, certain accrued expenses and other related charges, stock-based compensation, contingent liabilities, tax reserves and recoverability of the Company’s net deferred tax assets and related valuation allowance.


Although the Company regularly assesses these estimates, actual results could differ materially. The Company bases its estimates on historical experience and various other assumptions that it believes to be reasonable under the circumstances. Changes in estimates are recorded in the period in which they become known. 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 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.


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Summary of Significant Accounting Policies


Revenue Recognition


The Company derives recurring revenues from the sale of its EIS and related solutions. The Company’s customers include grid operators, utilities and enterprises. The Company does not recognize any revenues until persuasive evidence of an arrangement exists, delivery has occurred, the fee is fixed or determinable, and collection is deemed 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 the 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, the Company relies on historical data and known performance adjustments. These factors, and unanticipated changes in the economic and industry environment, could cause the 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. The Company’s revenue reserves were $475 as of June 30, 2015 and December 31, 2014 , respectively.


Revenues from grid operators and revenues from utilities principally represent demand response revenues. During the three and six months ended June 30, 2015 , revenues from grid operators and utilities were comprised of $51,559 and $84,144 , respectively, of demand response revenues. During the three and six months ended June 30, 2014, revenues from grid operators and utilities were comprised of $33,328 and $77,428 , respectively, of demand response revenues.


The Company’s enterprise revenues from the sales of its EIS and related solutions to its enterprise customers generally represent ongoing software or service arrangements under which the revenues are recognized ratably over the same period commencing upon delivery of the EIS and related solutions to the enterprise customer. Under certain of its arrangements, 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 enterprise 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 begins recognizing such revenue ratably over the expected enterprise customer relationship period (generally three years), once the enterprise 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 enterprise customer relationship period.


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The Company’s EIS and related solutions for utility customers and electric power grid operators also include the following demand response applications, EnerNOC Demand Manager and EnerNOC Demand Resource.


EnerNOC Demand Resource Solution


The Company’s grid operator revenues and utility revenues primarily reflect the sale of its EnerNOC Demand Resource solution. The revenues primarily consist of capacity and energy payments, including ancillary services payments, as well as payments derived from the effective management of its portfolio, including the Company’s participation in capacity auctions and third-party contracts and ongoing fixed fees for the overall management of utility-sponsored demand response programs. The Company derives revenues from its EnerNOC Demand Resource solution by making demand response capacity available in open market programs and pursuant to contracts that are entered into with electric power grid operators and utilities. In certain markets, the Company enters into contracts with electric power utilities, generally ranging from three to ten years in duration, to deploy its EnerNOC Demand Resource solution. The Company refers to these contracts as utility contracts.


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.


Demand response capacity revenues related to the Company’s participation in the PJM open market program for its Limited demand response product (referred to as the PJM summer-only open market program in prior filings) are being recognized at the end of the four month delivery period of June through September, or during the three months ended September 30th 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 Limited demand response product are recognized during the three months ended September 30th. As a result of the billing period not coinciding with the revenue recognition period, the Company had $17,510 and $96,404 in unbilled revenues from PJM at June 30, 2015 and December 31, 2014, respectively.


Two new demand response programs were introduced in the PJM market beginning in the 2014/2015 delivery year (June 1, 2014-May 31, 2015): the Extended and Annual demand response programs. Under the PJM Extended program, the delivery period is from June through October and then May in the subsequent calendar year. The revenues and any associated penalties, if any, for underperformance related to participation in the PJM Extended demand response program are separate and distinct from the Company’s participation in other offerings within the PJM open market program. Under the PJM Extended demand response program, penalties incurred as a result of underperformance for a demand response event dispatched during the months of June through September and for a demand response test event are substantially the same as the PJM Limited demand response program service offering that the Company has historically participated in. However, penalties incurred as a result of underperformance for an event dispatched during the month of October or the month of May are 1/52 multiplied by the number of the shortfall amount (committed capacity less actual delivered capacity) times the applicable capacity rate. Consistent with the PJM Limited demand response program, the fees paid under this program could potentially be subject to adjustment or refund based on performance during the applicable performance period. Due to the lack of historical performance experience with the PJM Extended program, the Company is unable to reliably estimate the amount of fees potentially subject to adjustment or refund as of the end of September. Therefore, until the Company is able to reliably estimate the amount of fees potentially subject to adjustment or refund, revenue from the PJM Extended program will be deferred and recognized at the end of the delivery period (i.e., May). Under the PJM Annual program, the delivery period is from June through May of the following year. The 2015/2016 delivery year began on June 1, 2015 and ends on May 31, 2016. Consistent with the Limited and Extended programs, to the extent the Company has MW obligation in the Annual program, until the Company is able to reliably estimate the amount of fees potentially subject to adjustment or refund, revenue from the PJM Annual program will be deferred and recognized at the end of the delivery period (i.e., May). However, in the event the Company reduces its MW obligation for a given program to zero through the effective management of its portfolio, including the Company’s participation in PJM incremental auctions, the Company recognizes revenue from such products at the beginning of the delivery year.


Demand response capacity revenues related to the Company’s participation in the Western Australia open market are potentially subject to refund and therefore, are deferred until a portion of such capacity revenues are reliably estimable, which occurs upon an emergency event dispatch or at the end of the program period on September 30th. Historically all capacity revenues have been recognized during the three months ended September 30th as there have previously been no emergency


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event dispatches. As of September 30, 2014, the Company determined that the amount of fees potentially subject to adjustment or refund was reliably estimable beginning with the new program year in Western Australia commencing on October 1, 2014. Therefore, beginning during the fourth quarter of 2014, revenues are recognized ratably over the delivery period from October 1 to September 30.


Demand response energy 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 and six months ended June 30, 2015 , the Company recognized $609 and $893 , respectively, of energy event revenues, and during the three and six months ended June 30, 2014, the Company recognized $4,199 and $24,769 , respectively, of energy event revenues.





The Company recorded an adjustment in the consolidated statement of operations for the three months ended June 30, 2015 to correct the presentation of certain revenues on a year-to-date basis. This correction resulted in an increase to both grid operator revenue and cost of revenue of $558 for the three months ended June 30, 2015.  In addition, the Company recorded an adjustment in the consolidated statement of operations to increase cost of goods sold by approximately $1,191 relating to the recognition of payments owed to enterprise customers enrolled in demand response programs, of which approximately $581 and $610 related to the three months ended March 31, 2015 and the year ended December 31, 2014, respectively.   The Company assessed the materiality of the historical misstatements, individually and in aggregate, on its prior annual and quarterly consolidated financial statements and concluded the effect of the error was not material to its consolidated financial statements for any of the periods.


The Company has evaluated the forward capacity programs in which it 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).


The Company has evaluated the factors within ASC 605, Revenue Recognition (ASC 605), regarding gross versus net revenue reporting for its demand response revenues and its payments to enterprise 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 enterprise customers to deliver such services. The Company manages all interactions with the electric power grid operators and utilities, while enterprise 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 enterprise 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 enterprise 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 payments to enterprise customers and has complete discretion in the contracting process with enterprise customers.


• The Company has complete discretion in determining which suppliers (enterprise customers) will provide the demand response services, provided that the enterprise 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 enterprise customer loads.





As a result, the Company has concluded 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 enterprise customers as cost of revenues.


EnerNOC Demand Manager Solution


With respect to EnerNOC Demand Manager, the Company generally receives an ongoing fee for overall management of the utility demand response program based on enrolled capacity or enrolled enterprise customers, which is not subject to


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adjustment based on performance during a demand response dispatch. The Company recognizes utility revenues from these fees ratably over the applicable service delivery period commencing upon when the enterprise 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 enterprise customer installations. The Company has determined that 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, these fees are recognized over the estimated customer relationship period, which is generally the greater of three years or the contract period, commencing upon the enrollment of the enterprise customers and delivery of the contracted services.


The Company follows the provisions of ASC Update No. 2009-13, Multiple-Deliverable Revenue Arrangements . 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 stand-alone 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 other EIS software and related solutions.


Stock-Based Compensation


The Company grants share-based awards to employees, non-employees, members of the board and advisory board members. The Company accounts for grants of stock-based compensation in accordance with ASC 718, Stock Compensation (ASC 718). The Company accounts for share-based awards granted to non-employees in accordance with ASC 505-50, Equity Based Payments to Non-Employees , which results in the Company continuing to re-measure the fair value of the non-employee share-based awards until such time as the awards vest. All share-based awards granted, including grants of stock options, restricted stock and restricted stock units, are recognized in the statement of operations based on their fair value as of the date of grant. As of June 30, 2015 , the Company had two stock-based compensation plans, which is more fully described in Note 9.


All shares underlying awards of restricted stock are restricted in that they are not transferable until they vest. Restricted stock typically vests ratably over a four year period from the date of issuance, with certain exceptions. 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.


Stock-based compensation expense recorded in the unaudited condensed consolidated statements of operations was as follows:


Three Months EndedJune 30,Six Months EndedJune 30,2015201420152014Selling and marketing expenses$308$1,372$1,951$2,565General and administrative expenses2,6962,1085,1264,804Research and development expenses317319653657Total stock-based compensation expense (1)$3,321$3,799$7,730$8,026


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(1) Stock-based compensation expense for the three and six months ended June 30, 2015 include $15 and $493 , respectively, related to the acquisition of World Energy that was settled with the equivalent cash payments.


In June 2015, the Company entered into a separation agreement with a former employee. The Company recorded a reversal of previously recognized stock-based compensation expense during the three months ended June 30, 2015 in the amount of $834 related to the cancellation of non-vested awards upon termination.


Stock-based compensation expense related to share-based awards granted to non-employees was not material for the three and six months ended June 30, 2015 and 2014 . The Company did not recognize income tax benefits from stock-based compensation arrangements during the three and six months ended June 30, 2015 and 2014 .  No material stock-based compensation expense was capitalized during the three and six months ended June 30, 2015 and 2014 .


The Company’s chief executive officer is required to receive his performance-based bonus, if achieved, in shares of the Company's common stock. The Company recorded this amount as stock-based compensation expense ratably over the applicable performance and service period in accordance with ASC 718. During the three and six months ended June 30, 2015 , the Company recorded $140 and $253 of stock-based compensation expense related to this performance based bonus.  During the three and six months ended June 30, 2014, the Company recorded $128 and $253 of stock-based compensation expense related to this performance based bonus.


Foreign Currency Translation


The financial statements of the Company’s international subsidiaries are translated in accordance with ASC 830, Foreign Currency Matters (ASC 830), into the Company’s reporting currency, which is the United States dollar. The functional currencies of the Company’s subsidiaries in Australia, Brazil, Canada, China, Germany, Ireland, India, Japan, New Zealand, South Korea, Switzerland and the United Kingdom are the local currencies.


Assets and liabilities are translated to the United States dollar from the local functional currency at the exchange rate in effect at each balance sheet date. Before translation, the Company re-measures foreign currency denominated assets and liabilities, including certain inter-company accounts receivable and payable which have not been deemed a “long-term investment,” as defined by ASC 830, into the functional currency of the respective entity, resulting in unrealized gains or losses recorded in the unaudited condensed consolidated statements of operations. Revenues and expenses are translated using average exchange rates during the respective periods.


Foreign currency translation adjustments are recorded as a component of stockholders’ equity within accumulated other comprehensive loss. Gains (losses) arising from transactions denominated in foreign currencies and the remeasurement of certain intercompany receivables and payables are included in other income (expense), net on the unaudited condensed consolidated statements of operations and were $1,680 and $247 for the three months ended June 30, 2015 and 2014 , respectively, and ($3,297) and $634 for the six months ended June 30, 2015 and 2014 , respectively.


Comprehensive Loss


Comprehensive loss is defined as the change in equity of a business enterprise during a period resulting from transactions and other events and circumstances from non-owner sources. The Company’s comprehensive loss is composed of net loss and foreign currency translation adjustments. As of June 30, 2015 and December 31, 2014 , 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 is zero.


Software Development Costs


The Company applies the provisions of ASC 350-40, Internal-Use Software (ASC 350-40). ASC 350-40 requires computer software costs associated with internal use software to be expensed as incurred until certain capitalization criteria are met, and it also defines which types of costs should be capitalized and which should be expensed. The Company capitalizes the payroll and payroll-related costs of employees and applicable third-party costs who devote time to the development of internal-use computer software and amortizes these costs on a straight-line basis over the estimated useful life of the software, which is generally three years. The Company’s judgment is required in determining the point at which various projects enter the stages at which costs may be capitalized, in assessing the ongoing value and impairment of the capitalized costs, and in determining the estimated useful lives over which the costs are amortized. Internal use software development costs of $1,336 and $1,743 for the three months ended  June 30, 2015 and 2014 , respectively, and $3,139 and $3,141 for the six months ended June 30, 2015 and 2014 , have been capitalized in accordance with ASC 350-40. Amortization of capitalized software development costs was $1,730 and $1,496 for the three months ended  June 30, 2015 and 2014 , respectively and $3,396 and $3,026 for the six months ended June 30, 2015 and 2014 , respectively. Accumulated amortization of capitalized software development costs was $30,999 and $27,603 as of June 30, 2015 and December 31, 2014 , respectively.


The costs for the development of new software and substantial enhancements to existing software that is intended to be sold or marketed (external use software) are expensed as incurred until technological feasibility has been established, at which time any additional costs would be capitalized. The Company has determined that technological feasibility of external use


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software is established at the time a working model of software is completed. Because the Company believes its current process for developing external use software will be essentially completed concurrently with the establishment of technological feasibility, no such costs have been capitalized to date.


Impairment of Long Lived Assets


The Company reviews long-lived assets, including property and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of assets may not be recoverable over its remaining estimated useful life. If these assets are considered to be impaired, the long-lived assets are measured for impairment at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets or liabilities. Impairment is recognized in earnings and equals the amount by which the carrying value of the assets exceeds their fair value determined by either a quoted market price, if any, or a value determined by utilizing a discounted cash flow (DCF) technique. If these assets are not impaired, but their useful lives have decreased, the remaining net book value is amortized over the revised useful life.


During the three and six months ended June 30, 2015 and 2014 , the Company identified certain impairment indicators related to certain demand response equipment as a result of the removal of such equipment from operational sites during each of these respective years. As such, the equipment had no remaining useful life and no fair value. The remaining net carrying value was written off, resulting in the recognition of impairment charges of $287 and $257 , for the three months ended June 30, 2015 and 2014, respectively, and $425 and $352 , for the six months ended June 30, 2015 and 2014, respectively, which is included in cost of revenues in the unaudited condensed consolidated statements of operations.  The Company also recognized impairment charges of $55 related to definite lived intangible assets for the three and six months ended June 30, 2015 , which is included in cost of revenues.  For the three and six months ended June 30, 2014, the Company recognized $160 and $323 related to impairment of definitive lived intangible assets.


Goodwill Impairment


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.  Events that would indicate impairment and trigger an interim impairment assessment include, but are not limited to, current economic and market conditions, including a decline in market capitalization, a significant adverse change in legal factors, business climate or operational performance of the business, and an adverse action or assessment by a regulator. The Company's annual impairment test date is November 30 (Impairment Test Date).


In performing the test, the Company utilizes the two-step approach prescribed under ASC 350. The first step requires a comparison of the carrying value of the reporting units to the fair value of these units. The Company considers a number of factors to determine the fair value of a reporting unit, including an independent valuation to conduct this test. The valuation is based upon expected future discounted operating cash flows of the reporting unit as well as analysis of recent sales or offerings of similar companies. The Company bases the discount rate used to arrive at a present value as of the date of the impairment test on its weighted average cost of capital (WACC). If the carrying value of the reporting unit exceeds its fair value, the Company will perform the second step of the goodwill impairment test to measure the amount of impairment loss, if any. The second step of the goodwill impairment test compares the implied fair value of a reporting unit’s goodwill to its carrying value.


