EnerNOC, Inc.
ENERNOC INC (Form: 10-K, Received: 03/16/2017 06:07:51)


 
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, 2016
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 2016 , the last business day of the Registrant’s second quarter of the fiscal year ended December 31, 2016 , was approximately $ 151.7 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 6, 2017 was 30,430,621 .
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for its 2017 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, 2016 , 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, 2016
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
 
 
 




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 15, 2017 .
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.




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 demand response solutions and energy intelligence software, or EIS, to enterprises, utilities, and electric power grid operators.
Demand Response Solutions
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 commercial, institutional and industrial end-users of energy, or 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 global 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. 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, electric power grid operator, and the C&I end-user. Performance expectations, as well as curtailment plans, are all managed through a single platform.
We receive payments from our utility customers and electric power grid operators for providing our demand response solutions, and we share these 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.
In 2016, 2015, and 2014, 83.3% , 79.5% , and 91.7% of our revenue, respectively, was derived from sales of our demand response solutions.
Energy Intelligence Software
Our EIS includes our subscription software, energy procurement solutions, and professional services. We initiated a restructuring plan in 2016 that was designed to materially reduce our operating expenses primarily related to our subscription-based software business and reduce our software organization in order to more appropriately match the current market opportunity. As a result, we expect revenue from our subscription software to be relatively flat for the year ended December 31, 2017 as compared to 2016.
Subscription Software
Our EIS provides enterprises with a Software-as-a-Service, or SaaS, energy management application that enables them to address their most important energy challenges, including:
energy cost visualization, budgets, forecasts, and accruals, which provide our enterprise customers with the ability to develop accurate energy budgets and track cost accruals;
utility bill validation and payment, 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;
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;
energy project tracking, which allows our enterprise customers to track the progress and impact of savings measures that have been implemented;
reporting for energy and sustainability disclosure and compliance, 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; and

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peak energy demand and the related cost impacts, 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.
Our EIS helps enterprises 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 built systems to collect and process several forms of data, including real-time energy interval data, tens of thousands of utility tariffs, real 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.
Energy Procurement Solutions
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 EIS brings together real-time and future market data, current customer contracts, a customer's risk profile, and a broad footprint of suppliers to a single marketplace. Our procurement platform allows our enterprise and utility customers to:
obtain the best price for energy when going to market by having over 300 unique energy suppliers compete for their business in an auction process;
identify opportunities to go to market based on their current contracts, their risk profile, and current market conditions;
manage energy contracts in a single location providing a more effective way to monitor expirations and current market exposure; and
better understand risk in their energy portfolio.
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.
Professional Services
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 demand response solutions and EIS. 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 demand response solutions and EIS 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 employees. 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.

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Developing Markets for Our Demand Response and EIS
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 demand response solutions and full suite of EIS offerings. We have two primary approaches to developing markets for our demand response solutions and EIS. First, we are helping customers understand the materiality of energy and sustainability to the future of their businesses. As C&I end-users and enterprises continue to better understand the material impacts of energy and sustainability, we are confident they will 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 took a significant step in our effort to realize efficiencies in our business by managing our operations in two distinct segments - Demand Response and Software. See Note 2 to our consolidated financial statements contained in Appendix A to this Annual Report on Form 10-K. We believe this realignment has created and will continue to create efficiencies in our overall business as a result of enhanced management focus within each segment on performance and key performance drivers. In addition, in fiscal 2016, we initiated a restructuring plan designed to materially reduce our operating expenses primarily related to our subscription-based software. We believe these reductions will create efficiencies that will improve the performance of the Software operating segment. Additional opportunities to realize efficiencies in our business have arisen and may continue to 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 investments to drive the growth of our demand response solutions and EIS, and we plan to manage the business accordingly.
Technology and Operations
We are focused on delivering industry-leading demand response solutions and EIS. Our technology can be broken down into two primary components: our NOC and our EIS platform.
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 our demand response programs, 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, Canada, Ireland, Japan, New Zealand, South Korea, and the United Kingdom.
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.
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.
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.

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Sales and Marketing
As of December 31, 2016 , our sales and marketing team consisted of 193 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 solutions. 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, 2016 , our research and development team consisted of 101 employees. Our research and development team is responsible for developing and enhancing our existing demand response solutions and EIS, as well as the engineering and design of new functionality.
Our research and development expenses were approximately $26.3 million , $29.3 million , and $20.7 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. During the years ended December 31, 2016 , 2015 and 2014 , we capitalized internal software development costs of $9.8 million , $8.4 million , and $6.0 million , respectively, and these amounts are included as software in property and equipment.
Customers
Electric Power Grid Operators
The electric power grid operators to which we provide our demand response solutions include PJM Interconnection, or PJM, the Australian Energy Market Operator, or AEMO, which was formerly known as the Australian Independent Market Operator Wholesale Electricity Market, Korea Power Exchange, or KPX, 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.
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, Southern California Edison, Tennessee Valley Authority 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.

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Enterprises
Our 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 is a representative list of our enterprise customers as of December 31, 2016 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
 
 
The Division of Capital Asset Management and Maintenance of the Commonwealth of Massachusetts
 
 
 
 
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.
Competition
We face competition from other providers of demand response solutions and EIS, 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 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.
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 demand response solutions being offered; and
the financial stability, historical performance levels and overall experience of the provider.
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.
Our primary competitors include Schneider Electric, Ecova, Siemens, 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 demand response and EIS sectors give us an advantage when competing for customers. In addition, 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

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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.
Regulatory
We provide our demand response solutions and EIS in competitive wholesale and retail electricity markets and in traditionally regulated electricity markets. Regulations and public policies within both types of markets impact whether, and how quickly, customers may adopt our solutions, the prices we can charge and profit margins we can earn, the MW we can enroll in certain demand response programs, the procurement solutions we can offer to wholesale and retail customers, 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.
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 eligibility or suitability of certain demand response resources for particular programs, and 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, regulations can impact the volume of demand response and capacity resources that are needed to be procured by utility or wholesale market operators, which can affect market clearing prices for our demand response resources. In addition, 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 assessments, we may alter our participation in both potential new and existing markets in which we currently offer our demand response solutions, including an assessment 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, 2016 , we held 23 patents in the United States, Canada and Australia, and had 57 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

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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, 2016 , 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 demand response and EIS 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 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 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. Historically, the revenue earned from this product has been recognized at the end of the delivery year in May. Under the new revenue recognition rules that we adopted on January 1, 2017, revenue will more closely align with the service delivery period, which is concentrated in the warmer months of the year. For further discussion of revenue recognition and our adoption of the new revenue recognition rules, please refer to Note 1 contained in Appendix A to this Annual Report on Form 10-K.
Employees
As of December 31, 2016 , we had 1,077 full-time employees, including 341 charged to cost of revenues, 193 in sales and marketing, 101 in research and development and 442 in general and administrative, including operations. Of these full-time employees, 532 were located in the United States with 355 located in New England, 29 located in California, and the remainder located in other areas across the United States. In addition, we had 272 full-time employees located in Brazil, 115 located in India, 5 located in Canada, 32 located in Germany, 25 located in Australia, 25 located in the United Kingdom and 71 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.
Segments
Effective January 1, 2016, we began operating two distinct business units: Demand Response and Software, each with dedicated sales, marketing, and operations functions. See Note 2 in Appendix A to this Annual Report on Form 10-K for a detailed report for each segment.
Geographic Information
For a description of our revenue and long-lived assets by geographic location, see Note 2 in Appendix A to this Annual Report on Form 10-K.
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

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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 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, 2016, we had an accumulated deficit of $304.7 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 demand response solutions and EIS, 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 demand response solutions and EIS or a market otherwise fails to develop for our demand response and EIS solutions, our ability to sell our demand response solutions and EIS and grow our business could be limited.
Our future success depends on continued commercial acceptance of our demand response solutions and EIS. The market for our demand response solutions and EIS is relatively new. If we are unable to educate our potential customers about the advantages of our demand response solutions and EIS over competing products and services, or if our existing customers no longer rely on our demand response solutions and EIS, our ability to sell our demand response solutions and EIS 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 demand response solutions and EIS that address those needs. If the market for our demand response solutions and EIS 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 demand response solutions and EIS.
The market for our demand response solutions and EIS 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 demand response solutions and EIS 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 offerings and enhance our existing demand response solutions and EIS. Initiatives to develop new demand response solutions and EIS 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 demand response solutions and EIS. In addition, software

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supporting our demand response solutions and EIS 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 offerings or enhancements to our existing demand response solutions and EIS on a timely basis, or if the market does not accept our new or enhanced demand response solutions and EIS, 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 demand response solutions and EIS 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.
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 demand response solutions and EIS.
A substantial majority of our revenues are and have been generated from open market program sales 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, 2016, 2015 and 2014, revenues generated from open market sales to PJM, an electric power grid operator, accounted for 44% , 40% and 52% , 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.
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 and utilities 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 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 demand response solutions and EIS 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

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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;
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.
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, 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 business by reducing our revenues and profit margins, thereby having a material adverse effect on our results of operations and financial condition.
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.

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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.
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 demand response solutions and EIS. 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.
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.

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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.
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.
If the software systems we use in providing our demand response solutions and EIS 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 demand response solutions and EIS, 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 demand response solutions and EIS, 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 demand response solutions and EIS need to interface with these non-standard systems in order to gather 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.

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We may face certain product liability or warranty claims if we disrupt our customers’ networks or applications, or if our demand response solutions and EIS 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 demand response solutions and EIS, 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 demand response solutions and EIS 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 demand response solutions and EIS, 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. 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 demand response solutions and EIS.
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 demand response solutions and EIS, 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 demand response solutions and EIS. 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

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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 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 demand response solutions and EIS;
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
issuance of potentially dilutive equity securities and/or the incurrence of debt or contingent liabilities, which could harm our financial condition.

