EnerNOC, Inc.
ENERNOC INC (Form: 10-K, Received: 03/10/2016 17:10:38)


 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
 
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 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)
Delaware
 
87-0698303
(State or Other Jurisdiction of
Incorporation or Organization)
 
(IRS Employer
Identification No.)
 
 
One Marina Park Drive
Suite 400
Boston, Massachusetts
 
02210
(Zip Code)
(Address of Principal Executive Offices)
 
 
Registrant’s telephone number, including area code:
(617) 224-9900
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
 
Name of Each Exchange on Which Registered
Common Stock, $0.001 par value
 
The NASDAQ Stock Market LLC
(The NASDAQ Global Market)
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes   ¨         No   ý
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes   ¨         No   ý
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   ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ¨
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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one).
Large accelerated filer   ¨
 
Accelerated filer   x
 
Non-accelerated filer   ¨
 
Smaller reporting company   ¨
 
 
(Do not check if a smaller reporting company)
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes   ¨         No   ý
The aggregate market value of the Registrant’s common stock held by non-affiliates of the Registrant as of June 30 2015, the last business day of the Registrant’s second quarter of the fiscal year ended December 31, 2015, was approximately $275.5 million based upon the last sale price reported for such date on The NASDAQ Global Market.
The number of shares of the Registrant’s common stock (the Registrant’s only outstanding class of stock) outstanding as of March 4, 2016 was 30,644,612 .
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for its 2016 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than 120 days after the end of the Registrant’s fiscal year ended December 31, 2015, relating to certain information required in Part III of this Annual Report on Form 10-K are incorporated by reference into this Annual Report on Form 10-K.
 




EnerNOC, Inc.
ANNUAL REPORT ON FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2015
Table of Contents
 
 
Page
 
 
 
 
PART I
 
 
 
Item 1.
 
Item 1A.
 
Item 1B.
 
Item 2.
 
Item 3.
 
Item 4.
 
 
 
 
 
Part II
 
 
 
Item 5.
 
Item 6.
 
Item 7.
 
Item 7A.
 
Item 8.
 
Item 9.
 
Item 9A.
 
Item 9B.
 
 
 
 
 
PART III
 
 
 
Item 10.
 
Item 11.
 
Item 12.
 
Item 13.
 
Item 14.
 
 
 
 
 
PART IV
 
 
 
Item 15.
 
 
 
Appendix A
 
F- 1
 
 
F- 2
 
 

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This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. For this purpose, any statements contained herein regarding our strategy, future operations, financial condition, future revenues, profits and profit margins, projected costs, market position, prospects, plans and objectives of management, other than statements of historical facts, are forward-looking statements. The words “anticipates,” “believes,” “estimates,” “expects,” “intends,” “may,” “plans,” “projects,” “will,” “would” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. We cannot guarantee that we actually will achieve the plans, intentions or expectations expressed or implied in our forward-looking statements. Matters subject to forward-looking statements involve known and unknown risks and uncertainties, including economic, regulatory, competitive and other factors, which may cause actual results, levels of activity, performance or the timing of events to be materially different than those exposed or implied by forward-looking statements. Important factors that could cause or contribute to such differences include the factors set forth under the caption “Risk Factors” in Item 1A of Part I of this Annual Report on Form 10-K. Although we may elect to update forward-looking statements in the future, we specifically disclaim any obligation to do so, even if our estimates change, and readers should not rely on those forward-looking statements as representing our views as of any date subsequent to March 10, 2016 .
Our primary trademark is EnerNOC. Other trademarks or service marks appearing in this Annual Report on Form 10-K are the property of their respective holders.

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PART I
Item 1.
Business
We use the terms “EnerNOC,” the “Company,” “we,” “us” and “our” in this Annual Report on Form 10-K to refer to the business of EnerNOC, Inc. and its subsidiaries.
Company Overview
We are a leading provider of energy intelligence software, or EIS, and demand response solutions to enterprises, utilities, and electric power grid operators.
Our EIS provides our enterprise customers with a suite of Software-as-a-Service, or SaaS, offerings that improve how enterprises manage and control energy costs for their organizations. We continually enhance and expand our EIS to meet the evolving needs of our enterprise customers by providing SaaS solutions to manage:
energy cost visualization, budgets, forecasts, and accruals;
utility bill validation and payment;
facility optimization, including benchmarking facilities and identifying cost savings opportunities;
energy project tracking;
reporting for energy and sustainability disclosure and compliance; and
peak energy demand and the related cost impacts.
Our EIS helps our enterprise customers quickly analyze data, achieve real‑time visibility and intelligence about their organization’s energy usage, reduce operational costs, comply and report on sustainability requirements, and drive better business decisions. We offer our EIS to our enterprise customers at four subscription levels: basic, standard, professional, and industrial.
In addition, our EIS provides our utility customers with a SaaS-based customer engagement platform that allows utilities to:
increase customer satisfaction;
meet energy efficiency mandates;
reduce cost through lower call volume; and
increase revenue through more effective targeting of existing utility-sponsored programs.
We deliver shared value for both the utility and its customers by combining our deep expertise with commercial, institutional and industrial end-users of energy, or C&I end-users, 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 C&I end-users, and small and medium-sized enterprises.
Our EIS also provides our enterprise and utility customers located in restructured or deregulated markets with the ability to more effectively manage energy supplier selection and the energy procurement process by providing highly-structured auction events designed to yield transparent and competitive energy pricing. Our energy procurement application consists of an online auction platform that enables our enterprise and utility customers to get the best price for electricity, natural gas and other energy resources by having energy suppliers compete for their business, as well as supplier contract management and price alert tools. Our energy procurement solutions also include supply procurement advisory services that assist our enterprise customers in developing and implementing risk management and purchasing strategies that provide maximum price transparency and structural savings.
In addition, our demand response solutions provide our utility customers and electric power grid operators with a managed service 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 C&I end-users. When we are called upon by our utility customers and electric power grid operators to deliver our contracted capacity, we use our Network Operations Center, or NOC, to remotely manage and reduce electricity consumption across our network of C&I end‑user sites, making demand response capacity available to our utility customers and electric power grid operators on demand while helping C&I end-users achieve energy savings, improve financial results and realize environmental benefits. We receive periodic payments from our utility customers and electric power grid operators for providing our demand response solutions, and we share these periodic payments with C&I end-users in exchange for those C&I end-users reducing their power consumption when called upon by us to do so. Our demand response solutions are also capable of providing our utility customers with the underlying technology to manage their own utility-sponsored demand response programs and secure reliable demand-side resources. This product consists of long‑term contracts with our utility customers for a technology-enabled managed service that provides our utility customers with real-time load monitoring, dispatching applications, customizable reports, and measurement and verification tools.

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In addition, we offer premium professional services that support the implementation of our EIS and help our enterprise customers set their energy management strategy, as well as provide energy audits and retro-commissioning. Professional services are offered to our customers as a means to further implement and extend our technology across their organizations.
Strategy
We are a technology company that aspires to change the way the world uses energy through the adoption of our EIS and demand response solutions. We intend to build on our leading position in the markets we serve by leveraging our bright and passionate workforce, scalable and proprietary technology, and substantial operating experience. Key elements of our strategy include:
Attracting and Retaining the Best People
In order to develop best-in-class technology and to be the leading provider of EIS and demand response solutions in the markets we serve, we must attract and retain the best people across our organization. Our workforce is the keystone of our business and our success is dependent upon the talent, passion and work ethic of our people. We pride ourselves on our strong culture and strive to create a workplace that attracts topflight people who share our values and vision, and are eager to join us in our relentless pursuit to change the way the world uses energy.
Investing in Technological Innovation
Our research and development investments have produced the technology that has kept us at the forefront of energy management since we were founded in 2001. Our technology investments primarily fall into two categories: investing for scale and investing for evolving customer needs. To support our growing customer base and the corresponding increase in data, we continue to make significant investments in scalable cloud deployments that can be leveraged on demand for complex analytics and machine learning. The pace of change in the energy industry has accelerated in recent years resulting in a growing number of new and more complex challenges for our customers. We seek to better understand those challenges and how to best address them through near and long-term product enhancements by working with our enterprise customer and utility customer advisory boards, which we refer to as our Customer Advisory Boards. Our Customer Advisory Boards, consisting of executives from each customer segment, provide us with unique insights that inform many of our research and development investments. We will continue to work closely with our Customer Advisory Boards and our customers, and as their needs evolve, we intend to invest in the research and development necessary to provide them with the technology they demand to manage their most important energy-related challenges.
Developing Markets for our EIS and Demand Response
We were a pioneer in developing the demand response market in the United States and internationally, and we aim to leverage that success by developing new markets for our full suite of EIS offerings and demand response solutions. We have two primary approaches to developing markets for our EIS and demand response solutions. First, we are helping customers understand the materiality of energy and sustainability to the future of their businesses. As enterprises continue to better understand the material impacts of energy and sustainability, we are confident they will be able to allocate discretionary budget for our EIS, as well as continue to leverage our demand response solutions, to tackle energy management. Second, we believe that building a robust and healthy EIS ecosystem through partnerships and thought leadership is an integral component of early-stage market development.
Driving Operational and Financial Efficiencies in Our Business
We manage a complex business that has experienced significant growth in the scale and scope of its operations in recent years. We work to maximize the efficiency of those operations by focusing on delivering the highest-value products to the highest-potential markets in the most cost-effective manner. Beginning in our fiscal year ending December 31, 2016, or fiscal 2016, we are taking a significant step in our effort to realize efficiencies in our business by managing our operations in two distinct segments - Software and Demand Response. See Note 3 to our consolidated financial statements contained in Appendix A to this Annual Report on Form 10-K. We expect this realignment to create efficiencies in our overall business as a result of enhanced management focus within each segment on performance and key performance drivers. Additional opportunities to realize efficiencies in our business may arise from portfolio assessments as we continue to evaluate the long-term strategic fit of each of our assets. We understand the necessity of operating efficiently as we make significant investments to drive the growth of our EIS and demand response solutions, and we plan to manage the business accordingly.
Energy Intelligence Software and Demand Response
Enterprise Solutions
At the heart of our EIS for enterprise customers is a rich set of analytics that provides prioritized actions and opportunities for our enterprise customers to lower their energy cost, and quantify environmental impacts for stakeholders. We built systems to collect and process several forms of data, including real-time energy interval data, tens of thousands of utility tariffs, real

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time market pricing data, utility bills, weather, customer energy contracts, customer demographic data, and customer production data. We use big data and machine-learning approaches to analyze this data for cost-saving opportunities and to predict future outcomes that can help our enterprise customers make better business decisions.
Our EIS for enterprise customers includes six core areas of functionality:
1)
Budget Forecasts, Cost Visualization and Accruals, which provide our enterprise customers with the ability to develop accurate energy budgets and track cost accruals.
2)
Utility Bill Management, which provides our enterprise customers with a central platform to collect historical utility bills, track trends in utility usage and costs, discover and report billing errors, and streamline accounts payable processes.
3)
Compliance and Reporting, which tracks trends in energy and carbon impact, visualizes real-time energy data to understand consumption patterns, automates reporting for purposes of compliance and benchmarking standards such as GRESB and ENERGY STAR, and disaggregates and tracks actual consumption and demand costs.
4)
Facility Optimization, which allows our enterprise customers to benchmark their facilities against one another, analyze meter data to identify cost savings opportunities and prioritize actions across a portfolio of facilities.
5)
Project Tracking, which allows our enterprise customers to track the progress and impact of savings measures that have been implemented.
6)
Demand Management, which alerts our enterprise customers when new demand thresholds are being reached, quantifies the cost impact of demand peaks, forecasts new facility and system peaks and alerts on real-time and day-ahead index prices.
Utility Solutions
Our EIS helps our utility customers better understand and engage their business customers to deliver outcomes. Our software platform collects and processes data, and uses big data and machine learning approaches to segment like businesses in a manner that enables our utility customers to provide personalized communication and recommendations to their customers.
Our EIS for utility customers includes three key areas of functionality:
1)
Customer Engagement Software, which provides customized, timely, and valuable content relating to a C&I end-user's energy usage or potential energy savings that is relevant for that C&I end-user.
2)
Energy Efficiency, which provides tools that help our utility customers meet energy efficiency mandates by delivering targeted, automated reports to their customers.
3)
Operational Effectiveness, which uses software analytics to improve effectiveness and reduce our utility customers' cost-to-serve their customers by providing targeted program design.
Energy Procurement Solutions
Our EIS includes an energy procurement platform that helps our enterprise and utility customers with the complexity of procuring energy in restructured or deregulated markets. Our EIS brings together real-time and future market data, current customer contracts, a customer's risk profile, and a broad footprint of over 500 suppliers to a single marketplace.
Our procurement platform allows our enterprise and utility customers to:
1)
Get the best price for energy when going to market by having a large number of energy suppliers compete for their business in an auction process.
2)
Identify opportunities to go to market based on their current contracts, their risk profile, and current market conditions.
3)
Manage energy contracts in a single location providing a more effective way to monitor expirations and current market exposure.
4)
Better understand risk in their energy portfolio.
Demand Response
Our demand response solutions centralize demand response event performance and help manage outcomes between the control rooms dispatching the resource and the C&I end-users providing the resource. By installing and enabling notification, monitoring and control technology at the C&I end-user site, we provide a single view of performance to the utility customer,

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electric power grid operator, and the C&I end-user. Performance expectations, as well as curtailment plans, are all managed through a single platform.
Technology and Operations
We are focused on delivering industry-leading EIS and demand response solutions. Our technology can be broken down into two primary components: our EIS platform and our NOC.
Energy Intelligence Software Platform
Our cloud based EIS platform is deployed within Amazon Web Services, or AWS, and is built using a microservices-based architecture, which allows for global deployment and provides best in class scalability and performance. Our EIS platform leverages many cutting edge technologies including HBase, Spark, Hadoop, Kafka, Redis, Splunk and AngularJS. The AWS cloud based services enable optimal global deployment for our EIS platform, while providing elastic scalability in support of on-demand compute intensive processing, such as large scale analytics. Our microservices architecture uses a collection of open source components and services that enable the flexible creation of products with a short time to market. Our cloud based EIS platform hosts our solutions portfolio and enables us to quickly build and deploy new EIS solutions. The platform enables us to efficiently scale our EIS in existing and emerging geographic regions, and rapidly grow the number of customers that leverage our platform.
We believe that a key factor to successfully offering our EIS is integrating data from disparate sources and utilizing it to deliver customer-focused solutions using open protocols and standards. Our EIS platform collects more than 1.5 billion monthly readings of customer and C&I end-user data ranging from sub-second to daily intervals, which is then integrated with near real-time, historical and forecasted market variables.
Our EIS platform measures, manages, benchmarks and helps optimize each enterprise customer’s energy consumption and facility operations. We use data science and analytics to forecast demand, continuously monitor and optimize building management equipment, model rates and tariffs, benchmark similar facilities, facilitate the analysis of complex consumption patterns, as well as measure real-time performance of demand response.
We use this data to provide our utility customers with an integrated customer engagement and demand side management solution. This allows utilities to serve their entire customer base of C&I end-users and small and medium-sized enterprises. Our EIS platform integrates data from utility meters, utility bills, and customer-based systems, as well as other sources, to deliver personalized insight on an enterprise’s energy use, as well as tools for customer administration and support.
In addition, our EIS has the ability to track our enterprise customers' greenhouse gas emissions by mapping their energy consumption with the fuel mix used for generation in their location, such as the proportion of coal, nuclear, natural gas, fuel oil and other sources used.
Our EIS platform is supported by a complete internet of things, or IoT, network built on open standards and secure communication. For our enterprise customers, data is collected utilizing an EnerNOC site server, the industry’s first presence-enabled smart grid technology. This always-on, two-way, presence-based connection significantly enhances visibility into our enterprise data collection network and streamlines the customer enablement process.
In addition, we continue to work to support open interfaces and industry standards to allow integration of data from disparate sources. These standards include RESTful services, OpenADR VEN/VTN, and other IoT protocols, such as HTTP and MQTT. This allows our EIS platform to collect advanced metering infrastructure data directly from utilities' meter data management systems.
Network Operations Center
Our NOC monitors all of our network data and health, including customer and C&I end-user connectivity, and electric power grid and market conditions, and serves as our 24/7 customer support center. For demand response, our technology enables our NOC to automatically respond to signals sent to us by utilities and electric power grid operators to deliver demand reductions within targeted geographic regions. Demand reduction is monitored remotely with near real-time data feeds, the results of which are displayed in our NOC through various data presentment screens. Each C&I end-user site is monitored for the duration of the demand response event and operations are restored to normal when the event ends. We currently participate in demand response programs across the United States, Australia, Austria, Canada, Germany, Ireland, Japan, New Zealand, South Korea, Switzerland and the United Kingdom.

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Sales and Marketing
As of December 31, 2015, our sales and marketing team consisted of 325 employees, which included professionals on our direct sales, channel sales, inside sales, sales operations, solutions engineering, marketing, product marketing, communications, and regulatory and government affairs teams.
Our salesforce is segmented between teams targeting named accounts and teams targeting mid-market accounts. Named accounts represent the largest opportunity for our EIS and are targeted through two dedicated teams organized by customer type: enterprise and utility. Our sales teams targeting mid-market accounts are organized by product type and are tasked primarily with selling our procurement solutions and securing demand response commitments.
Our marketing group is responsible for influencing all market stakeholders, including customers, C&I end-users, policymakers, industry analysts and the general media, attracting prospects to our business, enabling the sales engagement process with messaging, training and sales tools, and sustaining and expanding relationships with existing customers through renewal and retention programs and by identifying cross-selling opportunities. This group researches our current and future markets and leads our strategies for growth, competitiveness, profitability and increased market share.
Research and Development
As of December 31, 2015, our research and development team consisted of 210 employees. Our research and development team is responsible for developing and enhancing our existing EIS and demand response solutions, as well as the engineering and design of new functionality.
Our research and development expenses were approximately $29.3 million , $20.7 million , and $18.3 million for the years ended December 31, 2015, 2014 and 2013, respectively. During the years ended December 31, 2015 , 2014 and 2013 , we capitalized internal software development costs of $8.4 million , $6.0 million, and $7.9 million, respectively, and these amounts are included as software in property and equipment.
Customers
Enterprises
Our named account enterprise sales team primarily focuses its efforts on the following six vertical markets: manufacturing/industrial, commercial real estate, healthcare, government, education, and food sales and storage. The following table lists some of our enterprise customers as of December 31, 2015 in each of the six key vertical markets that we target:
Manufacturing/Industrial
 
Commercial Real Estate
 
Healthcare/Pharmaceutical
General Motors
 
Beacon Properties
 
Athena Health Care Associates
Kimberly-Clark, Inc.
 
