PART I
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:
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energy cost visualization, budgets, forecasts, and accruals, which provide our enterprise customers with the ability to develop accurate energy budgets and track cost accruals;
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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;
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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;
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energy project tracking, which allows our enterprise customers to track the progress and impact of savings measures that have been implemented;
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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.
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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:
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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;
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identify opportunities to go to market based on their current contracts, their risk profile, and current market conditions;
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manage energy contracts in a single location providing a more effective way to monitor expirations and current market exposure; and
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better understand risk in their energy portfolio.
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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.
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.
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.
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:
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Manufacturing/Industrial
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Commercial Real Estate
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Healthcare/Pharmaceutical
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General Motors
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Beacon Properties
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Athena Health Care Associates
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Kimberly-Clark, Inc.
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Beal Companies
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George Washington University Hospital
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Leggett & Platt
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Equity Office Properties
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Lonza Group AG
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Saint Gobain
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Morgan Stanley
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Temecula Valley Hospital
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US Silica
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Washington Realty Investment Trust
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Government
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Education
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Food Sales and Storage
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Baltimore Regional Cooperative Purchasing Committee
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California State University
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Great Lakes Cold Storage
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City of Albany, NY
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Colorado State University
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Shop Rite
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City of Corpus Christi, TX
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Knox County Schools
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SuperVALU
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County of Los Angeles, CA
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North Penn School District
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Weis Markets
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U.S. Postal Service
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Wicomico County Public Schools
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The Division of Capital Asset Management and Maintenance of the Commonwealth of Massachusetts
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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:
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the level of understanding and ability to segment the commercial and industrial customer base that the provider is able to deliver to the utility;
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the pricing of the demand response solutions being offered; and
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the financial stability, historical performance levels and overall experience of the provider.
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When competing for enterprise customers, we believe that the primary factors on which we compete are:
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the ability of the provider to service multiple sites across different geographic regions and to provide valuable software and technology-enabled solutions;
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the ability of the provider to apply customer-specific tariff and other pricing components to energy data; and
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the level of sophistication employed by the provider to identify and optimize energy management capabilities and opportunities.
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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
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
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
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.
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
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
challenges we may face as we enter and attempt to expand in international markets. International operations also entail a variety of other risks, including:
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compliance with numerous legislative, regulatory or market requirements of foreign countries;
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currency exchange fluctuations;
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longer payment cycles and greater difficulty in accounts receivable collection;
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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;
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difficulties in developing, staffing, and simultaneously managing a large number of varying foreign operations as a result of distance, language, and cultural differences;
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laws and business practices that favor local competitors or prohibit foreign ownership of certain businesses;
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potentially adverse tax consequences;
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compliance with laws of foreign countries, international organizations, such as the European Commission, treaties, and other international laws;
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insufficient revenues to offset increased expenses associated with acquisitions;
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assumption of liabilities and exposure to unforeseen liabilities of acquired companies;
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the inability to continue to benefit from local subsidies due to change in control; and
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unfavorable labor regulations.
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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.
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.
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:
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our ability to integrate our technology with new and existing hardware and software systems, including metering, building control, process control, and distributed generation systems;
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our ability to anticipate and support new standards, especially Internet-based standards and building control and metering system protocol languages; and
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our ability to integrate additional software modules under development with our existing technology and operational processes.
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If we are unable to adequately address any of these factors, our results of operations and prospects for growth could be materially adversely affected.
We may face certain product liability or warranty claims if we disrupt our customers’ networks or applications, or if our 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:
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utilizing components that we or third parties install or have installed at customer and C&I end-user sites;
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relying on metering information provided by third parties to accurately and reliably provide data to our utility customers and electric power grid operators;
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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
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outsourcing certain installation and maintenance operations to third-party providers.