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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 results of operations.
As a result of our annual goodwill impairment test conducted as of November 30, 2016, we determined that the fair value of each of our reporting units exceeded the carrying amount of the reporting unit's net assets, including goodwill. Therefore, the second step of the goodwill impairment test was not required. Our annual goodwill impairment test conducted as of November 30, 2015 resulted in the recognition of a $108.8 million goodwill impairment charge. As of December 31, 2016 we had approximately $72.4 million of goodwill and intangible assets on our consolidated balance sheet.
As a result of our adoption of the new revenue recognition guidance under Accounting Standards Codification 606, Revenue from Contracts with Customers , or ASC 606, we anticipate recording an increase to our Energy Procurement Solutions reporting unit’s net assets. The anticipated increase in net assets is expected to be greater than the excess fair value over the carrying value of net assets as of our annual impairment test on November 30, 2016. Therefore, we expect to perform an interim impairment test for the Energy Procurement Solutions reporting unit during the first quarter of 2017. Based on the fair value assumptions used in our November 30, 2016 impairment test, we are anticipating recording a goodwill impairment charge in the first quarter of 2017 of up to $5.8 million related to this reporting unit, which is part of the Software segment. Please see Note 5 to our consolidated financial statements contained in Appendix A to this Annual Report on Form 10-K for further information.
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, Demand Response and Software, 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 unprofitable, the risk of additional liabilities associated with these efforts, and the allocation of our operations, sales and marketing, research and development, general and administrative, and financial resources. 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

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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 recognizing revenues from those MW, under the current revenue recognition guidance 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 demand response solutions and EIS, 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 demand response solutions and EIS, enhancements to our existing demand response solutions and EIS, 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 Convertible 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 Convertible Notes at maturity, to raise the funds necessary to settle conversions of the Convertible Notes or to repurchase the Convertible 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 Convertible Notes.
At maturity in 2019, the entire outstanding principal amount of the Convertible Notes will become due and payable by us. Holders of the Convertible Notes will also have the right to require us to repurchase their Convertible Notes upon the occurrence of a fundamental change at a repurchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest, if any. In addition, upon conversion of the Convertible 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 Convertible 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 Convertible Notes, make repurchases of Convertible Notes surrendered therefor or settle conversions of the Convertible Notes. In addition, our ability to repurchase the Convertible Notes or to pay cash upon conversions of the Convertible 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 Convertible Notes, repurchase Convertible Notes at a time when the repurchase is required or to pay any cash payable on future conversions of the Convertible 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 Convertible Notes or make cash payments upon conversions thereof.
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.

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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 8, 2017. 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, 2016, 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.
Our restructuring activities could result in management distractions, operational disruptions and other difficulties.
In September 2016, our board of directors approved an approximate 15% reduction in our global workforce as part of a broader restructuring plan designed to materially reduce our operating expenses primarily related to our subscription-based energy intelligence software business. This reduction will result in reallocations of duties and may reduce employee morale, which could lead to unintended attrition or performance issues. Any restructuring effort could also cause disruptions with customers and other business partners, divert the attention of our management away from our operations and business objectives, harm our reputation, and expose us to increased risk of legal claims by terminated employees. We cannot guarantee that we will be able to realize sufficient cost savings and other anticipated benefits from such restructuring activities, or that we will not have to undertake future restructuring and cost control activities.
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 demand response solutions and EIS. We rely on our operations team to install, test, deliver and manage our demand response solutions and EIS. We rely on our sales and marketing team to sell our demand response solutions and EIS to our customers, build our brand and promote our company. 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

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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 demand response solutions and EIS. We hold 23 patents and numerous trademarks and copyrights; in addition we have filed 57 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 demand response solutions and EIS 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 demand response solutions and EIS. 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 demand response solutions and EIS, which could be time-consuming and expensive, divert attention and resources away from our daily operations, impede or prevent delivery of our demand response solutions and EIS 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 demand response solutions and EIS 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 demand response solutions and EIS and take certain measures to ensure that no open source software is used or distributed in such a way as to subject our demand response solutions and EIS to any unanticipated conditions or restrictions, such use or distribution could inadvertently occur. In the event that any of our demand response solutions and EIS 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 demand response solutions and EIS, each of which could reduce or eliminate the value of our demand response solutions and EIS. 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 demand response solutions and EIS, 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 demand response solutions and EIS, 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

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development and make us unable, or severely limit our ability, to provide our demand response solutions and EIS. 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 demand response solutions and EIS and even the perception of security risks involving our demand response solutions and EIS or the transmission of data over the Internet, whether or not valid, could harm our reputation and inhibit market acceptance of our demand response solutions and EIS and cause us to lose customers.
We use our demand response solutions and EIS to compile and analyze sensitive or confidential information related to our customers and C&I end-users. In addition, some of our demand response solutions and EIS allow us to remotely control equipment at our C&I end-user sites. Our demand response solutions and EIS 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 demand response solutions and EIS, or our customers’ or C&I end-users’ concerns about Internet security or the security of our demand response solutions and EIS whether or not they are warranted, could have a material adverse effect on our business, harm our reputation, inhibit market acceptance of our demand response solutions and EIS 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 demand response solutions and EIS, 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, 2016 , we had $24.4 million in outstanding letters of credit under the 2014 credit facility, leaving $5.6 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.
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

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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.
Adoption of new revenue recognition standard in 2017.
In May 2014, the Financial Accounting Standards Board issued new revenue recognition rules under ASC 606, which will allow entities to recognize revenue at the transfer of promised goods and services to customers in an amount that reflects the consideration to which the entity expects to be entitled. ASC 606 is effective for interim and annual periods beginning after December 31, 2017. We have elected to early adopt the new standard effective January 1, 2017 using the modified retrospective method.
In order to comply with the requirements of ASC 606 on January 1, 2017, we are continuing to update and enhance our internal accounting systems and our internal controls over financial reporting. If we are not successful in updating our policies, procedures, information systems and internal controls over financial reporting, the revenue that we recognize and the related disclosures that we provide under ASC 606 may not be complete or accurate, which could harm our operating results or cause us to fail to meet our reporting obligations. 
The application of the new standard will be based on all information available to us as of the date of adoption and up through subsequent interim reporting, including transition guidance published by the standard setters. However, we understand the interpretation of these new standards will continue to evolve as other public companies adopt ASC 606 and the standard setters issue new interpretive guidance related to these rules. As a result, changes in the interpretation of these rules could result in material adjustments to our application of the new standard, which could have a material adverse effect on our results of operations and financial condition.
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, 2016 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

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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.
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 demand response solutions and EIS;
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 demand response solutions and EIS which may impact the timing of our recognition of revenues;
delays or reductions in spending for demand response solutions and EIS 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.

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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, 2016 , through December 31, 2016 , our stock price fluctuated between a high of $7.88 on April 5, 2016 and a low of $2.92 on January 15, 2016. In addition, in the first quarter of 2017 our stock price has traded as low as $4.80 on March 14, 2017.
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 demand response solutions and EIS;
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;
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 demand response solutions and EIS 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 demand response solutions and EIS 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;

22



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
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.

23




Item 1B.
Unresolved Staff Comments
None.
Item 2.
Properties
Our corporate headquarters and principal office is located in Boston, Massachusetts. We lease approximately 110,000 square feet of office space under a lease agreement, or the 2012 Lease, expiring in July 2020. The lease agreement includes 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 a one time extension of the lease term for a 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 has been reduced to $1.2 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 currently lease a number of offices under various other lease agreements in the United States, Australia, Canada, New Zealand, Ireland, the United Kingdom, Brazil, India, 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.

24




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 2016
High
 
Low
First Quarter
$
7.74

 
$
2.92

Second Quarter
$
7.88

 
$
5.80

Third Quarter
$
7.74

 
$
5.26

Fourth Quarter
$
6.50

 
$
4.85

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

Stockholders
As of March 6, 2017 , we had approximately 431 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
Not applicable
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, 2016 , or fiscal 2016 :
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, 2016—October 31, 2016
 
44,984

 
$
5.41

 

 

November 1, 2016—November 30, 2016
 
2,532

 
5.15

 

 

December 1, 2016—December 31, 2016
 
17,337

 
6.05

 

 

Total for the fourth quarter of 2016
 
64,853

 
$
5.57

 

 

(1)  
We repurchased a total of 64,853 shares of our common stock in the fourth quarter of fiscal 2016, consisting of 44,984 , 2,532 and 17,337 shares in October, November and December 2016 , 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.
Securities Authorized for Issuance Under Equity Compensation Plans
Information about securities authorized for issuance under our equity compensation plan is incorporated herein by reference to Item 12 of Part III of this Annual Report on Form 10-K.

25




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,
(In thousands, except share and per share data)
2016
 
2015
 
2014
 
2013
 
2012
Selected Balance Sheet Data (at end of period):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
97,993

 
$
138,120

 
$
254,351

 
$
149,189

 
$
115,041

Total assets  
312,302

 
443,714

 
620,884

 
415,955

 
355,165

Total long-term debt
115,223

 
111,254

 
135,090

 

 

Total EnerNOC, Inc. stockholders’ equity
79,680

 
114,644

 
291,873

 
269,495

 
240,022

Selected Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Revenues
$
403,959

 
$
399,584

 
$
471,948

 
$
383,460

 
$
277,984

Cost of revenues
241,466

 
245,051

 
257,322

 
192,292

 
154,540

Gross profit
162,493

 
154,533

 
214,626

 
191,168

 
123,444

(Loss) income from operations
(35,588
)
 
(187,968
)
 
26,228

 
27,716

 
(20,388
)
Net (loss) income
(50,478
)
 
(185,118
)
 
11,997

 
22,088

 
(22,293
)
Common Share Data:
 
 
 
 
 
 
 
 
 
Net (loss) income per share, basic
$
(1.72
)
 
$
(6.51
)
 
$
0.43

 
$
0.80

 
$
(0.84
)
Net (loss) income per share, diluted
$
(1.72
)
 
$
(6.51
)
 
$
0.42

 
$
0.76

 
$
(0.84
)

26




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 demand response solutions and energy intelligence software, or EIS, to enterprises, utilities, and electric power grid operators.
Demand Response Solutions
Our demand response solutions provide 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 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 contracted capacity, we use our global 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.
Energy Intelligence Software
Our EIS includes our subscription software, energy procurement solutions, and professional services.
Subscription Software
Our EIS provides enterprises with a Software-as-a-Service, or SaaS, energy management application that enables them to address their most important energy challenges, including:
energy cost visualization, budgets, forecasts, and accruals;
utility bill validation and payment;
facility optimization;
energy project tracking;
reporting for energy and sustainability disclosure and compliance; and
peak energy demand and the related cost impacts.
Energy Procurement Solutions
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 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.
Professional Services
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.