In order to determine the fair values of reporting units, the Company utilizes both a market approach based on the quoted market price of its common stock and the number of shares outstanding and a DCF model under the income approach. The key assumptions that drive the fair value in the DCF model are the discount rates (i.e., WACC), terminal values, growth rates, and the amount and timing of expected future cash flows. If the current worldwide financial markets and economic environment were to deteriorate, this would likely result in a higher WACC because market participants would require a higher rate of return. In the DCF, as the WACC increases, the fair value decreases. The other significant factor in the DCF is its projected financial information (i.e., amount and timing of expected future cash flows and growth rates) and if its assumptions were to be adversely impacted this could result in a reduction of the fair value of the entity. As a result of completing the first step of the impairment assessment on the Impairment Test Date, the fair values (for the Company's reporting units) exceeded the carrying values for both reporting units, and as such, the second step was not required. To date, the Company has not been required to perform the second step of the impairment test.


The annual impairment testing process is subjective and requires judgment at many points throughout the analysis. If these estimates or their related assumptions change in the future, the Company may be required to record impairment charges for these assets not previously recorded.


Industry Segment Information


The Company views its operations and manages its business as one operating segment. Operating segments are defined as components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, in making decisions on how to allocate resources and assess performance. The Company has determined that its chief operating decision maker is its Chief Executive Officer.


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The Company operates in the major geographic areas noted in the chart below. The “All other” designation includes revenues from other international locations, primarily consisting of Germany, Ireland, New Zealand, South Korea and the United Kingdom. Revenues are based upon customer location and internationally totaled $20,983 and $13,551 for the three months ended June 30, 2015 and 2014 , respectively and $41,552 and $22,731 for the six months ended June 30, 2015 and 2014 .


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


Three Months Ended June 30,Six Months Ended June 30,2015201420152014United States71%69%66%76%Australia1011126Canada11131112All other87116Total100%100%100%100%





As of June 30, 2015 and December 31, 2014, the long-lived tangible assets related to the Company’s international subsidiaries were less than 10% of the Company’s long-lived tangible assets and were deemed not material.


2. Acquisition


World Energy Solutions, Inc.


On January 5, 2015, the Company completed the acquisition of World Energy Solutions, Inc., or World Energy, an energy management software and services firm located in Worcester, Massachusetts that helps enterprises to simplify the energy procurement process through a suite of SaaS tools. The Company believes that the acquisition and integration of World Energy’s software into its EIS platform will help deliver more value to its enterprise customers through enhanced technology-enabled capabilities to manage the energy procurement process.


The Company concluded that this acquisition represented a business combination under the provisions of ASC 805, Business Combinations (ASC 805), but has 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 World Energy.


The Company acquired World Energy for a purchase price of $5.50 per share and the assumption of debt for an aggregate purchase price of $79,913 , or $77,211 net of $2,702 in acquired cash. The Company paid cash of $68,538 for shares outstanding and $9,468 to repay debt. In addition, the Company was required to exchange and replace the outstanding share based awards of World Energy on the acquisition date.  The Company cash settled the outstanding restricted stock awards and vested stock options for which the per share exercise price was equal to or less than $5.50 per share, and issued replacement awards for World Energy vested, out-of-the-money stock options and non-vested stock options for a total value of $3,027 .  Of this amount, $1,849 was determined to be purchase price consideration and $1,178 was determined to be post combination stock-based compensation expense ( $443 was recognized immediately as expense upon the close of the transaction as there was no remaining service period, with the remaining expense to be recognized over a period of 2.3 years ).  In addition, the Company paid $58 for outstanding warrants.


Transaction costs of $367 related to World Energy were expensed as incurred and are included in general and administrative expenses in the Company’s unaudited condensed consolidated statements of operations.


The Company allocated the purchase price to the net tangible assets and intangible assets based upon their fair values at January 5, 2015. The difference between the aggregate purchase price and the fair value of assets acquired and liabilities assumed was allocated to goodwill, none of which is deductible for tax purposes. The Company's acquired identifiable intangible assets include $29,160 of customer relationships and $12,240 of developed technology. 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 amortizes these acquired 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. As of June 30, 2015, the acquired intangible assets will be amortized as follows: customer relationships (backlog) of 1.6 years ; customer relationships (contract renewals) of 7.1 years and developed technology of 4.2 years .


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The following table summarizes the purchase consideration paid for World Energy: Purchase consideration:Cash paid for stock, stock awards and warrants$70,445Repayment of debt9,468Fair value of consideration transferred$79,913





As of the filing date of this Quarterly Report on Form 10-Q, the Company is still in the process of valuing the assets acquired and liabilities assumed of World Energy’s business, including accounts receivable, deferred taxes, intangible assets and accrued expenses and other liabilities.


Cash$2,702Accounts receivable (1)9,550Prepaid expenses and other current assets1,596Property and equipment449Identified intangible assets41,400Goodwill38,956Accounts payable, accrued expenses and other liabilities (1)(12,247)Deferred revenue(320)Deferred tax liabilities, net(2,173)Total$79,913


(1) During the three months ended June 30, 2015, the Company recorded an acquisition accounting adjustment of $513 to accounts receivable and accrued expenses and other liabilities. The acquisition accounting is not complete and additional information that existed at the acquisition date may become known to the Company during the remainder of the measurement period.





World Energy Efficiency Services - Assets and liabilities held for sale


The acquisition of World Energy included the World Energy Efficiency Services business (WEES), which provides comprehensive, turnkey direct install energy efficiency services in New England.  As of the acquisition date of January 5, 2015, the Company committed to a plan to sell the WEES business. Based on the Company’s evaluation of the assets held for sale criteria under ASC 360-10, Impairment and Disposal of Long-Lived Assets , the Company concluded all of the criteria were met and that the assets and liabilities of the WEES business (Plan of Sale) that are expected to be sold should be classified as held for sale as of January 5, 2015. A definitive asset purchase agreement was executed on July 31, 2015 and subject to customary closing conditions, the sale of WEES is expected to close during the three month period ended September 30, 2015.


The held for sale balances relate to operational assets and liabilities associated with in-progress contracts, and separately identifiable intangible assets, including customer relationships and developed technology that were acquired in connection with the World Energy acquisition and specifically relate to WEES. Because the Company has concluded that WEES meets the definition of a business in accordance with ASC 805, included in assets held for sale is the allocated goodwill of WEES.


During the three months ended June 30, 2015, there was a change to the Plan of Sale related to certain assets and liabilities originally classified as held for sale.  As a result, the Company determined that identified intangible assets of $800 previously classified as held for sale will be excluded from the plan of sale and will be held and used by the Company. The Company recognized amortization expense of $400 during the three months ended June 30, 2015 to adjust the asset's carrying value for the change in estimate as of June 30, 2015.


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The following table summarizes the assets and liabilities held for sale as of June 30, 2015: As of June 30, 2015Goodwill$705Inventories94Fixed assets49Assets held for sale$848Accounts payable$(38)Deferred revenue(10)Liabilities held for sale$(48)


The Company has concluded that the WEES disposal does not meet the criteria of discontinued operations under ASC 205-20, Discontinued Operations because the sale of the WEES business does not represent a strategic shift that had a major effect on the Company's operations and financial results and therefore, the results of operations of WEES have not been presented as discontinued operations in the Company’s unaudited condensed consolidated statement of operations for the three and six months ended June 30, 2015.


3. Intangible Assets


The following table provides the gross carrying amount and related accumulated amortization of the Company's definite-lived intangible assets as of June 30, 2015 and December 31, 2014 :


As of June 30, 2015As of December 31, 2014Weighted AverageAmortizationPeriod (in years)GrossCarryingAmountAccumulatedAmortizationGrossCarryingAmountAccumulatedAmortizationCustomer relationships6.57$65,231$(24,390)$37,516$(19,725)Customer contracts1.634,875(3,896)4,912(3,618)Employment and non-compete agreements1.083,126(2,054)3,198(1,821)Software0.00120(120)120(120)Developed technology6.1725,138(5,257)13,615(3,407)Trade name0.351,102(961)1,124(777)Patents4.63180(95)180(86)Total$99,772$(36,773)$60,665$(29,554)


Amortization expense related to definite-lived intangible assets amounted to $4,027 and $2,479 for the three months ended  June 30, 2015 and 2014 , respectively and $7,945 and $4,362 for the six months ended June 30, 2015 and 2014 , respectively. Amortization expense for acquired developed technology, which was $935 and $616 for the three months ended  June 30, 2015 and 2014 , respectively, and $1,925 and $967 for the six months ended June 30, 2015 and 2014 , respectively is included in cost of revenues in the unaudited condensed consolidated statements of operations. Amortization expense for all other intangible assets is included as a component of operating expenses in the unaudited condensed consolidated statements of operations. The definite-lived intangible asset lives range from 1 to 15 years and the weighted average remaining life was 6 years at June 30, 2015 . Amortization expense is estimated to be approximately $7,420 , $12,796 , $9,797 , $7,107 , $6,349 and $19,530 for the six months ending December 31, 2015 , and years ending 2016, 2017, 2018, 2019 and beyond, respectively.


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4. Goodwill


The following table shows the change of the carrying amount of goodwill from December 31, 2014 to June 30, 2015 :


Balance at December 31, 2014$114,939Foreign currency translation impact(2,885)Acquisition of World Energy (Note 2)38,956Assets held for sale(705)Balance at June 30, 2015$150,305


5. Net Loss Per Share


ASC 260, Earnings Per Share (ASC 260), provides guidance on the computation, presentation and disclosure guidance for earnings per share. In particular, ASC 260-10-45-40 provides guidance on the earnings-per-share (EPS) ramifications of convertible securities. Under the terms of our convertible senior notes, conversion of the Notes may only be settled in shares of the Company's common stock.  However, under the terms of the Notes, the Company could have the option to settle conversions of the Notes in cash, shares of its common stock, or through any combination of cash and common stock, at its election, if shareholder approval is obtained (flexible settlement).


On May 27, 2015, the Company received stockholder approval at its annual meeting of stockholders (the Annual Meeting), to elect to settle conversions of Notes by paying or delivering, as the case may be, cash, shares of common stock or a combination of cash and shares of common stock. Under the applicable accounting standards, if the entity controls the means of settlement and past experience or a stated policy provides a reasonable basis to believe that the contract will be partially or wholly settled in cash. Therefore, because the Notes are now subject to flexible settlement, the Company may be eligible to account for the Notes using the “treasury stock” method of calculating diluted earnings per share, the effect of which is that the shares issuable upon conversion of convertible debt instruments are not included in the calculation of diluted earnings per share except to the extent that the conversion value of such convertible debt instruments exceeds their principal amount.


Prior to the shareholder approval at the Annual Meeting, the Company had determined the impact of the convertible notes on diluted EPS using the “if-converted” method. Under the “if-converted” method:





|  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | The Company (1) adds back interest expense recognized on the convertible debt to income available to common shareholders, (2) adjusts income available to common shareholders to the extent nondiscretionary adjustments based on income made during the period would have been computed differently had the interest on convertible debt never been recognized (e.g., expense associated with a profit sharing plan or a royalty agreement), and (3) adjusts income available to common shareholders for the income tax effect, if any, of (1) and (2).

|  |                                                                                                                                                                                                           
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | The convertible debt is assumed to have been converted at the beginning of the period (or at time of issuance, if later), and the resulting common shares is included in the number of shares outstanding.

For the three and six months ended June 30, 2015 , the convertible debt is not assumed to be converted as the impact is anti-dilutive.


Net loss attributable to EnerNOC, Inc. utilized in the calculation of net loss per share was the same for basic and diluted.


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A reconciliation of basic and diluted share amounts for the three and six months ended June 30, 2015 and 2014 are as follows:


Three Months EndedJune 30,Six Months EndedJune 30,2015201420152014Basic weighted average common shares outstanding28,327,86728,461,11128,172,39828,225,518Weighted average common stock equivalents————Diluted weighted average common shares outstanding28,327,86728,461,11128,172,39828,225,518Anti-dilutive shares related to:Stock options448,910833,076416,375864,054Nonvested restricted stock2,134,8632,136,8562,078,5812,133,837Restricted stock units42,605—77,1058,894Convertible debt5,774,928—5,774,928—


In the table above, 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. The convertible debt is not assumed to be converted as the impact is anti-dilutive. 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, 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 June 30, 2015 , the Company had 87,483 shares of common stock held in escrow.


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


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6. Fair Value Measurements


The Company’s financial instruments mainly consist of cash and cash equivalents, restricted cash, accounts receivable and accounts payable. The carrying amounts of these financial instruments approximate their respective fair value due to their short-term nature. The Company has $160,000 of convertible debt outstanding (See Note 7) as of June 30, 2015 . The fair value of the convertible debt was approximately $116,480 and $133,392 as of June 30, 2015 and December 31, 2014 and was determined based on the quoted market price and is classified as Level 1 measurement.


The table below presents the balances of assets and liabilities measured at fair value on a recurring basis at June 30, 2015 and December 31, 2014 : TotalsQuoted Prices inActive Marketsfor IdenticalAssets (Level 1)Significant OtherObservable Inputs(Level 2)Unobservable Inputs(Level 3)Fair Value Measurement at June 30, 2015Assets: Money market funds (1)$112,483$112,483$—$—Liabilities: Contingent purchase price consideration (2)742——742
 Fair Value Measurement at December 31, 2014Assets: Money market funds (1)$225,815$225,815$—$—Liabilities: Contingent purchase price consideration (2)649——649


(1) The money market funds balance included in cash and cash equivalents 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.


(2) Accrued contingent purchase price consideration relates to the Company’s acquisitions of Activation Energy DSU Limited, (Activation Energy), and Entelios AG, (Entelios), in February 2014. As of June 30, 2015 , approximately $642 associated with the Activation Energy acquisition has been reflected in accrued expense and other current liabilities in the condensed consolidated balance sheet. The additional $100 relates to the Entelios earn-out, which is reflected in accrued acquisition consideration in the condensed consolidated balance sheet.


(3) Accrued contingent purchase price consideration relates to the Company’s acquisitions of Activation Energy and Entelios. As of December 31, 2014, approximately $312 associated with the Activation Energy acquisition was recorded in accrued expense and other current liabilities in the condensed consolidated balance sheet. The remaining $337 was recorded in accrued acquisition consideration in the condensed consolidated balance sheet, of which $234 related to the Activation Energy acquisition and $103 related to the Entelios acquisition.


The following is a rollforward of the Level 3 assets and liabilities from January 1, 2015 through June 30, 2015 :


LiabilitiesBalance January 1, 2015$649Cash payment during the period(277)Increase due to change in assumptions and present value accretion409Change due to movement in foreign exchange rates(39)Balance June 30, 2015$742


7. Borrowings and Credit Arrangements


Credit Agreement


On August 11, 2014, the Company entered into a $30,000 senior secured revolving credit facility, the full amount of which may be available for issuances of letters of credit, pursuant to a loan and security agreement (the 2014 credit facility) with Silicon Valley Bank (SVB), which was subsequently amended on October 23, 2014. The 2014 credit facility is subject to continued covenant compliance and borrowing base requirements. As of June 30, 2015 , the Company was in compliance with all of its covenants under the 2014 credit facility. On August 6, 2015, the Company and SVB entered into a second amendment to the 2014 credit facility to extend the termination date from August 11, 2015 to August 9, 2016. The Company believes that it


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is reasonable it will comply with the covenants of the 2014 credit facility through its expiration date of August 9, 2016. As of June 30, 2015 , the Company had no borrowings, but had outstanding letters of credit totaling $20,284 under the 2014 credit facility. As of June 30, 2015 , the Company had $9,716 available under the 2014 credit facility for future borrowings or issuances of additional letters of credit.