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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
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:
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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;
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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:
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diversion of management time, including a shift in focus from operating the businesses to issues related to integration and administration;
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inadequate management resources available for integration activity and oversight;
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failure to retain and motivate key employees;
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failure to successfully manage relationships with customers and suppliers;
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failure of customers to accept our demand response solutions and EIS;
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failure to effectively coordinate sales and marketing efforts;
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failure to combine service offerings quickly and effectively;
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failure to effectively enhance acquired technology, applications, services and products or develop new applications, services and products relating to the acquired businesses;
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difficulties and inefficiencies in managing and operating businesses in multiple locations or operating businesses in which we have either limited or no direct experience;
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difficulties integrating financial reporting systems;
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difficulties in the timely filing of required reports with the SEC; and
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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;
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difficulties in achieving the expected synergies from an acquisition including taking longer than expected to achieve those synergies;
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incurring future impairment charges related to diminished fair value of businesses acquired as compared to the price we paid for them;
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restructuring operations or reductions in workforce, which may result in substantial financial charges; and
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issuance of potentially dilutive equity securities and/or the incurrence of debt or contingent liabilities, which could harm our financial condition.
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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
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:
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incur additional indebtedness;
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enter into transactions with affiliates;
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transfer assets; make certain acquisitions;
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pay dividends or make distributions on, or repurchase, EnerNOC stock;
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merge or consolidate; or
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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
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
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:
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earthquake, fire, flood and other natural disasters;
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terrorist attacks and attacks by computer viruses or hackers;
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computer systems, Internet, telecommunications or data network failure.
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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
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
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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
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:
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demand for and acceptance of our demand response solutions and EIS;
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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;
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changes in open market bidding program rules and reductions in pricing for demand response capacity;
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delays in the implementation and delivery of our demand response solutions and EIS which may impact the timing of our recognition of revenues;
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delays or reductions in spending for demand response solutions and EIS by our electric power grid operator or utility customers and potential enterprise customers;
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the long lead time associated with securing new customer contracts;
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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;
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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;
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the termination or expiration of existing contracts with electric power grid operators, utility customers, enterprise customers and/or C&I end-users;
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potential interruptions of our customers’ or C&I end-users' operations;
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development of new relationships and maintenance and enhancement of existing relationships with customers and strategic partners;
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temporary capacity programs that could be implemented by electric power grid operators and utilities to address short-term capacity deficiencies;
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the imposition of penalties or the reversal of deferred revenue due to our failure to meet a capacity commitment;
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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;
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global economic and credit market conditions; and
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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:
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demand for and acceptance of our demand response solutions and EIS;
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our ability to develop new relationships and maintain and enhance existing relationships with customers and strategic partners;
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termination of or rule changes in open market bidding programs and/or reductions in pricing for demand response capacity;
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the termination or expiration of existing contracts with enterprise and utility customers;
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general market conditions and overall fluctuations in equity markets in the United States;
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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;
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introduction of technological innovations or new demand response solutions and EIS by us or our competitors;
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actual or anticipated variations in quarterly revenues and operating results;
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the financial guidance we may provide to the public, any changes in such guidance or our failure to meet such guidance;
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changes in estimates or recommendations by securities analysts that cover our common stock;
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delays in the implementation and delivery of our demand response solutions and EIS which may impact the timing of our recognition of revenues;
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litigation or regulatory enforcement actions;
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changes in the regulations affecting our industry in the United States and internationally;
|
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|
|
•
|
the way in which we recognize revenues and the timing associated with our recognition of revenues;
|
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|
|
|
•
|
developments with respect to recent acquisitions, including with respect to expected synergies, and any unforeseen integration costs or impairment charges;
|
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|
|
|
•
|
developments or disputes concerning patents or other proprietary rights;
|
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|
|
•
|
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:
|
|
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|
•
|
allow the authorized number of directors to be changed only by resolution of our board of directors;
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|
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|
•
|
require that vacancies on the board of directors, including newly created directorships, be filled only by a majority vote of directors then in office;
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|
|
•
|
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;
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•
|
require that stockholder actions must be effected at a duly called stockholder meeting and prohibit stockholder action by written consent;
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|
•
|
prohibit cumulative voting in the election of directors, which would otherwise allow holders of less than a majority of stock to elect some directors;
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|
•
|
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;
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|
•
|
limit who may call stockholder meetings; and
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|
|
|
•
|
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.
