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ENERNOC INC - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations.
[November 07, 2014]

ENERNOC INC - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations.


(Edgar Glimpses Via Acquire Media NewsEdge) The following discussion should be read in conjunction with our unaudited condensed consolidated financial statements and related notes thereto included elsewhere in this Quarterly Report on Form 10-Q, as well as our audited financial statements and notes thereto and Management's Discussion and Analysis of Financial Condition and Results of Operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013, as filed with the Securities and Exchange Commission, or the SEC, on March 7, 2014, or our 2013 Form 10-K. This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Without limiting the foregoing, the words "may," "will," "should," "could," "expect," "plan," "intend," "anticipate," "believe," "estimate," "predict," "potential," "continue," "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 2013 Form 10-K and Quarterly Reports for the quarterly periods ended March 31, 2014 and June 30, 2014, as filed with the SEC on May 9, 2014, and August 7, 2014, respectively, or our 2014 First and Second Quarter 10-Qs. You should carefully review those factors and also carefully review the risks outlined in other documents that we file from time to time with the SEC.



Overview We are a leading provider of energy intelligence software, or EIS, and related solutions. We unlock the full value of energy management for commercial, institutional and industrial end-users of energy, which we refer to as our C&I or enterprise customers, as well as electric power grid operators and utilities by delivering a comprehensive suite of demand-side management solutions. Our EIS and related solutions help our customers buy energy better, use less energy and be more strategic about when they consume energy in order to reduce overall energy spend and maximize productivity of that spend.

Our EIS and related solutions provide technology-enabled demand response, demand management, utility bill management, supply management, visibility and reporting, facility optimization, and project management applications and services for our enterprise, electric power grid operator and utility customers.


Demand response is an alternative to traditional electric power generation and transmission infrastructure projects that enables electric power grid operators and utilities to reduce the likelihood of service disruptions, such as brownouts and blackouts, during periods of peak electricity demand, and otherwise manage the electric power grid during short-term imbalances of supply and demand or during periods when energy prices are high. Our solutions for utilities and grid operators include EnerNOC Demand Resource™, a turnkey demand response resource with a firm capacity commitment, and EnerNOC Demand Manager™, a Software-as-a-Service, or SaaS application that provides utilities and energy retailers with the underlying technology to manage their demand response programs and secure reliable demand-side resources. When we enter into an EnerNOC Demand Resource contract, we match obligation, in the form of megawatts, or MW, that we agree to deliver to our utility and electric power grid operator customers, with supply, in the form of MW that we are able to curtail from the electric power grid through our arrangements with our enterprise customers. When we are called upon by our utility or electric power grid operator customers to deliver our contracted capacity, we use our Network Operations Center, or NOC, to remotely manage and reduce electricity consumption across our growing network of enterprise customer sites, making demand response capacity available to electric power grid operators and utilities on demand while helping enterprise customers achieve energy savings, improve financial results and realize environmental benefits. We receive recurring payments from electric power grid operators and utilities 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 bilateral contracts to account for changes in supply and demand forecasts, as well as changes in programs and market rules in order to achieve more favorable pricing opportunities. We refer to the above activities as managing our portfolio of demand response capacity. 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. Our EnerNOC Demand Manager provides our utility customers with real-time load monitoring, dispatching applications, customizable reports, measurement and verification, and other professional services.

We build on our position as the world's leading demand response provider by using our EIS to provide our enterprise customers with the ability to: • manage energy supplier selection, procurement and implementation; 43 -------------------------------------------------------------------------------- Table of Contents • manage energy budget forecasting; • manage utility bills and payment; and • measure, track, analyze, report and manage greenhouse gas emissions.

Our EIS and related solutions provide our enterprise customers with the visibility they need to prioritize resources against the activities that will deliver the highest return on investment.

During the third quarter of our year ending December 31, 2014, or fiscal 2014, we began to offer our EIS and related solutions at three subscription levels: basic, standard, and professional. 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 a data-driven energy efficiency suite of premium consulting and custom training services, including technology integration services, supply consulting, energy efficiency planning, audits, assessments, commissioning and retro-commissioning services, which are available for an hourly or fixed fee. Our target customers for our EIS and related solutions are enterprises that spend approximately $100,000/year per site or more on energy, and we sell to these customers primarily through our direct salesforce.