Convertible Notes


On August 12, 2014, the Company entered into a purchase agreement with Morgan Stanley & Co. LLC relating to the Company’s sale of $160,000 aggregate principal amount of 2.25% convertible senior notes due August 15, 2019 (the Notes), as amended (the Offering). The Notes includes customary terms and covenants, including certain events of default after which the Notes may be declared or become due and payable immediately. The Notes are convertible at an initial conversion rate of 36.0933 shares of the common stock per $1,000 principal amount of Notes. However, because the Company received approval at the Annual Meeting, it may elect to settle conversions of Notes by paying or delivering, as the case may be, cash, shares of common stock or a combination of cash and shares of common stock. The conversion rate will be subject to adjustment in some events, but will not be adjusted for any accrued and unpaid interest.


The Company has concluded that ASC 470, Debt applies to the Notes and accordingly, the Company is required to account for the liability and equity components of its Notes separately to reflect its nonconvertible debt borrowing rate. The estimated fair value of the liability component at issuance of $137,430 was determined using a discounted cash flow technique. The excess of the gross proceeds received over the estimated fair value of the liability component totaling $22,570 has been allocated to the conversion feature (equity component) with a corresponding offset recognized as a discount to reduce the net carrying value of the Notes. The discount is being amortized to interest expense over a five year period ending August 15, 2019 (the expected life of the liability component) using the effective interest method. In addition, transaction costs are required to be allocated to the liability and equity components based on their relative percentages. The applicable transaction costs allocated to the liability and equity components at issuance were $4,056 and $666 , respectively. The transaction costs allocated to the liability represent debt issuance costs which are recorded as an asset and are being amortized to interest expense on a straight-line basis over a five year period. As of June 30, 2015 , $723 and $2,761 of deferred issuance costs are included in prepaid expenses and other current assets and deposits and other assets, respectively, in the Company’s unaudited condensed consolidated balance sheet.


Interest expense under the Notes is as follows:


June 30, 2015Three Months EndedSix Months EndedAccretion of debt discount$1,028$2,020Amortization of deferred financing costs170333Non-cash interest expense1,1982,3532.25% accrued interest9001,780Total interest expense from Notes$2,098$4,133


Based on the Company’s evaluation of the Notes in accordance with ASC 815-40, Contracts in Entity’s Own Equity , the Company determined that the Notes contain a single embedded derivative, comprising both the contingent interest feature related to timely SEC filing failure, requiring bifurcation as the features is not clearly and closely related to the host instrument. The Company has determined that the value of this embedded derivative was nominal as of the date of issuance and as of June 30, 2015 .


8. Commitments and Contingencies


In July 2012, the Company entered into a lease for its corporate headquarters at One Marina Park Drive, 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. In October 2014, the Company entered into an amendment to this lease to lease additional space. The lease term for this additional space commenced on January 1, 2015 and coincides with the term of the existing lease unless earlier terminated or further extended as provided for in the existing lease. The lease amendment contains both a rent holiday, under which lease payments did not commence until June 2015, and escalating rental payments. As a result, the Company recorded rent on a straight-line basis in accordance with ASC 840 beginning upon the lease commencement date. In June 2015, the Company entered into an agreement to sublease a portion of the additional space noted above commencing August 2015. The sublease term is through August 2017 and provides for straight-line rent payments over the lease term.


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In connection with the Company’s acquisitions completed in 2014 and January 2015, the Company acquired certain facility operating lease arrangements which were all considered to contain current market terms and rates. These leases have original lease terms between one and ten years and expire through September 2022. Certain of the leases require payments for additional expenses such as taxes, maintenance, and utilities and contain fair value renewal options. There were no ongoing rent holidays or escalating rent payments over the remaining lease terms as of the dates of acquisition.


In accordance with ASC 840, Leases (ASC 840), the Company recorded the lease incentives as deferred rent and will reflect these amounts as reductions of lease expense over the lease term. As of June 30, 2015 and December 31, 2014 , the Company had a deferred rent liability of $7,481 and $7,296 , respectively, of which $ 3,260 and $ 3,584 relate to landlord lease incentives. The remaining balances represent rent expense recorded on a straight-line basis in excess of contractual lease payments. These amounts are included in other liabilities in the accompanying unaudited condensed consolidated balance sheets.


As of June 30, 2015 , the Company was contingently liable under outstanding letters of credit for $20,284 . As of June 30, 2015 and December 31, 2014 , the Company had restricted cash balances of $288 and $813 , respectively, which primarily related 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 June 30, 2015 were $19,355 and included deposits held by certain customers of $1,307 at June 30, 2015 . 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 June 30, 2015 , the Company had $558 in deferred fees for these arrangements which were included in deferred revenues as of June 30, 2015 . As of June 30, 2015 , 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 $8,028 .


As of June 30, 2015 and December 31, 2014 , the Company accrued $570 and $344 , respectively, of performance adjustments related to fees received for its contractual commitments and participation in certain demand response programs. The Company believes that it is probable that these performance adjustments will need to be re-paid to the utility or electric power grid operator and since the utility or 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.


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 June 30, 2015 , the payment due upon termination would be $928 .


On March 15, 2011, the Federal Energy Regulatory Commission (FERC) issued Order 745, Demand Response Compensation in Organized Wholesale Energy Markets, which was effective April 25, 2011. Under Order 745, FERC amended its regulations under the Federal Power Act to ensure that when a demand response resource participating in an organized wholesale energy market administered by a Regional Transmission Organization (RTO) or Independent System Operator (ISO) has the capability to balance supply and demand as an alternative to a generation resource and when dispatch of that demand response resource is cost-effective as determined by the net benefits test described in Order 745, that demand response resource must be compensated for the service it provides to the energy market at the market price for energy, referred to as the locational marginal price (LMP). As a result, Order 745 impacted the energy rates that the Company received in two open market economic demand response programs.


On May 23, 2014, the United States Court of Appeals for the District of Columbia Circuit, or the Court, issued two orders (EPSA v. FERC) related to Order 745. In a 2-1 decision of a panel of the Court, the Court vacated Order 745 on the grounds that FERC lacked jurisdiction over demand response. The Court further stayed its own order until seven days following disposition of any timely petition for rehearing. Order 745 relates exclusively to compensation in FERC jurisdictional


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wholesale energy markets, and by its terms does not apply to FERC jurisdictional capacity markets. On June 11, 2014, FERC and other parties filed motions seeking rehearing en banc of the 2-1 decision vacating Order 745, which motions were denied on September 17, 2014. On September 22, 2014, FERC filed a motion with the Court to stay the issuance of the Court’s mandate in EPSA v. FERC until December 16, 2014. The Court granted that motion and subsequently granted a second motion to extend the stay until January 15, 2015, and thereafter if a petition for a writ of certiorari were filed with the United States Supreme Court. FERC, the Company and a number of other parties filed petitions for a writ of certiorari in the U.S. Supreme Court on January 15, 2015.  On May 4, 2015, the U.S. Supreme Court granted petitioners’ writs of certiorari and oral arguments have been scheduled for October 14, 2015. As a result, Order 745 remains in effect per the Court’s stay until after the U.S. Supreme Court issues its decision.


Pursuant to the Federal Power Act, Order 745 was implemented “subject to refund,” which means that FERC retained the discretion to order refunds, if appropriate, of revenues associated with implementation of Order 745. The “subject to refund” requirement does not require refund, and given FERC’s past treatment of its refund cases, the Company believes that the likelihood of refunds actually being required is not significant. The Company notes that with respect to the historical fees received from participation in programs that were impacted by Order 745, that Order 745 was effective and binding and that the Company delivered its service in accordance with the applicable market and program tariffs and manuals. As a result, the Company has concluded that the historical revenue recognition was appropriate and that the potential risk of refund as a result of the May 23, 2014 Court ruling on Order 745 should be evaluated as a potential contingent loss as a result of this event in accordance with ASC 450, Contingencies. Based on the Company’s assessment of this matter, it has determined that a loss is not currently probable. As a result, no loss accrual is currently recorded under ASC 450. Based on the Company’s assessment, it concluded that it is reasonably possible that the Company may incur a loss and the potential range of loss would be the fees received under the program, which is approximately $20,100 .


The Company has determined that due to the potential risk of refund, all fees received prospectively from continued participation after May 23, 2014 in wholesale energy market demand response programs implemented pursuant to Order 745 and administered by a RTO or ISO will be deferred until such time as the fees are either refunded or become no longer subject to refund or adjustment. Subsequent to May 23, 2014 through June 30, 2015 , the Company has received and deferred $2,767 of fees related to these programs.


9. Stockholders’ Equity





2014 Long-Term Incentive Plan





On May 29, 2014, the Company’s stockholders approved the EnerNOC, Inc. 2014 Long-Term Incentive Plan, which was amended by the Company’s stockholders at the Annual Meeting to increase the number of shares of common stock authorized for issuance under the 2014 Plan by 1,700,000 shares (collectively, the 2014 Plan). During the period of the effective date of the 2014 Plan through June 30, 2015 , the Company repurchased 354,362 shares to satisfy employee tax withholdings that became available for future grant under the 2014 Plan. As of June 30, 2015 , 2,496,502 shares were available for future grant under the 2014 Plan.


World Energy Solutions, Inc. 2006 Stock Incentive Plan


In connection with the Company’s acquisition of World Energy in January 2015, the Company assumed the World Energy Solutions, Inc. 2006 Stock Incentive Plan (the World Energy Plan). The World Energy Plan provides for the grant of incentive and nonstatutory stock options or stock purchase rights to employees of the Company who were employees of World Energy prior to January 5, 2015 or were hired by the Company after January 5, 2015. At June 30, 2015, 107,189 stock-based awards were available for future grants.


In connection with the Company’s acquisition of World Energy, options to purchase World Energy common stock that were assumed by the Company were converted into options to purchase the Company's common stock that are subject to the same vesting and other conditions that applied to the World Energy options immediately prior to the acquisition. All such options have a four year vesting schedule. Shares of World Energy common stock that were underlying the restricted stock awards that were not tendered in the acquisition and that were subject to forfeiture risks, repurchase options or other restrictions immediately prior to the acquisition were converted into shares of the Company’s common stock as provided in the merger agreement and remain subject to the same restrictions that applied to the World Energy restricted stock awards immediately prior to the acquisition. The terms may be adjusted upon certain events affecting the Company’s capitalization. No awards may be granted under the World Energy Plan after the completion of ten years from August 25, 2006, which is the date on which the World Energy Plan was adopted by the World Energy Board, but awards previously granted may extend beyond that date.


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Share Repurchase Program and Tax Withholding Obligations


On August 11, 2014, the Company’s Board of Directors authorized the repurchase of up to $50,000 of the Company’s common stock during the period from August 11, 2014 through August 8, 2015 (the 2014 Repurchase Program). The Company used $29,975 of the net proceeds from its Notes offering to repurchase 1,514,552 shares of its common stock at a purchase price of $19.79 per share, which was the closing price of the Common Stock on The NASDAQ Global Select Market on August 12, 2014. Additional repurchases of common stock under the 2014 Repurchase Program may be executed periodically on the open market as market and business conditions warrant. During the three and six months ended June 30, 2015 , the Company did not make any repurchases of its common stock.


On August 6, 2015, the Company's Board of Directors approved a new share repurchase program, effective upon the expiration of the Company’s 2014 Repurchase Program on August 8, 2015, that will enable the Company to repurchase up to $50,000 of the Company’s common stock during the period from August 9, 2015 to August 9, 2016 (the 2015 Repurchase Program). Repurchases under the Company’s 2015 Repurchase Program are expected to be made periodically on the open market as market and business conditions warrant, or under a Rule 10b5-1 plan.


The Company withheld 99,713 and 242,877 shares of its common stock during the three and six months months ended June 30, 2015 to satisfy employee minimum statutory income tax withholding obligations in connection with the vesting of restricted stock and restricted stock units under its equity incentive plans, which the Company pays in cash to the appropriate taxing authorities on behalf of its employees. All withheld shares became immediately available for future issuance under the 2014 Plan.





Stock-Based Compensation


The 2003 Plan, the 2007 Plan, the 2014 Plan, and the World Energy Plan (collectively, the Plans) provide for the grant of incentive stock options, nonqualified stock options, restricted and unrestricted stock awards and other stock-based awards to eligible employees, directors and consultants of the Company. Options granted under the Plans are exercisable for a period determined by the Company, but in no event longer than ten years from the date of the grant. Option awards are generally granted with an exercise price equal to the market price of the Company’s common stock on the date of grant. Stock option awards, restricted stock awards and restricted stock unit awards generally vest ratably over four years , with certain exceptions. During the six months ended June 30, 2015 and 2014 , the Company issued 72,926 and 6,632 shares of its common stock, respectively, to certain executives to satisfy a portion of the Company’s bonus obligations to those individuals.


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Stock Options


The following is a summary of the Company’s stock option activity during the six months ended June 30, 2015 :


Six Months Ended June 30, 2015Number ofSharesUnderlyingOptionsExercisePrice PerShareWeighted-AverageExercise PricePer ShareAggregateIntrinsicValueOutstanding at December 31, 2014725,578$0.35 - $43.38$18.01$2,978(2)Granted78,41310.99Exercised(99,392)10.23742(3)Cancelled(28,897)16.89Outstanding at June 30, 2015675,702$0.35 - $43.38$18.39$1,280(4)Weighted average remaining contractual life in years: 2.5Exercisable at end of period622,473$0.35 - $43.38$18.97$1,272(4)Weighted average remaining contractual life in years: 2.3Vested or expected to vest at June 30, 2015 (1)671,710$0.35 - $43.38$18.39$1,279(4)





(1) This represents the number of vested options as of June 30, 2015 plus the number of non-vested options expected to vest as of June 30, 2015 based on a 7.5% forfeiture rate.


(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, 2014 of $15.45 and the weighted-average exercise price of the underlying options.


(3) The aggregate intrinsic value was calculated based on the difference between the fair value of the Company’s common stock on the applicable exercise dates and the weighted-average exercise price of the underlying options.


(4) The aggregate intrinsic value was calculated based on the positive difference between the estimated fair value of the Company’s common stock on June 30, 2015 of $9.70 and the weighted-average exercise price of the underlying options.


The weighted average fair value per share of options granted during the six months ended June 30, 2015 was $9.92 .


As of June 30, 2015 , all 675,419 options were held by employees and directors of the Company and 283 option were held by a consultant. As of June 30, 2015 , the Company had $547 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 1.9 years.





Restricted Stock





The following table summarizes the Company’s restricted stock activity during the six months ended June 30, 2015 :


Number ofSharesWeighted AverageGrant Date FairValue Per ShareNonvested at December 31, 20142,170,267$17.18Granted1,374,47111.10Vested(648,327)16.30Cancelled(270,255)15.61Nonvested at June 30, 20152,626,156$15.06


For non-vested restricted stock subject to service-based vesting conditions outstanding as of June 30, 2015 , the Company had $26,003 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 2.9 years. For non-vested restricted stock subject to performance-based vesting conditions outstanding that were probable of vesting as of June 30, 2015 , which represents all of the outstanding non-vested restricted stock subject to performance-based vesting conditions, the Company had $2,669 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 1.6 years.


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In February 2015, the Company entered into a separation agreement with a former employee, which changed the employee’s status to non-employee consultant as of July 1, 2015 and provided for the vesting of 12,514 shares of previously non-vested restricted stock, to continue to vest through January 2, 2016, as long as the individual continues to serve as a consultant through the date of the applicable vesting. Through the non-employee consultation period, the restricted stock will be fair valued at the end of each reporting period, with changes in fair value being recorded to the consolidated statement of operations.