Beal Companies
 
George Washington University Hospital
Leggett & Platt
 
Equity Office Properties
 
Lonza Group AG
Saint Gobain
 
Morgan Stanley
 
Temecula Valley Hospital
US Silica
 
Washington Realty Investment Trust
 
 
 
 
 
Government
 
Education
 
Food Sales and Storage
Baltimore Regional Cooperative Purchasing Committee
 
California State University
 
Great Lakes Cold Storage
City of Albany, NY
 
Colorado State University
 
Shop Rite
City of Corpus Christi, TX
 
Knox County Schools
 
SuperVALU
County of Los Angeles, CA
 
North Penn School District
 
Weis Markets
U.S. Postal Service
 
Wicomico County Public Schools
 
 
Our contracts with enterprise customers typically take approximately six to twelve months to complete and have terms that generally range between one and five years.
Utilities
Our named account utility sales team focuses on the largest investor-owned, public power, and retailer utilities. Our utility customers include Pacific Gas and Electric, Consumers Energy, BC Hydro, and Smartest Energy. Our contracts with utility customers typically take 12 to 18 months to complete and have terms that generally range between three and ten years.
Electric Power Grid Operators
The electric power grid operators to which we provide our demand response solutions include PJM, the Australian Energy Market Operator, or AEMO, which was formerly known as the Australian Independent Market Operator Wholesale Electricity

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Market, Electric Reliability Council of Texas, Alberta Electric System Operator, and Ontario Power Authority among others. We may choose to participate in additional or different markets in the future based upon various factors, including our ability to secure acceptable pricing arrangements in such markets.
In order to participate in deregulated wholesale electricity markets in the United States and internationally, we are usually required to first become a market member. This typically entails signing membership agreements, which bind us and other participants to agree to adhere to the Federal Energy Regulatory Commission, or FERC, or the equivalent relevant regulatory authority in international markets approved by governing documents. After establishing membership in these deregulated markets, we secure access to the market by participating in forward “auctions” or “tenders,” in which we commit to delivering demand response resources several months or even years in advance of a defined delivery period. This auction activity often requires us to post financial assurance with the relevant market operator, and by committing to delivering demand response resources in future periods, we assume the risk of delivery of the committed resource levels and can be subject to financial penalties for both under-delivery and non-delivery.
Competition
We face competition from other providers of EIS and demand response solutions, advanced metering infrastructure service providers, and utilities and competitive electricity suppliers who offer their own products and services. We also compete with traditional supply-side resources, such as peaking power plants.
The industry in which we participate is fragmented. When competing for enterprise customers, we believe that the primary factors on which we compete are:
the ability of the provider to service multiple sites across different geographic regions and to provide valuable software and technology-enabled solutions;
the ability of the provider to apply customer-specific tariff and other pricing components to energy data; and
the level of sophistication employed by the provider to identify and optimize energy management capabilities and opportunities.
When competing for utility customers, we believe that the primary factors on which we compete are:
the level of understanding and ability to segment the commercial and industrial customer base that the provider is able to deliver to the utility;
the pricing of the customer engagement and demand response solutions and services being offered; and
the financial stability, historical performance levels and overall experience of the provider.
When competing to secure demand response commitments from C&I end-users, we principally compete on the breadth of programs and the sophistication of the proposal offered, as well as the amount of payments shared with those C&I end-users for their commitments.
Our primary competitors include Schneider Electric, Johnson Controls, Ecova, Siemens, IBM, Opower, C3 IoT, FirstFuel, CPower, and NRG Energy. We believe that our operational experience, deep understanding of energy use by C&I end-users, ability to process utility bill data in over 100 countries, proprietary solutions and data analytics, and leadership in the EIS and demand response sectors give us an advantage when competing for customers. In addition, across our EIS platform, we believe that we are unique in our ability to leverage real-time data to unlock the greatest amount of value and efficiency for our customers, which we believe positions us favorably to win in competitive situations.
Utilities and competitive electricity suppliers may offer energy software solutions at prices below cost or even for free in order to improve their customer relations or competitive positions, which could decrease our base of potential enterprise customers. In addition, utilities and competitive electricity suppliers could, and sometimes do, offer their own demand response solutions, which could decrease our base of potential demand response programs and C&I end-users. However, demand response programs, as administered by utilities alone, are bound to standard tariffs to which all C&I end-users in the utility’s service territory must abide. Utilities must treat all rate class C&I end-users equally in order to serve them under public utility commission-approved tariffs. In contrast, we have the flexibility to offer customized demand response solutions. We believe that we also have technology and operational experience at the facility-level that both utilities and competitive electricity suppliers lack.
We also compete with traditional supply-side resources such as natural gas-fired peaking plants. In some cases, utilities have an incentive to invest in these fixed assets rather than develop demand response as they are able to include the cost of fixed assets in their rate base. In addition, some utilities have a financial disincentive to invest in energy efficiency and demand response because reducing demand can have the effect of reducing their sales of electricity. However, we believe that our demand response solutions will continue to gain regulatory support as they are faster to market, require no electric power generation, transmission or distribution infrastructure, and are more cost-effective and more environmentally sound than traditional alternatives.

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Regulatory
We provide our EIS and demand response solutions in competitive wholesale and retail electricity markets and in traditionally regulated electricity markets. Regulations and public policies within both types of markets impact how quickly customers may adopt our EIS and demand response solutions, the prices we can charge and profit margins we can earn, the MW we can enroll in certain demand response programs, the timing with respect to when we begin earning revenue, and the various ways in which we are permitted or may choose to do business and accordingly, our assessments of which potential markets to most aggressively pursue. In addition, certain of our contracts with our utility customers are subject to regulatory approval, which may not be obtained on a timely basis, if at all.
With respect to our demand response solutions, the prices we can charge and revenues and profit margins we earn also can be affected by market regulations, such as program rules that can impact our administrative and compliance costs to manage a portfolio of demand response resources. For example, rules that mandate increased requirements, such as rules that might cause more frequent or longer dispatches, varying lead times, and more granularity as to the specific area where demand response may be dispatched may increase our costs. Similarly, market rules and regulations defining methodology for measurement of what constitutes demand response performance can affect the creditable amount of demand response capacity that we are able to enroll from C&I end-users and the amounts that we need to pay them for their participation.
In regional electricity markets in which we participate in auctions, changes in auction rules impact our participation in future auctions and the ability to reconfigure positions taken in prior auctions. For example, rules which impact quantities of capacity resources we are permitted to bid or purchase in an auction or transfer can impact bidding strategies and how we optimize our portfolio of demand response resources. Market rules and regulations may change subsequent to our assuming a long-term obligation, such as winning a bid to provide demand response capacity in a forward capacity market, but prior to the year in which that capacity is required to be delivered, which could significantly and negatively impact the results of our operations and financial condition. On an ongoing basis, we assess known, anticipated and potential changes to market rules and projected market prices for the solutions that we offer. As a result of such assessment, we may alter our participation in both potential new markets and in markets in which we currently offer our demand response solutions, including by determining not to participate in open market bids to provide demand response capacity.
The policies regarding the measurement and verification of demand response resources, reliability standards and air quality or emissions regulations often vary by jurisdiction and may affect how we do business. For example, some environmental agencies may limit the amount of emissions allowed from back-up generators utilized by C&I end-users, even when back-up generators are strictly used to maintain system reliability. In such a scenario, we would have to find alternative sources of capacity to meet our capacity obligations to our utility customers and electric power grid operators.
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 demand response solutions in those regions. The regional electricity markets are generally not subject to direct price/rate regulation, but they remain heavily regulated in other ways that can impact our costs, the level of compensation available, and/or the ability for demand response to participate and the terms of such participation. For instance, some markets have regulatory structures that do not yet include demand response as a qualifying resource for purposes of short-term reserve requirements known as ancillary services. As part of our business strategy, we intend to expand into additional regional electricity markets. However, unfavorable regulatory structures could limit the number of regional electricity markets available to us for expansion.
Intellectual Property
We utilize a combination of intellectual property safeguards, including patents, copyrights, trademarks and trade secrets, as well as employee and third-party confidentiality and proprietary information agreements, to protect our intellectual property. As of December 31, 2015, we held 17 patents in the United States, Canada and Australia, and had 60 published patent applications pending. Our patent applications and any future patent applications might not result in a patent being issued within the scope of the claims we seek or at all, and any patents we receive may be challenged, invalidated or declared unenforceable. We continually assess appropriate circumstances for seeking patent protection for those aspects of our technology, designs and methodologies, and processes that we believe provide significant competitive advantages.
As of December 31, 2015, we held numerous trademarks in the United States. Several of these trademarks are also registered in Australia, Canada, China, European Community, Japan, New Zealand and South Africa.
With respect to, among other things, proprietary know-how that is not patentable and processes for which patent protection may not offer the best legal and business protection, we rely on trade secret protection and employ confidentiality and proprietary information agreements to safeguard our interests. Many elements of our EIS and demand response solutions involve proprietary know-how, technology or data that are not covered by patents or patent applications, including technical processes, equipment designs, algorithms and procedures. We have taken security measures to try to protect these elements. All of our employees have entered into confidentiality and proprietary information agreements with us. These agreements address

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intellectual property protection issues and require our employees to assign to us all of the inventions, designs and technologies they develop during the course of employment with us. We also generally seek confidentiality and proprietary information protection from our customers and business partners before we disclose any sensitive aspects of our technology or business strategies. We have not been subject to any material intellectual property claims.
Seasonality
Our revenues can fluctuate from quarter to quarter based primarily upon the seasonality of our demand response business in certain of the markets in which we operate, where payments under certain of our long-term contracts and pursuant to certain open market bidding programs in which we participate are higher or concentrated in particular seasons and months. Peak demand for electricity and other capacity constraints tend to be seasonal. Peak demand tends to be most extreme in warmer months, which may lead some demand response capacity markets to yield higher prices for capacity or contract for the availability of a greater amount of capacity during these warmer months. For example, in the PJM forward capacity market, which is a market from which we derive a substantial portion of our revenues, we recognize demand response capacity-based revenue from PJM’s limited demand response product in September, at the end of the four month delivery period of June through September.
The PJM extended demand response product includes the period of June-October, plus May of the following year. We anticipate the revenue earned from this product will be recognized at the end of the delivery year in May. For further discussion of revenue recognition, please refer to Note 1 contained in Appendix A to this Annual Report on Form 10-K.
Employees
As of December 31, 2015, we had 1,366 full-time employees, including 278 charged to cost of revenues, 325 in sales and marketing, 210 in research and development and 553 in general and administrative, including operations. Of these full-time employees, 810 were located in the United States with 519 located in New England, 77 located in California, and the remainder located in other areas across the United States. In addition, we had 217 full-time employees located in Brazil, 115 located in India, 68 located in Canada, 42 located in Germany, 40 located in Australia, 25 located in the United Kingdom and 49 located in our other international locations. Our future success depends in part on our ability to attract, retain and motivate highly qualified personnel, for whom competition is intense. Except for certain employees of our Brazilian subsidiary that operate under a collective bargaining agreement, our employees are not represented by any labor unions or covered by a collective bargaining agreement. We have not experienced any work stoppages. We consider our relations with our employees to be good.
Segment Reporting
Effective January 1, 2016, we began operating as two distinct business units: Software and Demand Response, each with dedicated sales, marketing, and operations functions. These changes are designed to enable us to pursue distinct strategies for each business unit and to better evaluate our performance executing on those strategies with respect to our solutions.
Available Information
We were incorporated in Delaware on June 5, 2003 and have our corporate headquarters at One Marina Park Drive, Suite 400, Boston, Massachusetts 02210. We operated as EnerNOC, LLC, a New Hampshire limited liability company, from December 2001 until June 2003. We conduct operations globally and maintain a number of domestic and international subsidiaries. Our Internet website address is www.enernoc.com. The information contained on our website is not incorporated by reference into, and does not form any part of, this Annual Report on Form 10-K. We have included our website address as a factual reference and do not intend it to be an active link to our website. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, are available free of charge through the investor relations page of our internet website as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission, or the SEC.
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. The following risk factors and other information included in this Annual Report on Form 10-K should be carefully considered. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also adversely affect our business. This Annual Report on Form 10-K contains forward-looking statements under Section 21E of the Exchange Act and other federal securities laws. These statements relate to future events or our future financial performance and are identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “intends,” “seeks,” “anticipates,” “believes,” “estimates,” “potential” or “continue,” or the negative of such terms or other comparable terminology. These statements are only predictions. You should not place undue reliance on these forward-looking

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statements. Actual events or results may differ materially. Factors that may cause such differences include, but are not limited to, the factors discussed below and in our other filings with the SEC. These factors may cause our actual results to differ materially from any forward-looking statement.
Risks Related to Our Business and Industry
Our future profitability is uncertain and we may incur net losses in the future.
As of December 31, 2015, we had an accumulated deficit of $254.3 million . Although we achieved profitability for the years ended December 31, 2014, 2013 and 2010, with net income of $12.1 million , $22.1 million and $9.6 million, respectively, we incurred net losses for all other fiscal years since our inception. Our operating losses have historically been driven by start-up costs, costs of developing our technology, including new product and service offerings, and operating expenses related to increased headcount as a result of our overall growth and expansion into new markets. As we seek to grow our revenues and customer base, we plan to continue to invest in our business in order to capitalize on emerging opportunities and expand our EIS and demand response solutions, which will require increased operating expenses. Although we believe we will be able to grow our revenues at rates that will allow us to achieve profitability again in the future, these increased operating expenses, as well as other factors, will cause us to incur net losses for the foreseeable future.
If we fail to successfully educate existing and potential enterprise and utility customers, and electric power grid operators regarding the benefits of our EIS and demand response solutions or a market otherwise fails to develop for our EIS and demand response solutions, our ability to sell our EIS and demand response solutions and grow our business could be limited.
Our future success depends on continued commercial acceptance of our EIS and demand response solutions. The market for our EIS and demand response solutions is relatively new. If we are unable to educate our potential customers about the advantages of our EIS and demand response solutions over competing products and services, or if our existing customers no longer rely on our EIS and demand response solutions, our ability to sell our EIS and demand response solutions will be limited. In addition, the energy intelligence software sector is rapidly evolving and therefore, we cannot accurately assess the size of the market and we may have limited insight into trends that may emerge and affect our business. For example, we may have difficulty predicting customer needs and developing EIS and demand response solutions that address those needs. If the market for our EIS and demand response solutions does not continue to develop, our ability to grow our business could be limited and we may not be able to operate profitably.
The success of our business depends in part on our ability to develop new EIS offerings, and enhance the functionality of our current EIS and demand response solutions.
The market for our EIS and demand response solutions is characterized by rapid technological changes, frequent new software introductions, internet-demand response technology enhancements, uncertain product life cycles, changes in customer demands and evolving industry standards and regulations. We may not be able to successfully develop and market new EIS offerings that comply with present or emerging industry regulations and technology standards. Also, any new or modified regulation or technology standard could increase our cost of doing business.
As part of our strategy to enhance our EIS and demand response solutions and grow our business, we plan to continue to make substantial investments in the research and development of new technologies. Our future success will depend in part on our ability to continue to design and sell new, competitive EIS offerings and enhance our existing EIS and demand response solutions. Initiatives to develop new EIS and demand response solutions will require continued investment, and we may experience unforeseen problems in the performance of our technologies and operational processes, including new technologies and operational processes that we develop and deploy, to implement our EIS and demand response solutions. In addition, software supporting our EIS and demand response solutions is complex and can be expensive to develop, and new software and software enhancements can require long development and testing periods. If we are unable to develop new EIS offerings or enhancements to our existing EIS and demand response solutions on a timely basis, or if the market does not accept our new or enhanced EIS and demand response solutions, we will lose opportunities to realize revenues and obtain customers, and our business and results of operations will be adversely affected.
We operate in highly competitive markets; if we are unable to compete successfully, we could lose market share and revenues.
The market for EIS and demand response solutions is fragmented. Some traditional providers of advanced metering infrastructure services have added, or may add, energy software and services to their existing business. We face strong competition from other energy management service providers, both larger and smaller than we are. We also compete against traditional supply-side resources such as natural gas-fired peaking power plants. In addition, utilities and competitive electricity suppliers offer their own energy software and services, which could decrease our base of potential customers and revenues and have a material adverse effect on our results of operations and financial condition.

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Many of our competitors and potential competitors have greater financial resources than we do. Our competitors could focus their substantial financial resources to develop a competing business model or develop products or services that are more attractive to potential customers than what we offer. Some advanced metering infrastructure service providers, for example, are substantially larger and better capitalized than we are and have the ability to combine advanced metering and demand response services into an integrated offering to a large, existing customer base. Our competitors may offer services and products at prices below cost or even for free in order to improve their competitive positions. Any of these competitive factors could make it more difficult for us to attract and retain customers, cause us to lower our prices in order to compete, and reduce our market share and revenues, any of which could have a material adverse effect on our financial condition and results of operations. In addition, we may also face competition based on technological developments that reduce peak demand for electricity, increase power supplies through existing infrastructure or that otherwise compete with our EIS and demand response solutions.
An increased rate of terminations by our enterprise customers, or their failure to renew contracts when they expire, would negatively impact our business by reducing our revenues and requiring us to spend more money to maintain and grow our enterprise customer base.
The loss of revenues resulting from enterprise customer contract terminations or expirations could be significant, and limiting enterprise customer terminations is an important factor in our ability to achieve growth and profitability in future periods. The failure to maintain our existing enterprise customers could have a material adverse effect on our business, financial condition or results of operations as a combined company.
Enterprise customer and utility customer sales cycles can be lengthy and unpredictable and require significant employee time and financial resources with no assurances that we will realize revenues.
Sales cycles with enterprise and utility customers are generally long and unpredictable. The enterprises and utilities that are our potential customers generally have extended budgeting, procurement and approval processes. They also tend to be risk averse and to follow industry trends rather than be the first to purchase new products or services, which can extend the lead time for or prevent acceptance of new products or services. Accordingly, our potential enterprise and utility customers may take longer to reach a decision to purchase our EIS and demand response solutions. This extended sales process requires the dedication of significant time by our personnel and our use of significant financial resources, with no certainty of success or recovery of our related expenses. It is not unusual for an enterprise or utility customer to go through the entire sales process and not accept any proposal or quote. Long and unpredictable sales cycles with enterprise and utility customers could have a material adverse effect on our business, financial condition and results of operations.
A substantial majority of our revenues are and have been generated from open market program sales of demand response to PJM, and the modification or termination of this open market program or sales relationship, or the modification or termination of a sales relationship with any future significant utility customer or electric power grid operator could materially adversely affect our business.
During the years ended December 31, 2015, 2014 and 2013, revenues generated from open market sales to PJM, an electric power grid operator, accounted for 40% , 52% and 45% , respectively, of our total revenues. The modification or termination of our sales relationship with PJM, or the modification or termination of any of PJM’s open market programs in which we participate, including PJM’s introduction of new demand response products, changes to the operational requirements, including measurement and verification, related to the provision of demand response, modifications to the cost, quantity and clearing mechanics related to our participation in capacity auctions or other limitations on our ability to effectively manage our portfolio of demand response capacity, could significantly reduce our future revenues and profit margins and have a material adverse effect on our results of operations and financial condition.
The expiration of our existing utility contracts without obtaining renewal or replacement utility contracts, or the termination of any of our existing utility contracts, could negatively impact our business by reducing our revenues and profit margins, thereby having a material adverse effect on our results of operations and financial condition.
We have entered into utility contracts with our utility customers in different geographic regions in the United States, as well as in Australia, Canada, Germany, New Zealand and the United Kingdom, and are regularly in discussions to enter into new utility contracts. However, there can be no assurance that we will be able to renew or extend our existing utility contracts or enter into new utility contracts on favorable terms, if at all. If, upon expiration, we are unable to renew or extend our existing utility contracts and are unable to enter into new utility contracts, our future revenues and profit margins could be significantly reduced, which could have a material adverse effect on our results of operations and financial condition.
Our existing utility contracts generally contain termination provisions pursuant to which the utility customer can terminate the contract under certain circumstances, including in the event that we fail to comply with the terms or provisions contained therein. In addition, in the event that we breach any of our utility contracts, we may be liable to pay the utility customer an associated fee or penalty payment in connection with such breach. The termination of any of our existing utility contracts, or any fees or penalties payable by us in connection with a breach of our existing utility contracts, could negatively impact our

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business by reducing our revenues and profit margins, thereby having a material adverse effect on our results of operations and financial condition.
If we fail to obtain favorable prices in the open market programs in which we currently participate or choose to participate in the future, specifically in the PJM market, our revenues, gross profits and profit margins will be negatively impacted.
In open market programs, electric power grid operators generally seek bids from companies such as ours to provide demand response capacity based on prices offered in competitive bidding. These prices may be subject to volatility due to certain market conditions or other events and as a result, the prices offered to us for this demand response capacity may be significantly lower than historical prices. To the extent we are subject to price reductions in certain of the markets in which we currently participate or choose to participate in the future, our revenues, gross profits and profit margins could be negatively impacted. In addition, we may alter our participation in both new markets and in markets in which we currently offer our demand response solutions, including by determining not to participate in open market bids to provide demand response capacity. We also may be subject to reduced capacity prices or be unable to participate in certain open market programs for a period of time to the extent that our bidding strategy fails to produce favorable results. In addition, adverse changes in the general economic and market conditions in the regions in which we provide demand response capacity may result in a reduced demand for electricity, resulting in lower prices for capacity, both demand-side and supply-side, which could materially and adversely affect our results of operations and financial condition.
We depend on the electric power industry for revenues and as a result, our operating results have experienced, and may continue to experience, significant variability due to volatility in electric power industry spending and other factors affecting the electric utility industry, such as seasonality of peak demand and overall demand for electricity.
We derive revenues from the sale of our demand response solutions directly or indirectly, to the electric power industry. Sales of our demand response solutions to utility customers and electric power grid operators may be deferred, canceled or otherwise negatively impacted as a result of many factors, including challenging economic conditions, mergers and acquisitions involving these entities, fluctuations in interest rates, increased electric utility capital spending on traditional supply-side resources, and changing regulations and program rules, which could have a material adverse effect on our results of operations and financial condition.
Sales of demand response capacity in open market bidding programs are particularly susceptible to variability based on changes in spending patterns of electric power grid operators, and the associated fluctuating market prices for capacity. In addition, peak demand for electricity and other capacity constraints tend to be seasonal. Peak demand in the United States tends to be most extreme in warmer months, which may lead some demand response capacity markets to yield higher prices for demand response capacity or contract for the availability of a greater amount of demand response capacity during these warmer months. As a result, our demand response revenues may be seasonal and therefore, we believe that quarter to quarter comparisons of our operating results are not necessarily meaningful and that these comparisons cannot be relied upon as indicators of future performance.
Further, occasional events, such as significant volatility in natural gas prices or potential decreases in availability, can lead utilities and electric power grid operators to implement short-term calls for demand response capacity to respond to these events, but we cannot be sure that such calls will occur or that we will be in a position to generate revenues when they do occur. We have experienced, and may in the future experience, significant variability in our revenues on both an annual and a quarterly basis as a result of these and other factors, which could negatively impact our business and make it difficult for us to accurately forecast our future sales.
If the actual amount of demand response capacity that we make available under our capacity commitments is less than required, our committed capacity could be reduced and we could be required to make refunds or pay penalty fees, which could negatively impact our results of operations and financial condition.
We provide demand response capacity to our utility customers and electric power grid operators either under utility contracts or under terms established in open market bidding programs where capacity is purchased. Under the utility contracts and open market bidding programs, utilities and electric power grid operators make periodic payments to us based on the amount of demand response capacity that we are obligated to make available to them during the contract or delivery period, or make periodic payments to us based on the amount of demand response capacity that we bid to make available to them during the relevant period. We refer to these payments as committed capacity payments. Committed capacity is negotiated and established by the utility contract or set in the open market bidding process and is subject to subsequent confirmation by measurement and verification tests or performance in a demand response event. In our open market bidding programs, we offer different amounts of committed capacity to our electric power grid operator and utility customers based on market rules on a periodic basis. We refer to measured and verified capacity as our demonstrated or proven capacity. Once demonstrated, the proven capacity amounts typically establish a baseline of capacity for each C&I end-user site in our portfolio, on which committed capacity payments are calculated going forward and until the next demand response event or measurement and verification test when we are called upon to make capacity available.