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 services in several regions throughout the United States, as well as internationally in Australia, Brazil, China, Germany, India, Ireland, Japan, New Zealand, South Korea and the United Kingdom.

Significant Recent Developments On August 11, 2014, we terminated our $70.0 million senior secured revolving credit facility with the several lenders from time to time party thereto and Silicon Valley Bank, or SVB, as administrative agent, swingline lender, issuing lender, lead arranger and book manager, dated April 8, 2013, which we refer to as the 2013 credit facility, and entered into a $30.0 million senior secured revolving credit facility with SVB, which we refer to as the 2014 credit facility. The 2014 credit facility superseded and replaced the 2013 credit facility.

On August 12, 2014, we entered into a purchase agreement with Morgan Stanley & Co. LLC, acting on behalf of itself and the several initial purchasers, relating to our sale of $160.0 million aggregate principal amount of 2.25% convertible senior notes due 2019, or the Notes, in an offering exempt from registration under the Securities Act. On August 18, 2014, the Offering closed and we issued the Notes. The net proceeds from the offering of the Notes were approximately $155.3 million after deducting the discount of the initial purchasers and offering expenses payable by us. We used approximately $30.0 million of the net proceeds of the offering to repurchase 1,514,552 shares of our common stock from purchasers of the Notes in privately negotiated transactions effected through Morgan Stanley & Co. LLC, as our agent, at a purchase price of $19.79 per share, which was the closing price of our common stock on The NASDAQ Global Select Market on August 12, 2014. We intend to use the remaining net proceeds from the Notes for working capital, additional repurchases of our common stock, and other general corporate purposes, which may include the expansion of our current business through acquisitions of, or investments in, other businesses, products, product rights or technologies.

On October 9, 2014, we entered into an amendment to the lease for our principal executive offices, or the July 5, 2012 Lease, to lease additional space. Our lease for this additional space will commence on or about January 1, 2015, which is the date on which we have the right to control access and physical use of the leased space, and will be subject to the terms and conditions of the July 5, 2012 Lease. The lease term for the additional space shall coincide with the term for the July 5, 2012 Lease and expire on July 31, 2020 unless earlier terminated or further extended as provided in the July 5, 2012 Lease. The lease amendment contains both a rent holiday, under which lease payments do not commence until June 2015, and escalating rental payments.

On November 4, 2014, we and one of our wholly-subsidiaries, or Purchaser, entered into a definitive Agreement and Plan of Merger, or the Merger Agreement, to acquire World Energy Solutions, Inc., a Delaware corporation, or the Target. Pursuant to the Merger Agreement, Purchaser will commence an offer, or the Offer, to acquire all of the outstanding shares of the Target's common stock, par value $0.0001 per share, or the Shares, for $5.50 per share net to the seller in cash, without interest, subject to any required withholding of taxes. In addition to purchasing the Shares, we will assume the Target's outstanding debt for a total transaction value of approximately $76.0 million in cash. Completion of the Offer is subject to several conditions, including (i) that a majority of the Shares outstanding (determined on a fully diluted basis) be validly tendered and not validly withdrawn prior to the expiration of the Offer; (ii) the absence of a material adverse effect on the Target; and (iii) certain other customary conditions. The Offer is not subject to a financing condition.

The Offer will commence within 10 business days from the date of the Merger Agreement and will remain open until January 2, 2015, subject to possible extension on the terms set forth in the Merger Agreement. Following the completion of the Offer and subject to the satisfaction or waiver of certain conditions set forth in the Merger Agreement, Purchaser will merge with and into the Target, with the Target surviving as an indirect wholly owned subsidiary of ours, pursuant to the procedure provided for under Section 251(h) of the General Corporation Law of the State of Delaware without any stockholder approvals.