Restricted Stock Units





The following table summarizes the Company’s restricted stock unit activity during the six months ended June 30, 2015 :


Number ofSharesWeighted AverageGrant Date FairValue Per ShareNonvested at December 31, 2014256,872$20.08Granted69,95010.59Vested(4,095)19.74Cancelled(25,408)19.01Nonvested at June 30, 2015297,319$17.90





During the year ended December 31, 2014, the Company granted 250,382 shares of non-vested restricted stock units that contain performance-based vesting conditions to certain non-executive German employees in connection with its acquisition of Entelios. Vesting would be triggered for these shares if the employee remained employed with the Company and if certain earnings targets were met in 2014, 2015, and 2016.  As of June 30, 2015, the Company has determined that the earnings targets were not probable of being met, and thus the awards have not been deemed probable of vesting.


For non-vested restricted stock units subject to service-based vesting conditions outstanding as of June 30, 2015, the Company had $733 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 3.3 years. For non-vested restricted stock units subject to outstanding performance-based vesting conditions that were not probable of vesting at June 30, 2015 , the Company had $4,418 of unrecognized stock-based compensation expense. If and when any additional portion of these non-vested restricted stock units are deemed probable to vest, the Company will reflect the effect of the change in estimate in the period of change by recording a cumulative catch-up adjustment to retroactively apply the new estimate.


10. Income Taxes


The Company has recorded a $345 tax expense and a $1,940 tax benefit for the three and six months ended  June 30, 2015 , respectively. The tax expense is due to 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, offset by a tax benefit generated from foreign losses for the quarter. The benefit for income taxes for the six months ended June 30, 2015 also includes a $2,268 benefit from income taxes due to the release of a portion of the U.S. valuation allowance in connection with the World Energy acquisition.


ASC 740, Income Taxes (ASC 740) , 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 and six months ended  June 30, 2015 , 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 its U.S. earnings.


If the Company is able to make a reliable estimate of its U.S. annual effective tax rate as of September 30, 2015, the Company expects to utilize that rate to provide for income taxes on a current year-to-date basis. If the Company continues to be


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unable to make a reliable estimate of its annual effective tax rate as of September 30, 2015, the Company expects to provide for income taxes using a consistent methodology as was applied for the three and six months ended  June 30, 2015 .


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 June 30, 2015 , due to the uncertainty related to the ultimate use of certain deferred income tax assets, the Company has recorded a valuation allowance on certain of its deferred tax assets.


11. Concentrations of Credit Risk


Financial instruments that potentially subject the Company to significant concentrations of credit risk principally consist of cash and cash equivalents, restricted cash, accounts receivable and unbilled revenue. The Company maintains its cash and cash equivalent balances with highly rated financial institutions and as a result, such funds are subject to minimal credit risk.


The Company's significant customers consist of PJM Interconnection (PJM), Independent Market Operator (IMO) and and ISO-New England, Inc. (ISO-NE). PJM and ISO-NE are electric power grid operator customers in the mid-Atlantic and New England regions of the United States 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. IMO is an entity that was established to administer and operate the Western Australia (WA) wholesale electricity market. The main objectives of the IMO are to coordinate the supply of electricity, encourage competition in the market, establish fair and efficient markets, and ensure economic supply of electricity to customers in WA. No other customers comprised more than 10% of consolidated revenues during the three or six months ended June 30, 2015 and 2014 .


The following table presents the Company’s significant customers.


Three Months Ended June 30,20152014Revenues% of TotalRevenuesRevenues% of TotalRevenuesPJM$17,65224%$2,994*IMO7,19710%4,39710%ISO-NE**4,30610%


* Represents less than 10% of total revenues. Six Months Ended June 30,20152014Revenues% of TotalRevenuesRevenues% of TotalRevenuesPJM$17,81514%$21,21222%IMO14,47512%**


* Represents less than 10% of total revenues.


IMO was the only customer that comprised 10% or more of the Company’s accounts receivable balance at June 30, 2015 , representing 12% . PJM, Southern California Edison Company and IMO were the only customers that each comprised 10% or more of the Company’s accounts receivable balance at December 31, 2014 , representing 21% , 17% and 12% , respectively.


Unbilled revenue related to PJM was $17,510 and $96,404 at June 30, 2015 and December 31, 2014 , respectively. There was no significant unbilled revenue for any other customers at June 30, 2015 and December 31, 2014 .


Deposits consist of funds to secure performance under certain contracts and open market bidding programs with electric power grid operator and utility customers. Deposits held by these customers were $1,307 and $3,033 at June 30, 2015 and December 31, 2014 , respectively.


12. Legal Proceedings


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


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On November 6, 2014, a class action lawsuit was filed in the Delaware Court of Chancery against the Company, World Energy, Wolf Merger Sub Corporation, and members of the board of directors of World Energy arising out of the merger between the Company and World Energy. The lawsuit generally alleged that the members of the board of directors of World Energy breached their fiduciary duties to World Energy’s stockholders by entering into the merger agreement because they, among other things, failed to maximize stockholder value and agreed to preclusive deal-protection terms. The lawsuit also alleged that the Company and World Energy aided and abetted the board of directors of World Energy in breaching their fiduciary duties. The plaintiff sought to stop or delay the acquisition of World Energy by the Company, or rescission of the merger in the event it is consummated, and seeks monetary damages in an unspecified amount to be determined at trial. The parties engaged in settlement negotiations and on December 24, 2014, without admitting, but expressly denying any liability on behalf of the defendants, the parties entered into a memorandum of understanding (MOU) regarding a proposed settlement to resolve all allegations. The MOU was filed in the Delaware Court of Chancery on December 24, 2014. Among other things, the MOU provides that, in consideration for a release and the dismissal of the litigation, World Energy would include additional disclosures in a Form SC 14D9-A to be filed with the SEC no later than December 24, 2014. The MOU also provided that the litigation, including the preliminary injunction hearing, be stayed. The merger closed on January 5, 2015. On March 26, 2015, the parties executed and filed with the Delaware Chancery Court a formal stipulation of settlement. The Company has recognized an obligation of $300 in connection with the settlement. The Delaware Chancery Court initially scheduled a hearing to be held on June 30, 2015, which was subsequently rescheduled to August 20, 2015, to consider whether to approve the settlement. There can be no assurance that the Delaware Court of Chancery will approve the settlement.


13. Gain on Sale of Service Line


On April 16, 2014, the Company entered into an agreement with a third party to sell a component of the business, Utility Solutions Consulting, that the Company acquired in connection with its acquisition of Global Energy Partners, Inc. (Global Energy) 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).


On May 30, 2014, the Company sold the component for $4,750 . The Company concluded that Utility Solutions Consulting met the definition of a business in accordance with ASC 805.


The following table summarizes the assets sold in connection with this transaction: Customer relationship intangible assets, net$153Other definite-lived intangible assets, net39Goodwill489Total assets sold$681


The amount of goodwill allocated to Global Energy was based on the relative fair values of this business. In accordance with the agreement, the Company received $4,275 at closing and $475 is being held in escrow to cover general representations and warranties, as well as, potential purchase price adjustment, if any, for fees that could have been earned related to contracts that were not assigned. The potential remaining purchase price adjustment for fees that could have been earned for contracts that were not assigned was $364 as of June 30, 2014.  The Company recognized a gain from the sale of Global Energy totaling $3,378 , net of transaction costs totaling $327 during the three and six months ended June 30, 2014.


The Company 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 determined that the operations of Utility Solutions Consulting were neither quantitatively or qualitatively material to the Company’s current or historical consolidated operations 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 and six months ended June 30, 2014. As a result, the gain has been reflected as a separate component within income from operations with the corresponding discrete tax charge of $1,102 related to the increase in the deferred tax liability as a result of the increased book and tax basis difference in goodwill being recorded as a component of the Company’s provision for income taxes during the three and six month periods ended June 30, 2014.


14. Gain on Sale of Assets


On April 22, 2014, the Company entered into an agreement with a third party, enterprise customer of the Company to sell its remaining two contractual demand response capacity resources related to an open market demand response program, which allowed the buyer to enroll directly with the applicable grid operator. Under the terms of the agreement, the Company agreed to sell each of these two demand response capacity resources with such sale and transfer being effective as of the date that each resource has been paid for in full. The aggregate payment of $5,740 was allocated between each demand response capacity


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resource based on each resource’s relative fair value as determined by the potential future cash flows from each resource with $2,171 being allocated to the first demand response capacity resource and $3,569 being allocated to the second demand response capacity resource, of which guaranteed fees of $517 were recognized ratably through the end of the contractual period of March 31, 2015. The third party fully paid the purchase price for the first demand response capacity resource during the three months ended June 30, 2014 and as a result, the sale of this resource was completed. As a result of the first sale, the Company recognized a gain on the sale of this asset equal to the purchase price of $2,171 during the three and six months ended June 30, 2014. During the three months ended June 30, 2015, the Company received the remaining balance in the amount of $2,991 from the third party for the the second demand response capacity resource and completed the sale resulting in the recognition of a gain on the sale of this asset equal to the purchase price of $2,991 .





15. Recent Accounting Pronouncements


In  May  2014,  the  FASB  issued  ASU  No.  2014-09, Revenue  from  Contracts  with  Customers  (Topic  606) ("ASU  2014-09").  ASU  2014-09  is  a comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance under U.S. GAAP. The core principle under ASU 2014-09 is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also specifies the accounting for some costs to obtain or fulfill a contract with a customer. ASU 2014-09 also requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments. On July 9, 2015, the FASB decided to defer the effective date for this standard to annual periods beginning after December 15, 2017 and interim periods therein. Early adoption is permitted, but not before January 1, 2017, and an entity may apply the amendments in ASU 2014-09 either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying ASU 2014-09 at the date of initial application. Currently, the Company is evaluating both the method of adoption and the impact adoption will have on its consolidated financial statements. In evaluating the method  of  adoption,  the  Company  is  considering  a  number  of  factors,  including  the  disclosure  requirements  and  related  processes  and  controls required, as well as, the overall industry and peer public company adoption method trends.


In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements — Going Concern: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). The standard requires that the Company evaluates, at each interim and annual reporting period, whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year after the date the financial statements are issued, and provide related disclosures. ASU 2014-15 is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter, and early adoption is permitted. The Company does not expect to early adopt ASU 2014-15, which will be effective for its fiscal year ending December 31, 2016. The Company does not believe the standard will have a material impact on its consolidated financial position and results of operations.


In April 2015, the FASB issued ASU 2015-03, I nterest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs . The amendments in this update require that debt issuance costs related to a recognized debt liability (other than revolving credit facilities) be presented in the consolidated balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This update deals solely with financial statement display matters; recognition and measurement of debt issuance costs are unaffected. ASU 2015-03 is effective for annual periods ending after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not previously been issued. The Company does not expect to early adopt ASU 2015-03, which will be effective for its fiscal year ending December 31, 2016. The Company is currently in the process of evaluating the impact of adoption of this ASU on its consolidated financial position and results of operations.


In April 2015, the FASB issued ASU 2015-05, Intangibles—Goodwill and Other—Internal-Use Software: Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement (“ASU 2015-05”). The standard clarifies the circumstances under which a cloud computing customer would account for the arrangement as a license of internal-use software under ASC 350-40. ASU 2015-05 is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2015, and early adoption is permitted. The Company does not expect to early adopt ASU 2015-05, which will be effective for its fiscal year ending December 31, 2016. The Company does not believe the standard will have a material impact on its consolidated financial position and results of operations.








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


The following discussion should be read in conjunction with our unaudited condensed consolidated financial statements and related notes thereto included elsewhere in this Quarterly Report 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, 2014 , as filed with the Securities and Exchange Commission, or the SEC, on March 12, 2015, and as amended on March 13, 2015, or our 2014 Form 10-K/A. 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,” “likely,” “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 2014 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. Our enterprise customers use our software to transform how they manage and control spend for their organizations, while utilities leverage our software to better engage their customers and meet their demand-side management goals and objectives.


Our EIS and related solutions provide our enterprise customers with a Software-as-a-Service, or SaaS, solution to manage:


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|• | energy supplier selection, procurement and implementation;

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|• | energy budget forecasting;

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|• | utility bills and payment;

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|• | facility optimization, including the measurement, tracking, analysis and reporting on greenhouse gas emissions;

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|• | project tracking;

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|• | demand response, both in open and vertically-integrated markets; and

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|- | ----------------------------------------
|• | peak demand and the related cost impact.

Our EIS and related solutions provide our enterprise customers the visibility they need to prioritize resources against the activities that will deliver the highest return on investment. We offer our EIS and related solutions to our enterprise customers at four subscription levels: basic, standard, professional, and industrial. We deliver our SaaS solutions on all of the major Internet browsers and on leading mobile device operating systems. In addition to our EIS packages, we sell two categories of premium professional services, which we refer to as Software Enhancement Services and Energy and Procurement Services. Our Software Enhancement Services help our enterprise customers set their energy management strategy and enhance the effectiveness of EIS deployment. Our Energy and Procurement Services consist of audits, retro-commissioning, and supply procurement consulting. Our target enterprise customers for our EIS and related solutions are organizations that spend approximately $100 thousand/year or more per site on energy, and we sell to these customers primarily through our direct salesforce.


Our EIS for utilities is a SaaS solution that provides utilities with customer engagement, energy efficiency and demand response applications, while improving operational effectiveness. We deliver shared value for both the utility and its customers by combining our deep expertise with enterprise customers with energy data analytics, machine learning, and predictive algorithms to deliver segmentation and targeting capabilities that enable utilities to serve their most complex market segments, including commercial, institutional and industrial end-users of energy, and small or medium-sized enterprises. Our EIS and related solutions provide our utility customers with a cost-effective and holistic solution that improves customer satisfaction


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ratings, delivers savings and consumption reductions to achieve energy efficiency mandates, manages system peaks and grid constraints, and increases demand for utility-provided products and services.


Our EIS and related solutions for utility customers and electric power grid operators also include the demand response solutions and applications, EnerNOC Demand ManagerTM and EnerNOC Demand ResourceTM. EnerNOC Demand Manager is a SaaS application that provides utilities with the underlying technology to manage their demand response programs and secure reliable demand-side resources. Our EnerNOC Demand Manager product consists of long-term contracts with a utility customer for a SaaS solution that allows utilities to manage demand response capacity in utility-sponsored demand response programs. This product provides our utility customers with real-time load monitoring, dispatching applications, customizable reports, measurement and verification, and other professional services. Our EnerNOC Demand Resource is a turnkey demand response resource where we match obligation, in the form of megawatts, or MW, that we agree to deliver to our utility customers and electric power grid operators, with supply, in the form of MW that we are able to curtail from the electric power grid through our arrangements with our enterprise customers. When we are called upon by our utility customers and electric power grid operators to deliver our contracted capacity, we use our NOC to remotely manage and reduce electricity consumption across our growing network of enterprise customer sites, making demand response capacity available to our utility customers and electric power grid operators on demand while helping our enterprise customers achieve energy savings, improve financial results and realize environmental benefits. We receive recurring payments from our utility customers and electric power grid operators for providing our EnerNOC Demand Resource and we share these recurring payments with our enterprise customers in exchange for those enterprise 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 third-party 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.


Since inception, our business has grown substantially. We began by providing our demand response solutions in one state in the United States in 2003 and have expanded to providing our EIS and related solutions throughout the United States, as well as internationally in Australia, Brazil, Canada, China, Germany, India, Ireland, Japan, New Zealand, South Korea, Switzerland and the United Kingdom.





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 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 and trends related to 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.