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Under some of our utility contracts and in certain open market bidding programs, any difference between our demonstrated capacity and the committed capacity on which capacity payments were previously made will result in either a refund payment, which we also refer to as a performance penalty payment, from us to our electric power grid operator or utility customer, or an additional payment to us by such customer. Any refund payable by us would reduce our deferred revenues, but would not impact our previously recognized revenues. If there is a refund payment due to an electric power grid operator or utility customer, we generally make a corresponding adjustment in our payments to the C&I end-users who failed to make the appropriate level of capacity available, however we are sometimes unable to do so. In addition, some of our utility contracts with, and open market programs established by, our electric power grid operator and utility customers provide for penalty payments, which could be substantial, in certain circumstances in which we do not meet our capacity commitments, either in measurement and verification tests or in demand response events. Further, because measurement and verification test results for some utility contracts and in certain open market bidding programs establish capacity levels on which payments will be made until the next measurement and verification test or demand response event, the payments to be made to us under these utility contracts and open market bidding programs could be reduced until the level of capacity is established at the next measurement and verification test or demand response event. We could experience significant period-to-period fluctuations in our financial results in future periods due to any refund or penalty payments, capacity payment adjustments, replacement costs or other payments made to our electric power grid operator or utility customers, which could be substantial.
An increased rate of terminations by our C&I end-users, their failure to renew contracts when they expire or the failure of these C&I end-users to make the appropriate levels of capacity available when called upon could negatively impact our ability to achieve our committed capacity and cause us to make refund payments to, or incur penalties imposed by, our utility customers and electric power grid operators.
Our ability to provide demand response capacity under our utility contracts and in open market bidding programs depends on the amount of our MW obligations, and our ability to manage C&I end-users who enter into contracts with us to reduce electricity consumption on demand. If we are unsuccessful in limiting our C&I end-user terminations or if our existing C&I end-users do not renew their contracts as they expire, we may be unable to acquire a sufficient amount of MW or we may incur significant costs to replace MW in the demand response programs in which we participate, which could cause our revenues to decrease and our cost of revenues to increase.
In addition, certain demand response programs in which we currently participate or choose to participate in the future may have rigorous requirements, making it difficult for our C&I end-users to perform when called upon by us. In the event that our C&I end-users are unable to perform or perform at levels below that which they agreed to perform, we may be unable to achieve our committed capacity levels and may be subject to refunds or penalties, which could have a material adverse effect on our results of operations and financial condition.
Pricing pressure related to electric capacity made available to electric power grid operators and utilities, or in the percentage or fixed amount paid to C&I end-users for making capacity available, could adversely affect our results of operations and financial condition.
Decreases in the price of demand response capacity could result in a loss of utility customers or electric power grid operators or a decrease in the growth of our business, or it may require us to lower our prices for capacity to remain competitive, which could result in reduced revenues and lower profit margins and adversely affect our results of operations and financial condition. Additionally, increases in the percentage or fixed amount paid to C&I end-users by our competitors for making capacity available could result in a loss of C&I end-users or a decrease in the growth of our business. It could also require us to increase the percentage or fixed amount we pay to our C&I end-users to remain competitive, which would result in increases in the cost of revenues and lower profit margins and could adversely affect our results of operations and financial condition.
If the software systems we use in providing our EIS and demand response solutions or the manual implementation of such systems produce inaccurate information or are incompatible with the systems used by our customers or C&I end-users, it could preclude us from providing our EIS and demand response solutions, which could lead to a loss of revenues and trigger penalty payments.
Our software is complex and may contain undetected errors or failures when introduced or subsequently modified. Software defects or inaccurate data may cause incorrect recording, reporting or display of information preventing us from successfully providing our EIS and demand response solutions, which may result in lost revenues, customer and C&I end-user dissatisfaction, and our customers and C&I end-users may seek to hold us liable for any damages incurred. As a result, we could lose customers and C&I end-users, our reputation could be harmed, and our financial condition and results of operations could be materially adversely affected.
We currently serve a customer and C&I end-user base that uses a wide variety of constantly changing hardware, software applications and operating systems. Building control, process control and metering systems frequently reside on non-standard operating systems. Our EIS and demand response solutions need to interface with these non-standard systems in order to gather

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and assess data and to implement changes in electricity consumption. Our business depends on the following factors, among others:
our ability to integrate our technology with new and existing hardware and software systems, including metering, building control, process control, and distributed generation systems;
our ability to anticipate and support new standards, especially Internet-based standards and building control and metering system protocol languages; and
our ability to integrate additional software modules under development with our existing technology and operational processes.
If we are unable to adequately address any of these factors, our results of operations and prospects for growth could be materially adversely affected.
We may face certain product liability or warranty claims if we disrupt our customers’ networks or applications, or if our EIS and demand response solutions fail to meet customer expectations.
For some of our current and planned applications our software and hardware is integrated with our enterprise customers’ networks and software applications. The integration of our software and hardware may entail the risk of product liability or warranty claims based on disruption or security breaches to these networks or applications. In addition, the failure of our software and hardware to perform to customer expectations could give rise to warranty claims against us. Any of these claims, even if without merit, could result in costly litigation or divert management’s attention and resources. Although we carry general liability insurance, our current insurance coverage could be insufficient to protect us from any and all liability that may be imposed under these types of claims. A material product liability claim may seriously harm our results of operations.
Failure of third parties to manufacture or install quality products or provide reliable services in a timely manner or at all could cause delays in the delivery of our EIS and demand response solutions, or could result in a failure to provide accurate data to our customers or C&I end-users, which could damage our reputation, cause us to lose customers or C&I end-users and have a material adverse effect on our business results of operations and financial condition.
Our success depends on our ability to provide quality, reliable, and secure EIS and demand response solutions in a timely manner, which in part requires the proper functioning of facilities and equipment owned, operated, installed or manufactured by third parties upon which we depend. For example, our reliance on third parties includes:
utilizing components that we or third parties install or have installed at customer and C&I end-user sites;
relying on metering information provided by third parties to accurately and reliably provide data to our utility customers and electric power grid operators;
outsourcing email notification and cellular and paging wireless communications that are used to notify our C&I end-users of their need to reduce electricity consumption at a particular time and to execute instructions to devices installed at C&I end-user sites that are programmed to automatically reduce consumption on receipt of such communications; and
outsourcing certain installation and maintenance operations to third-party providers.
Any delays, malfunctions, inefficiencies or interruptions in these products, services or operations could adversely affect the reliability or operation of our EIS and demand response solutions, which could cause us to experience difficulty monitoring or retaining current customers or C&I end-users, and attracting new customers or C&I end-users. Any errors in metering information provided to us by third parties, including utilities and electric power grid operators, could also adversely affect the accuracy of customer data. Such delays and errors could result in an overpayment or underpayment to us and our enterprise customers from our electric power grid operator and utility customers, which in some instances may cause us to violate certain market rules and require us to make refunds to our electric power grid operator and utility customers and pay associated penalties or fines. In addition, in such instances our brand, reputation and growth could be negatively impacted.
Unfavorable regulatory decisions, changes to the market rules applicable to the demand response 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, 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 included an exemption allowing emergency generators to participate in emergency demand response programs for up to 100 hours per year. That 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, reversed those portions of the rule that contained 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, and the Court

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subsequently granted a stay until May 1, 2016.  There is no guarantee that the EPA will undertake a new rulemaking, and the provisions of a new rule, if any, are not known. The result may be a decrease to or elimination of the 100 hour per year exemption for participation by affected emergency generators in emergency demand response programs. If either a decrease or elimination of the 100 hour exemption is adopted, some of the demand response capacity reductions that we aggregate from C&I end-users 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, or reduce our obligation through capacity auctions and/or bilateral contracts. If we were unable to procure additional sources of capacity to meet these obligations or we are unable to reduce our obligation, we could be subject to substantial penalties, and our business and results of operations could be negatively impacted.
In addition, 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 requires 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 have a material adverse effect on our results of operations and financial condition.
Our business is subject to government regulation and may become subject to modified or new government regulation, which may negatively impact our ability to sell and market our EIS and demand response solutions.
Federal, state, provincial, local or foreign governmental entities may seek to change existing regulations, impose additional regulations or change their interpretation of the applicability of existing regulations. Any modified or new government regulation applicable to our current or future EIS and demand response solutions, whether at the federal, state, provincial or local level, may negatively impact the installation, servicing and marketing of, and costs and prices related to, our EIS and demand response solutions. In addition, despite our efforts to manage compliance with any other regulations to which we are subject, we may be found to be in non-compliance with such regulations and therefore subject to sanctions, including penalties or fines, which could have a material adverse effect on our business, financial condition and results of operations.
While the electric power markets in which we operate are regulated, most of our business is not directly subject to the regulatory framework applicable to the generation and transmission of electricity, with the exception of Celerity Energy Partners San Diego, LLC, or Celerity, which exports power to the electric power grid and is thus subject to direct regulation by FERC and its regulations related to the sale of wholesale power at market based rates. However, we may become directly subject to the regulation of FERC and state regulators for other parts of our business besides Celerity to the extent we are deemed to own, operate, or control generation used to make wholesale sales of power or provide ancillary services that involve a sale of electric energy or capacity for resale, or the export of power to the electric power grid, which could have a material adverse effect on our results of operations and financial condition.
In addition, we may be subject to governmental or regulatory investigations or audits from time to time in connection with our participation in certain demand response programs. Any investigation by FERC or any other governmental or regulatory authorities could result in a material adjustment to our historical financial statements and may have a material adverse effect on our results of operations and financial condition. As part of any regulatory investigation or audit, FERC or any other governmental or regulatory entity may review our performance under our utility contracts and open market bidding programs, cost structures, and compliance with applicable laws, regulations and standards. If an investigation or audit uncovers improper or illegal activities, we may be subject to civil and criminal penalties and administrative sanctions, in addition to any negative publicity associated with any such penalties or sanctions, as well as incur legal and related costs, which could have a material adverse effect on our results of operations and financial condition.
In addition, certain of our utility contracts are subject to approval by federal, state, provincial, local, or foreign regulatory agencies. There can be no assurance that such approvals will be obtained or be issued on a timely basis, if at all.
We face risks related to our expansion into international markets.
As part of our business strategy, we have in the past, and we intend to continue to consider the expansion of our addressable market by pursuing opportunities to provide our EIS and demand response solutions in international markets. New international markets may require us to respond to new and unanticipated regulatory, marketing, sales and other challenges. These efforts may be time-consuming and costly, and there can be no assurance that we will be successful in responding to these and other challenges we may face as we enter and attempt to expand in international markets. International operations also entail a variety of other risks, including:
compliance with numerous legislative, regulatory or market requirements of foreign countries;
currency exchange fluctuations;

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longer payment cycles and greater difficulty in accounts receivable collection;
compliance with U.S. laws, such as the U.S. Foreign Corrupt Practices Act, or FCPA, and local laws prohibiting bribery and corrupt payments to government officials;
difficulties in developing, staffing, and simultaneously managing a large number of varying foreign operations as a result of distance, language, and cultural differences;
laws and business practices that favor local competitors or prohibit foreign ownership of certain businesses;
potentially adverse tax consequences;
compliance with laws of foreign countries, international organizations, such as the European Commission, treaties, and other international laws;
insufficient revenues to offset increased expenses associated with acquisitions;
assumption of liabilities and exposure to unforeseen liabilities of acquired companies;
the inability to continue to benefit from local subsidies due to change in control; and
unfavorable labor regulations.
International operations are also subject to general geopolitical risks, such as political, social and economic instability and changes in diplomatic and trade relations. One or more of these factors could adversely affect any of our international operations and result in lower revenue and/or greater operating expenses than we expect, and could significantly affect our results of operations and financial condition.
We may not be able to identify suitable acquisition candidates or complete acquisitions successfully, which may inhibit our rate of growth, and acquisitions that we complete may expose us to a number of unanticipated operational and financial risks.
As part of our business strategy, we have in the past acquired, and we intend to continue to consider additional acquisitions of companies, technologies and products that we believe could accelerate our ability to compete in our core markets or allow us to enter new markets. However, we may be unable to implement this growth strategy if we cannot identify suitable acquisition candidates, reach agreement on potential acquisitions on acceptable terms, successfully integrate personnel or assets that we acquire or for other reasons. Our acquisition efforts may involve certain risks, including:
unexpected acquisition costs or liabilities that may cause us to fail to meet our previously stated financial guidance, or the effects of purchase accounting may be different from our expectations;
problems that may arise with our ability to successfully integrate the acquired businesses, which may result in us not operating as effectively and efficiently as expected, and may include:
diversion of management time, including a shift in focus from operating the businesses to issues related to integration and administration;
inadequate management resources available for integration activity and oversight;
failure to retain and motivate key employees;
failure to successfully manage relationships with customers and suppliers;
failure of customers to accept our EIS and demand response solutions;
failure to effectively coordinate sales and marketing efforts;
failure to combine service offerings quickly and effectively;
failure to effectively enhance acquired technology, applications, services and products or develop new applications, services and products relating to the acquired businesses;
difficulties and inefficiencies in managing and operating businesses in multiple locations or operating businesses in which we have either limited or no direct experience;
difficulties integrating financial reporting systems;
difficulties in the timely filing of required reports with the SEC; and
difficulties in implementing controls, procedures and policies, including disclosure controls and procedures and internal controls over financial reporting (appropriate for a larger public company) at companies that, prior to their acquisition, lacked such controls, procedures and policies, which may result in ineffective disclosure controls and procedures or material weaknesses in internal controls over financial reporting;
difficulties in achieving the expected synergies from an acquisition including taking longer than expected to achieve those synergies;
incurring future impairment charges related to diminished fair value of businesses acquired as compared to the price we paid for them;
restructuring operations or reductions in workforce, which may result in substantial financial charges; and

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issuance of potentially dilutive equity securities and/or the incurrence of debt or contingent liabilities, which could harm our financial condition.
We have recorded a significant amount of goodwill and intangible assets 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 which would have an adverse impact on our operating results.
Under U.S. generally accepted accounting principles, we are required to evaluate our goodwill and 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. The initial identification and valuation of these intangible assets and the determination of the estimated useful lives at the time of acquisition involve use of management judgments and estimates. These estimates are based on, among other factors, input from accredited valuation consultants, reviews of projected future income cash flows and statutory regulations.
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. We generally calculate fair value as the present value of estimated future cash flows to be generated by an asset using a risk-adjusted discount rate.
If the carrying value of goodwill or intangible assets is determined to be impaired, we will write-down the carrying value of the goodwill or intangible asset to its implied fair value in the period identified. This impairment test could result in a material impairment charge that would have an adverse impact on our financial condition and results of operations.
As a result of various factors, including but not limited to our market capitalization as of our November 30, 2015 test date, we concluded that the carrying amount of goodwill was higher than its implied fair value resulting in a goodwill impairment charge of $108.8 million . Following this impairment charge and as of December 31, 2015, we had approximately $94.1 million of goodwill and intangible assets on our consolidated balance sheet.
We expect to continue to expand our sales and marketing, operations, and research and development capabilities, as well as our financial and reporting systems, and as a result we may encounter difficulties in managing our growth, which could disrupt our operations.
We expect to experience continued growth in the number of our employees and significant growth in the scope of our operations. To manage our anticipated future growth, we must continue to implement and improve our managerial, operational, and financial and reporting systems, continue to improve our internal controls, procedures and compliance programs, expand our facilities, and continue to recruit and train additional qualified personnel. All of these measures will require significant expenditures and will demand the attention of management. Due to our limited resources, we may not be able to effectively manage the expansion of our operations, continue to implement sufficient internal controls, procedures or compliance programs, or recruit and adequately train additional qualified personnel. The physical expansion of our operations may lead to significant costs and may divert our management and business development resources. Any inability to manage growth could delay the execution of our business plan or disrupt our operations.
We allocate our operations, sales and marketing, research and development, general and administrative, and financial resources based on our business plan, which includes assumptions about the demand for our EIS and demand response solutions, current and future utility contracts and open market programs with utility customers and electric power grid operators, current and future contracts with enterprise customers, variable prices in open market programs for demand response capacity, the development of ancillary services markets which enable demand response as a revenue generating resource and a variety of other factors relating to electricity markets. However, these factors are uncertain. If our assumptions regarding these factors prove to be incorrect, actual demand for our EIS and demand response solutions could be significantly less than anticipated demand and we may not be able to sustain our revenue growth or achieve profitability in future periods.
We have begun to manage our operations in two reportable segments. The new operating structure has been in effect for a limited period of time, and there are no assurances that we will be able to successfully operate in distinct business units.
Effective January 1, 2016, we began operating as two distinct business units, Software and Demand Response, each with dedicated sales, marketing, and operations functions. These changes are designed to enable us to pursue distinct strategies for each business unit and to better evaluate our performance executing on those strategies. There are substantial uncertainties associated with these efforts, including the investment of significant time and resources, the possibility that these efforts will be