During the period beginning on the date of the Merger Agreement and continuing until 11:59 p.m. on December 29, 2014, or the Go-Shop End Date, the Target and its representatives and subsidiaries, on the terms and subject to the conditions set forth in the Merger Agreement, will have the right to solicit, initiate, encourage and facilitate any inquiry, discussion, offer or request that constitutes, or could lead to, a Takeover Proposal (as defined in the Merger Agreement) and (ii) engage in discussions and negotiations with, and furnish non-public information relating to the Target to any third party in connection with a Takeover Proposal or any inquiry, discussion, offer or request that could lead to a Takeover Proposal. In addition, at any time after the Go-Shop End Date until the closing of the Offer, we may engage in discussions or negotiations with any third party that submits an unsolicited bona fide Takeover Proposal following the Go-Shop End Date, if the Target's board of directors determines in good faith, after consultation with outside legal counsel, that such Takeover Proposal constitutes or could reasonably lead to a Superior Proposal (as defined in the Merger Agreement) and that failure to take such action could reasonably constitute a breach of its fiduciary obligations to the Target's stockholders under applicable law.

At any time prior to the closing of the Offer, the Target's board of directors may make a Target Adverse Recommendation Change (as defined in the Merger Agreement) if it determines in good faith that a Takeover Proposal constitutes a Superior Proposal and, after consultation with its outside legal counsel, that failure to make a Target Adverse Recommendation Change could reasonably constitute a breach of their fiduciary obligations to the Target's stockholders under applicable law. The Target can terminate the Merger Agreement based on a Superior Proposal by (i) providing four (4) business days' written notice, or the Notice Period, to Purchaser and us with respect to such Superior Proposal, (ii) negotiating in good faith with Purchaser and us during the Notice Period to make such adjustments in the Merger Agreement so that the Superior Proposal ceases to constitute a Superior Proposal, and (iii) determining in good faith after the Notice Period, after consultation with outside legal counsel and financial advisors, that the Superior Proposal continues to constitute a Superior Proposal.

Use of Non-Financial Business and Operational Data We utilize certain non-financial business and operational data to provide additional insight into factors and opportunities relevant to our business. This non-financial business and operational data is not utilized to either manage the business or make resource allocation decisions, and therefore does not necessarily have any direct correlation to our financial performance. However, the non-financial business and operational data may provide observations as to the scope of our operations and therefore, we believe the utilization of such data can provide insights into certain aspects of our business, such as market share and penetration and customer composition and depth.

44 -------------------------------------------------------------------------------- Table of Contents The following table outlines certain non-financial business and operational data utilized as of September 30, 2014 and December 31, 2013: September 30, December 31, 2014 2013 Utility Customers (1) 46 36 Grid Operator Customers (2) 14 8 C&I Customers Participating in Demand Response (3) (5) 6,300 5,800 C&I Customer Sites Participating in Demand Response (3) (5) 15,300 13,900 C&I Customers Under Enterprise Revenue Contracts (4) (5) 1,200 600 C&I Sites Under Enterprise Revenue Contracts (4) (5) 35,300 2,800 (1) The term "Utility Customers" describes the number of our electric utility customers that have a contract with us for demand response or energy services. We enter into contractual commitments with certain of these utility customers through bilateral contractual arrangements for the express purpose of reducing load on their grid when called upon, or dispatched, to do so. For certain of these utility customers we provide energy efficiency and consulting services. This measure does not have any direct correlation to our financial performance but may provide observations as to the progress of our sales and marketing efforts aimed at utility customers and our ability to recruit and maintain such customers with a need to curtail demand for electricity (2) The term "Grid Operator Customers" describes the number of our grid operator customers that actively rely on our demand response programs to manage load on their grid. We enter into contractual commitments with these grid operator customers through participation in open market auctions, as well as, bilateral contractual arrangements for the express purpose of optimizing load on their grid when called upon, or dispatched, to do so. This measure does not have any direct correlation to our financial performance but may provide observations as to the progress of our sales and marketing efforts aimed at grid operator customers and our ability to recruit and maintain such customers with a need to curtail demand for electricity.

(3) The term "C&I Customers Participating in Demand Response" describes the number of our C&I customers under contract to actively participate in our demand response programs. By extension, the term "C&I Sites Participating in Demand Response" describes the number of sites across our C&I customer base under contract to actively participate in our demand response programs.

Certain of these customers and sites may additionally use our EIS and related solutions to gain control of how and when they consume electricity. These two measures do not have any direct correlation to our financial performance but may provide observations as to the progress of our sales and marketing efforts and our ability to recruit and maintain customers with curtailable demand for electricity.