The following table outlines certain non-financial business and operational data utilized as of and for the six months ended June 30, 2015 and as of and for the year ended December 31, 2014 : June 30, 2015December 31, 2014Enterprise Customers(1)(7)4,3001,300Enterprise Sites(1)(7)79,10035,700Enterprise ARR (in millions)(2)(8)$58$20Enterprise ARR Churn Rate(2)(9)12%18%Enterprise ARR Net Churn Rate (2)(9)(4)%15%Utility Customers(3)5052Utility ARR (in millions)(4)(8)$64$67Utility ARR Churn Rate(4)(9)18%13%Utility ARR Net Churn Rate(4)(9)15%10%Grid Operators(5)1414Demand Response Customers(6)(7)6,4006,500Demand Response Sites(6)(7)15,00015,000


(1) The term “Enterprise Customers,” which we formerly referred to as “C&I Customers Under Enterprise Revenue Contracts,” describes the number of our customers that purchase our EIS and related solutions for enterprises. By extension, the term “Enterprise Sites,” which we previously referred to as “C&I Sites Under Enterprise Revenue


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Contracts,” describes the number of sites across our Enterprise Customer base that purchase our EIS and related solutions for enterprises.


(2) The term “Enterprise ARR” describes the annual recurring revenue from our contracts with Enterprise Customers, defined as all contracted subscription revenue, exclusive of non-recurring or one-time fees, from Enterprise Customers under active (non-expired or terminated) contracts at period end, normalized for a one year period regardless of payment mechanism or timing. Non-recurring or one-time fees include fees related to site installation or set-up, discrete consulting or project-based fees, and non-recurring professional services fees. By extension, the term “Enterprise ARR Churn Rate” describes the Enterprise ARR lost over the trailing four quarter period for any reason including, but not limited to non-renewal, early termination, or ongoing non-payment, as a percentage of the starting Enterprise ARR value over the trailing four quarter period. The term “Enterprise ARR Net Churn Rate” describes the (gain) loss of Enterprise ARR from Enterprise Customers that were purchasing our EIS and related solutions at the start of the trailing four quarter period, inclusive of changes to Enterprise ARR from renewal or upsell activity to these Enterprise Customers, as a percentage of the starting Enterprise ARR value over the trailing four quarter period.


(3) The term “Utility Customers” describes the number of our customers that purchase our EIS and related solutions for utilities.


(4) The term “Utility ARR” describes the annual recurring revenue from our contracts with Utility Customers, defined as all contracted subscription revenue, exclusive of non-recurring or one-time fees, from Utility Customers under active (non-expired or terminated) contracts at period end, normalized for a one year period regardless of payment mechanism or timing. Non-recurring or one-time fees include fees related to product set-up, discrete consulting or project based fees, variable demand response energy payments, and non-recurring professional services fees. By extension, the term “Utility ARR Churn Rate” describes the Utility ARR lost over the trailing four quarter period for any reason including, but not limited to non-renewal, early termination, demand response customer attrition, or ongoing non-payment, as a percentage of the starting Utility ARR value over the trailing four quarter period. The term “Utility ARR Net Churn Rate” describes the loss of Utility ARR from Utility Customers that were purchasing our EIS and related solutions at the start of the trailing four quarter period, inclusive of changes to ARR from renewal or upsell activity to these customers, as a percentage of the starting Utility ARR value over the trailing four quarter period.


(5) The term “Grid Operators,” which we formerly referred to as “Grid Operator Customers,” describes the number of operators of competitive wholesale electricity markets that rely on our demand response programs to manage load on their grid. We enter into contractual commitments with these grid operators through participation in open market auctions, as well as, negotiated contractual arrangements for the express purpose of optimizing load on their grid when called upon, or dispatched, to do so.


(6) The term “Demand Response Customers,” which we formerly referred to as C&I Customers Participating in Demand Response,” describes the number of our enterprise customers under contract to participate in our demand response programs. By extension, the term “Demand Response Sites,” which we formerly referred to as “C&I Sites Participating in Demand Response,” describes the number of sites across our Demand Response Customer base under contract to participate in our demand response programs. Certain of these customers and sites may additionally use our EIS and related solutions.


(7) Amounts rounded to nearest hundred.


(8) Amounts rounded to nearest million.


(9) Amounts rounded to nearest full percentage point.


The number of enterprise customers at June 30, 2015 was approximately 4,300 compared to approximately 1,300 at December 31, 2014 . This increase primarily reflects the addition of new enterprise customers from our acquisition of World Energy Solutions, Inc., or World Energy. This increase also reflects our ongoing efforts to develop our enterprise sales team, the relative success that our enterprise sales team has had in penetrating the market for our EIS and related solutions for enterprises, and the growing need for our solutions with enterprise customers who are increasingly turning to our EIS and related solutions to make strategic decisions about the how and when they consume or procure energy. The number of enterprise sites at June 30, 2015 was approximately 79,100 compared to approximately 35,700 at December 31, 2014. The number of enterprise sites has typically increased in tandem with the increase in enterprise customers, with most of the increase in sites coming from our acquisition of World Energy and new sales of our EIS and related solutions for enterprise customers. Enterprise ARR at June 30, 2015 was approximately $58 million compared to approximately $20 million at December 31, 2014. Enterprise ARR has typically increased in tandem with the increase in enterprise sites, with the increase coming from our acquisition of World Energy and our organic growth. We expect that the number of enterprise customers, the number of enterprise sites, and enterprise ARR will generally increase over time, but enterprise customers and sites may decrease in the near term as we select not to renew certain smaller or unprofitable customers acquired through our acquisition of World Energy. Our enterprise ARR gross churn rate was 12% at June 30, 2015 compared to 18% at December 31, 2014. Our enterprise ARR


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net churn rate was negative 4% at June 30, 2015 compared to 15% at December 31, 2014, which reflects the addition of ARR through upsells to existing enterprise customers.


The number of utility customers at June 30, 2015 was 50 compared to 52 at December 31, 2014. This decrease primarily reflects the non-renewal of certain utility contracts for our demand response offerings. Utility ARR at June 30, 2015 was approximately $64 million compared to $67 million at December 31, 2014. This decrease primarily reflects a reduction in size or non-renewal of certain utility demand response programs, partially offset by an increase in size of certain utility software contracts. Our utility ARR gross churn rate was 18% at June 30, 2015 compared to 13% at December 31, 2014. Our utility ARR net churn rate was 15% at June 30, 2015 compared to 10% at December 31, 2014. In general, we expect that the number of utility customers and utility ARR will increase over time and that our utility ARR gross churn rate and utility ARR net churn rate will fluctuate in future periods depending on the timing and terms of our utility contracts.


The number of grid operators at June 30, 2015 was 14, consistent with the number of grid operators at December 31, 2014. In general, we expect that the number of grid operators will remain the same or moderately increase over time.


The number of demand response customers was approximately 6,400 at June 30, 2015 , compared to 6,500 at December 31, 2014. The number of demand response sites at June 30, 2015 was approximately 15,000 as compared to approximately 15,000 at December 31, 2014. The number of demand response customers and the number of demand response sites 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.


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, as a result, such data and information may change over time.


Consolidated Results of Operations


Three and Six Months Ended June 30, 2015 Compared to the Three and Six Months Ended June 30, 2014


Revenues


The following table summarizes our revenues for the three and six months ended June 30, 2015 and 2014 ( in thousands):


Three Months Ended June 30,DollarPercentage20152014ChangeChangeRevenues:Grid operator$41,545$22,974$18,57180.8%Utility12,55711,9615965.0%Enterprise18,3989,1209,278101.7%Total$72,500$44,055$28,44564.6%Six Months Ended June 30,DollarPercentage20152014ChangeChangeRevenues:Grid operator$65,258$58,744$6,51411.1%Utility23,33822,2701,0684.8%Enterprise34,45515,54918,906121.6%Total$123,051$96,563$26,48827.4%


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Grid Operator Revenues


The overall increase in our revenues from grid operators was primarily attributable to changes in the following existing operating areas (dollars in thousands):


Increase (Decrease)Three Months EndedJune 30, 2014 toJune 30, 2015Six Months EndedJune 30, 2014 toJune 30, 2015PJM$14,658$(3,397)Western Australia (IMO)2,80010,079Korea (KPX)1,6614,350New England (ISO NE)(1,112)(2,378)Other (1)564(2,140)Total increase in grid operator revenues$18,571$6,514





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|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | The amounts included in ‘other’ relate to net decreases in various demand response programs, domestic and international, none of which are individually material.




The increase in revenues from grid operators during the three and six months ended June 30, 2015 as compared to the same periods in 2014 was primarily due to recognition of revenues associated with the recently introduced Extended and Annual PJM products, a change to ratable revenue recognition in the IMO program, and recognition of revenues associated with our new demand response program in Korea. This increase in revenue from grid operators was partially offset by the continued deferral of revenues related to our participation in the PJM Economic program pending final resolution of FERC Order 745 (see Note 8 contained in Part I to this Quarterly Report on Form 10-Q), and reduced revenue from our decreased participation in capacity auctions and bilateral contracts in the ISO-NE demand response program as compared to the same period in 2014. In addition, the decrease in PJM revenues for the six months ended June 30, 2015 as compared to the same period in 2014 was primarily due to a decrease in energy payments from PJM resulting from no PJM emergency demand response event dispatches in the first quarter of 2015 compared to a significant number of PJM emergency demand response event dispatches during the first quarter of 2014. We currently expect our total revenues from grid operators to decrease during fiscal 2015 as compared to fiscal 2014 due to significantly reduced capacity prices in IMO, lower revenue from our participation in PJM incremental auctions and deferral of revenue recognition to the second quarter of 2016 relating to our participation in PJM’s extended program in the 2015/2016 delivery year.





Utility Revenues


The overall increase in our revenues from utilities was primarily attributable to changes in the following existing operating areas (in thousands):


Increase (Decrease)Three Months EndedJune 30, 2014 toJune 30, 2015Six Months EndedJune 30, 2013 toJune 30, 2014Pacific Gas & Electric, or PG&E$(1,255)$(1,242)Pulse Energy customers1,0962,144Southern California Edison, or SCE9591,032Other (1)(204)(866)Total increase in utility revenues$596$1,068





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|--- | --------------------------------------------------------------------------------------------------------------------
|(1) | The amounts included in ‘Other’ relate to various demand response programs, none of which are individually material.

The increase in revenues from utility customers during the three and six months ended June 30, 2015 as compared to the same periods in 2014 was primarily due an increase in utility revenues related to our acquisition of Pulse Energy, which we acquired in the fourth quarter of 2014 and improved performance during demand response events in our SCE demand response program. This increase was partially offset by a decrease in utility revenues related to the reduction of megawatt commitment in our PG&E demand response program. We currently expect our fiscal 2015 utility revenues to grow between 13%-21% as


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compared to fiscal 2014 primarily due to the utility contracts acquired with Pulse Energy, expansion of existing utility customer contracts and the sale of our demand manager solution to new utility customers.





Enterprise Revenues


The increase in enterprise revenues during the three and six months ended June 30, 2015 , as compared to the same periods in 2014, related to the expansion of our procurement solutions resulting from our acquisition of World Energy in the first quarter of 2015 and our utility bill management solutions, which we acquired as part of our acquisition of Entech in the second quarter of 2014. We currently expect our fiscal 2015 enterprise revenues to grow between 70%-83% as compared to fiscal 2014 due to the acquisition of World Energy, expansion of existing enterprise customer contracts and the sale of our EIS solution to new enterprise customers.


Gross Profit and Gross Margin


The following table summarizes our gross profit and gross margin percentages for our EIS and related solutions for the three and six months ended June 30, 2015 and 2014 (dollars in thousands):


Three Months Ended June 30,20152014Gross ProfitGross MarginGross ProfitGross Margin$38,95753.7%$16,25336.9%Six Months Ended June 30,20152014Gross ProfitGross MarginGross ProfitGross Margin$57,55246.8%$32,62233.8%





The increase in gross profit and gross margin was primarily due to an increase in the percentage of revenues recognized as a result of the adjustment of our zonal capacity obligations through our participation in PJM incremental auctions, as well as an increase in higher margin enterprise revenue and a change in our overall enterprise customer compositions resulting from the acquisitions of World Energy and Entech.


We expect that our overall gross margin percentage for fiscal 2015 will be in the low to mid 40% range. This anticipated decrease in gross margin percentage compared to gross margin of 45% in fiscal 2014 is expected to result primarily from decreased profits from our participation in PJM incremental auctions. We expect this decrease will be partially offset by revenue growth from our higher margin enterprise business.


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Operating Expenses


The following table summarizes our operating expenses for the three and six months ended June 30, 2015 and 2014 (in thousands):


Three Months Ended June 30,Percentage20152014ChangeSelling and marketing$23,670$19,52621.2%General and administrative28,45324,19117.6%Research and development7,7354,99754.8%Gain on sale of service line—(3,378)(100.0)%Gain on sale of assets(2,991)(2,171)37.8%Total operating expenses$56,867$43,16531.7%Six Months Ended June 30,Percentage20152014ChangeSelling and marketing$52,166$38,02537.2%General and administrative56,74347,86818.5%Research and development15,18610,17249.3%Gain on sale of service line—(3,378)(100.0)%Gain on sale of assets(2,991)(2,171)37.8%Total operating expenses$121,104$90,51633.8%





Selling and Marketing Expenses


The following table summarizes our selling and marketing expenses for the three and six months ended June 30, 2015 and 2014 (in thousands):


Three Months Ended June 30,Percentage20152014ChangePayroll and related costs$15,563$12,31126.4%Stock-based compensation3081,372(77.6)%Other7,7995,84333.5%Total selling and marketing expenses$23,670$19,52621.2%Six Months Ended June 30,Percentage20152014ChangePayroll and related costs$32,847$24,41834.5%Stock-based compensation1,9512,565(23.9)%Other17,36811,04257.3%Total selling and marketing expenses$52,166$38,02537.2%


The increase in payroll and related costs for the three and six months ended June 30, 2015 was primarily due to an increase in the number of selling and marketing full-time employees from 263 at June 30, 2014 to 372 at June 30, 2015 , most of which resulted from acquisitions that we completed during fiscal 2014 and our acquisition of World Energy in January 2015, and an increase in salary rates per full-time employee. In addition, we experienced an increase in commission expense during the six months ended June 30, 2015 due to an increase in enterprise revenues.


The decrease in stock-based compensation expense for the three and six months ended June 30, 2015 was primarily due to the reversal of $0.8 million stock-based compensation expense related to the cancellation of awards upon the termination of employment of a former executive officer and the decrease in grant date fair value of stock-based awards.  This decrease was partially offset by an increase in the number of stock-based awards granted during the three and six months ended June 30, 2015 . Further offsetting the decrease for the six months ended June 30, 2015 was the settlement in 2015 of a portion of the


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fiscal 2014 bonuses in shares of our common stock recorded in stock-based compensation expense, as well as the immediate recognition of replacement awards issued to certain employees in connection with the acquisition of World Energy.


Other selling and marketing expenses include advertising, marketing, professional services, amortization and a company-wide overhead cost allocation. The increase in other selling and marketing expenses for the three and six months ended June 30, 2015 was primarily attributable to $1.5 million and $2.5 million increases, respectively, in amortization expense of acquired intangible assets as a result of our 2014 and 2015 acquisitions, $0.8 million and $2.7 million increases for the three and six months ended June 30, 2015, respectively, in various marketing initiatives, and $0.4 million and $1.5 million increases for the three and six months ended June 30, 2015, respectively, in overhead, which is based on increased headcount and information technology and communication costs. These increases were partially offset by a decrease in professional service fees of $0.8 million and $0.8 million for the three and six months ended June 30, 2015, respectively, due to lower acquisition related professional service fees during the three and six months ended June 30, 2015 as compared to the same periods in 2014.