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unprofitable, and the risk of additional liabilities associated with these efforts. Factors such as compliance with regulations, competitive alternatives, and shifting market preferences may also impact the successful implementation of these efforts.
Our results of operations could be adversely affected if our operating expenses and cost of sales do not correspond with the timing of our revenues.
Most of our operating expenses, such as employee compensation and rental expense for properties, are either relatively fixed in the short-term or incurred in advance of sales. Moreover, our spending levels are based in part on our expectations regarding future revenues. As a result, if revenues for a particular quarter are below expectations, we may not be able to proportionately reduce operating expenses for that quarter.
In certain forward capacity demand response markets in which we participate or may choose to participate in the future, it may take longer for us to begin earning revenues from MW we enable, in some cases up to a year after enablement. For example, the PJM limited demand response product operates on a June to May program-year basis, which means that a MW that we enable after June of each year will typically not be recognized until the following year. The up-front costs we incur to enable our MW in PJM and other similar markets, coupled with the delay in receiving revenues from those MW, could adversely affect our business, results of operations and financial condition.
We may require significant additional capital to pursue our growth strategy, but we may not be able to obtain additional financing on acceptable terms or at all.
The growth of our business will depend on substantial amounts of additional capital for marketing and product development of our EIS and demand response solutions, and posting financial assurances in order to enter into utility contracts and open market bidding programs with utilities and electric power grid operators. Our capital requirements will depend on many factors, including the rate of our revenue growth, our introduction of new EIS and demand response solutions, enhancements to our existing EIS and demand response solutions, and our expansion of sales and marketing and product development activities. In addition, we may consider strategic acquisitions of complementary businesses or technologies to grow our business, which could require significant capital and could increase our capital expenditures related to the future operation of acquired businesses or technologies. We may not be able to obtain loans or additional capital on acceptable terms or at all.
We may not have sufficient cash flow from our business to pay our outstanding indebtedness.
Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our indebtedness, including the $126.8 million aggregate principal amount of 2.25% convertible senior notes due 2019, or the Notes, depends on our future performance, which is subject to regulatory, economic, financial, competitive and other factors beyond our control. Our business may not continue to generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we may be required to adopt one or more alternatives, such as selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at such time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations.
We may not have the ability to repay the principal amount of the Notes at maturity, to raise the funds necessary to settle conversions of the Notes or to repurchase the Notes upon a fundamental change, and instruments governing our future debt may contain limitations on our ability to pay cash upon conversion or repurchase of the Notes.
At maturity in 2019, the entire outstanding principal amount of the Notes will become due and payable by us. Holders of the Notes will also have the right to require us to repurchase their Notes upon the occurrence of a fundamental change at a repurchase price equal to 100% of the principal amount of the Notes to be repurchased, plus accrued and unpaid interest, if any. In addition, upon conversion of the Notes following our receipt of stockholder approval, if applicable, unless we elect to deliver solely shares of our common stock to settle such conversion (other than cash in lieu of any fractional share), we will be required to make cash payments with respect to the Notes being converted. However, we may not have enough available cash or be able to obtain financing at the time we are required to repay the principal amount of the Notes, make repurchases of Notes surrendered therefor or settle conversions of the Notes. In addition, our ability to repurchase the Notes or to pay cash upon conversions of the Notes may be limited by law, by regulatory authority or by agreements governing our future indebtedness. Our failure to repay the principal amount of the Notes, repurchase Notes at a time when the repurchase is required or to pay any cash payable on future conversions of the Notes as required by the applicable indenture would constitute a default under the indenture. A default under the indenture or the fundamental change itself could also lead to a default under agreements governing our future indebtedness, including the $30.0 million senior secured revolving credit facility with Silicon Valley Bank, or SVB, which we refer to as the 2014 credit facility. If the repayment of the related indebtedness were to be accelerated after any applicable notice or grace periods, we may not have sufficient funds to repay the indebtedness, repurchase the Notes or make cash payments upon conversions thereof.

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The 2014 credit facility contains financial and operating restrictions that may limit our access to credit. If we fail to comply with covenants contained in the 2014 credit facility, we may be required to repay our indebtedness thereunder.
Provisions in the 2014 credit facility impose restrictions on our ability to, among other things:
incur additional indebtedness;
create liens;
enter into transactions with affiliates;
transfer assets; make certain acquisitions;
pay dividends or make distributions on, or repurchase, EnerNOC stock;
merge or consolidate; or
undergo a change of control.
In addition, we are required to meet certain financial covenants customary with this type of credit facility, including maintaining minimum unrestricted cash and a minimum specified ratio of current assets to current liabilities. The 2014 credit facility also contains other customary covenants. We may not be able to comply with these covenants in the future. Our failure to comply with these covenants may result in the declaration of an event of default and could cause us to be unable to borrow under the 2014 credit facility. In addition to preventing additional borrowings under the 2014 credit facility, an event of default, if not cured or waived, may result in the acceleration of the maturity of indebtedness outstanding under the 2014 credit facility, which would require us to pay all amounts outstanding. In addition, in the event that we default under the 2014 credit facility while we have letters of credit outstanding, we will be required to post up to 105% of the value of the letters of credit in cash with SVB to collateralize those letters of credit. Furthermore, the 2014 credit facility matures on August 9, 2016. If we fail to extend, renew or replace the 2014 credit facility when it matures, and we still have letters of credit issued and outstanding, we will be required to post up to 105% of the value of the letters of credit in cash with SVB to collateralize those letters of credit.
While we were in compliance with all of the financial covenants under the 2014 credit facility as of December 31, 2015, if an event of default occurs, we may not be able to cure it within any applicable cure period, if at all. If the maturity of our indebtedness is accelerated, we may not have sufficient funds available for repayment or collateralization of our letters of credit. In addition, we may not have the ability to borrow or obtain sufficient funds to replace the accelerated indebtedness on terms acceptable to us, or at all.
Failure to comply with laws and regulations could harm our business.
We are subject to regulation by various federal, state, local and foreign governmental agencies, including, but not limited to, agencies responsible for monitoring and enforcing employment and labor laws, electric system reliability, workplace safety, product safety, environmental laws, consumer protection laws, federal securities laws and tax laws and regulations.
We are subject to the FCPA, which generally prohibits U.S. companies and their intermediaries from making payments to foreign officials for the purpose of obtaining or keeping business or otherwise obtaining favorable treatment and requires companies to maintain appropriate record-keeping and internal accounting practices to accurately reflect the transactions of the company. Under the FCPA, U.S. companies may be held liable for actions taken by agents or local partners or representatives. In addition, regulators may seek to hold us liable for successor liability FCPA violations committed by companies which we acquire. We are also subject to the U.K. Bribery Act and may be subject to certain anti-corruption laws of other countries in which we do business. We are also subject to the export and re-export control laws of the U.S., including the U.S. Export Administration Regulations, or EAR. We are also subject to U.S. government contracting laws, rules and regulations, and may be subject to government contracting laws of other countries in which we do business. If we or our intermediaries fail to comply with the FCPA, EAR or U.S. government contracting laws, or the anti-corruption, export or governmental contracting laws of other countries, governmental authorities in the U.S. or other countries could seek to impose civil and/or criminal penalties, which could have a material adverse effect on our business, results of operations, financial conditions and cash flows.
If we lose key personnel upon whom we are dependent, or if we fail to attract and retain qualified personnel, we may not be able to manage our operations and meet our strategic objectives.
Our continued success depends upon the continued availability, contributions, vision, skills, experience and effort of our senior management, sales and marketing, research and development, and operations teams. We do not maintain “key person” insurance on any of our employees. We have entered into employment agreements with certain members of our senior management team, but none of these agreements guarantee the services of the individual for a specified period of time. All of the employment arrangements with our key personnel, including the members of our senior management team, provide that employment is at-will and may be terminated by the employee at any time and without notice. The loss of the services of any of our key personnel might impede our operations or the achievement of our strategic and financial objectives. We rely on our research and development team to research, design and develop new and enhanced EIS and demand response solutions. We rely on our operations team to install, test, deliver and manage our EIS and demand response solutions. We rely on our sales and marketing team to sell our EIS and demand response solutions to our customers, build our brand and promote our company.

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The loss or interruption of the service of members of our senior management, sales and marketing, research and development, or operations teams, or our inability to attract or retain other qualified personnel or advisors could have a material adverse effect on our business, financial condition and results of operations and could significantly reduce our ability to manage our operations and implement our strategy.
An inability to protect our intellectual property could negatively affect our business and results of operations.
Our ability to compete effectively depends in part upon the maintenance and protection of the intellectual property related to our EIS and demand response solutions. We hold 17 patents and numerous trademarks and copyrights; in addition we have filed 60 patent applications. Patent protection is unavailable for certain aspects of the technology and operational processes that are important to our business. Any patent held by us or to be issued to us, or any of our pending patent applications, could be challenged, invalidated, unenforceable or circumvented. Patent protection is unavailable for certain aspects of the technology and operational processes that are important to our business. To date, we have relied principally on patent, copyright, trademark and trade secret laws, as well as confidentiality and proprietary information agreements and licensing arrangements, to establish and protect our intellectual property. However, we have not obtained confidentiality and proprietary information agreements from all of our customers and vendors, and although we have entered into confidentiality and proprietary information agreements with all of our employees, we cannot be certain that these agreements will be honored. Some of our confidentiality and proprietary information agreements may not be in writing, and some customers are subject to laws and regulations that require them to disclose information that we would otherwise seek to keep confidential. Policing unauthorized use of our intellectual property is difficult and expensive, as is enforcing our rights against unauthorized use. The steps that we have taken or may take may not prevent misappropriation of the intellectual property on which we rely. In addition, effective protection may be unavailable or limited in jurisdictions outside the United States, as the intellectual property laws of foreign countries sometimes offer less protection or have onerous filing requirements. From time to time, third parties may infringe our intellectual property rights. Litigation may be necessary to enforce or protect our rights or to determine the validity and scope of the rights of others. Any litigation could be unsuccessful, cause us to incur substantial costs, divert resources away from our daily operations and result in the impairment of our intellectual property. Failure to adequately enforce our rights could cause us to lose rights in our intellectual property and may negatively affect our business.
We may be subject to damaging and disruptive intellectual property litigation related to allegations that our EIS and demand response solutions infringe on intellectual property held by others, which could result in the loss of use of those applications, services and products.
Third-party patent applications, patents and other intellectual property rights may relate to our EIS and demand response solutions. As a result, third-parties may in the future make infringement and other allegations that could subject us to intellectual property litigation relating to our EIS and demand response solutions, which could be time-consuming and expensive, divert attention and resources away from our daily operations, impede or prevent delivery of our EIS and demand response solutions and require us to pay significant royalties, licensing fees and damages. In addition, parties making infringement and other claims may be able to obtain injunctive or other equitable relief that could effectively block our ability to provide our EIS and demand response solutions and could cause us to pay substantial damages. In the event of a successful claim of infringement, we may need to obtain one or more licenses from third parties, which may not be available on reasonable terms, or at all.
The use of open source software in our systems and technology may expose us to additional risks and harm our intellectual property.
Our information technology and other systems include software that is subject to open source licenses. While we monitor the use of all open source software in our EIS and demand response solutions and take certain measures to ensure that no open source software is used or distributed in such a way as to subject our EIS and demand response solutions to any unanticipated conditions or restrictions, such use or distribution could inadvertently occur. In the event that any of our EIS and demand response solutions were determined to be subject to an open source license, whether through our own incorporation of software or through licensed software from a third-party provider, we could be required to release the affected portions of our source code publicly, make portions of such applications available under open source licenses, re-engineer all, or a portion of, such applications or otherwise be limited in the licensing of our EIS and demand response solutions, each of which could reduce or eliminate the value of our EIS and demand response solutions. Many of the risks associated with the usage of open source software are outside of our control and cannot be eliminated, and could negatively affect our business, results of operations and financial condition.
If our information technology systems fail to adequately gather, assess and protect data used in providing our EIS and demand response solutions, or if we experience an interruption in their operation, our business, financial condition and results of operations could be adversely affected.
The efficient operation of our business is dependent on our information technology systems. We rely on our information technology systems to effectively control the devices that gather and assess data used in providing our EIS and demand

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response solutions, manage relationships with our customers and C&I end-users, and maintain our research and development data. The failure of our information technology systems to perform as we anticipate could disrupt our business and product development and make us unable, or severely limit our ability, to provide our EIS and demand response solutions. In addition, our information technology systems are vulnerable to damage or interruption from:
earthquake, fire, flood and other natural disasters;
terrorist attacks and attacks by computer viruses or hackers;
power loss; and
computer systems, Internet, telecommunications or data network failure.
Any interruption in the operation of our information technology systems could result in decreased revenues under our contracts and commitments, reduced profit margins on revenues where fixed payments are due to our C&I end-users, reductions in our demonstrated capacity levels going forward, customer dissatisfaction and lawsuits, and could subject us to penalties, any of which could have a material adverse effect on our business, financial condition and results of operations.
Any internal or external security breaches involving our EIS and demand response solutions and even the perception of security risks involving our EIS and demand response solutions or the transmission of data over the Internet, whether or not valid, could harm our reputation and inhibit market acceptance of our EIS and demand response solutions and cause us to lose customers.
We use our EIS and demand response solutions to compile and analyze sensitive or confidential information related to our customers and C&I end-users. In addition, some of our EIS and demand response solutions allow us to remotely control equipment at our C&I end-user sites. Our EIS and demand response solutions rely on the secure transmission of proprietary data over the Internet for some of this functionality. Well-publicized compromises of Internet security, or cyber-attacks, could have the effect of substantially reducing confidence in the Internet as a medium of data transmission. The occurrence or perception of security breaches in our EIS and demand response solutions, or our customers’ or C&I end-users’ concerns about Internet security or the security of our EIS and demand response solutions whether or not they are warranted, could have a material adverse effect on our business, harm our reputation, inhibit market acceptance of our EIS and demand response solutions and cause us to lose customers, any of which could have a material adverse effect on our financial condition and results of operations.
In addition, if in handling sensitive or confidential information we fail to comply with privacy or security laws, we could incur civil liability to government agencies, customers, C&I end-users and/or individuals whose privacy is compromised. In addition, third parties may attempt to breach our security or inappropriately use our EIS and demand response solutions, particularly as we grow our business, through computer viruses, electronic break-ins and other disruptions. We may also face a security breach or electronic break-in by one of our employees or former employees. If a breach is successful, confidential information may be improperly obtained, and we may be subject to lawsuits and other liabilities.
Our ability to provide security deposits or letters of credit is limited and could negatively affect our ability to bid on or enter into utility contracts or arrangements with utilities and electric power grid operators.
We are increasingly required to provide security deposits in the form of cash to secure our performance under utility contracts or open market bidding programs with our utility customers and electric power grid operators for the provision of our demand response solutions. In addition, some of our utility customers and electric power grid operators require collateral in the form of letters of credit to secure our performance or to fund possible damages or penalty payments resulting from our failure to make available capacity at agreed upon levels or any other event of default by us. Our ability to obtain such letters of credit primarily depends upon our capitalization, working capital, past performance, management expertise and reputation and external factors beyond our control, including the overall capacity of the credit market. Events that affect credit markets generally may result in letters of credit becoming more difficult to obtain in the future, or being available only at a significantly greater cost. As of December 31, 2015, we had $22.4 million in outstanding letters of credit under the 2014 credit facility, leaving $7.6 million available under this facility for additional letters of credit.
We may be required, from time to time, to seek alternative sources of security deposits or letters of credit, which may be expensive and difficult to obtain, if available at all. Our inability to obtain letters of credit and, as a result, to bid or enter into utility contracts or arrangements with electric power grid operators or utilities, could have a material adverse effect on our future revenues and business prospects. In addition, in the event that we default under our utility contracts or open market bidding programs with our electric power grid operator and utility customers pursuant to which we have posted collateral, we may lose a portion of, or all such collateral, which could have a material adverse effect on our financial condition and results of operations.

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Our ability to use our net operating loss carryforwards may be subject to limitation.
Generally, a change of more than 50% in the ownership of a company’s stock, by value, over a three-year period constitutes an ownership change for United States federal income tax purposes. An ownership change may limit a company’s ability to use its net operating loss carryforwards attributable to the period prior to such change. We may experience ownership changes as a result of shifts in our stock ownership. As a result, as we earn net taxable income, our ability to use our pre-ownership change net operating loss carryforwards to offset United States federal taxable income may become subject to limitations, which could potentially result in increased future tax liabilities. Although, in the past, we have been able to utilize our net operating loss carryforwards to offset the maximum amount of taxable income allowed by the various tax jurisdictions in which we operate, we may not be able to utilize some or all of these net operating losses in the future.
We may have exposure to additional tax liabilities .
As a multinational corporation, we are subject to audit by various federal, state, local and foreign authorities regarding income tax and non-income tax matters. Significant judgment is required in determining our global provision for income taxes, withholding obligations and other tax liabilities. In the ordinary course of a global business, there are many intercompany transactions and calculations where the ultimate tax determination is uncertain. We are also subject to non-income taxes, such as payroll, sales, use, value-added, net worth, property, and goods and services taxes in the U.S. and various foreign jurisdictions. Although we believe our approach to determining the appropriate tax treatment is supportable and in accordance with relevant authoritative guidance, a final determination of tax audits or tax disputes could have an adverse effect on our financial condition, results of operations and cash flows.
In addition, our future effective tax rates could be favorably or unfavorably affected by changes in tax rates, changes in the valuation of our deferred tax assets or liabilities, or changes in tax laws or their interpretation. Such changes could have a material adverse impact on our financial results.
Fluctuations in the exchange rates of foreign currencies in which we conduct our business, in relation to the U.S. dollar, could harm our business and prospects.
We have various operations outside the United States. The expenses of our international operations are denominated in local currencies. In addition, our foreign sales may be denominated in local currencies. Fluctuations in foreign currency exchange rates could affect our revenues, cost of revenues and profit margins and could result in exchange losses. In addition, currency devaluation can result in a loss if we hold deposits of that currency or maintain receivable balances, including those from our international subsidiaries. In the last few years we have not hedged foreign currency exposures, but we may in the future hedge foreign currency denominated sales. There is a risk that any hedging activities will not be successful in mitigating our foreign exchange exposure and may adversely impact our financial condition and results of operations.
We are exposed to potential risks and will continue to incur significant costs as a result of the internal control testing and evaluation process mandated by Section 404 of the Sarbanes-Oxley Act of 2002.
We assessed the effectiveness of our internal control over financial reporting as of December 31, 2015 and assessed all deficiencies on both an individual basis and in combination to determine if, when aggregated, they constituted a material weakness. As a result of this evaluation, no material weaknesses were identified.
We expect to continue to incur significant costs, including increased accounting fees and increased staffing levels, in order to maintain compliance with Section 404 of the Sarbanes-Oxley Act. We continue to monitor controls for any weaknesses or deficiencies. No evaluation can provide complete assurance that our internal controls will detect or uncover all failures of persons within the company to disclose material information otherwise required to be reported. The effectiveness of our controls and procedures could also be limited by simple errors or faulty judgments. In addition, as we continue to expand globally, the challenges involved in implementing appropriate internal controls will increase and will require that we continue to improve our internal controls over financial reporting.
In the future, if we fail to complete the Sarbanes-Oxley 404 evaluation in a timely manner, or if our independent registered public accounting firm cannot opine in a timely manner to our internal control over financial reporting, we could be subject to regulatory scrutiny and a loss of public confidence in our internal controls, which could adversely impact the market price of our common stock. We or our independent registered public accounting firm may identify material weaknesses in internal controls over financial reporting, which also may result in a loss of public confidence in our internal controls and adversely impact the market price of our common stock. In addition, any failure to implement required, new or improved controls, or difficulties encountered in their implementation, could harm our operating results or cause us to fail to meet our reporting obligations.