Revenues and Expense Components
Revenues
We derive revenue from the sale of our demand response solutions and EIS. We recognize revenue in accordance with Accounting Standards Codification 605, Revenue Recognition (ASC 605) 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.
Revenues associated with the provision of our demand response solutions to utilities and electric power grid operators primarily consist of capacity and energy payments and ongoing fixed fees for the management of utility-sponsored demand response programs. We earn revenues from our demand response solutions by making demand response capacity available in open

27



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.
Revenues from the sale of our EIS to enterprises generally represent ongoing software or service arrangements under which the revenues are recognized ratably over the service delivery period commencing upon delivery of the EIS to the enterprise customer. Revenues from the sale of our procurement services are derived from fees paid by energy suppliers and energy consumers that utilize our online auction platform and advisory services. We derive professional service revenues from integration services related to our EIS and for other professional services engagements, including energy audits and retro-commissioning services.
Please see Note 1 to our consolidated financial statements contained in Appendix A to this Annual Report on Form 10-K for a discussion of the impact of the new revenue recognition guidance provided by Accounting Standards Codification 606, Revenue from Contracts with Customers, or ASC 606 , that we adopted using the modified retrospective method on January 1, 2017.
Cost of Revenues
Cost of revenues primarily consists of amounts owed or paid 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 energy payments 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. This depreciation is reflected in cost of revenues.
We also include in cost of revenues the amortization of acquired developed technology and capitalized internal-use software costs related to our demand response solutions and EIS and the monthly telecommunications and data costs we incur as a result of being connected to enterprise customer and C&I end-user sites. Additionally, cost of revenues includes third-party services, equipment maintenance costs, and internal payroll and related costs associated with the delivery of our professional services and our subscription based utility bill management solutions. Cost of revenues includes payroll and related costs of 341 and 278 employees at December 31, 2016 and 2015, respectively.
We capitalize and defer incremental direct costs incurred related to customer contracts that are deemed realizable and where the associated revenues have been deferred.
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 demand response solutions and EIS, (b) the way in which we manage 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, (c) our demand response event performance, (d) our ability to open and enter new markets and regions and expand deeper into markets we already serve, (e) the selling price of our demand response solutions and EIS, and (f) the introduction of new demand response solutions and EIS.
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. Full-time employees included in operating expenses declined from 1,088 employees at December 31, 2015 to 736 full-time employees at December 31, 2016 , primarily due to the sale of two businesses and restructuring actions undertaken during 2016. We expect a further decrease in operating expenses in 2017 reflecting the full year impact of our 2016 restructuring actions, as well as additional cost reduction initiatives that we are pursuing. Operating expenses exclude 341 and 278 employees whose costs are included in cost of revenues at December 31, 2016 and 2015, respectively. The components of operating expenses are as follows:
Selling and Marketing
Selling and marketing expenses consist primarily of (a) salaries and related personnel costs, including stock-based compensation, (b) commissions, (c) travel and other out-of-pocket expenses, (d) marketing programs such as trade shows and (e) an allocation of company-wide overhead costs. Full-time employees associated with selling and marketing declined to 193 at December 31, 2016 from 325 at December 31, 2015 . Commissions are recorded as an expense when earned by the employee.

28



General and Administrative
General and administrative expenses consist primarily of (a) salaries and related personnel costs, including stock-based compensation, related to our executive, finance, human resource, information technology, and operations organizations (b) external accounting and legal professional fees, (c) depreciation and amortization and (d) an allocation of company-wide overhead costs. Full-time employees associated with general and administrative functions declined to 442 at December 31, 2016 from 553 at December 31, 2015 . General and administrative employees as of December 31, 2016 included approximately 120 full-time employees who deliver professional services to our customers and whose salary and related personnel costs are reclassified to cost of revenues based on their utilization on customer contracts.
Research and Development
Research and development expenses consist primarily of (a) salaries and related personnel costs, including stock-based compensation, (b) payments to suppliers for design and consulting services, (c) costs relating to the design and development of new demand response solutions and EIS and enhancement of existing demand response solutions and EIS, (d) quality assurance and testing, and (e) an allocation of company-wide overhead costs. Full-time employees associated with research and development declined to 101 at December 31, 2016 from 210 at December 31, 2015 .
Stock-Based Compensation
We grant stock-based awards to employees and members of our board of directors. We account for stock-based compensation in accordance with ASC 718,  Stock Compensation (ASC 718). These awards, 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. From time to time, we grant restricted stock awards to non-employees and advisory board members.These awards are recognized in the statement of operations at fair value as measured each reporting period until the award vests. Our stock-based compensation plans are more fully described in Appendix A to this Annual Report on Form 10-K.
All shares underlying awards of restricted stock are not transferable until they vest. Restricted stock typically vests ratably over a three year period from the date of issuance, with certain exceptions. The fair value of restricted stock where 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 accelerated vesting in certain circumstances upon a change of control, if the employee who received the restricted stock leaves the Company prior to the vesting date for any reason, the shares of restricted stock are forfeited and returned to the Company.
Non-Operating Activities
Non-operating activities include interest expense, other expense, net, and gains on early extinguishment of debt. Interest expense primarily consists of interest expense on our 2.25% convertible senior notes due August 15, 2019, or the Convertible Notes, as well as fees associated with our $30 million senior secured revolving credit facility. Other expense, net consists primarily of foreign currency exchange gains or losses related to outstanding intercompany loans and losses related to the impairment of cost-method investments. Gain on early extinguishment of debt represents the gain we recorded in 2015 as a result of the repurchase in cash of $33.2 million in aggregate principal amount of our Convertible 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
Revenues
The following table summarizes our revenues for the years ended December 31, 2016 , 2015 and 2014 (dollars in thousands):
 
Year Ended December 31,
 
Dollar Change
 
Percentage Change
 
2016
 
2015
 
2014
 
2016 vs 2015
 
2015 vs 2014
2016 vs 2015
 
2015 vs 2014
Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
 
Demand Response
$
336,666

 
$
317,792

 
$
432,856

 
$
18,874

 
$
(115,064
)
 
5.9
 %
 
(26.6
)%
Software
67,293

 
81,792

 
39,092

 
(14,499
)
 
42,700

 
(17.7
)%
 
109.2
 %
Total revenues
$
403,959

 
$
399,584

 
$
471,948

 
$
4,375

 
$
(72,364
)
 
1.1
 %
 
(15.3
)%
For a discussion and analysis of revenues, as compared to the prior years, please refer to Segment Results of Operations below.

29



Gross Profit and Gross Margin
The following table summarizes our gross profit and gross margin for the years ended December 31, 2016 , 2015 and 2014 (dollars in thousands):
Year Ended December 31,
2016
 
2015
 
2014
Gross Profit
 
Gross Margin
 
Gross Profit
 
Gross Margin
 
Gross Profit
 
Gross Margin
$162,493
 
40.2%
 
$154,533
 
38.7%
 
$214,626
 
45.5%
The increase in consolidated gross profit during the year ended December 31, 2016 , as compared to 2015 , was consistent with the increase in revenues and gross margin. The decrease in consolidated gross profit during the year ended December 31, 2015 , compared to 2014 , was primarily due to lower revenues and decline in gross margin as discussed below.
The increase in consolidated gross margin for the year ended December 31, 2016 , as compared to 2015 , was primarily due to an increase in higher margin revenues from our participation in incremental auctions associated with our PJM Interconnection, or PJM, program and improved management of our demand response portfolios, partially offset by a decline in pricing throughout various demand response programs. The decrease in consolidated gross margin during the year ended December 31, 2015, as compared to 2014, was primarily due to a decrease in high-margin revenue from our participation in incremental auctions and bilateral contracts in the PJM and ISO-NE demand response programs.
We currently expect that our gross profit and gross margin percentage will decrease in 2017 primarily as a result of the shift in our participation between different PJM programs across delivery years and the corresponding impact on revenue recognition, a reduction in higher margin revenue from our decreased participation in PJM incremental auctions and an increase in lower margin revenue from our expanding international demand response programs.
Operating Expenses
The following table summarizes our operating expenses for the years ended December 31, 2016 , 2015 and 2014 (dollars in thousands):
 
Year Ended December 31,
 
Percentage Change
 
2016
 
2015
 
2014
 
2016 vs 2015
 
2015 vs 2014
Operating expenses and income:
 
 
 
 
 
 
 
 
 
Selling and marketing
$
86,989

 
$
97,175

 
$
76,960

 
(10.5
)%
 
26.3
%
General and administrative
97,179

 
110,267

 
97,729

 
(11.9
)%
 
12.8
%
Research and development
26,269

 
29,287

 
20,671

 
(10.3
)%
 
41.7
%
Gains on sale of businesses
(19,875
)
 
(2,991
)
 
(6,962
)
 
n/m

 
n/m

Restructuring and asset impairment charges
7,519

 

 

 
n/m

 
n/m

Goodwill impairment

 
108,763

 

 
n/m

 
n/m

Total operating expenses and income
$
198,081

 
$
342,501

 
$
188,398

 
(42.2
)%
 
81.8
%
Selling and Marketing Expenses
The following table summarizes our selling and marketing expenses for the years ended December 31, 2016 , 2015 and 2014 (dollars in thousands):
 
Year Ended December 31,
 
Percentage Change
 
2016
 
2015
 
2014
 
2016 vs 2015
 
2015 vs 2014
Payroll and related costs
$
55,549

 
$
60,946

 
$
49,318

 
(8.9
)%
 
23.6
 %
Stock-based compensation
3,287

 
4,316

 
5,488

 
(23.8
)%
 
(21.4
)%
Amortization of intangible assets
8,667

 
10,148

 
5,876

 
(14.6
)%
 
72.7
 %
Other
19,486

 
21,765

 
16,278

 
(10.5
)%
 
33.7
 %
Total selling and marketing expenses
$
86,989

 
$
97,175

 
$
76,960

 
(10.5
)%
 
26.3
 %
The decrease in payroll and related costs for the year ended December 31, 2016 , as compared to 2015 , was primarily due to the divestiture of our Utility Programs Group and Utility Customer Engagement businesses, and the restructuring actions completed in the third quarter of 2016. 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 Solutions, or World Energy, respectively. Please refer to Note 16 contained in Appendix A to this Annual Report on Form 10-K for more information about these acquisitions. In addition, we experienced an increase in commission expense during the year ended December 31, 2015 due to an increase in subscription software revenues.