(4) The term "C&I Customers Under Enterprise Revenue Contracts" describes the number of our C&I customers that separately purchase our EIS and related solutions to gain control of how and when they consume or procure electricity. By extension, the term "C&I Sites Under Enterprise Revenue Contracts" describes the number of sites across our C&I customer base that separately purchase our EIS and solutions. These two measures do not have any direct correlation to our financial performance but may provide observations as to the progress of our sales and marketing efforts and our ability to recruit and maintain enterprise customers.

(5) Amounts rounded to nearest hundred.

The number of utility customers that have contracts with us and actively rely on our demand response solutions or energy services at September 30, 2014 was 46 compared to 36 at December 31, 2013. We generally receive recurring cash payments from each utility customer actively relying on our demand response solutions in exchange for the capacity we commit to reduce for them. In addition, we receive additional cash payments in the form of energy payments from utility customers actively relying on our demand response solutions when we are actually called upon to reduce load and subsequently deliver on that commitment. The increase in the number of utility customers that have contracts with us and actively rely on our demand response solutions or energy services at September 30, 2014 as compared to December 31, 2013 primarily reflects the addition of new customers from our recent acquisitions of Entelios AG, or Entelios, and Activation Energy DSU Ltd, or Activation, as well as the addition of new customers that have contracts for our energy services. In general, we expect that the number of utility customers that actively rely on our demand response solutions or energy services will increase over time.

The number of grid operator customers that actively rely on our demand response solutions to reduce the load on their grid at September 30, 2014 was 14 compared to eight at December 31, 2013. We generally receive recurring cash payments from each grid 45 -------------------------------------------------------------------------------- Table of Contents operator customer in exchange for the capacity we commit to reduce for them. In addition, we receive additional cash payments in the form of energy payments from grid operator customers when we are actually called upon to reduce load and subsequently deliver on that commitment. The increase in the number of grid operator customers that actively rely on our demand response solutions to reduce the load on their grid at September 30, 2014 as compared to December 31, 2013 primarily reflects the addition of new customers from our recent acquisitions of Entelios and Activation. In general, we expect that the number of grid operator customers that have contracts with us and actively rely on our demand response solutions to reduce the load on their grid will increase over time.

The number of C&I customers participating in demand response was approximately 6,300 at September 30, 2014 compared to 5,800 at December 31, 2013. The number of C&I customer sites participating in demand response at September 30, 2014 was approximately 15,300 as compared to approximately 13,900 at December 31, 2013.

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

The number of C&I customers with enterprise revenue that have deployed our EIS and related solutions at September 30, 2014 was approximately 1,200 compared to approximately 600 at December 31, 2013. This increase of approximately 600 reflects our acquisition of EnTech Utility Service Bureau, Inc., or Entech US, EnTech Utility Service Bureau Ltd., or Entech UK and EnTech USB Private Limited, or Entech India, which we collectively refer to as Entech. The increase is also due to our increased 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, 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 use energy.

The number of C&I sites with enterprise revenue that are under the management of our enterprise EIS and related solutions at September 30, 2014 was approximately 35,300 compared to approximately 2,800 at December 31, 2013. The number of C&I sites with enterprise revenue that are under the management of our EIS and related solutions has increased in tandem with the increase in C&I customers with enterprise revenue, with most of the increase coming from our acquisition of Entech. We expect that the number of C&I customers with enterprise revenue and C&I sites with enterprise revenue that use or are managed by our EIS and related solutions will continue to increase in the future as the market for these solutions continues to grow.

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

Revenues and Expense Components Revenues We derive recurring revenues from the sale of our EIS and related solutions. We do not recognize any revenues until persuasive evidence of an arrangement exists, delivery has occurred, the fee is fixed or determinable, and we deem collection to be reasonably assured. Our customers include grid operators, utilities and enterprises.

Our grid operator revenues and utility revenues primarily reflect the sale of our demand response solutions. The revenues primarily consist of capacity and energy payments, including ancillary services payments, as well as payments derived from the effective management of our portfolio, including our participation in capacity auctions and bilateral contracts and ongoing fixed fees for the overall management of utility-sponsored demand response programs.

We derive revenues from our EnerNOC Demand Resource solution by making demand response capacity available in open market programs and pursuant to contracts that we enter into with electric power grid operators and utilities. In certain markets, we enter into contracts with electric power utilities, generally ranging from three to ten years in duration, to deploy our EnerNOC Demand Resource solution. We refer to these contracts as utility contracts.