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Risks Related to Our Common Stock
We expect our quarterly revenues and operating results to fluctuate. If we fail in future periods to meet our publicly announced financial guidance or the expectations of securities analysts or investors, the market price of our common stock could decline substantially.
Our quarterly revenues and operating results have fluctuated in the past and may vary from quarter to quarter in the future. Accordingly, we believe that period-to-period comparisons of our results of operations may be misleading. The results of one quarter should not be used as an indication of future performance. We provide public guidance on our expected results of operations for future periods. This guidance is comprised of forward-looking statements subject to risks and uncertainties, including the risks and uncertainties described in this Annual Report on Form 10-K and in our other public filings and public statements, and is based necessarily on assumptions we make at the time we provide such guidance. Our revenues and operating results may fail to meet our previously stated financial guidance or the expectations of securities analysts or investors. Our failure to meet such expectations or our financial guidance could cause the market price of our common stock to decline substantially.
Our quarterly revenues and operating results may vary depending on a number of factors, including:
demand for and acceptance of our EIS and demand response solutions;
the seasonality of our demand response business in certain of the markets in which we operate, where revenues recognized under certain utility contracts and pursuant to certain open market bidding programs can be concentrated in particular seasons and months;
changes in open market bidding program rules and reductions in pricing for demand response capacity;
delays in the implementation and delivery of our EIS and demand response solutions which may impact the timing of our recognition of revenues;
delays or reductions in spending for EIS and demand response solutions by our electric power grid operator or utility customers and potential enterprise customers;
the long lead time associated with securing new customer contracts;
the structure of any forward capacity market in which we participate, which may impact the timing of our recognition of revenues related to that market;
the mix of our revenues during any period, particularly on a regional basis, since local fees recognized as revenues for demand response capacity tend to vary according to the level of available capacity in given regions;
the termination or expiration of existing contracts with electric power grid operators, utility customers, enterprise customers and/or C&I end-users;
potential interruptions of our customers’ or C&I end-users' operations;
development of new relationships and maintenance and enhancement of existing relationships with customers and strategic partners;
temporary capacity programs that could be implemented by electric power grid operators and utilities to address short-term capacity deficiencies;
the imposition of penalties or the reversal of deferred revenue due to our failure to meet a capacity commitment;
the elimination, modification or flawed design of, or our decision not to participate or to reduce our participation in, any demand response program in which we currently participate;
global economic and credit market conditions; and
increased expenditures for sales and marketing, software development and other corporate activities.
Our stock price has been and is likely to continue to be volatile and the market price of our common stock may fluctuate substantially.
For the period of January 1, 2015, through December 31, 2015, our stock price fluctuated between a high of $19.04 on February 26, 2015 and a low of $ 3.76 on December 21, 2015. In addition, in the first quarter of 2016 our stock price has traded as low as $2.92 .
Our stock price is likely to continue to be volatile and subject to significant price and volume fluctuations in response to market and other factors, including:
demand for and acceptance of our EIS and demand response solutions;
our ability to develop new relationships and maintain and enhance existing relationships with customers and strategic partners;
termination of or rule changes in open market bidding programs and/or reductions in pricing for demand response capacity;

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the termination or expiration of existing contracts with enterprise and utility customers;
general market conditions and overall fluctuations in equity markets in the United States;
the elimination, modification or flawed design of, or our decision not to participate or to reduce our participation in, any demand response program in which we currently participate;
introduction of technological innovations or new EIS and demand response solutions by us or our competitors;
actual or anticipated variations in quarterly revenues and operating results;
the financial guidance we may provide to the public, any changes in such guidance or our failure to meet such guidance;
changes in estimates or recommendations by securities analysts that cover our common stock;
delays in the implementation and delivery of our EIS and demand response solutions which may impact the timing of our recognition of revenues;
litigation or regulatory enforcement actions;
changes in the regulations affecting our industry in the United States and internationally;
the way in which we recognize revenues and the timing associated with our recognition of revenues;
developments with respect to recent acquisitions, including with respect to expected synergies, and any unforeseen integration costs or impairment charges;
developments or disputes concerning patents or other proprietary rights;
period-to-period fluctuations in our financial results;
potential interruptions of our customers’ operations;
the seasonality of our demand response business in certain of the markets in which we operate;
failure to secure adequate capital to fund our operations, or the future sale or issuance of equity securities at prices below fair market price;
economic and other external factors including disasters or crises; and
any announcement by us or our competitors of significant acquisitions, strategic partnerships, joint ventures or capital commitments.
These and other external factors may cause the market price and demand for our common stock to fluctuate substantially, which may limit or prevent investors from readily selling their shares of common stock and may otherwise negatively affect the liquidity of our common stock. In addition, in the past, when the market price of a stock has been volatile, holders of that stock have instituted securities class action litigation against the company that issued the stock. Our stock price has been particularly volatile recently and may continue to be volatile in the near term and we could incur substantial costs defending any lawsuit brought against us by any of our stockholders. Such a lawsuit could also divert the time and attention of our management.
Provisions of our certificate of incorporation, bylaws and Delaware law, and of some of our employment arrangements, may make an acquisition of us or a change in our management more difficult and could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Certain provisions of our certificate of incorporation and bylaws could discourage, delay or prevent a merger, acquisition or other change of control that stockholders may consider favorable, including transactions in which we may have otherwise received a premium to the market value of our common stock. These provisions also could limit the price that investors might be willing to pay in the future for shares of our common stock, thereby depressing the market price of our common stock. Stockholders who wish to participate in these transactions may not have the opportunity to do so. Furthermore, these provisions could prevent or frustrate attempts by our stockholders to replace or remove our management. These provisions:
allow the authorized number of directors to be changed only by resolution of our board of directors;
require that vacancies on the board of directors, including newly created directorships, be filled only by a majority vote of directors then in office;
establish a classified board of directors, providing that not all members of the board be elected at one time;
authorize our board of directors to issue, without stockholder approval, blank check preferred stock that, if issued, could operate as a “poison pill” to dilute the stock ownership of a potential hostile acquirer to prevent an acquisition that is not approved by our board of directors;
require that stockholder actions must be effected at a duly called stockholder meeting and prohibit stockholder action by written consent;
prohibit cumulative voting in the election of directors, which would otherwise allow holders of less than a majority of stock to elect some directors;
establish advance notice requirements for stockholder nominations to our board of directors or for stockholder proposals that can be acted on at stockholder meetings, which were modified in February 2014;
limit who may call stockholder meetings; and

23



require the approval of the holders of 75% of the outstanding shares of our capital stock entitled to vote in order to amend certain provisions of our certificate of incorporation and bylaws.
Some of our employment arrangements and equity agreements provide for severance payments and accelerated vesting of benefits, including accelerated vesting of equity awards, upon a change of control. These provisions may discourage or prevent a change of control. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the Delaware General Corporation Law, which may, unless certain criteria are met, prohibit large stockholders, in particular those owning 15% or more of our outstanding voting stock, from merging or combining with us for a prescribed period of time.
The foregoing provisions could impede a merger, takeover or other business combination involving us or discourage a potential acquirer from making a tender offer for our common stock, which, under certain circumstances, could reduce the market price of our common stock.
We do not intend to pay dividends on our common stock.
We have not declared or paid any cash dividends on our common stock to date, and we do not anticipate paying any dividends on our common stock in the foreseeable future. Except for opportunistic repurchases of outstanding debt and/or equity securities, we currently intend to retain all available funds and any future earnings for use in the development, operation and growth of our business. In addition, the 2014 credit facility prohibits us from paying dividends and future loan agreements may also prohibit the payment of dividends. Any future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements, business opportunities, contractual restrictions and other factors deemed relevant. To the extent we do not pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in our common stock.
If securities or industry analysts do not publish research or publish inaccurate or unfavorable research about our business, our stock price and trading volume could decline.
The trading market for our common stock will continue to depend in part on the research and reports that securities or industry analysts publish about us or our business. If these analysts do not continue to provide adequate research coverage or if one or more of the analysts who cover us downgrade our stock or publish inaccurate or unfavorable research about our business, our stock price could decline. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, demand for our stock could decrease, which could cause our stock price and trading volume to decline.
The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and The NASDAQ Stock Market LLC, require significant resources, increase our costs and distract our management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
As a public company with equity securities listed on NASDAQ, we must comply with statutes and regulations of the SEC and the requirements of NASDAQ. Complying with these statutes, regulations and requirements occupies a significant amount of the time of our board of directors and management and significantly increases our costs and expenses. In addition, as a public company we incur substantial costs to obtain director and officer liability insurance policies. These factors could make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee.

24




Item 1B.
Unresolved Staff Comments
None.
Item 2.
Properties
Our corporate headquarters and principal office is located in Boston, Massachusetts, where we lease approximately 110,000 square feet of office space under a lease agreement, or the 2012 Lease, expiring in July 2020 with a right to first offer, subject to the rights of existing tenants in the building, whereby we may lease certain additional space in the building during the lease term and the right to extend the lease term for one period of five years upon the expiration of the initial term. The average monthly rent over the initial term of the 2012 Lease is $0.4 million, exclusive of operating expenses. We were required to provide a security deposit in the form of an unconditional and irrevocable letter of credit of approximately $1.8 million, which was reduced to $1.5 million and will continue to be reduced on an annual basis through the lease term . We are required to pay our pro rata share of any building operating expenses and real estate taxes over and above a base year, as well as certain utility costs. Additionally, we also have certain rights to sublease the leased space.
We also lease a number of offices under various other lease agreements in the United States, Australia, Canada, New Zealand, Ireland, the United Kingdom, Germany, Switzerland, Brazil, India, Japan, and South Korea. We do not own any real property. We believe that we have adequate space for our anticipated needs and that suitable additional space will be available at commercially reasonable prices as needed.
Item 3.
Legal Proceedings
We are subject to legal proceedings, claims and litigation arising in the ordinary course of business. We do not expect the ultimate costs to resolve these matters to have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
Item 4.
Mine Safety Disclosures
Not applicable.

25




PART II
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Price Range of Our Common Stock
Our common stock is currently traded on The NASDAQ Global Market under the symbol “ENOC”. The following table sets forth the high and low sales prices per share of our common stock as reported on The NASDAQ Global Market for the periods indicated.
Fiscal 2015
High
 
Low
First Quarter
$
19.04

 
$
10.36

Second Quarter
$
14.69

 
$
9.45

Third Quarter
$
11.21

 
$
7.23

Fourth Quarter
$
9.79

 
$
3.76

Fiscal 2014
High
 
Low
First Quarter
$
23.45

 
$
16.85

Second Quarter
$
24.35

 
$
16.98

Third Quarter
$
21.25

 
$
16.91

Fourth Quarter
$
17.15

 
$
12.29

Stockholders
As of March 4, 2016 , we had approximately 720 stockholders of record. This number does not include stockholders for whom shares are held in a “nominee” or “street” name.
Dividend Policy
We have never paid or declared any cash dividends on our common stock. Except for opportunistic repurchases of outstanding debt and/or equity securities, we currently intend to retain all available funds and any future earnings to fund the development and expansion of our business, and we do not anticipate paying any cash dividends in the foreseeable future. Any future determination to pay dividends will be at the discretion of our board of directors and will depend on our financial condition, results of operations, capital requirements, and other factors that our board of directors deem relevant. Additionally, the terms of the 2014 credit facility preclude us, and the terms of any future debt or credit facility may preclude us, from paying dividends.
Unregistered Sales of Equity Securities
As previously disclosed in our Current Report on Form 8-K on November 26, 2014, we issued 583,218 shares of our common stock as partial consideration to the stockholders of Pulse Energy Inc., or Pulse Energy, upon the closing of our acquisition of Pulse Energy. In addition, we may issue up to an additional 699,855 shares of common stock to Pulse Energy’s stockholders if and to the extent that certain earn-out provisions are met.
The issuance of our common stock is exempt from the registration requirements pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended, or the Securities Act, Rule 506 of Regulation D promulgated under the Securities Act, or Regulation D, and/or Regulation S promulgated under the Securities Act, or Regulation S, based upon representations we have obtained from each Pulse Energy stockholder receiving such shares that, among other things, the Pulse Energy stockholder is either (a) an “accredited investor” as that term is defined in Rule 501(a) of Regulation D or (b) not a “U.S. Person” as that term is defined in Rule 902(k) of Regulation S.

26



Issuer Purchases of Equity Securities
The following table provides information about our purchases of our common stock during the fourth quarter of the year ended December 31, 2015, or fiscal 2015:
Fiscal Period
 
Total Number
of Shares
Purchased (1)
 
Average Price
Paid per Share (2)
 
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs
 
Approximate Dollar
Value of Shares that
May Yet Be  Purchased
Under the Plans
or Programs
October 1, 2015—October 31, 2015
 
34,652

 
$
7.88

 

 
$
50,000,000

November 1, 2015—November 30, 2015
 
10,379

 
6.57

 

 
50,000,000

December 1, 2015—December 31, 2015
 
25,655

 
4.06

 

 
50,000,000

Total for the fourth quarter of 2015
 
70,686

 
$
6.29

 

 
$
50,000,000

(1)  
We repurchased a total of 70,686 shares of our common stock in the fourth quarter of fiscal 2015, consisting of 34,652 , 10,379 and 25,655 shares in October, November and December 2015, respectively, to cover employee minimum statutory income tax withholding obligations in connection with the vesting of restricted stock under our equity incentive plans, which we pay in cash to the appropriate taxing authorities on behalf of our employees.
(2)  
Average price paid per share is calculated based on the average price per share paid for the repurchase of shares under our publicly announced share repurchase program and the average price per share related to repurchases of our common stock to cover employee minimum statutory income tax withholding obligations in connection with the vesting of restricted stock under our equity incentive plans which we pay in cash to the appropriate taxing authorities on behalf of our employees. Amounts disclosed are rounded to the nearest two decimal places.

27




Item 6.
Selected Financial Data
The selected financial data presented below is derived from our audited consolidated financial statements and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in Item 7 and our consolidated financial statements and accompanying notes thereto included in Appendix A to this Annual Report on Form 10-K. The consolidated statements of operations and balance sheet data for all periods presented is derived from the audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K or in Annual Reports on Form 10-K for prior years on file with the SEC.
 
Year Ended December 31, (1)
(In thousands, except share and per share data)
2015
 
2014
 
2013
 
2012
 
2011
Selected Balance Sheet Data (at end of period):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
138,120

 
$
254,351

 
$
149,189

 
$
115,041

 
$
87,297

Total assets  (2)
443,714

 
620,884

 
415,955

 
355,165

 
355,260

Total long-term debt (2)
111,254

 
135,090

 

 

 

Total EnerNOC Inc. stockholders’ equity
114,644

 
291,873

 
269,495

 
240,022

 
247,740

Selected Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Revenues
$
399,584

 
$
471,948

 
$
383,460

 
$
277,984

 
$
286,608

Cost of revenues
245,051

 
257,322

 
192,292

 
154,540

 
163,211

Gross profit
154,533

 
214,626

 
191,168

 
123,444

 
123,397

(Loss) income from operations
(187,968
)
 
26,228

 
27,716

 
(20,388
)
 
(9,537
)
Net (loss) income
$
(185,118
)
 
$
11,997

 
$
22,088

 
$
(22,293
)
 
$
(13,383
)
Common Share Data:
 
 
 
 
 
 
 
 
 
Net (loss) income per share, basic
$
(6.51
)
 
$
0.43

 
$
0.80

 
$
(0.84
)
 
$
(0.52
)
Net (loss) income per share, diluted
$
(6.51
)
 
$
0.42

 
$
0.76

 
$
(0.84
)
 
$
(0.52
)
(1) Includes the results of operations from the date of acquisition relating to our acquisitions of World Energy Solutions, Inc. in January 2015, and Pulse Energy Inc., EnTech Utility Service Bureau, Inc., EnTech USB Private Limited, Universal Load Center Co. Ltd., Entelios AG, and Activation Energy DSU Limited in 2014.
(2) During the fourth quarter of 2015, we elected to early adopt Accounting Standards Update (ASU) 2015-03 "Simplifying the Presentation of Debt Issuance Costs" and applied the changes retrospectively to all prior periods. Prior period deferred financing costs of $3,818 as of December 31, 2014, consisting of $687 of current and $3,131 of non-current assets, were reclassified to long term liabilities as a direct reduction to the associated debt in conformity with current year presentation. Also during the fourth quarter of 2015, we elected to early adopt ASU 2015-17 "Balance Sheet Classification of Deferred Taxes" and applied the changes prospectively effective for the December 31, 2015 balance sheet. As a result, we have presented all deferred tax assets and liabilities as non-current on our consolidated balance sheet as of December 31, 2015, and we have not reclassified current deferred tax assets and liabilities on our consolidated balance sheet for prior periods.

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Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our “Selected Financial Data” and consolidated financial statements and accompanying notes thereto included elsewhere in this Annual Report on Form 10-K. In addition to the historical information, the discussion contains certain forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those expressed or implied by the forward-looking statements due to applications of our critical accounting policies and factors including, but not limited to, those set forth under the caption “Risk Factors” in Item 1A of Part I of this Annual Report on Form 10-K.
Overview
We are a leading provider of energy intelligence software, or EIS, and demand response solutions to enterprises, utilities, and electric power grid operators.
Our EIS provides our enterprise customers with a suite of Software-as-a-Service, or SaaS, offerings that improve how enterprises manage and control energy costs for their organizations. We continually enhance and expand our EIS to meet the evolving needs of our enterprise customers by providing SaaS solutions to manage:
energy cost visualization, budgets, forecasts, and accruals;
utility bill validation and payment;
facility optimization, including benchmarking facilities and identifying cost savings opportunities;
energy project tracking;
reporting for energy and sustainability disclosure and compliance; and
peak energy demand and the related cost impacts.
Our EIS helps our enterprise customers quickly analyze data, achieve real‑time visibility and intelligence about their organization’s energy usage, reduce operational costs, comply and report on sustainability requirements, and drive better business decisions. We offer our EIS to our enterprise customers at four subscription levels: basic, standard, professional, and industrial.
Our EIS provides our utility customers with a SaaS-based customer engagement platform that allows utilities to:
increase customer satisfaction;
meet energy efficiency mandates;
reduce cost through lower call volume; and
increase revenue through more effective targeting of existing utility-sponsored programs.
We deliver shared value for both the utility and its customers by combining our deep expertise with commercial, institutional and industrial end-users of energy, or C&I end-users, 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 C&I end-users, and small and medium-sized enterprises.
Our EIS also provides our enterprise and utility customers located in restructured or deregulated markets with the ability to more effectively manage energy supplier selection and the energy procurement process by providing highly-structured auction events designed to yield transparent and competitive energy pricing. Our energy procurement application consists of an online auction platform that enables our enterprise and utility customers to get the best price for electricity, natural gas and other energy resources by having energy suppliers compete for their business, as well as supplier contract management and price alert tools. Our energy procurement solutions also include supply procurement advisory services that assist our enterprise customers in developing and implementing risk management and purchasing strategies that provide maximum price transparency and structural savings.
Our demand response solutions provide our utility customers and electric power grid operators with a managed service 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 C&I end-users. When we are called upon by our utility customers and electric power grid operators to deliver our contracted capacity, we use our Network Operations Center, or NOC, to remotely manage and reduce electricity consumption across our network of C&I end-user sites, making demand response capacity available to our utility customers and electric power grid operators on demand while helping C&I end-users achieve energy savings, improve financial results and realize environmental benefits. We receive periodic payments from our utility customers and electric power grid operators for providing our demand response solutions, and we share these periodic payments with C&I end-users in exchange for those C&I end-users reducing their power consumption when called upon by us to do so. Our demand response solutions are

29



also capable of providing our utility customers with the underlying technology to manage their own utility-sponsored demand response programs and secure reliable demand-side resources. This product consists of long‑term contracts with our utility customers for a technology-enabled managed service that provides our utility customers with real-time load monitoring, dispatching applications, customizable reports, and measurement and verification tools.
In addition, we offer premium professional services that support the implementation of our EIS and help our enterprise customers set their energy management strategy, as well as provide energy audits and retro-commissioning. Professional services are offered to our customers as a means to further implement and extend our technology across their organizations.
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 years ended December 31, 2015 and December 31, 2014 :
 
December 31, 2015
 
December 31, 2014
Enterprise Customers (1)(7)
4,100

 
1,300

Enterprise Sites (1)(7)
81,500

 
35,700

Enterprise ARR (in millions) (2)
$
61

 
$
20

Enterprise ARR Gross Churn Rate (2)
18
 %
 
18
%
Enterprise ARR Net Churn Rate (2)
(1
)%
 
15
%
Utility Customers (3)
52

 
52

Utility ARR (in millions) (4)
$
65

 
$
67

Utility ARR Gross Churn Rate (4)
16
 %
 
13
%
Utility ARR Net Churn Rate (4)
12
 %
 
10
%
Grid Operators (5)
14

 
14

Demand Response Customers (6)(7)
6,500

 
6,500

Demand Response Sites (6)(7)
15,200

 
15,000

(1)  
The term “Enterprise Customers,” describes the number of our customers that purchase our EIS for enterprises. By extension, the term “Enterprise Sites,” describes the number of sites across our Enterprise Customer base that purchase our EIS 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 Gross 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 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 demand response 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 Gross 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 demand response 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,” 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,” describes the number of our C&I end-users under contract to participate in our demand response programs. By extension, the term “Demand Response Sites,” 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 purchase our EIS.
(7)  
Amounts rounded to nearest hundred.