30



The decrease in stock-based compensation for the year ended December 31, 2016 , as compared to 2015 , was primarily due to a decrease in the number and grant date fair value of stock-based awards granted during the period, as well as a reduction in selling and marketing employees due to the 2016 restructuring activity noted above. 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.
Amortization of intangible assets decreased for the year ended December 31, 2016 , as compared to 2015 , due to customer relationship intangible assets becoming fully amortized or retired as part of the Utility Customer Engagement business sale. Amortization of intangible assets increased in 2015, as compared to 2014, as a result of acquisitions that we completed during 2014 and our acquisition of World Energy in January of 2015.
The decrease in other selling and marketing expenses for the year ended December 31, 2016 , as compared to 2015 , was primarily due to a reduction in employee travel and training during 2016. 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 facility costs associated with sales and marketing activities.
We currently expect a decrease in selling and marketing expense in fiscal 2017, compared to fiscal 2016, due to the full year impact of our divestitures and third quarter 2016 restructuring activities.
General and Administrative Expenses
The following table summarizes our general and administrative expenses for the years ended December 31, 2016 , 2015 and 2014 (dollars in thousands):
 
Year Ended December 31,
 
Percentage Change
 
2016
 
2015
 
2014
 
2016 vs 2015
 
2015 vs 2014
Payroll and related costs
$
59,631

 
$
64,578

 
$
54,273

 
(7.7
)%
 
19.0
 %
Stock-based compensation
7,904

 
8,907

 
9,225

 
(11.3
)%
 
(3.4
)%
Amortization of intangible assets
482

 
1,143

 
1,261

 
(57.8
)%
 
(9.4
)%
Gain on escrow settlement (Note 15)
(3,535
)
 

 

 
n/m

 
n/m

Other
32,697

 
35,639

 
32,970

 
(8.3
)%
 
8.1
 %
Total general and administrative expenses
$
97,179

 
$
110,267

 
$
97,729

 
(11.9
)%
 
12.8
 %
Payroll and related costs for the year ended December 31, 2016 , as compared to 2015 , decreased primarily as a result of our restructuring actions completed in the second half of 2016. 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 an increase in the number of general and administrative full-time employees, the majority of which resulted from the expansion of our global services function, hiring into open positions in our finance and operations organizations, our acquisitions completed during 2014 and our acquisition of World Energy in January 2015.
The decrease in stock-based compensation for the year ended December 31, 2016 , as compared to 2015 , was primarily due to a decrease in the number and grant date fair value of stock-based awards granted during the period and a reduction in general and administrative employees due to the 2016 restructuring activities noted above. The decrease in stock-based compensation for the year ended December 31, 2015 , as compared to 2014 , was primarily related 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.
During the year ended December 31, 2016, we received $3.5 million for the settlement of claims against the former shareholders of an acquired entity, which is further described in Note 15 to the consolidated financial statements included in Appendix A to this Annual Report on Form 10-K.
Other general and administrative expenses include third-party software fees, audit, external legal, other professional services, facility-related expenses, and depreciation. These costs declined for the year ended December 31, 2016 , as compared to 2015 , due to lower facility costs as a result of subleasing arrangements, a decline in depreciation expense due to current year divestitures, and lower costs related to acquisitions, primarily driven by the integration of World Energy in 2015. 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.

31



We currently expect a decrease in general and administrative expenses in fiscal 2017, as compared to fiscal 2016, due to the full year impact of our third quarter 2016 restructuring activities.
Research and Development Expenses
The following table summarizes our research and development expenses for the years ended December 31, 2016 , 2015 and 2014 (dollars in thousands):
 
Year Ended December 31,
 
Percentage Change
 
2016
 
2015
 
2014
 
2016 vs 2015
 
2015 vs 2014
Payroll and related costs
$
15,639

 
$
16,750

 
$
12,069

 
(6.6
)%
 
38.8
%
Stock-based compensation
1,264

 
1,362

 
1,350

 
(7.2
)%
 
0.9
%
Other
9,366

 
11,175

 
7,252

 
(16.2
)%
 
54.1
%
Total research and development expenses
$
26,269

 
$
29,287

 
$
20,671

 
(10.3
)%
 
41.7
%
During the years ended December 31, 2016 , 2015 and 2014 , total research and development payroll and related costs are net of $5.2 million , $5.3 million and $6.0 million , respectively, of capitalized payroll costs associated with internal-use software development activities. The decrease in payroll and related costs for the year ended December 31, 2016, as compared to 2015 , was due to a reduction in research and development employees in connection with the sale of our Utility Customer Engagement business and restructuring activities completed in the third quarter of 2016. The increase in payroll and related costs for the year ended December 31, 2015, as compared to 2014, was due to an increase in the number of research and development employees associated primarily with our software development efforts related to enhancing the features and functionality of our EIS offerings.
The decrease in stock-based compensation for the year ended December 31, 2016 , as compared to 2015 , was primarily due to a decrease in the number and grant date fair value of stock-based awards granted during the period due to the 2016 restructuring activities noted above. Stock-based compensation for the year ended December 31, 2015, as compared to 2014, was relatively consistent.
Other research and development expenses include technology expenses, professional services, facilities and a company-wide overhead cost allocation. The decrease in other research and development expenses for the year ended December 31, 2016 , as compared to 2015 , was primarily attributable to decreases in data storage and external software costs. The increase in other research and development expenses for the year ended December 31, 2015, as compared to 2014, was primarily due to an increase in these costs.
We currently expect research and development expenses to decline in fiscal 2017, as compared to fiscal 2016, due to the full year impact of our divested businesses and third quarter 2016 restructuring activities.
Gains on Sale of Businesses
The following table summarizes our gains on sale of businesses and demand response capacity resources for the years ended December 31, 2016 , 2015 and 2014 (in thousands):
 
Year Ended December 31,
 
2016
 
2015
 
2014
Utility Programs Group
$
17,333

 
$

 
$

Utility Customer Engagement
2,542

 

 

Demand Response resources

 
2,991

 
2,171

Utility Solutions Consulting

 

 
3,737

Valley Tracker

 

 
1,054

Total gains on sale of businesses and assets
$
19,875

 
$
2,991

 
$
6,962

During the year ended December 31, 2016, we divested two businesses and recognized gains of $19.9 million . These gains exceeded gains on the sale of demand response capacity resources sold during the year ended December 31, 2015. During the ended December 31, 2014, we divested two businesses and demand response capacity resources and recognized gains of $7.0 million. Please see Note 4 to the accompanying financial statements included in Appendix A to this Annual Report on Form 10-K for a complete description of these strategic divestitures.
Restructuring Charges
On May 23, 2016, our Board of Directors approved a restructuring plan, or the Q2 2016 Restructuring Plan, in order to enhance our strategic focus, deliver operational and cost efficiencies, and sell our Utility Customer Engagement business. The Q2 2016 Restructuring Plan included a reduction in our North American workforce of approximately 5% and office space

32



consolidations. On September 21, 2016, our Board of Directors approved an additional restructuring plan, or the Q3 2016 Restructuring Plan, to reduce our global workforce by approximately 15% in order to materially reduce operating expenses primarily related to our subscription-based energy intelligence software business. The majority of actions related to these plans were completed during 2016.
The following table summarizes restructuring activities for the year ended December 31, 2016 (in thousands):
Description
 
Year Ended 
 December 31, 2016
Employee related charges for severance and retention
 
$
3,842

Contract terminations
 
719

Non-cash asset impairment charges, primarily leasehold improvements
 
2,958

Total
 
$
7,519

During 2016, we subleased a portion of our corporate office space, which resulted in a non-cash impairment charge of $2.5 million related to leasehold improvements. Severance and employee-related costs were $1.1 million as of December 31, 2016 and are expected to be settled in the first and second quarters of 2017. We expect that these restructuring activities will result in annual savings, through lower personnel related and operating costs, of approximately $35 million to $40 million. The benefits of these restructuring activities began in the fourth quarter of 2016.
Goodwill Impairment
As a result of our annual goodwill impairment test conducted as of November 30, 2016, we determined that the implied fair value of goodwill exceeded its carrying amount and, therefore, no impairment was required. Our annual goodwill test for the prior year, conducted as of November 30, 2015, resulted in the recognition of a $108.8 million goodwill impairment charge for the year ended December 31, 2015. There was no such impairment in 2016. See Critical Accounting Policies in this Item 7 and Note 5 contained in Appendix A to this Annual Report on Form 10-K for further information regarding the results of our 2016 goodwill test and the factors that contributed to the 2015 impairment charge.
As a result of our adoption of the new revenue recognition guidance under ASC 606, we anticipate recording an increase to our Energy Procurement Solutions reporting unit’s net assets. The anticipated increase in net assets is expected to be greater than the excess fair value over the carrying value of net assets as of our annual impairment test on November 30, 2016. Therefore, we expect to perform an interim impairment test for the Energy Procurement Solutions reporting unit during the first quarter of 2017. Based on the fair value assumptions used in our November 30, 2016 impairment test, we are anticipating recording a goodwill impairment charge in the first quarter of 2017 of up to $5.8 million related to this reporting unit, which is part of the Software segment. Please see Note 5 to our consolidated financial statements contained in Appendix A to this Annual Report on Form 10-K for further information.
Interest and Other Expense, Net
Interest expense was $7.3 million for the year ended December 31, 2016 , as compared to $8.9 million in 2015 . The decrease was due to the early retirement of a portion of our Convertible Notes in the fourth quarter of 2015. The increase in interest expense from $4.7 million during the year ended December 31, 2014 to $8.9 million in 2015 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, 2016 was $5.6 million , which primarily includes realized and unrealized foreign currency losses of $4.4 million , $1.8 million in losses related to cost-method investments, offset partially by interest income on our money market funds. Foreign currency losses in 2016 were primarily due to the weakening of the Great British Pound and the Euro, which declined 17% and 4% against the U.S. dollar, respectively. Foreign currency losses in 2015 were primarily due to the weakening of the Canadian dollar, the Euro and the 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 2014.
We carry equity investments with no readily determinable market value. We periodically assess these investments for indicators of a reduction in fair value by reviewing information regarding the investment, such as current financial forecasts and recent or pending rounds of financing activity. During 2016, we identified factors that indicated these investments were impaired, resulting in an impairment loss of $1.8 million . The carrying value of these investments was $0.7 million as of December 31, 2016. In future periods, additional impairment charges may be required based on the future financial performance or financing activities related to these investments.
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 our Convertible 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 these Convertible Notes of $9.2 million based on the

33



difference between the carrying amount of the repurchased Convertible Notes and the cash consideration. We had no similar debt extinguishment in 2016 or 2014.
Income Taxes
For the year ended December 31, 2016 , we recorded an income tax provision of $2.0 million , which was driven by the mix of earnings from foreign operations and reflects changes relating to valuation allowances associated with deferred tax assets for certain foreign entities. For the year ended December 31, 2015 , we recorded an income tax benefit of $10.0 million 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. For the year ended December 31, 2014, we recorded an income tax provision of $5.9 million that included a $1.1 million income tax benefit due to the release of a portion of the U.S. valuation allowance in connection with our acquisition of EnTech and a $1.1 million income tax provision related to our sale of the Utility Solutions Consulting business.