Where we operate in open market programs, our revenues from demand response capacity payments may vary month-to-month based upon our enrolled capacity and the market payment rate. Where we have a utility contract, we receive periodic capacity payments, which may vary monthly or seasonally based upon enrolled capacity and predetermined payment rates. Under both open market programs and utility contracts, we receive capacity payments regardless of whether we are called upon to reduce demand for electricity from the electric power grid; and we recognize revenue over the applicable delivery period, even when payments are made over a different period. We generally demonstrate our capacity either through a demand response event or a measurement and verification test. This demonstrated capacity is typically used to calculate the continuing periodic capacity payments to be made to us until the next demand response event or measurement and verification test establishes a new demonstrated capacity amount. In most cases, we also receive an additional payment for the amount of energy usage that we actually curtail from the grid during a demand response event. We refer to this as energy event revenues.

46 -------------------------------------------------------------------------------- Table of Contents As program rules may differ for each open market program in which we participate and for each utility contract, we assess whether or not we have met the specific service requirements under the program rules and recognize or defer revenues related to our EnerNOC Demand Resource solution, as necessary. We recognize demand response capacity revenues when we have provided verification to the electric power grid operator or utility of our ability to deliver the committed capacity under the open market program or utility contract. Committed capacity is verified through the results of an actual demand response event or a measurement and verification test. Once the capacity amount has been verified, the revenues are recognized and future revenues become fixed or determinable and are recognized monthly over the performance period until the next demand response event or measurement and verification test. In subsequent demand response events or measurement and verification tests, if our verified capacity is below the previously verified amount, the electric power grid operator or utility customer will reduce future payments based on the adjusted verified capacity amounts. Under certain utility contracts and open market program participation rules, our performance and related fees are measured and determined over a period of time. If we can reliably estimate our performance for the applicable performance period, we will reserve the entire amount of estimated penalties that will be incurred, if any, as a result of estimated underperformance prior to the commencement of revenue recognition. If we are unable to reliably estimate the performance and any related penalties, we defer the recognition of revenues related to our EnerNOC Demand Resource solution until the fee is fixed or determinable. Any changes to our original estimates of net revenues are recognized as a change in accounting estimate in the earliest reporting period that such a change is determined.

We generally begin earning revenues from our MW within approximately one to three months from the date on which we enable the MW, or the date on which we can reduce the MW from the electricity grid if called upon to do so. The most significant exception is the PJM Interconnection, or PJM, forward capacity market, which is a market from which we derive a substantial portion of our revenues. Because PJM operates on a June to May program-year basis, a MW that we enable after June of each year may not begin earning revenue until June of the following year. Certain other markets in which we currently participate, such as the Western Australia market, or may choose to participate in the future, operate or may operate in a manner that could create a delay in recognizing revenue from the MW that we enable in those markets.

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

The introduction in the PJM market of the Extended-Limited and Annual demand response products beginning in the 2014/2015 delivery year could adversely impact our ability to successfully manage our portfolio of demand response capacity in the PJM open market program and could negatively impact our results of operations and financial condition. For the 2014/2015 delivery year, we have no material capacity revenue related to the PJM Extended-Limited and Annual demand response products.

Our revenues have historically been higher in the second and third quarters of our fiscal year due to seasonality in the demand response market. We expect, based on the fact that we generally recognize substantially all of our demand response capacity revenue related to our participation in the PJM open market program for its Limited demand response product, and the Western Australia, or WA, demand response program governed by the Independent Market Organization, or IMO, which we refer to as the WA demand response program, during the three month period ended September 30th of each year, that our revenues will typically be higher in the third quarter as compared to any other quarter in our fiscal year.

Demand response capacity revenues related to our participation in the WA demand response program are potentially subject to refund and therefore, are deferred until a portion of such capacity revenues are reliably estimable which currently, occurs upon an emergency event dispatch or until the end of the program period on September 30th. Historically all capacity revenues have been recognized during the three month period ended September 30th as there have previously been no emergency event dispatches. During the three month period ended June 30, 2014, there was an emergency event dispatch in this open market program and as a result, a portion of the capacity revenues were fixed and no longer subject to adjustment resulting in the recognition of $4.3 million of capacity revenues and $2.0 million of related cost of revenues. As of September 30, 2014, we 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, future revenues will be recognized ratably over the delivery period from October 1 to September 30.