30



The number of our enterprise customers at December 31, 2015 was approximately 4,100 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 the results of our ongoing efforts to develop our enterprise sales team, the relative success that our enterprise sales team has had in penetrating the market, and the growing need for our solutions with enterprise customers who are increasingly turning to our EIS to make strategic decisions about how and when they consume or procure energy. The number of enterprise sites at December 31, 2015 was approximately 81,500 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. Enterprise ARR at December 31, 2015 was approximately $61 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 as well as 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 opt not to renew certain smaller or unprofitable customers acquired through our acquisition of World Energy. Our enterprise ARR gross churn rate was 18% at December 31, 2015 and December 31, 2014 . Our enterprise ARR net churn rate was negative 1% at December 31, 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 that we served at December 31, 2015 was 52 , consistent with the number of utility customers as of December 31, 2014 . This primarily reflects the non-renewal of certain utility contracts for our demand response offerings offset by an increase in customers contracting for our utility EIS. Utility ARR at December 31, 2015 was approximately $65 million compared to approximately $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 added utility software contracts. Our utility ARR gross churn rate was 16% at December 31, 2015 compared to 13% at December 31, 2014 . Our utility ARR net churn rate was 12% at December 31, 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 to which we delivered demand response at December 31, 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 6,500 for both December 31, 2015 and December 31, 2014 . The number of demand response sites at December 31, 2015 was approximately 15,200 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.
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.
Significant Recent Developments
In December 2015, in privately negotiated transactions, we completed repurchases, in cash, of $33.2 million in aggregate principal amount of our outstanding 2.25% convertible senior notes due 2019, or the Notes, at a weighted average price of 59.2% of principal for a total purchase price of $19.7 million plus accrued interest. We recorded a gain on the extinguishment of the Notes of $9.2 million based on the difference between the carrying amount of the repurchased Notes and the cash consideration. The gain is classified as gain on early extinguishment of debt within the consolidated statements of operations.
On January 25, 2016, the United States Supreme Court reversed the D.C. Circuit Court’s May 2014 ruling in FERC v. Electric Power Supply Association thereby upholding FERC Order No. 745 and affirming FERC’s jurisdiction over the participation of demand response in U.S. wholesale electricity markets. The Supreme Court’s landmark ruling preserved the structure of a key market for our grid operator demand response operations.
Effective January 1, 2016, we began operating as two distinct business units: Software and Demand Response, each with dedicated sales, marketing and operations functions. We are evaluating the impact of this change in organizational structure on our future reportable segment information, which will be provided in future periodic filings. Prior periods will be reclassified and presented consistent with the revised current period presentation.

31



Revenues and Expense Components
Revenues
We derive revenues primarily from the sale of our EIS and demand response solutions. We recognize revenues when 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 enterprises, utilities and electric power grid operators. During the years ended December 31, 2015, 2014 and 2013, revenues from grid operators and utilities were comprised of $314.3 million , $424.5 million and $342.1 million, respectively, of demand response revenues.
Revenues from the sale of our EIS to our enterprise and utility 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 to the enterprise or utility 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.
Revenues associated with the provision of our demand response solutions to our utility customers and electric power grid operators 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 earn revenues from our demand response solutions by making demand response capacity available in open market programs and pursuant to contracts that we enter into with our utility customers, which generally range from three to ten years in duration, to deploy our demand response solutions.
We also earn revenues from the provision of our demand response solutions in the form of ongoing fees from utility customers for overall management of utility-sponsored demand response programs. These fees are typically based on enrolled capacity or enrolled C&I end-users, and are not subject to adjustment based on performance during demand response dispatches. We recognize revenues from these fees ratably over the applicable service delivery period commencing upon when the C&I end-users have been enrolled and the contracted services have been delivered. In addition, we may receive additional fees for program start-up and for C&I end-user 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 end-users and delivery of the contracted services.
Cost of Revenues
Cost of revenues primarily consists of amounts owed to our C&I end-users 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 end-users 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 end-user 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 enterprise customer and C&I end-user sites, which monitor energy usage, communicate with the NOC 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 demand response solutions, the monthly telecommunications and data costs we incur as a result of being connected to enterprise customer and C&I end-user sites, services and products, third-party services, equipment costs, equipment depreciation, our internal payroll and related costs allocated to an enterprise customer or C&I end-user site, 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. 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 Annual Report on Form 10-K.
We capitalize and defer incremental direct costs incurred related to customer contracts where the associated revenues have been deferred as long as the deferred incremental direct costs are deemed realizable. During the years ended December 31, 2015 , 2014 and 2013 , we capitalized $52.8 million , $38.8 million and $25.1 million , respectively, of incremental direct costs associated with customer contracts. These deferred expenses would not have been incurred without our participation in a certain open market program and will be expensed in proportion to when the related revenue is recognized. Certain of these incremental direct payments are recorded as a reduction of revenues when the associated revenues are recognized as they relate

32



to third-party demand response arrangements where the third party has become the primary obligor of the demand response obligation. During the years ended December 31, 2015 , 2014 and 2013 , we expensed $14.5 million , $30.6 million and $26.1 million , respectively, of capitalized incremental direct costs to cost of revenues and recorded $12.6 million , $11.1 million , and $0.4 million , respectively, as a reduction to revenues. As of December 31, 2015 , there have been no material recoverability issues related to capitalized incremental direct costs.
We also capitalize the costs of our production and generation equipment utilized in the delivery of our demand response solutions and expense this equipment over the lesser of its estimated useful life or the term of the contractual arrangement. During the years ended December 31, 2015 , 2014 and 2013 , we capitalized $7.8 million , $10.1 million and $8.7 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. Gross margin is calculated as the ratio of gross profit to total revenues. Our gross profit has been, and will continue to be, affected by many factors, including (a) the demand for our EIS and demand response solutions, (b) the selling price of our EIS and demand response 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, including our outcomes in negotiating favorable contracts with our customers and our participation in capacity auctions and third-party contracts, (e) the introduction of new EIS and demand response solutions, (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.
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 928 full-time employees at December 31, 2014 to 1,088 full-time employees at December 31, 2015 , primarily as a result of our fiscal 2014 and 2015 acquisitions. Full time employees in operating expenses exclude 197 and 278 employees included in cost of revenues at December 31, 2014 and 2015 , respectively. As noted above under “Cost of Revenues,” a portion of our headcount and associated payroll and related expenses are included within cost of revenues. In addition, we incur up-front costs associated with the enablement of new MW in the demand response programs in which we participate. We expect to keep headcount relatively flat for the foreseeable future as we manage a more consistent MW volume and transfer existing resources to support expected expansion in EIS. In addition, our operating expenses include the expenses related to the operation and oversight of our NOC. We expect our overall operating expenses to slightly decrease in absolute dollar terms for the foreseeable future, as we leverage the investments we have made over the last several years and drive efficiencies across our general and administrative functions.
In certain forward capacity markets in which we choose to participate, such as PJM, we may install our equipment at a C&I end-user site to allow for the curtailment of MW from the electric power grid up to twelve months in advance of enrolling the C&I end-user in a particular program (i.e., we enable the C&I end-user). As a result, there has been a trend of incurring operating expenses at the time of enablement, including salaries and related personnel costs, associated with enabling certain of our C&I end-users, in advance of recognizing the corresponding revenues.
Selling and Marketing
Selling and marketing expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards made to our sales and marketing personnel, (b) commissions, (c) travel and other out-of-pocket expenses, (d) marketing programs such as trade shows and (e) other related overhead. Full-time employees associated with selling and marketing grew from 306 at December 31, 2014 to 325 at December 31, 2015 . Commissions are recorded as an expense when earned by the employee.
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 made to our executive, finance, human resource, information technology and operations organizations, (b) facilities expenses, (c) external accounting and legal professional fees, (d) depreciation and amortization and (e) other related overhead. Full-time employees associated with general and administrative costs grew from 461 at December 31, 2014 to 553 at December 31, 2015 .
Research and Development
Research and development expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards made to our research and development personnel, (b) payments to suppliers for design and consulting services, (c) costs relating to the design and development of new EIS and demand response solutions and

33



enhancement of existing EIS and demand response solutions, (d) quality assurance and testing, and (e) other related overhead. Full-time employees associated with research and development grew from 161 at December 31, 2014 to 210 at December 31, 2015 . During the years ended December 31, 2015 , 2014 and 2013 , we capitalized software development costs of $5.3 million , $6.0 million and $7.9 million , respectively, which are included in property and equipment.
Stock-Based Compensation
We grant share-based awards to employees, non-employees, members of the board and advisory board members. We account for grants of stock-based compensation in accordance with ASC 718,  Stock Compensation (ASC 718). We account for share-based awards granted to non-employees in accordance with ASC 505-50, Equity Based Payments to Non-Employees , which results in continuous fair value measurements 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 December 31, 2015 the Company had two stock-based compensation plans, which are more fully described in Appendix A to this Annual Report on Form 10-K.
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.
Interest Expense; Other Expense, Net; and Gain on Early Extinguishment of Debt
Interest expense primarily consists of interest expense related to the Notes, as well as fees associated with our 2014 credit facility. Interest expense also consists of interest expense associated with letters of credit and other financial assurances. Other expense, net consists primarily of gains or losses on transactions denominated in currencies other than our or our subsidiaries’ functional currency and other non-operating income and expenses. Gain on early extinguishment of debt represents the gain we recorded as a result of the repurchase in cash of $33.2 million in aggregate principal amount of the Notes at a weighted average price of 59.2% of principal for a total purchase price of $19.7 million plus accrued interest.
Consolidated Results of Operations
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Revenues
The following table summarizes our revenues for the years ended December 31, 2015 and 2014 (dollars in thousands):
 
Year Ended December 31,
 
Dollar Change
 
Percentage Change
 
2015
 
2014
 
Revenues:
 
 
 
 
 
 
 
Grid operator
$
259,302

 
$
368,828

 
$
(109,526
)
 
(29.7
)%
Utility
63,204

 
62,026

 
1,178

 
1.9
 %
Enterprise
77,078

 
41,094

 
35,984

 
87.6
 %
Total revenues
$
399,584

 
$
471,948

 
$
(72,364
)
 
(15.3
)%

34



Grid Operator Revenues
The decrease in our revenues from grid operators was primarily attributable to changes in the following operating areas (dollars in thousands):
 
Revenue Increase (Decrease)
 
December 31, 2014
to
December 31, 2015
PJM
$
(84,048
)
Western Australia (AEMO)
(26,792
)
South Korea (KPX)
17,135

Alberta (AESO)
(6,176
)
New England (ISO NE)
(6,033
)
Ontario Power Authority (OPA)
(2,991
)
Other (1)
(621
)
Total decrease in grid operator revenues
$
(109,526
)
(1)  
The amounts included in ‘other’ relate to various demand response programs, none of which have individually material changes.
The decrease in revenues from grid operators for the year ended December 31, 2015 , as compared to 2014 , was primarily due to our increased participation in PJM’s extended program in the 2015/2016 delivery year, which resulted in the deferral of revenue recognition to the second quarter of 2016, lower revenue associated with capacity auctions and bilateral contracts in the PJM and ISO-NE demand response programs, and a change during the fourth quarter of 2014 to ratable revenue recognition and decreased pricing in the AEMO program. The decrease in PJM revenues for the year ended December 31, 2015 as compared to 2014 was also attributed to significantly lower energy payments resulting from fewer demand response event dispatches during 2015 . The decrease in revenues was also due to lower pricing and fewer enrolled MWs in our Canadian demand response programs in AESO and OPA, and foreign currency exchange losses due to relative weakness of the Canadian and Australian dollars against the US dollar. This decrease in revenue was partially offset by revenue associated with our demand response program in South Korea. We currently expect our revenue from grid operators to be flat to 10% lower during fiscal 2016 as compared to fiscal 2015.
Utility Revenues
 
Revenue Increase (Decrease)
 
December 31, 2014
to
December 31, 2015
Southern California Edison (SCE)
$
3,800

Idaho Power/Salt River Project (SRP)
(3,592
)
Utility Software
3,180

Pacific Gas & Electric (PG&E)
(2,667
)
Other (1)
457

Total increase in utility revenues
$
1,178

(1)  
The amounts included in ‘other’ relate to various demand response programs, none of which have individually material changes.
The increase in revenues from utility customers during the year ended December 31, 2015 , as compared to 2014 , was primarily due to an increase in utility software revenues related to our acquisition of Pulse Energy Inc., or 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 offset by reduced revenue from the conclusion of two domestic demand response programs and a decrease in participation in our PG&E demand response program. We currently expect our demand response revenues from utility customers to be flat to 10% lower during fiscal 2016 as compared to fiscal 2015. We currently expect our software revenues from utility customers to increase during fiscal 2016, as compared to fiscal 2015.

35



Enterprise Revenue
 
Revenue Increase (Decrease)
 
December 31, 2014
to
December 31, 2015
Procurement and energy efficiency revenue acquired in the World Energy acquisition
$
41,113

Subscription software - Massachusetts Department of Energy Resources (MA DOER)
(3,223
)
Subscription software - other
6,409

Divested service line
(5,092
)
Energy efficiency
(2,703
)
Other
(520
)
Total increase in enterprise revenues
$
35,984

The increase in enterprise revenues during the year December 31, 2015 , as compared to 2014 , was primarily related to the expansion of our procurement solutions resulting from our acquisition of World Energy in the first quarter of 2015 and an increase in our subscription software packages. This increase in revenue was partially offset by a decrease in enterprise revenue resulting from our December 30, 2014 sale of a component of our business related to our automated demand response offering for agricultural sites, the completion of our 2010 agreement with the MA DOER in August 2014, and a reduction of energy efficiency professional services revenues.
We currently expect software revenues from enterprise customers to increase in fiscal 2016, compared to fiscal 2015. This increase is expected to be partially offset by lower professional services revenues due to the divesture of the World Energy efficiency business in the fourth quarter of fiscal 2015.
Gross Profit and Gross Margin
The following table summarizes our gross profit and gross margin percentages for our EIS and demand response solutions for the years ended December 31, 2015 and 2014 (dollars in thousands):
Year Ended December 31,
2015
 
2014
Gross Profit
 
Gross Margin
 
Gross Profit
 
Gross Margin
$154,533
 
38.7%
 
$214,626
 
45.5%
The decrease in gross profit during the year ended December 31, 2015 as compared to 2014 was primarily due to lower revenue associated with capacity auctions and bilateral contracts in the PJM and ISO-NE demand response programs, lower pricing and fewer MWs enrolled in our Canadian demand response programs in AESO and OPA, and foreign currency exchange losses due to relative weakness of the Canadian and Australian dollars against the US dollar. The decrease was also due to our increased participation in PJM’s extended program in the 2015/2016 delivery year, which resulted in the deferral of profits to the second quarter of 2016, and a change during the fourth quarter of 2014 to ratable revenue recognition and decreased pricing in the AEMO program. The decrease in gross margin during the year ended December 31, 2015, as compared to 2014, was primarily due to a decrease in high-margin revenue associated with capacity auctions and bilateral contracts in the PJM and ISO-NE demand response programs. We currently expect that both our gross profit and gross margin percentage will decrease in 2016 primarily resulting from decreased participation in incremental auctions, although we expect this decrease to be partially offset by higher-margin revenue associated with the growth of our EIS solutions.

36



Operating Expenses
The following table summarizes our operating expenses for the years ended December 31, 2015 and 2014 (dollars in thousands):
 
Year Ended December 31,
 
Percentage
Change
 
2015
 
2014
 
Operating expenses and income:
 
 
 
 
 
Selling and marketing
$
97,175

 
$
76,960

 
26.3
%
General and administrative
110,267

 
97,729

 
12.8
%
Research and development
29,287

 
20,671

 
41.7
%
Gain on sale of service lines

 
(4,791
)
 
N/A

Gain on sale of assets
(2,991
)
 
(2,171
)
 
37.8
%
Goodwill impairment
108,763

 

 
N/A

Total operating expenses and income
$
342,501

 
$
188,398

 
81.8
%
Selling and Marketing Expenses
The following table summarizes our selling and marketing expenses for the years ended December 31, 2015 and 2014 (dollars in thousands):
 
Year Ended December 31,
 
Percentage Change
 
2015
 
2014
 
Payroll and related costs
$
60,946

 
$
49,318

 
23.6
 %
Stock-based compensation
4,316

 
5,488

 
(21.4
)%
Amortization of intangible assets
10,148

 
5,876

 
72.7
 %
Other
21,765

 
16,278

 
33.7
 %
Total selling and marketing expenses
$
97,175

 
$
76,960

 
26.3
 %
The increase in payroll and related costs for the year ended December 31, 2015 as compared to 2014 was primarily due to the full-time employees added as a result of the December 2014 and January 2015 acquisitions of Pulse Energy and World Energy, respectively, as well as an increase in salary rates for full time employees. The number of selling and marketing full-time employees was 306 at December 31, 2014 and 325 at December 31, 2015 . In addition, we experienced an increase in commission expense during the year ended December 31, 2015 due to an increase in enterprise revenues. During 2015, we changed our U.S. paid time off program from a capped program based on service and employment status to an unlimited time off program. This policy change reduced vacation expense related to our sales and marketing employees by approximately $0.6 million compared to the prior year.
The decrease in stock-based compensation for the year ended December 31, 2015 , as compared to 2014 was primarily due to the reversal of $0.8 million of stock-based compensation expense related to the cancellation of awards upon the execution of a separation agreement with 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 year ended December 31, 2015 , as well as the recognition of stock-based compensation for replacement awards issued to certain employees in connection with the acquisition of World Energy.
Other selling and marketing expenses include advertising, marketing, third party commissions, professional services, and a company-wide overhead cost allocation. The increase in other selling and marketing expenses for the year ended December 31, 2015 as compared to 2014 was primarily attributable to third party commissions associated with the World Energy business and higher overhead allocations due to increases in facility costs. Selling and marketing expenses also increased due to higher amortization expense of acquired intangible assets as a result of acquisitions that we completed during fiscal 2014 and our acquisition of World Energy in January 2015. We currently expect a modest increase in sales and marketing expense in fiscal 2016, compared to fiscal 2015, as we invest to support our continued growth and ongoing market expansion.