ASC 740, Income Taxes (ASC 740), provides the criteria for the recognition, measurement, presentation and disclosure 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, 2016, the Company recorded a $0.6 million reserve primarily related to a possible liability for foreign withholding tax.
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, 2016, 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 that 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 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, 2016 was (4.0)% as compared to an effective tax rate of 5.1% for the year ended December 31, 2015.
Segment Results of Operations
Effective in the first quarter of 2016 , we began operating two reportable segments: Demand Response and Software. We evaluate and assess the performance of our operating segments based on revenues and adjusted EBITDA, which is the measure of segment profit or loss that is reported to our Chief Operating Decision Maker for purposes of making decisions about allocating resources to each segment and assessing segment performance. Please refer to Note 2 in Appendix A to this Annual Report on Form 10-K for a reconciliation of segment income (loss) to consolidated income (loss) before income taxes. We define segment adjusted EBITDA as segment income (loss) from operations excluding depreciation, amortization and asset impairments; stock-based compensation and restructuring charges. In addition, we do not allocate to our operating segments certain corporate level expenses; gains and losses on the sale of businesses; impairment of goodwill and intangible assets; gains on extinguishment of debt as well as direct and incremental expenses and gains associated with acquisitions, divestitures, reorganizations and settlements.
Revenues
Demand Response Segment Revenues
The following table summarizes our Demand Response segment revenues for the years ended December 31, 2016 , 2015 and 2014 (in thousands):
 
Year Ended December 31,
 
Dollar Change
 
Percentage Change
 
2016
 
2015
 
2014
 
2016 vs 2015
 
2015 vs 2014
2016 vs 2015
 
2015 vs 2014
Demand Response Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
 
Grid operator
$
274,728

 
$
258,008

 
$
368,829

 
$
16,720

 
$
(110,821
)
 
6.5
%
 
(30.0
)%
Utility
61,938

 
59,784

 
64,027

 
2,154

 
(4,243
)
 
3.6
%
 
(6.6
)%
Demand Response
$
336,666

 
$
317,792

 
$
432,856

 
$
18,874

 
$
(115,064
)
 
5.9
%
 
(26.6
)%

34



The following table summarizes the significant changes in our grid operator revenue (dollars in thousands):
 
Revenue Increase (Decrease)
 
December 31, 2015
to
December 31, 2016
 
December 31, 2014
to
December 31, 2015
PJM
$
17,723

 
$
(84,048
)
South Korea (KPX)
12,501

 
17,135

Alberta (AESO)
(5,721
)
 
(6,176
)
New England (ISO-NE)
(4,842
)
 
(6,033
)
Texas (ERCOT)
(2,561
)
 
(2,486
)
New York (NYISO)
(2,042
)
 
(1,024
)
Western Australia (AEMO)
(903
)
 
(26,792
)
Other
2,565

 
(1,397
)
Total increase (decrease) in grid operator revenues
$
16,720

 
$
(110,821
)
The increase in PJM revenues for the year ended December 31, 2016 , as compared to 2015 , was primarily due to our increased participation in the 2015/2016 PJM Extended program for which revenue was recognized in May 2016. The increase in revenues associated with our South Korea program was primarily due to an increase in enrolled MW in the current year. These increases were partially offset by lower pricing and fewer enrolled MW in our Alberta program as well as fewer enrolled MW in our New York and Texas programs. The decline in ISO-NE revenues was largely due to lower MW obligations resulting from our participation in reconfiguration auctions in these programs.
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 for the 2015/2016 delivery year, which resulted in the deferral of revenue associated with this PJM program to the second quarter of 2016 combined with lower revenue associated with capacity auctions and bilateral contracts in the PJM and ISO-NE demand response programs. The decrease in revenues associated with PJM programs 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 associated with Western Australia in 2015, as compared to 2014, was due to a change to ratable revenue recognition in the program in 2014, which resulted in revenue for multiple program years being recognized in 2014, partially offset by decreased pricing in 2014. The decrease in revenues was also due to lower pricing and fewer MW in our Alberta program. These decreases were partially offset by increased revenue associated with our South Korea program.
We have made the election to adopt the revenue recognition guidance under ASC 606 effective January 1, 2017 using the modified retrospective method. Although we expect that the adoption of the new guidance will allow us to accelerate revenue recognized on certain grid operator demand response programs in 2017, we currently expect grid operator revenues to decline by 20% to 30% as compared to 2016 due to a shift in our participation in PJM programs. More specifically, during 2016 we recognized approximately $75.0 million of revenue for our participation in the 2015/2016 PJM Extended program, for which the delivery period ended in 2016. During 2016, we also recognized approximately $94.0 million of revenue for our participation in the 2016/2017 PJM Limited program, for which the delivery period ended in September 2016. In 2017, we will primarily participate in the PJM 2017/2018 Extended program, for which we expect to recognize revenue ratably throughout the 2017/2018 delivery term. Please refer to Note 1 to the accompanying financial statements included in Appendix A to this Annual Report on Form 10-K for further discussion of the impact of our adoption of ASC 606.

35



The following table summarizes the significant changes in our utility revenues by utility programs (dollars in thousands):
 
Revenue Increase (Decrease)
 
December 31, 2015
to
December 31, 2016
 
December 31, 2014
to
December 31, 2015
Consolidated Edison (Con Ed)
$
2,568

 
$
87

San Diego Gas and Electric (SDG&E)
1,687

 
191

Southern California Edison (SCE)
(1,115
)
 
3,800

Idaho Power/Salt River Project (SRP)
(1,167
)
 
(3,592
)
Pacific Gas & Electric (PG&E)
(1,334
)
 
(2,667
)
Other
1,515

 
(2,062
)
Total increase (decrease) in utility revenues
$
2,154

 
$
(4,243
)
The increase in Con Ed revenues during the year ended December 31, 2016, as compared to 2015, was primarily due to a performance-based bonus payment recognized in 2016 as well as an increase in enrolled MW and pricing. The increase in SDG&E revenue was due to the recognition of previously deferred revenues upon the completion of the associated contract. These increases were partially offset by lower energy event revenue in our SCE program, the conclusion of our SRP program in the second quarter of 2015 and lower MW obligations in our PG&E program.
The decrease in revenue from utility customers during the year ended December 31, 2015, as compared to 2014, was due to the conclusion of the SRP program in 2015 and a decrease in participation in our PG&E program, which was partially offset by energy event revenue in our SCE program.
We currently expect revenues from our utility customers in 2017 to be consistent with 2016.
Software Segment Revenues
The following table summarizes our Software segment revenues for the years ended December 31, 2016 , 2015 and 2014 (in thousands):
 
Year Ended December 31,
 
Dollar Change
 
Percentage Change
 
2016
 
2015
 
2014
 
2016 vs 2015
 
2015 vs 2014
2016 vs 2015
 
2015 vs 2014
Software Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
 
Subscription software
$
24,799

 
$
19,885

 
$
13,880

 
$
4,914

 
$
6,005

 
24.7
 %
 
43.3
%
Procurement solutions
35,603

 
36,428

 
5,733

 
(825
)
 
30,695

 
(2.3
)%
 
535.4
%
Professional services
6,891

 
25,479

 
19,479

 
(18,588
)
 
6,000

 
(73.0
)%
 
30.8
%
Software
$
67,293

 
$
81,792

 
$
39,092

 
$
(14,499
)
 
$
42,700

 
(17.7
)%
 
109.2
%
Subscription software revenues increased during the year ended December 31, 2016 , as compared to 2015 , primarily due to increased sales of our subscription software packages and from our value added reseller partnerships. Subscription software annual recurring revenue, or ARR, which is an operating metric utilized by management, was $28 million as of December 31, 2016 as compared to $27 million as of December 31, 2015. We define ARR as contracted subscription-based expected billings, normalized for a one-year period. Procurement solutions revenue decreased slightly during this period primarily due to our decision to not renew certain smaller or unprofitable customers acquired through our acquisition of World Energy. In previous periods, we had reported procurement solutions ARR. We believe that procurement solutions ARR is no longer a meaningful metric as a result of our adoption of ASC 606 on January 1, 2017, which will accelerate the recognition of revenue for energy procurement auctions (generally upon the completion of the auction) and significantly reduce the amount of recurring revenue. The decline in professional services revenues was due to the divestiture of our World Energy efficiency business in the fourth quarter of 2015 and our Utility Programs Group business in the second quarter of 2016.
The increase in subscription software revenue in 2015, as compared to 2014, was due to the increase in the number of customers utilizing our EIS. The increase in procurement solutions and professional services was a result of our acquisition of World Energy in January 2015.
We currently expect our Software segment revenues to decline in fiscal 2017 primarily due to lower professional services revenues associated with our Utility Programs Group business, which was divested in the second quarter of 2016, and the impact that the adoption of ASC 606 will have on our procurement solutions revenue. Although we expect that the adoption of ASC 606 will accelerate revenue recognition for completed procurement auctions prospectively, revenue related to auctions completed prior to 2017 will be adjusted through accumulated deficit upon adoption of the new guidance under the modified

36



retrospective transition method, generating a year-over-year decline in revenue. Please refer to Note 1 to the accompanying financial statements included in Appendix A to this Annual Report on Form 10-K for further discussion of the impact of our adoption of ASC 606.
Segment adjusted EBITDA
The following table summarizes segment adjusted EBITDA for the year ended December 31, 2016 , 2015 and 2014 (in thousands):
 
Year Ended December 31,
 
Dollar Change
 
2016
 
2015
 
2014
 
2016 vs 2015
 
2015 vs 2014
Demand Response adjusted EBITDA
$
68,427

 
$
52,274

 
$
128,670

 
$
16,153

 
$
(76,396
)
Software adjusted EBITDA
$
(53,505
)
 
$
(58,300
)
 
$
(38,551
)
 