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

Under certain utility contracts and open market programs, such as PJM's Emergency Load Response Program, the period during which we are required to perform may be shorter than the period over which we receive payments under that contract or program. In these cases, we record revenue, net of reserves for estimated penalties related to potential delivered capacity shortfalls, over the mandatory performance obligation period, and a portion of the revenues that have been earned is recorded and accrued as unbilled revenue. Revenues related to the current PJM open market program year were recognized during the three month period ended September 30, 2014, and we had $155.1 million in unbilled revenues from PJM at September 30, 2014.

Revenues generated from PJM and IMO accounted for 68% and 13%, respectively, of our total revenues for the three month period ended September 30, 2014, and 58% and 11%, respectively, of our total revenues for the nine month period ended September 30, 2014. Revenues generated from PJM and IMO accounted for 62% and 16%, respectively, of our total revenues for the three month period ended September 30, 2013 and 50% and 13% of our total revenues for the nine month period ended September 30, 2013. Other than PJM and IMO, no individual electric power grid operator or utility customer accounted for more than 10% of our total revenues for the three or nine month periods ended September 30, 2014 and 2013.

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

Our enterprise revenues reflect the sales of our EIS and related solutions to large C&I customers that seek to gain control of how and when they consume or procure electricity. Enterprise revenue primarily reflects the sale of EIS and related solutions, and generally represents ongoing arrangements where the revenues are recognized ratably over the service period commencing upon delivery of the contracted solutions to the C&I 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. In addition, under certain of our other arrangements, in particular those arrangements entered into by our wholly-owned subsidiary, M2M Communications, or M2M, we sell proprietary equipment to customers that is utilized to provide the ongoing solutions that we deliver. Currently, this equipment has been determined to not have stand-alone value. As a result, we defer the fees associated with the equipment and begin recognizing those fees ratably over the expected customer relationship period (generally three years), once the customer is receiving from us the ongoing services. In addition, we capitalize the associated direct and incremental costs, which primarily represent the equipment and third-party installation costs, and recognize such costs over the expected customer relationship period.

Cost of Revenues Cost of revenues for our demand response services primarily consists of amounts owed to our C&I customers for their participation in our demand response network and are generally recognized over the same performance period as the corresponding revenue. We enter into contracts with our C&I customers under which we deliver recurring cash payments to them for the capacity they commit to make available on demand. We also generally make an energy payment when a C&I customer reduces consumption of energy from the electric power grid during a demand response event. The equipment and installation costs for our devices located at our C&I customer sites, which monitor energy usage, communicate with C&I customer sites and, in certain instances, remotely control energy usage to achieve committed capacity, are capitalized and depreciated over the lesser of the remaining estimated customer relationship period or the estimated useful life of the equipment, and this depreciation is reflected in cost of revenues.

We also include in cost of revenues our amortization of acquired developed technology, amortization of capitalized internal-use software costs related to our EIS and related solutions, the monthly telecommunications and data costs we incur as a result of being connected to C&I customer sites, services and products, third-party services, equipment costs, equipment depreciation, our internal payroll and 48 -------------------------------------------------------------------------------- Table of Contents related costs allocated to a C&I customer site and our internal payroll, the wages and associated benefits that we pay to our project managers for the performance of their services, and related costs of revenue related to the delivery of services of our utility bill management solution, which we acquired in our acquisition of Entech. Certain costs, such as equipment depreciation and telecommunications and data costs, are fixed and do not vary based on revenues recognized. These fixed costs could impact our gross margin trends during interim periods as described elsewhere in this Quarterly Report on Form 10-Q.

We defer incremental direct costs related to the acquisition or origination of a utility contract or open market program in a transaction that results in the deferral or delay of revenue recognition. As of September 30, 2014 and December 31, 2013, we had no deferred incremental direct costs related to the acquisition or origination of a utility contract or open market program and during the three and nine month periods ended September 30, 2014 and 2013, no contract origination costs were deferred.