37



General and Administrative Expenses
The following table summarizes our general and administrative expenses for the years ended December 31, 2015 and 2014 (dollars in thousands):
 
Year Ended December 31,
 
Percentage
Change
 
2015
 
2014
 
Payroll and related costs
$
64,578

 
$
54,273

 
19.0
 %
Stock-based compensation
8,907

 
9,225

 
(3.4
)%
Amortization of intangible assets
1,143

 
1,261

 
(9.4
)%
Other
35,639

 
32,970

 
8.1
 %
Total general and administrative expenses
$
110,267

 
$
97,729

 
12.8
 %
The increase in payroll and related costs for the year ended December 31, 2015 , as compared to 2014 , was primarily attributable to a full year of expenses related to acquisitions completed during 2014, an increase in the number of general and administrative full-time employees from 461 at December 31, 2014 to 553 at December 31, 2015 , the majority of which resulted from the expansion of our global services function, hiring into open positions in our finance and operations organizations, and our acquisition of World Energy in January 2015, which included general and administrative operations personnel. The increase in salaries and wages was partially offset by an increase in reclassifications of payroll costs to cost of revenue for the wages and associated benefits that we pay to our project managers for the performance of their services, and costs related to the delivery of services of our utility bill management solution. Also partially offsetting this increase was the change in our U.S. vacation policy, which reduced vacation expense related to our general and administrative employees by approximately $0.8 million compared to the prior year.
The decrease in stock-based compensation for the year ended December 31, 2015 , as compared 2014 , was primarily due to a decrease in the number and grant date fair value of stock-based awards granted during the period, partially offset by stock-based compensation expense related to awards settled and replaced in connection with our acquisition of World Energy.
Other general and administrative expenses include third party software fees, professional services such as consulting, audit, and external legal, rent and facility-related expenses, and depreciation. The increase in other general and administrative expenses for the year ended December 31, 2015, as compared to 2014, was primarily due to an increase in rent and facility-related expenses related to the expansion of our corporate lease and the acquisition of World Energy leased facilities, an increase in third-party software fees, and increased depreciation expense, primarily related to leasehold improvements. We currently expect a modest decrease in general and administrative expenses in fiscal 2016, compared to fiscal 2015.
Research and Development Expenses
The following table summarizes our research and development expenses for the years ended December 31, 2015 and 2014 (dollars in thousands):
 
 
Year Ended December 31,
 
Percentage
Change
 
 
 
2015
 
2014
 
 
Payroll and related costs
$
16,750

 
$
12,069

 
38.8
%
 
Stock-based compensation
1,362

 
1,350

 
0.9
%
 
Other
11,175

 
7,252

 
54.1
%
 
Total research and development expenses
$
29,287

 
$
20,671

 
41.7
%
During the years ended December 31, 2015 and 2014 , total research and development payroll and related costs totaled $16.8 million and $12.1 million , respectively, which are net of $5.3 million and $6.0 million , respectively, of capitalized internal-use software development costs. 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 161 at December 31, 2014 to 210 at December 31, 2015 , which was due to our increased software development efforts related to features and functionality of our EIS offerings.
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 year ended December 31, 2015 , as compared to 2014 , was primarily attributable to increases in data storage costs and external software costs. We currently expect research and development expenses in fiscal 2016 to be comparable to fiscal 2015 as we develop new technologies and enhance existing technologies to support our continued growth.

38



Gain on Sale of Service Lines
During the three months ended June 30, 2014, we sold Utility Solutions Consulting for $4.8 million, a component of the business that we acquired in connection with our acquisition of Global Energy related to consulting and engineering support services. We recognized a gain from the sale of Utility Solutions Consulting totaling $3.7 million, net of direct transaction costs totaling $0.3 million during the year ended December 31, 2014. In addition, during 2014, we sold Valley Tracker for $1.6 million, a component of our business that we acquired in connection with our acquisition of M2M related to our automated demand response offering designed to ensure demand response customers can connect their equipment remotely and access meter data securely. We recognized a gain from the sale of Valley Tracker totaling $1.1 million during the year ended December 31, 2014. These gains did not recur in 2015.
Gain on Sale of Assets
During 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 2014 and as a result, the sale of this resource was completed resulting in the recognition of a gain on the sale of this asset equal to the purchase price of $2.2 million. During the year ended December 31, 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 .
Goodwill Impairment
As a result of our annual goodwill impairment test conducted as of November 30, 2015, we recognized a $108.8 million goodwill impairment charge for the year ended December 31, 2015. See Critical Accounting Policies in this Item 7 and Note 4 contained in Appendix A to this Annual Report on Form 10-K for further information regarding the impairment charge.
Interest and Other Expense, Net
Interest expense was $8.9 million for the year ended December 31, 2015 compared to $4.7 million in 2014 . This increase was due to interest expense recorded on our convertible notes that were issued in August 2014 and were outstanding for the full year in 2015.
Other expense, net for the year ended December 31, 2015 was $7.4 million , which primarily includes foreign currency losses, offset partially by other income. The increase in foreign currency losses as compared to 2014 was primarily due to the weakening of the Canadian dollar, the Euro and Australian dollar against the U.S. Dollar by 16%, 10% and 11%, respectively, which resulted in foreign currency unrealized and realized losses of $8.0 million for 2015 compared to $4.4 million for the prior year.
Gain on Early Extinguishment of Debt
In December 2015, in privately negotiated transactions, we completed repurchases, in cash, of $33.2 million in aggregate principal amount of the Notes at a weighted average price of 59.2% of principal for a total purchase price of $19.7 million plus accrued interest. We recorded a gain on the extinguishment of the Notes of $9.2 million based on the difference between the carrying amount of the repurchased Notes and the cash consideration.
Income Taxes
We recorded a benefit for income taxes of $10.0 million for the year ended December 31, 2015 that includes approximately $7.9 million related to the impairment of tax-deductible goodwill and a $2.0 million benefit from income taxes due to the release of a portion of the U.S. valuation allowance in connection with our acquisition of World Energy. We recorded a provision for income taxes of $5.9 million for the year ended December 31, 2014 that included a $1.1 million benefit from income taxes due to the release of a portion of the U.S. valuation allowance in connection with the EnTech acquisition during the year ended December 31, 2014 and a $1.1 million expense for deferred income taxes in connection with the sale of Utility Solutions Consulting during the year ended December 31, 2014.
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 year ended December 31, 2015 , there were no material changes in our uncertain tax positions.
Deferred tax assets are reduced by a valuation allowance if, based on the weight of available positive and negative evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. As of December 31, 2015, we have a valuation allowance recorded against certain net domestic and foreign deferred tax assets. Based on our analysis, we have concluded that it is not more likely than not that the majority of our deferred tax assets can be realized and therefore a valuation allowance has been assigned to these deferred tax assets. If we are subsequently able to utilize all or a

39



portion of the deferred tax assets for which a valuation allowance has been established, then we may be required to recognize these deferred tax assets through the reduction of the valuation allowance which could result in a material benefit to our results of operations in the period in which the benefit is determined.
Our effective tax rate for the year ended December 31, 2015 was 5.1% compared to an effective tax rate of 32.9% for the year ended December 31, 2014 .


40




Year Ended December 31, 2014 Compared to Year Ended December 31, 2013
Revenues
The following table summarizes our revenues for the years ended December 31, 2014 and 2013 (dollars in thousands) :
 
Year Ended December 31,
 
Dollar Change
 
Percentage Change
 
2014
 
2013
 
Revenues:
 
 
 
 
 
 
 
Grid operator
$
368,828

 
$
279,258

 
$
89,570

 
32.1
 %
Utility
62,026

 
71,611

 
(9,585
)
 
(13.4
)%
Enterprise
41,094

 
32,591

 
8,503

 
26.1
 %
Total revenues
$
471,948

 
$
383,460

 
$
88,488

 
23.1
 %
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):
 
Revenue Increase (Decrease)
 
December 31, 2013
to
December 31, 2014
PJM
$
71,487

Western Australia (AEMO)
9,222

Alberta (AESO)
5,716

Ireland (SEMO)
4,110

Other (1)
(965
)
Total decrease in grid operator revenues
$
89,570

(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 was primarily due to an increase in pricing and enrolled MW in our PJM and AEMO demand response programs. The increase in AEMO revenue was further driven by our ability to recognize revenues in Western Australia ratably over the delivery period of October 1 through September 30, commencing on October 1, 2014. The increase in revenues from grid operators was also due to revenues recognized from our SEMO demand response program in Ireland, for which revenues were recognized for the first time during the year ended December 31, 2014 as a result of our acquisition of Activation Energy. The increase in revenues from grid operators was also a result of an increase in enrolled MW in certain demand response programs in Alberta, Canada, including ancillary services demand response programs that we did not start participating in until the three month period ended September 30, 2013.
Utility Revenues
The overall decrease in our revenues from utilities was primarily attributable to changes in the following existing operating areas (dollars in thousands):
 
Revenue Increase (Decrease):
 
December 31, 2013
to
December 31, 2014
Southern California Edison (SCE)
$
(5,605
)
Pacific Gas and Electric (PG&E)
1,505

Other (1)
(5,485
)
Total decrease in utility revenues
$
(9,585
)
(1)  
The amounts included in ‘other’ relate to net decreases in various demand response programs, none of which are individually material.
The decrease in utility revenues was primarily due to a decrease of revenues from SCE and PG&E as a result of underperformance penalties and a decrease in enrolled MW.

41



Enterprise Revenues
The increase in revenues from enterprise customers was primarily due to revenues recognized during the year ended December 31, 2014 related to our utility bill management services, which were acquired as part of our acquisition of EnTech, as well as an increase in the number of enterprise customers and consulting engagements. The increase in enterprise revenue was partially offset by the end of certain energy efficiency incentive based programs, from which we derived revenues in 2013, and the completion of our 2010 agreement with the Massachusetts Department of Energy Resources in August 2014.
Gross Profit and Gross Margin
The following table summarizes our gross profit and gross margin percentages for our EIS and demand response solutions for the years ended December 31, 2014 and 2013 (dollars in thousands):
Year Ended December 31,
2014
 
2013
Gross Profit
 
Gross Margin
 
Gross Profit
 
Gross Margin
$214,626
 
45.5%
 
$191,168
 
49.9%
The increase in gross profit was primarily due to an increase in grid operator revenues. Our gross margin percentage decreased primarily due to an increase in PJM revenues from delivering demand response which historically yield a lower gross margin than our other programs and solutions, as well as changes to our overall enterprise customer composition. In addition, our gross margin percentage declined due to a decrease in revenues from our SCE demand response program as a result of a decrease in event performance without associated decreases in costs. These decreases in our gross margin were partially offset by an increase in gross margin in our PG&E demand response program, as revenues related to this program were deferred in 2013 with the associated program costs being expensed.
Operating Expenses and Income
The following table summarizes our operating expenses and income for the years ended December 31, 2014 and 2013 (dollars in thousands):
 
Year Ended December 31,
 
Percentage
Change
 
2014
 
2013
 
Operating expenses and income:
 
 
 
 
 
Selling and marketing
$
76,960

 
$
65,915

 
16.8
%
General and administrative
97,729

 
79,220

 
23.4
%
Research and development
20,671

 
18,317

 
12.9
%
Gain on sale of service lines
(4,791
)
 

 
N/A

Gain on sale of assets
(2,171
)
 

 
N/A

Total operating expenses and income
$
188,398

 
$
163,452

 
15.3
%
Selling and Marketing Expenses
The following table summarizes our selling and marketing expenses for the years ended December 31, 2014 and 2013 (dollars in thousands):
 
Year Ended December 31,
 
Percentage
Change
 
2014
 
2013
 
Payroll and related costs
$
49,318

 
$
40,613

 
21.4
 %
Stock-based compensation
5,488

 
5,829

 
(5.9
)%
Other
22,154

 
19,473

 
13.8
 %
Total selling and marketing expenses
$
76,960

 
$
65,915

 
16.8
 %
The increase in payroll and related costs was primarily due to an increase in the number of selling and marketing full-time employees from 231 at December 31, 2013 to 306 at December 31, 2014, most of which resulted from acquisitions that we completed during 2014. Payroll and other employee related costs were also impacted by a higher cash bonus expense for the year ended December 31, 2014, as a portion of the bonuses earned for the year ended December 31, 2013, or fiscal 2013, were settled in shares of our common stock and recorded in stock-based compensation expense during fiscal 2013. In addition, we experienced an increase in commission expense during 2014 related to our increase in revenues and enterprise customers.

42



The decrease in stock-based compensation was primarily due to the settlement of a portion of the fiscal 2013 bonuses in shares of our common stock.
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 was primarily attributable to a $1.2 million increase in various marketing initiatives, a $0.8 million increase in amortization expense, and a $0.4 million increase in overhead.
General and Administrative Expenses
The following table summarizes our general and administrative expenses for the years ended December 31, 2014 and 2013 (dollars in thousands):
 
Year Ended December 31,
 
Percentage
Change
 
2014
 
2013
 
Payroll and related costs
$
54,273

 
$
45,279

 
19.9
%
Stock-based compensation
9,225

 
8,629

 
6.9
%
Other
34,231

 
25,312

 
35.2
%
Total general and administrative expenses
$
97,729

 
$
79,220

 
23.4
%
The increase in payroll and related costs was primarily attributable to an increase in the number of general and administrative full-time employees from 386 at December 31, 2013 to 461 at December 31, 2014, most of which resulted from acquisitions that we completed during 2014. The increase also resulted from higher overall salary rates and higher bonus expense in 2014 due to a portion of the fiscal 2013 bonuses that were settled in shares of our common stock and recorded in stock-based compensation expense.
The increase in stock-based compensation was primarily due to an increase in the overall grant-date fair value of stock-based awards granted as a result of the increase in our stock price.
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 was primarily attributable to higher professional fees of $6.2 million due to increased accounting, consulting and legal fees incurred related to our recent acquisitions and other matters, including the derivative and class action complaint, and our international tax planning. Other factors that contributed to the increase: $1.2 million of higher software license fees which were partially the result of our increase in headcount, $0.9 million of higher depreciation costs primarily due to a full year of depreciation expense relative to our corporate headquarters, and higher dues, subscriptions and conference costs of approximately $0.5 million. The increase in other general and administrative expenses was partially offset by a $0.5 million decrease in rent expense, as during the first half of 2013 we incurred rent expense for both our prior and current corporate headquarters.
Research and Development Expenses
The following table summarizes our research and development expenses for the years ended December 31, 2014 and 2013 (dollars in thousands):
 
Year Ended December 31,
 
Percentage
Change
 
2014
 
2013
 
Payroll and related costs
$
12,069

 
$
9,977

 
21.0
 %
Stock-based compensation
1,350

 
1,410

 
(4.3
)%
Other
7,252

 
6,930

 
4.6
 %
Total research and development expenses
$
20,671

 
$
18,317

 
12.9
 %
The increase in payroll and related costs was primarily driven by an increase in the number of research and development full-time employees from 99 at December 31, 2013 to 161 at December 31, 2014 and an increase in salary rates per full-time employee. The increase was also attributable to a portion of the fiscal 2013 bonuses that were settled in shares of our common stock and recorded in stock-based compensation expense. Additionally, overall capitalized development internal labor costs increased as we conducted more development activities by leveraging our employee base instead of utilizing third parties. This increase in capitalized internal labor development costs partially offset the increase in payroll and payroll related costs for the year ended December 31, 2014.
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 was primarily attributable to an

43



increase of $0.8 million in the allocation of company-wide overhead costs, which is based on headcount, higher information technology and communication costs of $0.7 million, and higher consulting and professional fees of $0.3 million, partially offset by decreased software and license costs.
Gain on Sale of Service Lines
During 2014, we sold Utility Solutions Consulting, a component of the business that we acquired in connection with our acquisition of Global Energy related to consulting and engineering support services. We recognized a gain from the sale of Utility Solutions Consulting totaling $3.7 million, net of direct transaction costs totaling $0.3 million during the year ended December 31, 2014.
Also during 2014, we sold Valley Tracker, a component of the business that we acquired in connection with our acquisition of M2M for $1.6 million. We recognized a gain of $1.1 million during the year ended December 31, 2014.
Gain on Sale of Assets
During 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 paid the purchase price for the first demand response capacity resource during 2014 and as a result, the sale of this resource was completed resulting in a gain on the sale of this asset equal to the purchase price of $2.2 million.
Interest and Other Expense, Net
Interest expense was $4.7 million for the year ended December 31, 2014 compared to $1.6 million for the year ended December 31, 2013. This increase was largely due to interest expense recorded on the Notes, which was $3.0 million for the year ended December 31, 2014.
Other expense, net for the year ended December 31, 2014 was $3.7 million, which primarily included foreign currency losses offset partially by other income. The $2.4 million increase as compared to the year ended December 31, 2013 was primarily due to the weakening of the Euro and Australian dollar against the U.S. dollar, which resulted in a loss of $4.4 million for the year ended December 31, 2014, as compared to a $1.7 million loss for the year ended December 31, 2013.
Income Taxes
We recorded a provision for income taxes of $5.9 million and $2.6 million for the years ended December 31, 2014 and 2013, respectively. The key components of our provision for income taxes include estimated foreign taxes on profits earned by our foreign subsidiaries who have no available net operating loss carryforwards; certain state taxes for jurisdictions where we have utilized all available net operating loss carryforwards; and amortization of tax deductible goodwill, which generates a deferred tax liability that cannot be offset by net operating losses or other deferred tax assets since its reversal is considered indefinite in nature. Additionally, the provision for income taxes for the year ended December 31, 2014 includes a $1.1 million benefit from deferred income taxes due to the release of a portion of the U.S. valuation allowance in connection with the EnTech acquisition and a $1.1 million provision for deferred income taxes in connection with the sale of Utility Solutions Consulting.
Our effective tax rate for the year ended December 31, 2014 was 32.9% compared to an effective tax rate of 10.7% for the year ended December 31, 2013.
Liquidity and Capital Resources
Overview
We have generated significant cumulative losses since inception. As of December 31, 2015 , we had an accumulated deficit of $254.3 million . As of December 31, 2015 , our principal sources of liquidity were cash and cash equivalents totaling $138.1 million , and our $30 million senior secured revolving credit facility. During 2015, our cash decreased by $116.3 million from the December 31, 2014 balance of $254.4 million . The reduction of cash during 2015 was principally driven by the $77.2 million of cash used to acquire World Energy, net of cash acquired, $23.6 million of cash used for the purchase of property and equipment, including $8.4 million of capitalized internal-use software development costs, $19.7 million of cash used to retire $33.2 million of principal of the Notes; partially offset by $3.5 million of cash generated from operating activities.

44



Cash Flows
The following table summarizes our cash flows for the years ended December 31, 2015 , 2014 and 2013 (dollars in thousands):
 
Year Ended December 31,
 
2015
 
2014
 
2013
Cash flows provided by operating activities
$
3,480

 
$
60,439

 
$
79,464

Cash flows used in investing activities
(93,909
)
 
(74,422
)
 
(37,889
)
Cash flows (used in) provided by financing activities
(22,504
)
 
120,865

 
(6,804
)
Effects of exchange rate changes on cash and cash equivalents
(3,298
)
 
(1,720
)
 
(623
)
Net change in cash and cash equivalents
$
(116,231
)
 
$
105,162

 
$
34,148

The following table presents our net cash from operating activities (dollars in thousands):
 
Year Ended December 31,
 
2015
 
2014
 
2013
Net (loss) income
$
(185,118
)
 
$
11,997

 
$
22,088

Goodwill impairment
108,763

 

 

Stock-based compensation expense
14,085

 
16,063

 
15,868

Gain on settlement of convertible senior notes
(9,230
)
 

 

Other non-cash items (1)
42,684

 
39,770

 
31,634

Gains on sales of service lines and assets
(2,991
)
 
(6,962
)
 

Change in working capital
35,287

 
(429
)
 
9,874

Net cash (used in) provided by operating activities
$
3,480

 
$
60,439

 
$
79,464

(1) Other non-cash items in 2015 , 2014 and 2013 primarily consist of depreciation and amortization, impairment charges on long lived assets, unrealized foreign exchange translation losses, deferred taxes and non-cash interest expense.
Net cash provided by operating activities was $3.5 million in 2015 as compared to net cash provided by operating activities in 2014 of $60.4 million . The decrease in net cash provided by operating activities was due to increased net losses in 2015 as compared to net income in 2014 , partially offset by higher non-cash items and a $35.7 million decrease in working capital in 2015 as compared to 2014.
Cash flows from working capital for the year ended December 31, 2015 were primarily due to an increase in deferred revenue of $39.8 million , a decrease in unbilled revenue of $27.3 million , partially offset by an increase in capitalized incremental direct customer contract costs of $25.8 million . These changes were primarily driven by our increased participation in the PJM extended program, which impacted the timing of revenue recognition compared to the prior year. In addition, cash flows from working capital are due to an increase in accrued capacity payments of $13.1 million , partially offset by a decrease of $19.8 million in accounts payable, accrued expenses and other current liabilities.
Cash provided by operating activities for the year ended December 31, 2014 was approximately $60.4 million and was driven by net income plus stock-based compensation and other non-cash items. Cash used by working capital consisted of an increase of $31.1 million in unbilled revenues, primarily related to the PJM demand response market, a decrease of $8.1 million in deferred revenue, and an increase in accounts receivable of $3.0 million . This activity was partially offset by an increase of $20.3 million in accounts payable, accrued expenses and other current liabilities, an increase in accrued capacity payments of $16.3 million , an increase of $3.6 million in accrued payroll and related expenses, and a decrease in capitalized incremental direct customer contract costs of $2.5 million .
Cash provided by operating activities for the year ended December 31, 2013 was approximately $79.5 million and was driven by net income plus stock-based compensation and other non-cash items and $9.9 million of net cash provided by working capital. Cash provided by working capital consisted primarily of an increase in accrued capacity payments of $28.5 million , partially offset by an increase of $21.4 million in unbilled revenues primarily related to the PJM demand response program.