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|
Item 1B.
|
Unresolved Staff Comments
|
None.
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.
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|
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|
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.
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.
|
|
|
|
|
|
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
|
)
|
|
|
|
|
|
|
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;
|
|
|
|
|
•
|
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
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.
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.
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.
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.
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
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
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
|
)%
|
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.
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
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
|
|
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.
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.
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.
|
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
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
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.
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.
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.
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
|
|
|
$
|
(4.51
|
)
|
(1)
The three month period ended December 31, 2015 includes a goodwill impairment charge of
$108.8 million
, net of a
$7.9 million
tax benefit, as well as a
$9 million
gain on the extinguishment of debt. The three month periods ended June 30, 2016 and September 30, 2016 include gains on the sale of businesses of $17.4 million and $2.3 million, respectively. The three month period ended September 30, 2016 includes a gain of $3.5 million from the settlement of an escrow account and a charge of $2.9 million related to restructuring activities. Please refer to Notes 3, 4 and 15 to our financial statements contained in Appendix A to this Annual Report on Form 10-K for further information.
|
|
|
|
|
|
Item 7A.
|
Quantitative and Qualitative Disclosure About Market Risk
|
Foreign Currency Exchange Risk
Our international businesses are subject to risks, including, but not limited to, unique economic conditions, changes in political climate, differing tax structures, other regulations and restrictions, and foreign exchange rate volatility. Accordingly, our future results could be materially adversely impacted by changes in these or other factors.
A majority of our foreign revenue and expenses are transacted in local currencies. Fluctuations in foreign currency rates could affect our revenue, cost of revenues and profit margins and could result in foreign exchange losses. In addition, currency devaluations could result in losses if we maintain deposits or receivables (third-party or intercompany) in the devalued foreign currency. Revenues generated outside of the United States for the years ended December 31,
2016
,
2015
and
2014
were
23%
,
21%
and
19%
, respectively, of our consolidated revenues. We anticipate that revenues generated outside the United States will continue to represent greater than 10% of our consolidated revenues.
International operating expenses for the years ended December 31,
2016
,
2015
and
2014
, that are incurred in local currencies were approximately
17%
,
16%
, and
15%
, respectively, of consolidated operating expenses. Our operating results and certain assets and liabilities that are denominated in foreign currencies are affected by changes in the relative strength of the U.S. dollar against the applicable foreign currency. Our operating expenses denominated in foreign currencies are positively affected when the U.S. dollar strengthens against the applicable foreign currency and adversely affected when the U.S. dollar weakens.
In June 2016, the citizens of the United Kingdom (UK) voted to leave the European Union, an event that is commonly referred to as "Brexit." A near term effect of Brexit was a weakening of the British Pound (GBP) of approximately 17% relative to the U.S. dollar and other currencies. Our operations in the UK are not significant and comprise less than 1% of our revenue and less than 2% of our operating expenses. We maintain intercompany loans and receivables with our UK affiliates and, as a result, the weakening of the GBP resulted in unrealized foreign exchange losses of approximately $3.5 million for the year ended December 31, 2016.
During the years ended December 31,
2016
,
2015
and
2014
, we recognized foreign exchange losses of
$4.4 million
,
$8.0 million
and
$4.4 million
, respectively. These losses primarily relate to intercompany loans denominated in foreign currencies, largely driven by fluctuations in the Canadian dollar, Euro, GBP and Australian dollar relative to the U.S. dollar. As of December 31, 2016, the effect of a hypothetical 10% adverse change in exchange rates related to these currencies relative to the U.S. dollar would increased our foreign exchange losses by between $6 million to $8 million.