$
4,795

 
$
(19,749
)
Demand Response adjusted EBITDA
The increase in Demand Response adjusted EBITDA for the year ended December 31, 2016 , as compared to 2015 , was due to an increase in grid operator revenues and gross profit primarily attributable to our participation in the 2015/2016 PJM Extended program, for which revenue was recognized in May 2016, an increase in high margin revenue associated with our participation in PJM incremental auctions, and improved management of our demand response portfolios. The decline in adjusted EBITDA for the year ended December 31, 2015, as compared to 2014, was primarily due to a decline in grid operator revenues and lower gross margins. 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 from our participation in incremental auctions and bilateral contracts in the PJM and ISO-NE demand response programs. We currently expect our Demand Response adjusted EBITDA for fiscal 2017 to decrease , as compared to 2016, as a result of the shift in our participation between different PJM programs across delivery years, partially offset by the acceleration of revenue for certain demand response programs due to the adoption of ASC 606.
Software adjusted EBITDA
We have incurred losses in our software segment in each of the three years ended December 31, 2016, 2015 and 2014 as we invested in the growth of our EIS. The improved Software segment adjusted EBITDA for the year ended December 31, 2016 , as compared to 2015 , was primarily the result of reduced operating expenses attributable to our restructuring actions executed throughout 2016. Software adjusted EBITDA losses increased in 2015, as compared to 2014, due to investments in selling and marketing and research and development related to our EIS. We currently expect our Software adjusted EBITDA for fiscal 2017, as compared to 2016, to improve by $30 million to $35 million primarily as a result of decreased operating expenses.
Liquidity and Capital Resources
Overview
We have generated significant cumulative losses since inception. As of December 31, 2016 , we had an accumulated deficit of $304.7 million . As of December 31, 2016 , our principal sources of liquidity were cash and cash equivalents totaling $98.0 million , and our $30 million senior secured revolving credit facility. During 2016, our cash, cash equivalents and restricted cash decreased by $39.5 million . This reduction was principally driven by net losses of $50.4 million , less non-cash items of $38.3 million , a $32.6 million increase in working capital, as further described below, and capital expenditures of $15.7 million , including $9.8 million of capitalized internal-use software development costs, partially offset by $22.9 million of cash received from the sales of businesses.
The $116.6 million reduction of cash, cash equivalents and restricted cash during 2015 was principally driven by $76.9 million of cash used for acquisitions, $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 our Convertible Notes, partially offset by $3.2 million of cash generated from operating activities.
Cash Flows
The following table summarizes our cash flows for the years ended December 31, 2016 , 2015 and 2014 (dollars in thousands):
 
Year Ended December 31,
 
2016
 
2015
 
2014
Cash flows (used in) provided by operating activities
$
(44,769
)
 
$
3,172

 
$
60,439

Cash flows provided by (used in) investing activities
7,767

 
(93,731
)
 
(75,443
)
Cash flows (used in) provided by financing activities
(2,511
)
 
(22,723
)
 
120,865

Effects of exchange rate changes on cash and cash equivalents
(16
)
 
(3,298
)
 
(1,720
)
Net change in cash, cash equivalents and restricted cash
$
(39,529
)
 
$
(116,580
)
 
$
104,141


37



Cash Used in Operating Activities
The following table summarizes our consolidated cash flows used in operating activities for the years ended December 31, 2016, 2015 and 2014 (dollars in thousands):
 
Year Ended December 31,
 
2016
 
2015
 
2014
Net (loss) income
$
(50,478
)
 
$
(185,118
)
 
$
11,997

Non-cash items (1)
58,976

 
56,769

 
55,833

Gains on sales of businesses, excluding transaction costs
(20,638
)
 
(2,991
)
 
(6,962
)
Goodwill impairment

 
108,763

 

Gain on settlement of convertible senior notes

 
(9,230
)
 

Change in working capital and other activities
(32,629
)
 
34,979

 
(429
)
Net cash (used in) provided by operating activities
$
(44,769
)
 
$
3,172

 
$
60,439

(1) Non-cash items in 2016 , 2015 and 2014 primarily consist of depreciation and amortization, impairment charges on long lived assets, unrealized foreign exchange translation losses, deferred taxes and non-cash interest expense.
Cash used in operating activities for the years ended December 31, 2016 , 2015 and 2014 reflect net losses adjusted for non-cash activity, gains on the sale of businesses, and the impact of changes in our working capital balances relative to the beginning of the year.
Working capital accounts are largely impacted by our PJM program and other demand response programs. For instance, in connection with our PJM program, we receive cash payments ratably from June through May, but typically recognize the corresponding revenues in September or in the following May. This dynamic, and similar dynamics in other demand response programs, account for the majority of the changes in the working capital accounts described in greater detail below.
Cash collections from demand response customers and payments to C&I end-users, in advance of recognition in the statement of operations, increase our “deferred revenue” and “capitalized incremental direct customer contract costs” balances, respectively. These balances reverse through our statement of operations upon recognition of revenues and the corresponding cost of revenues. 
Recognition of revenues and cost of revenues in advance of cash collections and payments increase our “unbilled revenue” and “accrued capacity payments” balances, respectively. These balances decline as cash is collected and payments are disbursed.
Further impacting our cash flows is the timing of inbound receipts from demand response customers, as compared to the timing of outbound disbursements to C&I end-users. For instance, the PJM program remits cash every week, while we typically disburse C&I payments on a quarterly basis, 45 days in arrears.
The $44.8 million of cash used in operations for the year ended December 31, 2016 compares to $3.2 million cash provided by operations during 2015 . The $47.9 million change is primarily due to the decline in PJM pricing for the 2016/2017 program year relative to the 2015/2016 program year. More specifically, PJM cash inflows for the year ended December 31, 2016 , reflect five months of collections for the 2015/2016 program year and seven months of collections for the lower priced 2016/2017 program year. PJM cash outflows to C&I end-users over the same period reflect eight months of payments for the higher priced 2015/2016 program year and only four months of payments for the lower priced 2016/2017 program year. The impact of the PJM programs was partially offset by cash received for the recovery of an escrow settlement claim (Note 15 to the accompanying financial statements), improved management of our demand response portfolio, year-over-year increases in our subscription software revenues, and a reduction in our operating expense spending as a result of our restructuring actions.
Cash Provided By (Used In) Investing Activities
Cash provided by investing activities was $7.8 million for the year ended December 31, 2016 , and consisted primarily of $22.9 million in cash received for the sale of the Utility Programs Group and Utility Customer Engagement businesses, partially offset by capital expenditures of $15.7 million , including $9.8 million for the capitalization of internal-use software development costs.
Cash used in investing activities was $93.7 million for the year ended December 31, 2015 , reflecting net payments of $76.9 million for acquisitions, largely World Energy, and $23.6 million of capital expenditures.
Cash Used in Financing Activities
Cash used in financing activities for the year ended December 31, 2016 was $2.5 million , and consisted primarily of payments made for employee restricted stock minimum tax withholdings. Cash used in financing activities for the year ended December 31, 2015 was $22.7 million and largely included payments of $19.7 million for purchases of our Convertible Notes and $4.3 million used for employee restricted stock minimum tax withholdings.

38



We believe, based on our present business plan, that our cash and cash equivalents of $98.0 million and future cash flows from our operating, investing and financing activities will be sufficient to meet our cash needs for at least the next 24 months.
Borrowings and Credit Arrangements
Credit Agreement
In August 2014, we entered into a $30 million senior secured revolving credit facility, or the 2014 credit facility, with Silicon Valley Bank, or SVB, pursuant to a loan and security agreement, as amended, which is available for issuances of letters of credit and revolving loans. In August 2016, we and SVB entered into a third amendment to the 2014 credit facility to extend the maturity from August 9, 2016 to August 8, 2017. The 2014 credit facility is subject to continued covenant compliance and borrowing base requirements. As of December 31, 2016 , we were in compliance with all covenants, had no outstanding borrowings and had outstanding letters of credit totaling $24.4 million under the 2014 credit facility. For further discussion of the 2014 credit facility, please refer to Note 10 contained in Appendix A to this Annual Report on Form 10-K.
Convertible Notes
In August 2014, we sold $160 million aggregate principal amount of Convertible Notes due August 15, 2019. The Convertible Notes include customary terms and covenants, including certain events of default after which they may be declared or become due and payable immediately. The Convertible Notes are convertible at an initial conversion rate of 36.0933 shares of the common stock per one thousand dollar principal amount (equivalent to an initial conversion price of approximately $27.71 per share of common stock). We may elect to settle conversions of the Convertible 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.
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 Convertible Notes for a total purchase price of $19.7 million plus accrued interest. We recorded a gain on the extinguishment of the Convertible Notes of $9.2 million based on the difference between the carrying amount of the repurchased Convertible Notes and the cash consideration. We may from time to time seek to retire or repurchase additional outstanding Convertible Notes through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions or by other means. 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 Convertible Notes, please refer to Note 10 contained in Appendix A to this Annual Report on Form 10-K.
Interest expense under the Convertible Notes is as follows (dollars in thousands):
 
Year Ended December 31, 2016
 
Year Ended December 31, 2015
Accretion of debt discount and issuance costs
$
3,969

 
$
4,699

2.25% accrued interest
2,845

 
3,532

Total interest expense from the Convertible Notes
$
6,814

 
$
8,231

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 $15.7 million , $23.6 million and $25.6 million during the years ended December 31, 2016 , 2015 and 2014 , respectively. We expect our capital expenditures to be lower in fiscal 2017 , as compared to 2016, as we pursue lower cost solutions for connecting to enterprise and C&I end-users' energy data, we do not anticipate substantial office build-outs, and we expect to have fewer R&D employees dedicated to internal-use software development.
Off-Balance Sheet Arrangements
As of December 31, 2016 , 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, 2016 , we had outstanding letters of credit totaling $24.4 million . For information on these commitments and contingent obligations, see “Liquidity and Capital Resources—Borrowings and Credit Arrangements” above and Note  10 contained in Appendix A to this Annual Report on Form 10-K.