45



The following table presents our net cash from investing activities (dollars in thousands):
 
Year Ended December 31,
 
2015
 
2014
 
2013
Payments for investments and acquisitions, net of cash acquired
$
(77,465
)
 
$
(54,195
)
 
$

Capital expenditures
(23,629
)
 
(25,553
)
 
(36,663
)
Proceeds on sales of service lines and assets
3,937

 
8,046

 

Other investing activities
$
3,248

 
$
(2,720
)
 
$
(1,226
)
Net cash used in investing activities
$
(93,909
)
 
$
(74,422
)
 
$
(37,889
)
Cash used in investing activities was $93.9 million for the year ended December 31, 2015 . During the year ended December 31, 2015 , we made payments, net of cash acquired of $77.5 million for acquisitions (primarily World Energy). We made $23.6 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 production equipment expenditures due to an increase in our installed customer base. We also made capital expenditures for office equipment, furniture and fixtures, and leasehold improvements associated with the expansion of our corporate office space. Cash used in investing activities for the year ended December 31, 2015 was partially offset by $3.9 million in cash proceeds from the sale of two contractual demand response capacity resources related to an open market demand response program, and the sale of the energy efficiency services business acquired as part of our acquisition of World Energy.
Cash used in investing activities was $74.4 million for the year ended December 31, 2014 . During the year ended December 31, 2014 , we made payments, net of cash acquired of $54.2 million for business acquisitions and investments. We made $25.6 million of capital expenditures, primarily related to software additions, production equipment, office equipment, furniture and fixtures, and leasehold improvements associated with leasing new office space. Cash used in investing activities for the year ended December 31, 2014 was partially offset by $5.9 million and $2.2 million in cash proceeds from our sale of service lines and our sale of assets, respectively.
Cash used in investing activities was $37.9 million for the year ended December 31, 2013. During the year ended December 31, 2013, we incurred $36.7 million in capital expenditures primarily related to the build-out of our corporate headquarters, purchases of production equipment and capitalized internal use software costs.
The following table presents our cash flows (used in) provide by financing activities (dollars in thousands):
 
Year Ended December 31,
 
2015
 
2014
 
2013
Proceeds from convertible notes
$

 
$
160,000

 
$

Payments made to repurchase and retire convertible notes
(19,733
)
 

 

Debt issuance costs
400

 
(4,724
)
 

Cash used to purchase common stock, net
(3,171
)
 
(35,036
)
 
(7,399
)
Excess tax benefit related to exercise of options, restricted stock and restricted stock units

 
625

 
595

Net cash (used in) provided by financing activities
$
(22,504
)
 
$
120,865

 
$
(6,804
)
Cash (used in) provided by financing activities was $(22.5) million , $120.9 million and $(6.8) million for the years ended December 31, 2015 , 2014 and 2013 , respectively. For the year ended December 31, 2015, cash used in financing activities includes payments of $19.7 million for open-market purchases of the Notes. We also acquired $4.3 million of common stock related to employee restricted stock minimum tax withholdings and received $1.1 million of cash for the exercise of stock options.
For the year ended December 31, 2014, cash provided by financing activities primarily consisted of the net proceeds from the sale and issuance of the Notes in August 2014 totaling $155.3 million, less $30.0 million of the net proceeds which were used to repurchase shares of our common stock. We realized $1.6 million of cash from the exercise of stock options, recognized an excess tax benefit related to the exercise of stock options, restricted stock and restricted stock units of $0.6 million, and made payments of approximately $6.6 million for employee restricted stock minimum tax withholdings.
During the year ended December 31, 2013, cash used in financing activities primarily consisted of payments made to repurchase shares of our common stock of $9.5 million, as well as employee restricted stock minimum tax withholding

46



payments of $0.3 million, partially offset by proceeds that we received from exercises of options to purchase shares of our common stock of $2.4 million.
Borrowings and Credit Arrangements
Credit Agreement
On August 11, 2014, we entered into a $30 million senior secured revolving credit facility, or the 2014 credit facility, the full amount of which may be available for issuances of letters of credit, pursuant to a loan and security agreement with Silicon Valley Bank, or SVB. The 2014 credit facility was subsequently amended on October 23, 2014. On August 6, 2015, we and SVB entered into a second amendment to the 2014 credit facility to extend the termination date to August 9, 2016. The 2014 credit facility is subject to continued covenant compliance and borrowing base requirements. As of December 31, 2015 , we had no outstanding borrowings and had outstanding letters of credit totaling $22.4 million under the 2014 credit facility. For further discussion of the 2014 credit facility, please refer to Note 9 contained in Appendix A to this Annual Report on Form 10-K.
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 the Notes, due August 15, 2019 in an offering exempt from registration under the Securities Act of 1933, as amended. The Notes include 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 the Notes. However, because we received approval at the annual meeting of stockholders held on May 27, 2015, we may elect to settle conversions of the 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.
Upon issuance of the Notes, we accounted 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 using the effective interest method. In addition, transaction costs were 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. In addition, during 2015 we were reimbursed for $0.4 million of transaction costs, which were allocated to the liability component. The transaction costs allocated to the liability are being amortized to interest expense on a straight-line basis over a five year period. As discussed in Note 9, we adopted ASU 2015-03, Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, as of December 31, 2015. As a result of adopting this accounting standard, we reclassified $687 and $3,131 of unamortized deferred issuance costs from current assets and other assets, respectively, to a direct reduction of the debt obligation for December 31, 2014. As a result, the adjusted carrying amount of the Notes on the balance sheet, net of unamortized discounts and offering expenses, were $111,254 and $135,090 as of December 31, 2015 and December 31, 2014, respectively.
As noted above, in December 2015, in privately negotiated transactions, we completed repurchases in cash of $33.2 million in aggregate principal amount of the outstanding Notes, at a weighted average price of 59.2% of principal for a total purchase price of $19.7 million plus accrued interest. We recorded a gain on the extinguishment of the Notes of $9.2 million based on the difference between the carrying amount of the repurchased Notes and the cash consideration.
We may from time to time seek to retire or purchase additional outstanding debt through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.
For further discussion of the Notes, please refer to Note 9 contained in Appendix A to this Annual Report on Form 10-K.
Interest expense under the Notes is as follows (dollars in thousands):
 
Year Ended December 31, 2015
 
Year Ended December 31, 2014
Accretion of debt discount
$
4,064

 
$
1,474

Amortization of deferred financing costs
635

 
238

Non-cash interest expense
4,699

 
1,712

2.25% accrued interest
3,532

 
1,330

Total interest expense from the Notes
$
8,231

 
$
3,042


47



Contingent Earn-Out Payments
In connection with our acquisitions of Entelios AG, or Entelios, Activation Energy DSU Limited, or Activation Energy, Universal Load Center Co. Ltd., or ULC, and Pulse Energy, we agreed to pay additional purchase price consideration, or earn-out payments, on the achievement of certain milestones. See Note 2 to our consolidated financial statements contained in Appendix A to this Annual Report on Form 10-K.
The earn-out payment for Entelios was based on the achievement of certain minimum defined profit metrics for the years ended December 31, 2014 and 2015. We did not achieve the 2015 or 2014 milestones resulting in no additional payouts.
The earn-out payment for Activation Energy was based on the achievement of certain minimum defined MW enrollment as well as profit metrics for the years ended December 31, 2014 and 2015. The earn-out provided a maximum payment of 1.0 million Euros ($1.4 million), including up to 0.3 million Euros and up to 0.7 million Euros related to the achievement of the defined profit metrics for the years ended December 31, 2014 and 2015, respectively. In January 2015, following the full achievement of Activation Energy's milestone for 2014, we disbursed 0.3 million Euros ($0.3 million) to the former Activation Energy shareholders. In February 2016, following the full achievement of Activation Energy’s milestone for 2015, we disbursed 0.7 million Euros ($0.8 million) to the former Activation Energy shareholders.
In connection with our acquisition of ULC in April 2014, we agreed to pay a maximum of $1.8 million in earn-out payments. The earn-out payments, if any, are be based on the achievement of certain defined market legislation and certain operational metrics. The market legislation metric was achieved in May 2014, with $0.3 million paid out over 2014 and 2015. The remaining $1.5 million is payable to those former ULC stockholders who remain employed as of the time of payment, if such operational metrics are achieved. We concluded these payments should be accounted for as compensation arrangements and expensed ratably over the applicable service period, if achievement is deemed probable. Through January 2016 we have paid $0.3 million for the achievement of certain operational metrics.
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, and would be paid in the form of our common stock, except for a small portion of the payment that would be paid in cash, if such targets are reached. 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 weighted probability assumptions of these outcomes. Because the contingent consideration is expected to be primarily 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 has been estimated to equal $1.6 million and will not be re-measured subsequent to the acquisition date due to equity classification.
Capital Spending
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 $23.6 million , $25.6 million and $36.7 million during the years ended December 31, 2015 , 2014 and 2013 , respectively. We expect our capital expenditures for 2016 to modestly increase over our capital expenditures for 2015 due primarily to increased site implementations.
Off-Balance Sheet Arrangements
As of December 31, 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 December 31, 2015 , we had outstanding letters of credit totaling $22.4 million . For information on these commitments and contingent obligations, see “Liquidity and Capital Resources—Borrowings and Credit Arrangements” above and Note  9 to our consolidated financial statements contained herein.

48



Contractual Obligations
Information regarding our significant contractual obligations is set forth in the following table and includes the operating lease arrangement described above. Payments due by period have been presented based on payments due subsequent to December 31, 2015 (in millions):
 
Payments Due By Period
Contractual Obligations
Total
 
Less than
1 Year
 
1-3
Years
 
3-5
Years
 
More than
5 Years
Convertible senior notes
$
126.8

 
$

 
$
126.8

 
$

 
$

Interest on convertible senior notes
10.3

 
2.9

 
7.4

 

 

Operating lease obligations
33.4

 
7.5

 
14.6

 
10.6

 
0.7

Total contractual obligations
$
170.5

 
$
10.4

 
$
148.8

 
$
10.6

 
$
0.7

The future payments related to uncertain tax positions have not been presented in the table above due to the uncertainty of the amounts and timing of cash settlement with the taxing authorities. See Note 12 to our consolidated financial statements contained in Appendix A to this Annual Report on Form 10-K.
Our fixed interest payments at 2.25% relating to the Notes, which mature on August 19, 2019, are presented in the table above.
Our operating lease obligations relate primarily to the leases of our corporate headquarters in Boston, Massachusetts and our offices in Worcester, San Francisco, California; Baltimore, Maryland; Boise, Idaho, Vancouver, Canada; Australia, United Kingdom, Germany, Switzerland, Ireland, South Korea, Brazil and India.
In connection with our acquisition of M2M, we are required to pay additional consideration that was deferred at the date of the acquisition. This deferred purchase price consideration of $7.0 million will be paid upon the earlier of the satisfaction of certain conditions contained in the definitive agreement or seven years after the acquisition date of January 25, 2011. The deferred purchase price consideration is not subject to adjustment or forfeiture. We recorded our estimate of the fair value of the deferred purchase price consideration based on the evaluation of the likelihood of the achievement of the contractual conditions that would result in the payment of the deferred purchase price consideration prior to seven years from the acquisition date and weighted probability assumptions of these outcomes. The cash portion of the deferred purchase price consideration has been recorded as a liability, initially estimated to be less than $0.5 million, discounted to reflect the time value of money. As the milestone payment date approaches, the fair value of this liability will increase. The fair value of the deferred purchase price consideration of $3.4 million, related to the 254,654 shares of common stock to be issued upon the milestone payment date, has been classified as additional paid-in capital within stockholders’ equity. With respect to the cash portion of the deferred purchase price consideration, the increase in fair value is recorded as an expense in our accompanying consolidated statements of operations. At December 31, 2015 , the liability was recorded at $0.6 million . The deferred purchase price consideration to be paid in shares meets the requirements of an equity instrument and, accordingly, will not be remeasured at fair value each reporting period. This acquisition had no contingent consideration or earn-out payments.
As of December 31, 2015 , we had no borrowings, but had outstanding letters of credit totaling $22.4 million under the 2014 credit facility. As of December 31, 2015 , we had $7.6 million available under the 2014 credit facility for future borrowings or issuances of additional letters of credit.
We typically grant certain customers a limited warranty that guarantees that our hardware products will substantially conform to current specifications for one year from the delivery date. Based on our operating history, the liability associated with product warranties has been determined to be nominal. We also indemnify our customers from third-party claims relating to the intended use of our products. Pursuant to these clauses, we indemnify and agree to pay any judgment or settlement relating to a claim.
We guarantee the electric capacity we have committed to deliver pursuant to certain long-term contracts. Such guarantees may be secured by cash or letters of credit. Performance guarantees as of December 31, 2015 and 2014 were $20.2 million and $23.7 million , respectively. For the year ended December 31, 2015 , these performance guarantees included deposits held by certain customers of $0.1 million .
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) income attributable to EnerNOC, non-GAAP net (loss) income per share attributable to EnerNOC, 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.

49



The GAAP measure most comparable to non-GAAP net (loss) income attributable to EnerNOC is GAAP net (loss) income attributable to EnerNOC; the GAAP measure most comparable to non-GAAP net (loss) income per share attributable to EnerNOC is GAAP net (loss) income per share attributable to EnerNOC; the GAAP measure most comparable to adjusted EBITDA is GAAP net (loss) income attributable to EnerNOC; and the GAAP measure most comparable to free cash flow is cash flows provided by operating activities. Reconciliations of each of these non-GAAP financial measures to the corresponding GAAP measures are included below.
Use and Economic Substance of Non-GAAP Financial Measures
Management uses these non-GAAP measures when evaluating our operating performance and for internal planning and forecasting purposes. Management believes that such measures help indicate underlying trends in our business, are important in comparing current results with prior period results, and are useful to investors and financial analysts in assessing our operating performance. For example, management considers non-GAAP net (loss) income attributable to EnerNOC to be an important indicator of the overall performance because it eliminates the effects of events that are either not part of our core operations or are non-cash compensation expenses. In addition, management considers adjusted EBITDA to be an important indicator of our operational strength and the performance of our business and a good measure of our historical operating trend. Moreover, management considers free cash flow to be an important indicator of our operating trend and the 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) income attributable to EnerNOC as net (loss) income attributable to EnerNOC 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, divestitures, or restructuring activities, impairment of goodwill, gains on early extinguishment of debt, and amortization expenses related to acquisition-related intangible assets, net of related tax effects.
Management defines adjusted EBITDA as net (loss) income attributable to EnerNOC excluding depreciation, amortization, asset impairments, stock-based compensation, direct and incremental expenses related to acquisitions, divestitures and restructuring activities, impairment of goodwill, gains on early extinguishment of debt, interest expense, income taxes and other expense, net.
Management defines free cash flow as net cash provided by operating activities, less capital expenditures, plus net cash provided by 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.
Material Limitations Associated with the Use of Non-GAAP Financial Measures
Non-GAAP net (loss) income attributable to EnerNOC, non-GAAP net (loss) income per share attributable to EnerNOC, 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) Income Attributable to EnerNOC and Non-GAAP Net (Loss) Income per Share Attributable to EnerNOC
Net loss for the year ended December 31, 2015 was $(185.1) million , or $(6.51) per both basic and per diluted share, compared to net income of $12.1 million , or $0.43 per basic share and $0.42 per diluted share for the year ended December 31, 2014 , and net income of $22.1 million , or $0.80 per basic share and $0.76 per diluted share for the year ended December 31, 2013 . Non-GAAP net loss for the year ended December 31, 2015 was $(56.3) million , or $(1.98) per diluted share, compared to non-GAAP net income of $39.9 million , or $1.39 per diluted share for the year ended December 31, 2014 , and non-GAAP net income of $45.0 million or $1.55 per diluted share for the year ended December 31, 2013 .

50



The reconciliation of GAAP net (loss) income attributable to EnerNOC to non-GAAP net (loss) income attributable to EnerNOC is set forth below (dollars in thousands, except share and per share data):
 
Year Ended December 31,
 
2015
 
2014
 
2013
GAAP net (loss) income attributable to EnerNOC
$
(185,075
)
 
$
12,094

 
$
22,088

Adjustments to reconcile GAAP net (loss) income to Non-GAAP net (loss) income:
 
 
 
 
 
Stock–based compensation expense
14,585

 
16,063

 
15,868

Amortization of acquired intangible assets
15,252

 
9,252

 
7,029

Direct and incremental expenses related to acquisitions, divestitures, and restructuring (1)
3,222

 
3,550

 

Impairment of goodwill and intangible assets
108,763

 

 

Debt discount portion of interest expense related to convertible notes
4,064

 
1,474

 

Gain on early extinguishment of debt
(9,230
)
 


 


Tax impact of items listed above
(7,900
)
 
(2,486
)
 

Non-GAAP net (loss) income attributable to EnerNOC
$
(56,319
)
 
$
39,947

 
$
44,985

 
 
 
 
 
 
GAAP net (loss) income per diluted share
$
(6.51
)

$
0.42

 
$
0.76

Non-GAAP net (loss) income per diluted share
$
(1.98
)
 
$
1.39

 
$
1.55

(1) Includes costs for third party professional services (legal, accounting, valuation) and severance.
Adjusted EBITDA
Adjusted EBITDA was $(21.1) million , $76.4 million and $71.4 million for the years ended December 31, 2015 , 2014 and 2013 , respectively.
The reconciliation of net (loss) income to adjusted EBITDA is set forth below (dollars in thousands):
 
Year Ended December 31,
 
2015
 
2014
 
2013
Net (loss) income attributable to EnerNOC
$
(185,075
)
 
$
12,094

 
$
22,088

Reconciling Adjustments:
 
 
 
 
 
Depreciation and amortization (1)
40,287

 
31,417

 
27,844

Stock-based compensation expense
14,585

 
16,063

 
15,868

Direct and incremental expenses related to acquisitions, divestitures and restructuring (2)
3,222

 
3,550

 

Impairment of goodwill and intangible assets
108,763

 

 

Gain on extinguishment of debt
(9,230
)
 

 

Other expense, net (3)
7,444

 
3,699

 
1,342

Interest expense
8,946

 
4,656

 
1,646

(Benefit from) Provision for income tax (4)
(10,010
)
 
4,891

 
2,640

Adjusted EBITDA
$
(21,068
)
 
$
76,370

 
$
71,428

(1)  
Includes impairments to fixed assets and other long term assets recorded during the year ended December 31, 2015 .
(2)  
Includes costs for third party professional services (legal, accounting, valuation) and severance.
(3)  
Other expense, net primarily relates to foreign currency (gains) losses.
(4)  
Excludes discrete tax provision of $985 recorded during the year ended December 31, 2014 related to the sale of the USC business component.

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Free Cash Flow
Cash flows from operating activities were $3.5 million , $60.4 million and $79.5 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. We had $(16.2) million , $42.9 million and $42.8 million of free cash flow for the years ended December 31, 2015 , 2014 and 2013 , respectively. The reconciliation of cash flows from operating activities to free cash flow is set forth below (dollars in thousands):

Year Ended December 31,

2015
 
2014
 
2013
Net cash provided by operating activities
$
3,480

 
$
60,439

 
$
79,464

Add: Net cash provided by the sale of assets or disposals of components of an entity
3,937

 
8,046

 

Subtract: Purchases of property and equipment
(23,629
)
 
(25,553
)
 
(36,663
)