We currently do not have a program in place that is designed to mitigate our exposure to changes in foreign currency exchange rates. From time to time we evaluate potential programs, including the use of derivative financial instruments, to reduce our exposure to foreign exchange gains and losses, and the volatility of future cash flows caused by changes in currency exchange rates. The utilization of forward foreign currency contracts could reduce, but not eliminate, the impact of currency exchange rate movements.
Interest Rate Risk
We incur interest expense on borrowings outstanding under our Convertible Notes and 2014 credit facility. The Convertible Notes have a fixed interest rate. The interest on revolving loans under the 2014 credit facility accrues, at our election, at either (i) the LIBOR (determined based on the per annum rate of interest at which deposits in U.S. dollars are offered to SVB in the London interbank market) plus 2.00%, or (ii) the “prime rate” as quoted in the Wall Street Journal with respect to the relevant interest period plus 1.00%.
As of December 31,
2016
and 2015, we had no aggregate principal amount outstanding under the 2014 credit facility and had outstanding letters of credit totaling
$24.4 million
and $22.4 million, respectively.
The return from cash equivalents, which are maintained in money market accounts, will vary as short-term interest rates change. A hypothetical 10% increase or decrease in interest rates, however, would not have a material adverse effect on our financial condition or results of operations.
Commodity Risk
We are exposed to certain risks related to our ongoing business, including the variability of energy pricing in certain open-market demand response programs. In one particular program, we manage this risk through the use of a commodity swap arrangement. In this arrangement, we deliver MW capacity and receive a variable price based on market conditions. We convert this variable fee to a fixed fee by paying or receiving funds from the counterparty to the arrangement based on the difference between the agreed fixed price and the market price. This arrangement does not contain a required minimum delivery volume, has no notional amount and is effective for one year. A hypothetical 10% increase or decrease in the pricing of MW in this market would not have a material adverse effect on our financial condition, or results of operations.
|
|
|
|
|
|
Item 8.
|
Financial Statements and Supplementary Data
|
All financial statements and schedules required to be filed hereunder are included as Appendix A hereto and incorporated into this Annual Report on Form 10-K by reference.
|
|
|
|
|
|
Item 9.
|
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
|
None.
|
|
|
|
|
|
Item 9A.
|
Controls and Procedures
|
Disclosure Controls and Procedures.
Our principal executive officer and principal financial officer, after evaluating the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this Annual Report on Form 10-K, have concluded that, based on such evaluation, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to our management, including our principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act as a process designed by, or under the supervision of, our principal executive and principal financial officers and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, and includes those policies and procedures that:
|
|
|
|
•
|
pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets;
|
|
|
|
|
•
|
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and directors; and
|
|
|
|
|
•
|
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
|
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.
Our management assessed the effectiveness of our internal control over financial reporting as of
December 31, 2016
. In making this assessment, management used the criteria set forth by the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 Framework), or the COSO criteria.
Based on this assessment, management concluded that, as of
December 31, 2016
, our internal control over financial reporting was effective based on these criteria.
Ernst & Young LLP, the independent registered public accounting firm that audited our consolidated financial statements included elsewhere in this Annual Report on Form 10-K, has issued an attestation report on our internal control over financial reporting. That report appears below in this Item 9A under the heading “Report of Independent Registered Public Accounting Firm.”
Changes in Internal Control Over Financial Reporting
No change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the fiscal quarter ended
December 31, 2016
that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
EnerNOC, Inc.
We have audited EnerNOC, Inc.’s internal control over financial reporting as of December 31, 2016 based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). EnerNOC, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, EnerNOC, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of EnerNOC, Inc. as of December 31, 2016 and December 31, 2015, and the related consolidated statements of operations, comprehensive (loss) income, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2016 of EnerNOC, Inc. and our report dated
March 15, 2017
expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Boston, Massachusetts
March 15, 2017
|
|
|
|
|
|
Item 9B.
|
Other Information
|
Not applicable.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except share and per share data)
1. Description of Business, Basis of Presentation and Summary of Significant Accounting Policies
Description of Business
EnerNOC, Inc. (the Company) is a leading provider of demand response solutions and energy intelligence software (EIS) to enterprises, utilities, and electric power grid operators.