General and Administrative Expenses


The following table summarizes our general and administrative expenses for the three and six months ended June 30, 2015 and 2014 (in thousands):


Three Months Ended June 30,Percentage20152014ChangePayroll and related costs$15,782$13,63915.7%Stock-based compensation2,6962,10827.9%Other9,9758,44418.1%Total general and administrative expenses$28,453$24,19117.6%Six Months Ended June 30,Percentage20152014ChangePayroll and related costs$33,531$27,08523.8%Stock-based compensation5,1264,8046.7%Other18,08615,97913.2%Total general and administrative expenses$56,743$47,86818.5%


The increase in payroll and related costs for the three and six months ended June 30, 2015 was primarily attributable to an increase in the number of general and administrative full-time employees from 418 at June 30, 2014 to 547 at June 30, 2015 , most of which resulted from acquisitions that we completed during 2014 and our acquisition of World Energy in 2015, and an increase in salary rates per full-time employee.


The increase in stock-based compensation expense for the three months ended June 30, 2015 was primarily due to the timing of annual grants issued to the non-employee independent members of the Company’s board of directors, as the Company granted fully-vested share-based payment awards to its non-employee independent members of the board of directors during the three months ended June 30, 2015 versus the three months ended March 31, 2014. The slight increase in stock-based compensation expense for the six months ended June 30, 2015 related to awards settled and replaced in connection with the World Energy acquisition. Partially offsetting these increases were a decrease in grant date fair value of stock-based awards.


Other general and administrative expenses include professional services, rent, depreciation and a company-wide overhead cost allocation. The increase in other general and administrative expenses for the three months ended June 30, 2015 was primarily attributable to a $1.0 million increase in professional service expenses and a $0.7 million increase in overhead, which is based on increased headcount and information technology and communication costs. The increase in other general and administrative expenses for the six months ended June 30, 2015 was primarily attributable to a $1.2 million increase in rent expense related to our 2014 acquisitions, a $0.5 million increase in professional services and $0.5 million of  related higher depreciation costs.


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Research and Development Expenses


The following table summarizes our research and development expenses for the three and six months ended June 30, 2015 and 2014 (dollars in thousands):


Three Months Ended June 30,Percentage20152014ChangePayroll and related costs$4,488$3,05646.9%Stock-based compensation317319(0.6)%Other2,9301,62280.6%Total research and development expenses$7,735$4,99754.8%Six Months Ended June 30,Percentage20152014ChangePayroll and related costs$8,982$6,20644.7%Stock-based compensation653657(0.6)%Other5,5513,30967.8%Total research and development expenses$15,186$10,17249.3%


During the three months ended June 30, 2015 and 2014, total research and development payroll costs totaled $5.8 million and $4.2 million, respectively, of which $1.3 million and $1.2 million, respectively, were capitalized. During the six months ended June 30, 2015 and 2014, total research and development payroll costs totaled $11.5 million and $8.4 million, respectively, of which $2.5 million and $2.2 million, respectively, were capitalized. These capitalized costs are typically amortized over a three-year period in cost of revenues. The increase in payroll and related costs was primarily driven by an increase in the number of research and development full-time employees from 143 at June 30, 2014 to 206 at June 30, 2015 and an increase in salary rates per full-time employee.


Other research and development expenses include technology expenses, professional services, facilities and a company-wide overhead cost allocation. The increase in other research and development expenses for the three and six months ended June 30, 2015 was primarily attributable to increases in information technology and communication costs of $1.3 million and $1.7 million, respectively, and consulting and professional fees of $0.1 million and $0.2 million, respectively.


Gain on Sale of Service Line


During the three months ended June 30, 2014, we sold Utility Solutions Consulting, a component of our business that we acquired in connection with our acquisition of Global Energy related to consulting and engineering support services to the global electric utility industry, with a particular focus on providing consulting services to utilities for $4.8 million. We recognized a gain from the sale of Utility Solutions Consulting totaling $3.4 million, net of direct transaction costs totaling $0.3 million during the three and six months ended June 30, 2014.


Gain on Sale of Assets


During the three months ended June 30, 2014, we entered into an agreement with a third party enterprise customer to sell two contractual demand response capacity resources related to an open market demand response program to that third party allowing the third party the ability to enroll directly with the applicable grid operator. The third party fully paid the purchase price for the first demand response capacity resource during the three months ended June 30, 2014 and as a result, the sale of this resource was completed resulting in the recognition a gain on the sale of this asset equal to the purchase price of $2.2 million. During the three months ended June 30, 2015, we received payment in full from the third party for the second demand response capacity resource and completed the sale resulting in the recognition of a gain on the sale of this asset of $3.0 million .


Interest Expense and Other Income (Expense), Net


Interest expense was $2.2 million for the three months ended  June 30, 2015 compared to $0.6 million for the three months ended  June 30, 2014 and $4.5 million for the six months ended June 30, 2015 compared to $1.1 million for the six months ended June 30, 2014 . This increase was largely due to interest expense recorded on our convertible senior notes due August 2019, which was $2.1 million and $4.1 million for the three and six months ended June 30, 2015 , respectively.


Other income (expense), net for the three and six months ended June 30, 2015 was $1.7 million and $(3.0) million , respectively, which primarily includes foreign currency gains and losses offset partially by other income. The $1.3 million increase and the $3.9 million decrease as compared to the three and six months ended June 30, 2014 , respectively, was


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primarily due to fluctuations in the Canadian dollar and Euro, which resulted in foreign currency gains (losses) of $1.7 million and ($3.3) million for the three and six months ended June 30, 2015 , respectively, as compared to $0.2 million and $0.6 million gain for the three and six months ended June 30, 2014 , respectively. We currently do not hedge any of our foreign currency transactions.


Income Taxes


We recorded a $0.3 million tax expense and a $1.9 million tax benefit for the three and six months ended June 30, 2015 , respectively.  The tax expense is due to 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, offset by a tax benefit generated from foreign losses for the quarter. The benefit for income taxes for the six months ended June 30, 2015 also includes a $2.3 million benefit from income taxes due to the release of a portion of the U.S. valuation allowance in connection with the World Energy acquisition.


ASC 740, Income Taxes (ASC 740) 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 and six months ended June 30, 2015 , there were no material changes in our 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. 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.


If we are able to make a reliable estimate of our U.S. annual effective tax rate as of September 30, 2015, we expect to utilize that rate to provide for income taxes on a current year-to-date basis. If we continue to be unable to make a reliable estimate of our annual effective tax rate as of September 30, 2015, we expect to provide for income taxes using a consistent methodology as was applied for the three and six months ended June 30, 2015 .


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 June 30, 2015 , due to the uncertainty related to the ultimate use of certain deferred income tax assets, we have recorded a valuation allowance on certain of our deferred tax assets.


Liquidity and Capital Resources


Overview


We have generated significant cumulative losses since inception. As of June 30, 2015 , we had an accumulated deficit of $138.3 million . As of June 30, 2015 , our principal sources of liquidity were cash and cash equivalents totaling $143.6 million , a decrease of $110.8 million from the December 31, 2014 balance of $254.4 million , which was principally driven by the cash paid for the acquisition of World Energy, as well as cash used in operations. At June 30, 2015 and December 31, 2014, the majority of our excess cash was invested in money market funds.


During the six months ended June 30, 2015 , we utilized $77.2 million ( $79.9 million less $2.7 million of acquired cash) of our cash and cash equivalents in connection with the acquisition of World Energy. We believe our existing cash and cash equivalents and our anticipated net cash flows from operating activities will be sufficient to meet our anticipated cash needs, including investing activities, for at least the next 12 months. Our future working capital requirements will depend on many factors, including, without limitation, the rate at which we sell our EIS and related solutions to enterprise 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 EIS and related solutions, the expansion of our sales and marketing and research and development activities, and the geographic expansion of our business operations.


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Cash Flows


The following table summarizes our cash flows for the six months ended June 30, 2015 and 2014 (in thousands):


Six Months Ended June 30,20152014Cash flows (used in) provided by operating activities$(23,668)$5,726Cash flows used in investing activities(83,535)(41,864)Cash flows used in financing activities(2,130)(4,448)Effects of exchange rate changes on cash and cash equivalents(1,463)300Net change in cash and cash equivalents$(110,796)$(40,286)


Cash Flows (Used in) Provided by Operating Activities


Cash used in operating activities for the six months ended  June 30, 2015 was $23.7 million and consisted of net loss of $69.1 million , which was offset by $16.4 million of net cash provided by working capital and other activities and $32.0 million of non-cash items. The non-cash items consisted primarily of depreciation and amortization, stock-based compensation expense, unrealized foreign exchange translation losses, non-cash interest expense and deferred taxes. Cash provided by working capital and other activities consisted of a decrease of $45.6 million in accrued capacity payments, a decrease of $18.2 million in accounts payable, accrued expenses and other current liabilities, an increase in capitalized incremental direct customer contract costs of $11.2 million and an increase in prepaid expenses and other current assets of $5.8 million . This increase in cash provided by working capital and other activities was partially offset by a decrease of $78.3 million in unbilled revenue, most of which related to the PJM demand response market, a decrease of $10.7 million in trade accounts receivable and an increase of $9.6 million in deferred revenue.


Cash provided by operating activities for the six months ended June 30, 2014 was $5.7 million and consisted of a net loss of $57.8 million and gains of $5.5 million on the sales of service line and assets, which are included as a component of net loss but represent investing activities, offset by $24.7 million of non-cash items, and $44.3 million of net cash provided by working capital and other activities. The non-cash items consisted primarily of depreciation and amortization and stock-based compensation expense. Cash provided by working capital and other activities consisted of a decrease of $12.6 million in trade accounts receivable due to the timing of cash receipts under the demand response programs in which we participate, a decrease of $65.6 million in unbilled revenue, most of which related to the PJM demand response market, an increase of $29.9 million in deferred revenue primarily related to the Western Australia demand response program and an increase of $12.3 million in accounts payable, accrued expense and other current liabilities primarily due to the timing of payments. These increases in cash provided by operating activities were offset by cash used in working capital and other activities consisting of an increase in prepaid expenses and other current assets of $4.0 million, an increase in capitalized incremental direct customer contract costs of $33.8 million and a decrease of $38.7 million in accrued capacity payments.


Cash Flows Used in Investing Activities


Cash used in investing activities was $83.5 million for the six months ended  June 30, 2015 . During the six months ended  June 30, 2015 , we made net payments of $77.6 million for acquisitions. This includes the purchase of World Energy, as well as an earn-out payment for Activation Energy DSU Limited, or Activation Energy, and a working capital settlement for Pulse Energy. In addition, during the six months ended  June 30, 2015 , we made $11.3 million of capital expenditures, primarily related to software additions, including capitalized software development costs, to further expand the functionality of our software and solutions, as well as, demand response equipment expenditures due to an increase in our installed customer base. Cash used in investing activities for the six months ended  June 30, 2015 was partially offset by proceeds from the sale of assets of $3.0 million and an increase in restricted cash of $2.3 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 $41.9 million for the six months ended June 30, 2014. During the six months ended June 30, 2014, we made payments, net of cash acquired, of $3.9 million, $20.2 million, $10.6 million and $0.3 million for the acquisitions of Activation Energy, Entelios AG, or Entelios, Entech, and another immaterial acquisition of a foreign entity, respectively. We also made $12.6 million of capital expenditures, primarily related to software additions, including capitalized software development costs, to further expand the functionality of our software and solutions, as well as, demand response equipment expenditures due to an increase in our installed customer base. Cash used in investing activities for the six months ended June 30, 2014 was partially offset by cash provided from investing activities of $4.3 million and $2.2 million related to our sale of a service line and our sale of assets, respectively.


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Cash Flows Used In Financing Activities


Cash used in financing activities was $2.1 million for the six months ended  June 30, 2015 and consisted of payments made for employee restricted stock minimum tax withholdings totaling $3.1 million , partially offset by $1.0 million of cash received from the exercise of stock options.


Cash used in financing activities was $4.4 million for the six months ended June 30, 2014 and consisted of payments made for employee restricted stock minimum tax withholdings totaling $5.0 million, partially offset by $0.6 million of cash received from the exercise of stock options.


Borrowings and Credit Arrangements


Credit Agreement


On August 11, 2014, we entered into a $30.0 million senior secured revolving credit facility, the full amount of which may be available for issuances of letters of credit, pursuant to a loan and security agreement, or the 2014 credit facility, with Silicon Valley Bank (SVB), which was subsequently amended on October 23, 2014. The 2014 credit facility is subject to continued covenant compliance and borrowing base requirements. As of June 30, 2015 , we were in compliance with all of our covenants under the 2014 credit facility. On August 6, 2015, the Company and SVB entered into a second amendment to the 2014 credit facility to extend the termination date from August 11, 2015 to August 9, 2016. We believe that it is reasonably assured that we will comply with the covenants of the 2014 credit facility through its expiration date of August 9, 2016. As of June 30, 2015 , we had no borrowings, but had outstanding letters of credit totaling $20.3 million , under the 2014 credit facility. As of June 30, 2015 , we had $9.7 million available under the 2014 credit facility for future borrowings or issuances of additional letters of credit.


Convertible Notes


On August 12, 2014, we entered into a purchase agreement with Morgan Stanley & Co. LLC relating to the sale of $160.0 million aggregate principal amount of 2.25% convertible senior notes due August 15, 2019, or the Notes, in an offering exempt from registration under the Securities Act of 1933, as amended, which we refer to as the Offering. The Notes includes customary terms and covenants, including certain events of default after which the Notes may be declared or become due and payable immediately. The Notes are convertible at an initial conversion rate of 36.0933 shares of the common stock per $1.0 million principal amount of Notes. However, because we received approval at the annual meeting of stockholders held on May 27, 2015, we may elect to settle conversions of Notes by paying or delivering, as the case may be, cash, shares of our common stock or a combination of cash and shares of common stock. The conversion rate will be subject to adjustment in some events, but will not be adjusted for any accrued and unpaid interest.


We have concluded that ASC 470, Debt applies to the Notes and accordingly, we are required to account for the liability and equity components of the Notes separately to reflect their nonconvertible debt borrowing rate. The estimated fair value of the liability component of $137.4 million was determined using a discounted cash flow technique. The excess of the gross proceeds received over the estimated fair value of the liability component totaling $22.6 million has been allocated to the conversion feature (equity component) with a corresponding offset recognized as a discount to reduce the net carrying value of the Notes. The discount is being amortized to interest expense over a five year period ending August 15, 2019 (the expected life of the liability component) using the effective interest method. In addition, transaction costs are required to be allocated to the liability and equity components based on their relative percentages. The applicable transaction costs allocated to the liability and equity components at issuance were $4.1 million and $0.7 million , respectively. The transaction costs allocated to the liability represent debt issuance costs and are recorded as an asset and are being amortized to interest expense on a straight-line basis over a five year period. As of June 30, 2015 , $0.7 million and $2.8 million of deferred issuance costs are included in prepaid expenses and other current assets and deposits and other assets, respectively, in our unaudited condensed consolidated balance sheet.


Interest expense under the Notes is as follows (in millions):


June 30, 2015Three Months EndedSix Months EndedAccretion of debt discount$1.0$2.0Amortization of deferred financing costs0.20.4Non-cash interest expense$1.2$2.42.25% accrued interest0.91.7Total interest expense from Notes$2.1$4.1


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Based on our evaluation of the Notes in accordance with ASC 815-40, Contracts in Entity’s Own Equity , we determined that the Notes contain a single embedded derivative, comprising both the contingent interest feature related to timely SEC filing failure, requiring bifurcation as the features is not clearly and closely related to the host instrument. We have determined that the value of this embedded derivative was nominal as of the date of issuance and as of June 30, 2015 .