In addition, we capitalize incremental direct payments incurred related to customer contracts where the associated revenues have been deferred as long as the capitalized incremental direct payments are deemed realizable. During the three month periods ended September 30, 2014 and 2013, we capitalized $1.0 million and $1.2 million, respectively, of incremental direct payments associated with customer contracts. During the nine month periods ended September 30, 2014 and 2013, we capitalized $37.5 million and $18.4 million, respectively, of incremental direct payments associated with customer contracts.

These capitalized payments will be amortized in proportion to the related revenue being recognized. Certain of these incremental direct payments are recorded as a reduction of revenues when the associated revenues are recognized as they relate to bilateral demand response arrangements where the other bilateral party has become the primary obligor of the demand response obligation. During the three month periods ended September 30, 2014 and 2013, we expensed $26.9 million and $22.7 million, respectively, of capitalized incremental direct payments to cost of revenues and recorded $11.1 million and $0.4 million, respectively, as a reduction to revenues. During the nine month periods ended September 30, 2014 and 2013, we expensed $29.1 million and $25.2 million, respectively, of capitalized incremental direct payments to cost of revenues and recorded $11.1 million and $0.4 million, respectively, as a reduction to revenues. As of September 30, 2014, there were no material realizability issues related to capitalized incremental direct payments.

We also capitalize the costs of our production and generation equipment utilized in the delivery of our demand response services and expense this equipment over the lesser of its estimated useful life or the term of the contractual arrangement. During the three month periods ended September 30, 2014 and 2013, we capitalized $2.6 million and $1.3 million, respectively, of production and generation equipment costs. During the nine month periods ended September 30, 2014 and 2013, we capitalized $7.9 million and $8.9 million, respectively, of production and generation equipment costs. We believe that the above accounting treatments appropriately match expenses with the associated revenues.

Gross Profit and Gross Margin Gross profit consists of our total revenues less our cost of revenues. Our gross profit has been, and will continue to be, affected by many factors, including (a) the demand for our EIS and related solutions, (b) the selling price of our EIS and related solutions, (c) our cost of revenues, (d) the way in which we manage, or are permitted to manage by the relevant electric power grid operator or utility, our portfolio of demand response capacity, (e) the introduction of new EIS and related solutions, services and products, (f) our demand response event performance and (g) our ability to open and enter new markets and regions and expand deeper into markets we already serve. The effective management of our portfolio of demand response capacity, including our outcomes in negotiating favorable contracts with our customers and our participation in capacity auctions and bilateral contracts, and our demand response event performance, are the primary determinants of our gross profit and gross margin.

Operating Expenses Operating expenses consist of selling and marketing, general and administrative, and research and development expenses. Personnel-related costs are the most significant component of each of these expense categories. We grew from 738 full-time employees at September 30, 2013 to 1,031 full-time employees expenses at September 30, 2014 primarily as a result of our fiscal 2014 acquisitions to drive overall growth and expansion into new markets over the past year. As noted above under "Cost of Revenues", a portion of our headcount and associated payroll and related expenses are included within cost of revenues. We expect to continue to hire employees to support our growth for the foreseeable future. In addition, we incur significant up-front costs associated with the expansion of the number of contractual MW, which we expect to continue for the foreseeable future. We expect our overall operating expenses to increase in absolute dollar terms for the foreseeable future as we continue to enable new C&I customer sites and expand the development of our EIS and related solutions, services and products. In addition, possible future acquisitions and associated amortization expense of intangible assets acquired could potentially increase our operating expenses in future periods.

49 -------------------------------------------------------------------------------- Table of Contents Selling and Marketing Selling and marketing expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards, related to our sales and marketing organization, (b) commissions, (c) travel and other out-of-pocket expenses, (d) marketing programs such as trade shows and (e) other related overhead. Commissions are recorded as an expense when earned by the employee. We expect an increase in selling and marketing expenses in absolute dollar terms through at least the end of fiscal 2014 as we invest in infrastructure to support our continued growth and we expect that selling and marketing expenses as a percentage of revenues will be consistent with the year ended December, 31, 2013, or fiscal 2013, primarily due to the additional expenses that result from our recently completed acquisitions and ongoing market expansion.