39



Contractual Obligations
Information regarding our significant contractual obligations is set forth in the following table. Payments due by period have been presented based on payments due subsequent to December 31, 2016 (in millions):
 
Payments Due By Period
Contractual Obligations
Total
 
Less than
1 Year
 
1-3
Years
 
3-5
Years
 
More than
5 Years
Convertible Notes: principal
$
126.8

 
$

 
$
126.8

 
$

 
$

Convertible Notes: interest
7.4

 
2.8

 
4.6

 

 

Operating lease obligations (1)
27.8

 
7.9

 
15.3

 
4.3

 
0.3

Business acquisition deferred purchase price (2)
0.7

 

 
0.7

 

 

Total contractual obligations
$
162.7

 
$
10.7

 
$
147.4

 
$
4.3

 
$
0.3

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 13 to our consolidated financial statements contained in Appendix A to this Annual Report on Form 10-K.
(1) Our operating lease obligations relate primarily to the leases of our corporate headquarters in Boston, Massachusetts and our offices in San Francisco, California; Baltimore, Maryland; Boise, Idaho; Australia; New Zealand; United Kingdom; Ireland; South Korea; Brazil and India.
(2) In connection with a business acquisition completed in 2011, we are required to pay additional cash consideration of $0.7 million in 2018 that was deferred at the date of the acquisition. The remainder of the deferred purchase price will be settled in 254,654 shares of our common stock, which was recorded as additional paid-in capital on the acquisition date and is not remeasured to fair value either periodically or upon settlement as it meets certain criteria. We have no other open contingent purchase price obligation as of December 31, 2016.
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, 2016 and 2015 were $22.9 million and $20.2 million , respectively. For the year ended December 31, 2016 , 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, including consolidated adjusted EBITDA and free cash flow. These non-GAAP measures are not in accordance with, or an alternative for, generally accepted accounting principles in the United States.
The GAAP measure most comparable to consolidated adjusted EBITDA is GAAP net income (loss) attributable to EnerNOC, Inc. and the GAAP measure most comparable to free cash flow is cash flow provided by (used in) operating activities. Reconciliations of each of these non-GAAP financial measures to the corresponding GAAP measures are included below.
Use and Economic Substance of Non-GAAP Financial Measures
We use these non-GAAP measures when evaluating our operating performance and for internal planning and forecasting purposes. We believe 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, we consider consolidated 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. In addition, we consider free cash flow to be an indicator of our liquidity trend and the performance of our business.
The following is an explanation of the non-GAAP measures that we utilize, including the adjustments we make as part of the non-GAAP measures:
Management defines consolidated adjusted EBITDA as net income (loss) attributable to EnerNOC, Inc., excluding depreciation, amortization and asset impairments; stock-based compensation; gains on the sale of businesses; direct and incremental expenses or gains associated with acquisitions, divestitures, reorganizations and escrow settlements; impairment of goodwill and intangible assets; restructuring charges; gains on extinguishment of debt, interest and other income (expense), net; and benefit from (provision for) income tax.
Management defines free cash flow as net cash provided by (used in) operating activities less capital expenditures. Management defines capital expenditures as purchases of property and equipment, which includes capitalization of internal-use software development costs.

40



Material Limitations Associated with the Use of Non-GAAP Financial Measures
Consolidated 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 as 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 used by other companies, even where similarly titled, and therefore should not be used to compare our performance to that of other companies.
Consolidated adjusted EBITDA
Consolidated adjusted EBITDA was $(4.0) million , $(24.1) million and $70.4 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. The reconciliation of consolidated adjusted EBITDA to net income (loss) attributable to EnerNOC, Inc. is set forth below (dollars in thousands):
 
Years Ended December 31,
 
2016
 
2015
 
2014
Net income (loss) attributable to EnerNOC, Inc.
$
(50,410
)
 
$
(185,075
)
 
$
12,094

Depreciation, amortization and asset impairments (1)
34,151

 
40,287

 
31,417

Stock-based compensation
12,455

 
14,585

 
16,063

Restructuring charges (2)
7,519

 

 

Gains on sale of businesses (3)
(19,875
)
 
(2,991
)
 
(6,962
)
Direct and incremental (gains) expenses associated with acquisitions, divestitures, reorganizations and escrow settlements (4)
(2,713
)
 
3,222

 
3,550

Impairment of goodwill and intangible assets

 
108,763

 

Gain on extinguishment of debt

 
(9,230
)
 

Interest and other expense, net
12,929

 
16,390

 
8,355

Provision for (benefit from) income tax
1,961

 
(10,010
)
 
5,876

Consolidated adjusted EBITDA
$
(3,983
)
 
$
(24,059
)
 
$
70,393

 
 
 
 
 
 
Demand Response adjusted EBITDA
$
68,427

 
$
52,274

 
$
128,670

Software adjusted EBITDA
(53,505
)
 
(58,300
)
 
(38,551
)
Corporate unallocated expenses
$
(18,905
)
 
$
(18,033
)
 
$
(19,726
)
(1) Includes impairments of production equipment no longer in operation.
(2) Includes employee related severance and retention costs, asset impairments, and contract termination costs associated with approved restructuring plans.
(3) Consolidated adjusted EBITDA excludes gains on the sale of businesses. Prior period results have been updated to conform to current period presentation.
(4) Includes expenses that are direct and incremental to business acquisitions and divestitures, including third-party professional fees for legal, accounting and valuation services; employee related costs associated with reorganizing the business; and a gain recorded in the year ended December 31, 2016 associated with the recovery of an escrow settlement claim as further described in Note 15 .
Free Cash Flow
Cash flows from operating activities were $(44.8) million , $3.2 million and $60.4 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. We had $(60.5) million , $(20.5) million and $34.9 million of free cash flow for the years ended December 31, 2016 , 2015 and 2014 , respectively. The reconciliation of cash flows from operating activities to free cash flow is set forth below (dollars in thousands):
 
Year Ended December 31,
 
2016
 
2015
 
2014
Net cash provided by operating activities
$
(44,769
)
 
$
3,172

 
$
60,439

Subtract: Purchases of property and equipment and capitalization of internal use software
(15,704
)
 
(23,629
)
 
(25,553
)
Free cash flow (1)
$
(60,473
)
 
$
(20,457
)
 
$
34,886

(1) Free cash flow does not include cash received from the sale of businesses. Prior period results have been updated to conform to current period presentation.
Critical Accounting Policies and Use of Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these consolidated financial statements

41



requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates, including those related to revenue recognition for multiple element arrangements, allowance for doubtful accounts, valuations and purchase price allocations related to business combinations, expected future cash flows including growth rates, discount rates, terminal values and other assumptions and estimates used to evaluate the recoverability of long-lived assets and goodwill, amortization methods and periods, certain accrued expenses and other related charges, stock-based compensation, contingent liabilities, tax reserves and recoverability of our deferred tax assets and related valuation allowance. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates if past experience or other assumptions do not turn out to be substantially accurate. Any differences could have a material impact on our financial condition and results of operations.
Of our significant accounting policies, which are described in Note 1 to our consolidated financial statements contained in Appendix A to this Annual Report on Form 10-K, we believe that the following accounting policies involve a greater degree of judgment and complexity. Accordingly, these are the policies we believe are the most critical to aid in fully understanding and evaluating our financial condition and results of operations.
Revenue Recognition
We recognize revenues in accordance with ASC 605, Revenue Recognition. 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.
Revenues from the sales of our demand response solutions to our utility customers and 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 also earn revenues from our demand response solutions in the form of ongoing fees from utility customers for the 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.
Revenue is generally recognized as we perform these services. In some cases, fees paid by our customers are subject to retroactive refund based on how we perform over the entire contractual performance period. In cases where we are not able to reliably estimate the amount of fees potentially subject to refund or adjustment, we defer revenue until the end of the delivery period. This estimate is based on several factors, including how performance is measured in the program, our historical performance in the program or similar programs, the significance of the potential penalty and other factors.
Revenue from the sale of our EIS is derived from subscription fees paid by customers for access to and use of our cloud based platform for a specified period of time, which is typically three years. We recognize revenue ratably over the contractual service period commencing upon delivery of the EIS to the customer. The most significant judgment or estimate in standalone EIS revenue arrangements is the collectibility of fees based on our assessment of the customer's credit worthiness. We closely monitor our cash collections and will defer revenue when we deem that collection is not reasonable assured.
Revenue from the sale of our energy procurement solutions is derived from fees paid by energy suppliers and energy consumers who utilize our online auction platform. Fees are paid by our customers based on the amount of energy consumed under energy contracts entered into as a result of the use of our auction platform based on a contractual commission rate. Revenue is recognized monthly as energy is consumed. To the extent actual energy information is not available, we utilize historical usage data and overall industry trends to estimate usage and adjust this estimate in the period in which actual usage data is received. To date, differences between actual and estimated usage have not been significant.
We periodically enter into multiple-element arrangements with our customers in which a customer may purchase a combination of our EIS and other service, such as demand response, procurement solutions or professional services. We account for multi-element arrangements under ASU 2009-13,  Multiple Element Arrangements , whereby we assess whether each element has standalone value and determine the revenue to be recognized for each unit of accounting based on the standard’s fair value hierarchy, including best estimate of selling price, and then allocate the value of each element in the arrangement based on its relative selling price. Estimates and judgment in this process include our assessment of whether a service has standalone value and, if so, the relative selling price of each item in the arrangement.
For further discussion of revenue recognition and the impact of the new revenue recognition guidance provided by ASC 606 , which we adopted using the modified retrospective method as of January 1, 2017, please refer to Note 1 contained in Appendix A to this Annual Report on Form 10-K.
Business Combinations
We record tangible and intangible assets acquired and liabilities assumed in business combinations under the purchase method of accounting. Amounts paid for each acquisition are allocated to the assets acquired and liabilities assumed based on their fair

42



value at the date of acquisition. The fair value of identifiable intangible assets is based on valuations that use information and assumptions, such as the financial forecasts of acquired entities, customer attrition rates, and our weighted average cost of capital. We primarily use the income approach to determine the estimated fair value of identifiable intangible assets, including customer relationships, non-compete agreements, developed technology and trade names. We estimate the fair value of contingent consideration, if applicable, at the time of the acquisition based on its estimated probability of payment using all pertinent information known to us at the time. We allocate any excess purchase price over the fair value of the net tangible and intangible assets acquired and liabilities assumed to goodwill. The use of different assumptions could materially impact the purchase price allocation and our financial condition and results of operations. As of December 31, 2016, there are no further contingent purchase price arrangements or preliminary purchase price allocations that are subject to adjustment or revision.
Acquired Intangible Assets
We amortize our intangible assets that have finite lives using either the straight-line method or, if reliably determinable, based on the pattern in which the economic benefit of the asset is expected to be consumed utilizing expected undiscounted future cash flows. Amortization is recorded over the estimated useful lives ranging from one to fourteen years. We review our intangible assets subject to amortization to determine if any adverse conditions exist or a change in circumstances has occurred that would indicate impairment or a change in the remaining useful life. If the carrying value of an asset exceeds its undiscounted cash flows, we will write-down the carrying value of the intangible asset to its fair value in the period identified. In assessing recoverability, we must make assumptions regarding estimated future cash flows. If these estimates or related assumptions change in the future, we may be required to record an impairment charge. To the extent fair value estimates are required, we generally calculate fair value as the present value of estimated future cash flows to be generated by the asset using a risk-adjusted discount rate. In estimating the useful life of the acquired assets, we primarily consider our expected future use of the asset in our business and the forecasted, directly associated cash flows expected to be generated from the use of the asset.
If the estimate of an intangible asset’s remaining useful life is changed, we amortize the remaining carrying value of the intangible asset prospectively over the revised remaining useful life. If the intangible asset is sold as part of a larger asset group, we cease to amortize the intangible asset and we adjust the carrying value of the asset group to fair value. We must exercise judgment to determine whether the intangible asset qualifies as held for sale and the fair value of the asset group. We utilize market data, recent third-party offers for the asset group and other available data to determine fair value.
Goodwill
As of December 31, 2016, we had $36.7 million of goodwill on the balance sheet. Goodwill is assessed annually for impairment on November 30 and at other times during the year based upon the existence of certain indicators of impairment. Goodwill is tested for impairment at the reporting unit level using a two-step process: the first step compares the fair value of the reporting unit to its carrying value. If the carrying value exceeds the fair value, the second step of the test is performed to measure the amount of impairment loss, if any. In order to determine the fair value of our reporting units, we utilize an income approach using a discounted cash flow model incorporating our most recently approved five-year forecast. The key assumptions that drive the fair value in this model are the discount rates, terminal values, growth rates, changes in working capital and the amount and timing of expected future cash flows. The annual impairment testing process is subjective and requires judgment at many points throughout the analysis. If these estimates or their related assumptions change in the future, we may be required to record additional impairment charges for these assets not previously recorded.
For the 2016 test, we identified three reporting units: (1) Demand Response, (2) Subscription Software and Services, and (3) Energy Procurement Solutions. The estimated fair value of these reporting units exceeded their respective carrying value. As a result, a step two analysis was not required. Our annual goodwill impairment test for the prior year, conducted as of November 30, 2015, resulted in the recognition of a $108.8 million goodwill impairment charge.
As a result of our adoption of the new revenue recognition guidance under ASC 606, we anticipate recording an increase to our Energy Procurement Solutions reporting unit’s net assets. The anticipated increase in net assets is expected to be greater than the excess fair value over the carrying value of net assets as of our annual impairment test on November 30, 2016. Therefore, we expect to perform an interim impairment test for the Energy Procurement Solutions reporting unit during the first quarter of 2017. Based on the fair value assumptions used in our November 30, 2016 impairment test, we anticipate recording a goodwill impairment charge in the first quarter of 2017 of up to $5.8 million related to this reporting unit, which is part of the Software segment.
In future periods, we may be subject to additional factors that constitute a change in circumstances, indicating that the carrying value of goodwill could exceed fair value. These changes may consist of, but are not limited to, a sustained decline in the our market capitalization, reduced future cash flow estimates, an adverse action or assessment by a regulatory agency, or slower growth rates in our industry. Any of these factors, or others, could require us to record a charge to earnings in the consolidated financial statements during the period in which any impairment of goodwill is determined, negatively impacting our results of operations.