Contingent Earn-Out Payments


As discussed in Note 2 contained in Appendix A to the 2014 Form 10-K, in connection with our 2014 acquisitions of Entelios, Activation Energy, Universal Load Center Co., Ltd., or ULC, and Pulse Energy, we may be obligated to pay additional contingent purchase price consideration related to contingent earn-out payments.


The earn-out payment for Entelios, if any, is based on the achievement of certain minimum defined profit metrics for the years ended December 31, 2014 and 2015. The 1.5 million Euros ($2.0 million) maximum earn-out payment includes up to 0.6 million Euros and 0.9 million Euros related to the achievement of the defined profit metrics for the years ended December 31, 2014 and 2015. 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. We determined that the earn-outs’ fair value as of the acquisition date was 0.1 million Euros ($0.1 million). This reflects our 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 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 condensed consolidated statements of operations. Entelios did not achieve the 2014 milestones. During the six months ended June 30, 2015, the change in the fair value that resulted from the accretion of the time value of money discount was not material; as a result, the June 30, 2015 liability remained at 0.1 million Euros ($0.1 million) representing the potential payout associated with the 2015 milestones.


The earn-out payment for Activation Energy is based on the achievement of certain minimum defined MW enrollment, as well as profit metrics for the years ended December 31, 2014 and 2015, respectively. The 1.0 million Euros ($1.4 million) maximum earn-out payment includes up to 0.3 million Euros and 0.7 million Euros related to the achievement of the defined profit metrics for the years ended December 31, 2014 and 2015. 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. We determined that the earn-outs’ fair value as of the acquisition date was 0.2 million Euros ($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. In January 2015, we disbursed 0.3 million Euros ($0.3 million) related to the 2014 milestone. At June 30, 2015, the liability was recorded at 0.6 million Euros ($0.6 million) representing the potential payout associated with the 2015 milestones.


In connection with our acquisition of ULC in April 2014, 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. The market legislation metric, which was deemed purchase price consideration, was achieved in May 2014, with the $0.3 million payment retained to cover general business representations and warranties to be paid 18 months after the closing date. The remaining $1.5 million of potential payout is payable to those stockholders of the acquired entity who are employees as of the time of payment. We concluded these payments should be accounted for as compensation arrangements and expensed ratably over the applicable service period for the amount, if achievement is deemed probable. The first performance milestone of $0.5 million was achieved in December 2014, with $0.2 million paid at such time. The remaining $0.3 million will be paid in January 2016 and 2017. The second performance milestone of $1.0 million has not yet been achieved. As of June 30, 2015, we have recorded a liability of approximately $0.4 million associated with the unpaid market legislation metric and the accrued unpaid first performance milestone in Accrued acquisition consideration in the accompanying balance sheet.


The earn-out payment for Pulse Energy, if any, will be based on the achievement of sales targets for the years ended December 31, 2015, 2016 and 2017. To the extent targets are reached, payment will predominantly be in the form of our common stock with immaterial amounts of cash paid to the U.S. based employees. The earn-out is a binary outcome in that either full or no payment is due. 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 and weighed probability assumptions of these outcomes. Because the contingent consideration is expected to be settled in our own shares and the criteria in ASC 815, Contracts in Entity’s Own Equity , was met, the fair value of the earn-out was recorded in equity as additional paid-in capital. The fair value of the earn-out was estimated at $1.6 million and remains within equity.


Capital Spending


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We have made capital expenditures primarily for general corporate purposes to support our growth and for equipment installations related to our business. Our capital expenditures totaled $11.3 million and $12.6 million during the six months ended June 30, 2015 and 2014 , respectively. We expect our capital expenditures for 2015 to exceed our capital expenditures for 2014 due primarily to increased site installations, higher capitalized software attributable to capitalized wages consistent with the expected growth in research and development headcount, higher leasehold improvements and office equipment consistent with overall headcount growth.


Off-Balance Sheet Arrangements


As of June 30, 2015 , we did not have any off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of Regulation S-K, that have or are reasonably likely to have a current or future effect on our financial condition, changes in our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. We have issued letters of credit in the ordinary course of our business in order to participate in certain demand response programs. As of June 30, 2015 , we had outstanding letters of credit totaling $ 20.3 million . For information on these commitments and contingent obligations, please refer to “Liquidity and Capital Resources-Borrowings and Credit Arrangements” above and Note 7 contained in Part I to this Quarterly Report on Form 10-Q.


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 provided by (used in) 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 loss attributable to EnerNOC, Inc. to be an important indicator of the overall performance because it eliminates the material 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:


• Management defines non-GAAP net loss attributable to EnerNOC, Inc. as net loss attributable to EnerNOC, Inc. before accretion expense related to the debt-discount portion of interest expense associated with the convertible note issuance, stock-based compensation, direct and incremental expenses related to acquisitions or divestitures, direct and incremental expenses related to restructuring activities, and amortization expenses related to acquisition-related intangible assets, net of related tax effects.


• Management defines adjusted EBITDA as net loss attributable to EnerNOC, Inc., excluding depreciation, amortization, stock-based compensation, direct and incremental expenses related to acquisitions or divestitures, direct and incremental expenses related to restructuring activities, interest expense, income taxes and other (expense) income.


• Management defines free cash flow as net cash provided by (used in) operating activities, less capital expenditures, plus net cash provided by (used in) the sale of assets or disposals of components of an entity. Management defines capital expenditures as purchases of property and equipment, which includes capitalization of internal-use software development costs.


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


Non-GAAP net loss attributable to EnerNOC, Inc., non-GAAP net 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.


Non-GAAP net loss for the three months ended  June 30, 2015 was $8.9 million , or $0.32 per basic and diluted share, compared to non-GAAP net loss of $20.7 million, or $0.73 per basic and diluted share, for the three months ended  June 30, 2014 . Non-GAAP net loss for the six months ended June 30, 2015 was $48.5 million, or $1.72 per basic and diluted share, compared to non-GAAP net loss of $44.1 million, or $1.57 per basic and diluted share, for the six months ended June 30, 2014 .


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The reconciliation of GAAP net loss attributable to EnerNOC, Inc. to non-GAAP net loss attributable to EnerNOC, Inc. is set forth below (dollars in thousands, except share and per share data):


Three Months Ended June 30,20152014GAAP net loss attributable to EnerNOC, Inc.$(18,780)$(27,385)ADD: Stock-based compensation expense3,3213,799ADD: Amortization expense of acquired intangible assets4,0272,479ADD: Direct and incremental expenses related to acquisitions or divestitures (1)221413ADD: Direct and incremental expenses related to restructuring (2)1,240—ADD: Debt discount portion of convertible debt1,028—Non-GAAP net loss attributable to EnerNOC, Inc.$(8,943)$(20,694)GAAP net loss per diluted share attributable to EnerNOC, Inc.$(0.66)$(0.96)ADD: Stock-based compensation expense0.120.13ADD: Amortization expense of acquired intangible assets0.140.09ADD: Direct and incremental expenses related to acquisitions or divestitures (1)0.010.01ADD: Direct and incremental expenses related to restructuring (2)0.04—ADD: Debt discount portion of convertible debt0.03—Non-GAAP net loss per diluted share attributable to EnerNOC, Inc.$(0.32)$(0.73)Weighted average number of common shares outstandingBasic and diluted28,327,86728,461,111


Six Months Ended June 30,20152014GAAP net loss attributable to EnerNOC, Inc.$(69,082)$(57,798)ADD: Stock-based compensation expense7,7308,026ADD: Amortization expense of acquired intangible assets7,9454,362ADD: Direct and incremental expenses related to acquisitions or divestitures (1)1,6031,359ADD: Direct and incremental expenses related to restructuring (2)1,240—ADD: Debt discount portion of convertible debt2,020—Non-GAAP net loss attributable to EnerNOC, Inc.$(48,544)$(44,051)GAAP net loss per diluted share attributable to EnerNOC, Inc.$(2.45)$(2.05)ADD: Stock-based compensation expense0.270.28ADD: Amortization expense of acquired intangible assets0.280.15ADD: Direct and incremental expenses related to acquisitions or divestitures (1)0.060.05ADD: Direct and incremental expenses related to restructuring (2)0.04—ADD: Debt discount portion of convertible debt0.08—Non-GAAP net loss per diluted share attributable to EnerNOC, Inc.$(1.72)$(1.57)Weighted average number of common shares outstandingBasic and diluted28,172,39828,225,518


(1) Represents costs primarily related to acquisitions for third party professional services (legal, accounting, valuation) and severance.





(2) Represents costs associated with reorganizing the business for our continued enterprise and utility focus.





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Adjusted EBITDA


Adjusted EBITDA was ($3.2) million , and ($15.9) million for the three months ended  June 30, 2015 and 2014 , respectively. Adjusted EBITDA was ($33.2) million , and ($34.4) million for the six months ended June 30, 2015 and 2014 , respectively.


The reconciliation of net loss to adjusted EBITDA is set forth below (dollars in thousands):


Three Months Ended June 30,Six Months Ended June 30,2015201420152014Net loss attributable to EnerNOC, Inc.$(18,780)$(27,385)$(69,082)$(57,798)Add back:Depreciation and amortization9,9147,84219,74815,207Stock-based compensation expense3,3213,7997,7308,026Direct and incremental expenses related to acquisitions or divestitures (1)2214131,6031,359Direct and incremental expenses related to restructuring (2)1,240—1,240—Other (income) expense, net (3)(1,705)(374)2,952(948)Interest expense2,2406034,5321,053Provision for (benefit from) income tax (4)345(838)(1,940)(1,263)Adjusted EBITDA$(3,204)$(15,940)$(33,217)$(34,364)





|    |                                                                                                                                       
|--- | --------------------------------------------------------------------------------------------------------------------------------------
|(1) | Represents costs primarily related to acquisitions for third party professional services (legal, accounting, valuation) and severance.

|    |                                                                                                           
|--- | ----------------------------------------------------------------------------------------------------------
|(2) | Represents costs associated with reorganizing the business for our continued enterprise and utility focus.

|    |                                                                    
|--- | -------------------------------------------------------------------
|(3) | Other expense primarily relates to foreign currency (gains) losses.

|    |                                                                                                                                                                 
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------
|(4) | Excludes discrete tax provision of $1,102 recorded during the three and six month periods ended June 30, 2014 related to the sale of the USC business component.







Free Cash Flow


Cash flows used in operating activities were $(5.2) million and $(23.7) million for the three and six months ended June 30, 2015 , respectively. Cash flows provided by operating activities were $17.3 million and $5.7 million for the three and months ended June 30, 2014 , respectively. We had negative free cash flow of $8.3 million for the three months ended  June 30, 2015 compared to positive free cash flow of $17.3 million for the three months ended  June 30, 2014 . We had negative free cash flow of $32.0 million for the six months ended June 30, 2015 compared to free cash flow of $0.4 million for the six months ended June 30, 2014 . The reconciliation of cash flows from operating activities to free cash flow is set forth below (in thousands):


Three Months Ended June 30,Six Months Ended June 30,2015201420152014Net cash (used in) provided by operating activities$(5,216)$17,292$(23,668)$5,726Add:Net cash provided by the sale of assets or disposals of components of an entity2,9916,4462,9916,446Subtract:Purchases of property and equipment(6,084)(6,473)(11,290)(12,586)Free cash flow$(8,309)$17,265$(31,967)$(414)


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Critical Accounting Policies and Use of Estimates


The discussion and analysis of our financial condition and results of operations are based upon our interim unaudited condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates, including those related to revenue recognition for multiple element arrangements, allowance for doubtful accounts, valuations and purchase price allocations related to business combinations, expected future cash flows including growth rates, discount rates, terminal values and other assumptions and estimates used to evaluate the recoverability of long-lived assets and goodwill, estimated fair values of intangible assets and goodwill, amortization methods and periods, certain accrued expenses and other related charges, stock-based compensation, contingent liabilities, tax reserves and recoverability of our net deferred tax assets and related valuation allowance. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates if past experience or other assumptions do not turn out to be substantially accurate. Any differences may have a material impact on our financial condition and results of operations.


The critical accounting estimates used in the preparation of our financial statements that we believe affect our more significant judgments and estimates used in the preparation of our interim 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 2014 Form 10-K.


There have been no material changes to our critical accounting policies or estimates during the three and six months ended June 30, 2015 .


Goodwill Impairment


In accordance with ASC 350, Intangibles-Goodwill and Other (ASC 350), we test 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.  Events that would indicate impairment and trigger an interim impairment assessment include, but are not limited to, current economic and market conditions, including a decline in market capitalization, a significant adverse change in legal factors, business climate or operational performance of the business, and an adverse action or assessment by a regulator. Our annual impairment test date is November 30 (Impairment Test Date).


In performing the test, we utilize the two-step approach prescribed under ASC 350. The first step requires a comparison of the carrying value of the reporting units to the fair value of these units. We consider a number of factors to determine the fair value of a reporting unit, including an independent valuation to conduct this test. The valuation is based upon expected future discounted operating cash flows of the reporting unit as well as analysis of recent sales or offerings of similar companies. We base the discount rate used to arrive at a present value as of the date of the impairment test on its weighted average cost of capital (WACC). If the carrying value of the reporting unit exceeds its fair value, we will perform the second step of the goodwill impairment test to measure the amount of impairment loss, if any. The second step of the goodwill impairment test compares the implied fair value of a reporting unit’s goodwill to its carrying value.


In order to determine the fair values of our reporting units, we utilize both a market approach based on the quoted market price of our common stock and the number of shares outstanding and a DCF model under the income approach. The key assumptions that drive the fair value in the DCF model are the discount rates (i.e., WACC), terminal values, growth rates, and the amount and timing of expected future cash flows. If the current worldwide financial markets and economic environment were to deteriorate, this would likely result in a higher WACC because market participants would require a higher rate of return. In the DCF, as the WACC increases, the fair value decreases. The other significant factor in the DCF is its projected financial information (i.e., amount and timing of expected future cash flows and growth rates) and if its assumptions were to be adversely impacted this could result in a reduction of the fair value of the entity. As a result of completing the first step of the impairment assessment on the Impairment Test Date, the fair values (for our reporting units) exceeded the carrying values for both reporting units, and as such, the second step was not required. To date, we have not been required to perform the second step of the impairment test.


Any loss resulting from an impairment test would be reflected in operating income (loss) as an impairment expense in our consolidated statements of operations. The annual impairment testing process is subjective and requires judgment at many points throughout the analysis. If these estimates or their related assumptions change in the future, we may be required to record impairment charges for these assets not previously recorded.





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Revenue Recognition


We recognize revenues in accordance with ASC 605, Revenue Recognition (ASC 605). Our customers include enterprises, grid operators, and utilities. 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. 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 credit reviews 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 internal 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 do not properly reflect reserve requirements, then a change in the allowances would be made in the period in which such a determination was made and revenues in that period could be affected.


Revenues from grid operators and revenues from utilities principally represent demand response revenues. During the three and six months ended June 30, 2015 , revenues from grid operators and utilities were comprised of $51.6 million and $84.1 million , respectively, of demand response revenues. During the three and six months ended June 30, 2014, revenues from grid operators and utilities were comprised of $33.3 million and $77.4 million , respectively, of demand response revenues.


Our enterprise revenues from the sales of our EIS and related solutions to our enterprise customers generally represent ongoing software or service arrangements under which the revenues are recognized ratably over the same period commencing upon delivery of the EIS and related solutions to the enterprise customer. Under certain of our arrangements, 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.


Our EIS and related solutions for utility customers and electric power grid operators also include the demand response applications and solutions, EnerNOC Demand Resource and EnerNOC Demand Manager. Our grid operator revenues and utility revenues primarily reflect the sale of our EnerNOC Demand Resource solution. 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 of demand response capacity, including our participation in capacity auctions and third-party 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 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.