General and Administrative General and administrative expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards and bonuses, related to our executive, finance, human resource, information technology and operations organizations, (b) facilities expenses, (c) accounting and legal professional fees, (d) depreciation and amortization and (e) other related overhead. We expect an increase in general and administrative expenses in absolute dollar terms through at least the end of fiscal 2014 as we invest in infrastructure to support our continued growth and we expect that general and administrative expenses as a percentage of revenues will be consistent with fiscal 2013 primarily due to the additional expenses that result from our recently completed acquisitions and ongoing market expansion.

Research and Development Research and development expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards, related to our research and development organization, (b) payments to suppliers for design and consulting services, (c) costs relating to the design and development of new energy management applications, solutions and products and enhancement of existing energy management applications, solutions and products, (d) quality assurance and testing and (e) other related overhead. During the three and nine month periods ended September 30, 2014, we capitalized software development costs, including software license fees and external consulting costs, of $1.5 million and $4.6 million, respectively. During the three and nine month periods ended September 30, 2013, we capitalized software development costs, including software license fees and external consulting costs, of $1.5 million and $5.8 million, respectively, which are included as software in property and equipment at September 30, 2014. We expect an increase in research and development expenses in absolute dollar terms for the foreseeable future as we develop new technologies and enhance our existing technologies to support our continued growth; and, we expect that research and development expenses as a percentage of revenues will be consistent with fiscal 2013 primarily due to the additional expenses that result from our recently completed acquisitions and ongoing market expansion.

Stock-Based Compensation We account for stock-based compensation in accordance with Accounting Standards Codification, or ASC, 718 Stock Compensation. As such, all share-based payments to employees, including grants of stock options, restricted stock and restricted stock units, are recognized in the statement of income based on their fair values as of the date of grant.

During the nine month period ended September 30, 2014, we granted 388,034 shares of non-vested restricted stock to certain executives that contain performance-based vesting conditions. Of these shares, 25% vest in 2015 if the performance criteria related to certain 2014 operating results are achieved and the executive is still employed as of the vesting date and the remaining 75% of the shares vest quarterly over a three year period thereafter as long as the executive is still employed as of the vesting date. If the performance criteria related to certain 2014 operating results are not achieved, 100% of the shares are forfeited.

During the nine month periods ended September 30, 2014, we 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 our acquisition of Entelios. Of these shares, up to 10% vest in 2015 if the performance criteria related to certain 2014 operating results are achieved and the employee is still employed as of the vesting date, up to 20% vest in 2016 if the performance criteria related to certain 2015 operating results are achieved and the employee is still employed as of the vesting date, and up to the remaining 70% of the shares vest in 2017 if the performance criteria related to certain 2016 operating results are achieved and the employee is still employed as of the vesting date. If the performance criteria related to certain 2014, 2015 and 2016 operating results are not achieved, 100% of the shares are forfeited. As of September 30, the awards have not been deemed probable of vesting.

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

50 -------------------------------------------------------------------------------- Table of Contents For the three month periods ended September 30, 2014 and 2013, we recorded expenses of approximately $4.1 million and $3.8 million, respectively, in connection with share-based payment awards to employees and non-employees. For the nine month periods ended September 30, 2014 and 2013, we recorded expenses of approximately $12.2 million and $11.8 million, respectively, in connection with share-based payment awards to employees and non-employees. With respect to stock option grants through September 30, 2014, a future expense of non-vested stock options of approximately $0.1 million is expected to be recognized over a weighted average period of 2.3 years. For non-vested restricted stock subject to service-based vesting conditions outstanding as of September 30, 2014, we had $21.3 million 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 September 30, 2014, which represents all of the outstanding non-vested restricted stock subject to performance-based vesting conditions, we had $7.1 million of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 1.7 years. For non-vested restricted stock units subject to service-based vesting conditions outstanding as of September 30, 2014, the Company had $0.2 million 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 September 30, 2014, we had $4.9 million of unrecognized stock-based compensation expense. If and when any additional portion of these non-vested restricted stock units are deemed probable to vest, we 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.

Interest Expense and Other (Expense) Income, Net Interest expense primarily consists of interest expense related to our Notes, as well as fees associated with the 2012, 2013 and 2014 credit facilities. Interest expense also consists of fees associated with issuing letters of credit and other financial assurances. Other income and expense consist primarily of gains or losses on transactions denominated in currencies other than our or our subsidiaries' functional currency, interest income earned on cash balances, and other non-operating income and expense.

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