43



Impairment of Long-Lived Assets
We review long-lived assets, including property, equipment and capitalized software costs, for impairment whenever events or changes in circumstances indicate that the carrying amount of assets may not be recoverable over their remaining estimated useful life. If these assets are considered to be impaired, the long-lived assets are measured for impairment at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets or liabilities. Impairment is recognized in earnings and equals the amount by which the carrying value of the assets exceeds their fair value determined by either a quoted market price, if any, or a value determined by utilizing a discounted cash flow technique. If these assets are not impaired, but their useful lives have decreased, the remaining net book value is amortized over the revised useful life.
During the years ended December 31, 2016 , 2015 and 2014 , certain production equipment was removed from operational sites or abandoned. As such, the equipment had no remaining useful life and no fair value. The remaining net carrying value was written off, resulting in the recognition of impairment charges of $1.1 million , $0.5 million , and $1.1 million , respectively, which is included in cost of revenues in the accompanying consolidated statements of operations. In addition, in 2016 we modified a non-cancelable sublease agreement with a third-party for excess office space in our corporate headquarters. In connection with this sublease, we determined that the carrying value for the associated leasehold improvements and furniture and fixtures would not be recovered. Accordingly, we recorded a $2.5 million impairment charge to adjust these long-lived assets to fair value.
We classify long-lived asset groups as "held for sale" when our board of directors approves the sale of the asset group and it is probable that the sale will occur within one year, among other criteria. If the asset group represents a business, goodwill is assigned based on the asset group's fair value relative to the applicable reporting unit in which the business resides. Long-lived assets that are included in the asset group are reclassified to "held for sale" on the consolidated balance sheet and are no longer depreciated or amortized. If the initial carrying value of the asset group exceeds its fair value less cost to sell, the carrying value of the asset group is adjusted through an impairment charge. If certain criteria are met, cumulative translation adjustments are assigned to the asset group for purposes of determining its carrying amount. Subsequent changes in fair value, not to exceed the initial carrying value of the asset group, are recorded through earnings until the asset group is sold, at which time the resulting gain or loss is recorded in the consolidated statement of operations within "gains (losses) on sale of businesses".
Software Development Costs
We capitalize eligible costs associated with software developed or obtained for internal use. We capitalize the payroll and payroll-related costs of employees and applicable third-party costs that devote time to the development of internal-use computer software. We amortize these costs on a straight-line basis over the estimated useful life of the software, which is generally three to five years. Our judgment is required in determining the point at which various projects enter the stages at which costs may be capitalized, in assessing the ongoing value and impairment of the capitalized costs, and in determining the estimated useful lives over which the costs are amortized. Internal use software development costs of $9.8 million , $8.4 million and $6.0 million for the years ended December 31, 2016 , 2015 and 2014 , respectively, have been capitalized. As of December 31, 2016 , there were $12.6 million of unamortized software development costs on the balance sheet. We assessed the recoverability of these costs and determined that they were recoverable based on forecasted cash flows and direct costs associated with these cash flow.
Stock-Based Compensation
We issue various types of stock-based awards to employees, non-employees, board members and advisory board members under stockholder-approved plans. When applicable, we measure compensation cost at fair value on the grant date and recognize this cost as stock-based compensation expense over the requisite service period. We make estimates and assumptions that impact the amounts of expense recognized in our consolidated statement of operations, including estimated forfeiture rates. Also, for awards which include performance conditions, we make estimates as to the probability that the underlying performance conditions will be met. Changes to these estimates and assumptions may have a significant impact on the value and timing of stock-based compensation expense, which could have a material impact on our consolidated financial statements.
For stock option awards, determining the amount of stock-based compensation to be recorded requires us to develop estimates to be used in calculating the grant-date fair value. We use a lattice model to determine the fair value of our stock option awards which requires the consideration of a number of factors to determine the fair value of stock option awards. The model requires us to make estimates on various items including the risk-free interest rate, vesting term, expected volatility and forfeiture rate.

44



Accounting for Income Taxes
We determine deferred tax assets and liabilities based on the difference between the financial reporting and tax bases of our assets and liabilities. We measure deferred tax assets and liabilities using enacted tax rates and laws that will be in effect when we expect the differences to reverse. Our provision for income taxes is comprised of a current and a deferred provision. The current income tax provision is calculated as the estimated taxes payable or refundable on tax returns for the current year. The deferred income tax provision is calculated for the estimated future tax effects attributable to temporary differences and carryforwards by using expected tax rates in effect in the years during which the differences are expected to reverse or the carryforwards are expected to be realized.
Our net deferred tax assets primarily relate to net operating loss and tax credit carryforwards, and deductible temporary differences. In determining the realizability our net deferred tax assets and the need for a valuation allowance, we weigh the available positive and negative evidence to determine if it is more likely than not that some or all of our net deferred tax assets will be realized. In making these determinations, we are required to make judgments and estimates about our domestic and foreign profitability, the timing and extent of the utilization of net operating loss carryforwards, applicable tax rates, transfer pricing methodologies and tax planning strategies. Judgments and estimates related to our projections and assumptions are inherently uncertain; therefore, actual results could differ materially from our projections. We have accumulated consolidated net losses since our inception and as a result, we have recorded a valuation allowance against the majority of our deferred tax assets.
We have recorded certain tax reserves to address potential exposures involving our income tax positions. These potential tax liabilities result from the varying application of statutes, rules, regulations and interpretations by different taxing jurisdictions. Uncertainty in income taxes is recognized in our financial statements using a two-step process to determine the amount of tax benefit to be recognized. The tax position must first be evaluated to determine the likelihood that it will be sustained upon external examination. If the tax position is deemed more-likely-than-not to be sustained, the tax position is then assessed to determine the amount of benefit to recognize in the financial statements. The amount of the benefit that may be recognized is the largest amount that we believe has a greater than 50% likelihood of being realized upon ultimate settlement.
In the ordinary course of global business, there are many transactions and calculations where the ultimate tax outcome is uncertain. Judgment is required in determining our worldwide income tax provision. Although we believe our estimates are reasonable, no assurance can be given that the final outcome of tax matters will be consistent with our historical income tax accruals, and the differences could have a material impact on our income tax provision and operating results in the period in which such determination is made.
Recent Accounting Pronouncements
For a discussion of recent accounting pronouncements and the potential impact on our consolidated financial statements upon the adoption of these accounting pronouncements, please refer to Note 1, "Description of Business, Basis of Presentation and Summary of Significant Accounting Policies" to our consolidated financial statements included in Appendix A to this Annual Report on Form 10-K.

45



Selected Quarterly Financial Data
The table below sets forth selected unaudited quarterly financial information. The information is derived from our unaudited consolidated financial statements and includes, in the opinion of management, all normal and recurring adjustments that management considers necessary for a fair statement of results for such periods. The operating results for any quarter are not necessarily indicative of results for any future period (in thousands, except share and per share data).
Year Ended December 31, 2016
1st Qtr
 
2nd Qtr
 
3rd Qtr  
 
4th Qtr
Revenues
$
53,380

 
$
132,694

 
$
167,781

 
$
50,104

Gross profit
20,786

 
51,163

 
70,816

 
19,728

Operating expenses
60,974

 
46,910

 
47,395

 
42,802

(Loss) income from operations
(40,188
)
 
4,253

 
23,421

 
(23,074
)
Net (loss) income
(40,569
)
 
97

 
20,618

 
(30,624
)
Basic net (loss) income per share:
$
(1.41
)
 
$
0.00

 
$
0.70

 
$
(1.04
)
Diluted net (loss) income per share:
$
(1.41
)
 
$
0.00

 
$
0.65

 
$
(1.04
)
Year Ended December 31, 2015
1st Qtr
 
2nd Qtr
 
3rd Qtr
 
4th Qtr (1)
Revenues
$
50,551

 
$
72,500

 
$
217,324

 
$
59,209

Gross profit
18,595

 
38,957

 
74,178

 
22,803

Operating expenses
64,236

 
56,867

 
55,730

 
165,668

(Loss) income from operations
(45,641
)
 
(17,910
)
 
18,448

 
(142,865
)
Net (loss) income
(50,305
)
 
(18,790
)
 
12,964

 
(128,987
)
Basic net (loss) income per share:
$
(1.80
)
 
$
(0.66
)
 
$
0.46

 
$
(4.51
)
Diluted net (loss) income per share:
$
(1.80
)
 
$
(0.66
)
 
$
0.44