With respect to the EnerNOC Demand Manager application, we generally receive an ongoing fee for overall management of the utility demand response program based on enrolled capacity or enrolled enterprise 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 enterprise 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 enterprise customer installations. We have determined that 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


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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 enterprise customers and delivery of the contracted services.


For further discussion of our revenue recognition policy, please refer to Note 1 contained in Part I to this Quarterly Report on Form 10-Q.


Recent Accounting Pronouncements


In  May  2014,  the  FASB  issued  ASU  No.  2014-09, Revenue  from  Contracts  with  Customers  (Topic  606) ("ASU  2014-09").  ASU  2014-09  is  a comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance under U.S. GAAP. The core principle under ASU 2014-09 is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also specifies the accounting for some costs to obtain or fulfill a contract with a customer. ASU 2014-09 also requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments. On July 9, 2015, the FASB decided to defer the effective date for this standard to annual periods beginning after December 15, 2017 and interim periods therein. Early adoption is permitted, but not before January 1, 2017, and an entity may apply the amendments in ASU 2014-09 either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying ASU 2014-09 at the date of initial application. Currently, we are evaluating both the method of adoption and the impact adoption will have on our consolidated financial statements. In evaluating the method  of  adoption,  we are considering  a  number  of  factors,  including  the  disclosure  requirements  and  related  processes  and  controls required, as well as, the overall industry and peer public company adoption method trends.


In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements — Going Concern: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). The standard requires that we evaluate, at each interim and annual reporting period, whether there are conditions or events that raise substantial doubt about our ability to continue as a going concern within one year after the date the financial statements are issued, and provide related disclosures. ASU 2014-15 is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter, and early adoption is permitted. We do not expect to early adopt ASU 2014-15, which will be effective for its fiscal year ending December 31, 2016. We do not believe the standard will have a material impact on our consolidated financial position and results of operations.


In April 2015, the FASB issued ASU 2015-03, I nterest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs . The amendments in this update require that debt issuance costs related to a recognized debt liability (other than revolving credit facilities) be presented in the consolidated balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This update deals solely with financial statement display matters; recognition and measurement of debt issuance costs are unaffected. ASU 2015-03 is effective for annual periods ending after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not previously been issued. We do not expect to early adopt ASU 2015-03, which will be effective for its fiscal year ending December 31, 2016. We are currently in the process of evaluating the impact of adoption of this ASU on our consolidated financial position and results of operations.


In April 2015, the FASB issued ASU 2015-05, Intangibles—Goodwill and Other—Internal-Use Software: Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement (“ASU 2015-05”). The standard clarifies the circumstances under which a cloud computing customer would account for the arrangement as a license of internal-use software under ASC 350-40. ASU 2015-05 is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2015, and early adoption is permitted. We do not expect to early adopt ASU 2015-05, which will be effective for its fiscal year ending December 31, 2016. We do not believe the standard will have a material impact on our consolidated financial position and results of operations.











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Item 3.Quantitative and Qualitative Disclosures About Market Risk


Except as disclosed herein, there have been no material changes during the three or six months ended June 30, 2015 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 2014 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 majority of our foreign expenses and sales activities are transacted in local currencies, including Australian dollars, Euros, Brazilian real, British pounds, Canadian dollars, Indian rupee, Japanese yen, South Korean Won and New Zealand dollars. 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 or receivables (third party or intercompany) in a foreign currency. During the three months ended  June 30, 2015 and 2014 , our sales generated outside the United States were 29% and 31% , respectively. During the six months ended June 30, 2015 and 2014 , our sales generated outside the United States were 34% and 24% , respectively. We anticipate that sales generated outside the United States will continue to represent greater than 10% of our consolidated sales and will continue to grow in subsequent fiscal years.


The operating expenses of our international subsidiaries that are incurred in local currencies did not have a material adverse effect on our business, results of operations or financial condition for fiscal 2015 . 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 operating 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 months ended  June 30, 2015 and 2014 , we recognized foreign exchange gains of $1.7 million and $0.2 million , respectively. During the six months ended June 30, 2015 and 2014 , we recognized foreign exchange (losses) gains of $(3.3) million and $0.6 million , respectively. These changes primarily relate to intercompany receivables denominated in foreign currencies, largely driven by fluctuations to the Canadian dollar and Euro.


We currently do not have a program in place that is designed to mitigate our exposure to changes in foreign currency exchange rates. We are evaluating 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.


Interest Rate Risk


We incur interest expense on borrowings outstanding under our Notes and 2014 credit facility. The Notes have fixed interest rates. Borrowings under our 2014 credit facility bear interest at a rate per annum, at our option, initially. The interest on revolving loans under the 2014 credit facility will accrue, at our election, at either (i) the LIBOR (determined based on the per annum rate of interest at which deposits in United States Dollars are offered to SVB in the London interbank market) plus 2.00%, or (ii) the “prime rate” as quoted in the Wall Street Journal with respect to the relevant interest period plus 1.00%.


As of June 30, 2015 , we had no aggregate principal amount outstanding under the 2014 credit facility, but had outstanding letters of credit totaling $ 20.3 million under the 2014 credit facility.


The return from cash and cash equivalents will vary as short-term interest rates change. A hypothetical 10% increase or decrease in interest rates, however, would not have a material adverse effect on our financial condition.





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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.


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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 November 6, 2014, a class action lawsuit was filed in the Delaware Court of Chancery against us, World Energy, Wolf Merger Sub Corporation, and members of the board of directors of World Energy arising out of the merger between us and World Energy. The lawsuit generally alleged that the members of the board of directors of World Energy breached their fiduciary duties to World Energy’s stockholders by entering into the merger agreement because they, among other things, failed to maximize stockholder value and agreed to preclusive deal-protection terms. The lawsuit also alleged that we and World Energy aided and abetted the board of directors of World Energy in breaching their fiduciary duties. The plaintiff sought to stop or delay the acquisition of World Energy by us, or rescission of the merger in the event it was consummated, and seeks monetary damages in an unspecified amount to be determined at trial. The parties engaged in settlement negotiations and on December 24, 2014, without admitting, but expressly denying any liability on behalf of the defendants, the parties entered into a memorandum of understanding, or the MOU, regarding a proposed settlement to resolve all allegations. The MOU was filed in the Delaware Court of Chancery on December 24, 2014. Among other things, the MOU provides that, in consideration for a release and the dismissal of the litigation, World Energy would include additional disclosures in a Form SC 14D9-A to be filed with the SEC no later than December 24, 2014. The MOU also provided that the litigation, including the preliminary injunction hearing, be stayed. The merger closed on January 5, 2015. On March 26, 2015, the parties executed and filed with the Delaware Chancery Court a formal stipulation of settlement. The Company has recognized an obligation of $0.3 million in connection with the settlement. The Delaware Chancery Court initially scheduled a hearing to be held on June 30, 2015, which was subsequently rescheduled to August 20, 2015, to consider whether to approve the settlement. There can be no assurance that the Delaware Court of Chancery will approve the settlement.


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 2014 Form 10-K. During the three and six months ended June 30, 2015, there were no material changes to the risk factors that were disclosed in our 2014 Form 10-K or our 2015 First Quarter 10-Q other than as set forth below.


The following risk factor replaces and supersedes the corresponding risk factor set forth in our 2015 First Quarter Form 10-Q:


Unfavorable regulatory decisions, changes to the market rules applicable to the programs in which we currently participate or may participate in the future, and varying regulatory structures in certain regional electric power markets could negatively affect our business and results of operations.


Unfavorable regulatory decisions in markets where we currently operate or choose to operate in the future could significantly and negatively affect our business. For example, in a May 23, 2014 decision by the United States Court of Appeals for the D.C. Circuit, the court held that the Federal Energy Regulatory Commission, or FERC, did not have jurisdiction under the Federal Power Act to issue FERC Order 745, an order that required, among other things, that economic demand response resources participating in the wholesale energy markets administered by electric power grid operators, such as PJM, be paid the locational marginal price of energy. The U.S. Supreme Court has granted certiorari to review the decision of the D.C. Circuit. While we believe that Order 745 was effective and binding and that we delivered service in accordance with the applicable market and program tariffs and manuals, if the decision affirmed and FERC Order 745 is invalidated, certain revenues earned prior to May 23, 2014 in connection with our participation in price-based/economic demand response programs, which we have estimated to be approximately $20.1 million, may become subject to refund, which could negatively impact our business and results of operations. Revenue of $2.8 million earned subsequent to May 23, 2014 and through June 30, 2015 has been deferred; we will continue to defer future revenues relating to these programs until final regulation resolution is reached. In the event the court’s decision is broadened to include capacity or ancillary services markets in which we currently operate or choose to operate in the future, our future revenues and profit margins may be significantly reduced and our results of operations and financial condition could be negatively impacted. Program or market rules could also be modified to change the design of or pricing related to a particular demand response program, which may adversely affect our participation in that program or cause us to cease participation in that program altogether, or a demand response program in which we currently participate could be eliminated in its entirety and/or replaced with a new program that is more expensive for us to operate or


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require substantial changes to the business to enable continued participation. Any elimination or change in the design of any demand response program, including the retroactive application of market rule changes, could adversely impact our ability to successfully manage our portfolio of demand response capacity in that program, especially in the PJM market where we continue to have substantial operations, and could have a material adverse effect on our results of operations and financial condition.


Regulators could also modify market rules in certain areas to further limit the use of back-up generators in demand response markets or could implement bidding floors or caps that could lower our revenue opportunities. For example, the Environmental Protection Agency, or the EPA, issued a final rule in the National Environmental Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines that would have allowed emergency generators to participate in emergency demand response programs for up to 100 hours per year. The final rule was challenged by parties opposing the 100 hour limit, among other things. In a decision issued on May 1, 2015, the United States Court of Appeals for the District of Columbia, or the Court, invalidated portions of the EPA’s final rule, including the 100 hour limit and remanded the rule back to the EPA for further action.  On July 15, 2015, the EPA filed a motion for a stay of the court’s order to allow the EPA to consider whether to propose a new final rule, among other reasons.  There is no guarantee that the Court will grant the motion for a stay or that the EPA will propose a new rule whether or not the stay is granted, and the provisions of any new rule, if any, is not known.  In the event this decision is implemented or upheld on rehearing or further appeal, the result may be a decrease to the 100 hour per year limit for, or the elimination of any, participation by affected emergency generators in emergency demand response programs. If the final rule is invalidated and a more restrictive rule is adopted, some of the demand response capacity reductions that we aggregate from enterprise customers willing to reduce consumption from the electric power grid by activating their own back-up generators during demand response events would not qualify as capacity without the addition of certain emissions reduction equipment. If this were to occur, we may have to find alternative sources of capacity to meet our capacity obligations to our utility customers and electric power grid operators. If we were unable to procure additional sources of capacity to meet these obligations we could be subject to substantial penalties, and our business and results of operations could be negatively impacted.


The electric power industry is highly regulated. The regulatory structures in regional electricity markets are varied and some regulatory requirements make it more difficult for us to provide some or all of our EIS and related solutions in those regions. For instance, in some markets, regulated quantity or payment levels for demand response capacity or energy make it more difficult for us to cost-effectively enroll and manage many enterprise customers in demand response programs. Further, some markets have regulatory structures that do not yet include demand response as a qualifying resource for purposes of short-term reserve requirements known as ancillary services. Unfavorable regulatory structures could limit the number of regional electricity markets available to us for expansion.


In addition, a buildup of new electric generation facilities or reduced demand for electric capacity could result in excess electric generation capacity in certain regional electric power markets. Excess electric generation capacity and unfavorable regulatory structures could lower the value of demand response services and limit the number of economically attractive regional electricity markets that are available to us, which could negatively impact our business and results of operations.


The following risk factor is added to the risk factors included in our 2014 Form 10-K:


We have substantial investments in recorded goodwill as a result of prior acquisitions and may encounter events or circumstances that would require us to record an impairment charge relating to our goodwill and other intangible assets balances.


Under U.S. generally accepted accounting principles, we are required to evaluate our intangible assets for impairment when events or changes in circumstances indicate the carrying value may not be recoverable. We test goodwill for impairment at least annually, and more frequently if impairment indicators are present. In future periods, we may be subject to factors that may constitute a change in circumstances, indicating that the carrying value of our goodwill exceeds fair value or our intangible assets may not be recoverable. These changes may consist of, but are not limited to, declines in our stock price and a sustained decline in our market capitalization, reduced future cash flow estimates, an adverse action or assessment by a regulator and slower growth rates in our industry. Any of these factors, or others, could require us to record a significant charge to earnings in our financial statements during the period in which any impairment of our goodwill or amortizable intangible assets were determined, negatively impacting our results of operations.





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





Issuer’s Purchases of Equity Securities


The following table provides information about our purchases of our common stock during the second quarter ended June 30, 2015 :


Fiscal PeriodTotal Numberof SharesPurchased (1)Average PricePaid per Share (2)Total Number ofShares Purchasedas Part of PubliclyAnnounced Plansor Programs (3)Approximate DollarValue of Shares thatMay Yet Be PurchasedUnder the Plansor Programs  (3)Through March 31, 2015—$——$20,027,016April 1, 2015 - April 30, 201557,83211.77—20,027,016May 1, 2015 - May 31, 20158,82312.65—20,027,016June 1, 2015 - June 30, 201533,0589.91—20,027,016Total for the second quarter of 201599,713$11.23—$20,027,016





|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | We repurchased a total of99,713shares of our common stock in the first quarter of fiscal 2015 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. Shares withheld (or not issued) to satisfy a tax withholding obligation in connection with an award will immediately be added to the share reserve as and when such shares become returning shares and become available for issuance.

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | Average price paid per share is calculated based on the average price per share paid for the repurchase of shares under our publicly announced share repurchase program and the average price per share related to shares 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 11, 2014, our Board of Directors authorized the repurchase of up to $50.0 million of our common stock during the period from August 11, 2014 through August 8, 2015. We refer to this as the 2014 Repurchase Program. We used $30.0 million of the net proceeds from our offering of the Notes to repurchase 1,514,552 shares of our common stock at a purchase price of $19.79 per share, which was the closing price of the common stock on The NASDAQ Global Select Market on August 12, 2014 under the 2014 Repurchase Program. There were no repurchases of our common stock in the first or second quarters of fiscal 2015 pursuant to the 2014 Repurchase Program. On August 6, 2015, our Board of Directors approved a new share repurchase program, effective upon the expiration of our 2014 Repurchase Program on August 8, 2015, that will enable us to repurchase up to $50.0 million of our common stock during the period from August 9, 2015 to August 9, 2016 (the 2015 Repurchase Program). Repurchases under our 2015 Repurchase Program are expected to be made periodically on the open market as market and business conditions warrant, or under a Rule 10b5-1 plan.




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Item 6. Exhibits.


3.1First Amendment to Second Restated Bylaws of EnerNOC, Inc. (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed July 16, 2015 (File No. 001-33471) and incorporated herein by reference.10.1@EnerNOC, Inc. 2014 Long-Term Incentive Plan, and forms of agreement thereunder (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed May 29, 2015 (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 June 30, 2015, formatted in XBRL (Extensible Business Reporting Language): (i) the Unaudited Condensed Consolidated Balance Sheets, (ii) the Unaudited Condensed Consolidated Statements of Operations, (iii) the Unaudited Condensed Consolidated Statements of Comprehensive Loss, (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





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SIGNATURES


Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Amendment No. 1 to Quarterly Report on Form 10-Q/A to be signed on its behalf by the undersigned thereunto duly authorized.


EnerNOC, Inc.Date: August 7, 2015By:/s/ Timothy G. HealyTimothy G. HealyChief Executive Officer(principal executive officer)Date: August 7, 2015By:/s/ Neil MosesNeil MosesChief Operating Officer and Chief Financial Officer (principal financial and accounting officer)





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