The Company’s demand response solutions provide utilities and electric power grid operators with a managed service demand response resource that matches obligation in the form of megawatts (MW) that the Company agrees to deliver to utility customers and electric power grid operators, with supply, in the form of MW that are curtailed from the electric power grid through the Company's arrangements with commercial and industrial end-users of energy (C&I end-users). When called upon by utilities and electric power grid operators to deliver contracted capacity, the Company uses its global Network Operations Center (NOC) to remotely manage and reduce electricity consumption across its network of C&I end-user sites, making demand response capacity available to utilities and electric power grid operators on demand, while helping C&I end-users achieve energy savings, improve financial results and realize environmental benefits.
The Company’s EIS provides enterprises with a Software-as-a-Service (SaaS) energy management application that enables them to better manage and control energy costs for their organizations. The Company offers premium professional services that support the implementation of its EIS and help its enterprise customers set their energy management strategies while also providing energy audit and retro-commissioning services. The Company's energy procurement solutions provide customers with the ability to more effectively manage their energy supplier selection and energy procurement process by providing highly-structured, SaaS-enabled auction events.
Basis of Presentation
The accompanying consolidated financial statements of the Company include the accounts of its wholly-owned subsidiaries and have been prepared in conformity with accounting principles generally accepted in the United States. Intercompany transactions and balances are eliminated in consolidation. The Company owns a
60%
equity interest in EnerNOC Japan K.K. (ENOC Japan), for which it consolidates in accordance with Accounting Standards Codification (ASC) 810,
Consolidation
(ASC 810),
and accounts for the remaining
40%
as a non-controlling interest.
Reclassifications
Effective during the first quarter of 2016, the Company began operating
two
reportable segments: Demand Response and Software. The Company updated the presentation of the revenue categories on its consolidated statements of operations. The Company has reclassified prior period revenue categories to conform to the current period presentation. This reclassification had no impact on total revenue or any other income statement result. For further discussion regarding the Company's reorganization and the impact on segment reporting, please refer to Note 2. The Company has made other reclassifications to prior period financial statement balances to conform with current period presentation, none of which were material to the consolidated financial statements.
Summary of Significant Accounting Policies
i) Use of Estimates in the Preparation of Financial Statements
The preparation of these consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Significant estimates made by management relate to revenue recognition reserves, allowance for doubtful accounts, the underlying inputs for the valuation of assets and liabilities acquired in business combinations, the fair value of reporting units, including forecasted cash flows and weighted average cost of capital used in the Company's goodwill impairment analysis, expected future cash flows used to evaluate the recoverability of long-lived assets, amortization methods and periods, valuation of cost-method investments, certain accrued expenses and other related charges, stock-based compensation, contingent liabilities, tax reserves and recoverability of the Company's net deferred tax assets and related valuation allowance. While the Company believes that such estimates are fair when considered in conjunction with the consolidated financial statements taken as a whole, the actual amounts of such items, when known, could differ from these estimates.
ii) Cash and Cash Equivalents and Restricted Cash
Cash and cash equivalents are comprised of highly liquid investments with insignificant interest rate risk and maturities of three months or less at the time of acquisition. The Company held no marketable securities as of December 31, 2016 or 2015. Restricted cash represents amounts required to be set aside by a contractual agreement with an insurer for the settlement of employee medical and dental claims in connection with the Company's domestic health insurance plan and amounts ascribed to a performance guarantee for a demand response program.
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported on the consolidated balance sheets that sum to the total of the same such amounts shown in the consolidated statement of cash flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
Cash and cash equivalents
|
$
|
97,993
|
|
|
$
|
138,120
|
|
|
$
|
254,351
|
|
|
$
|
149,189
|
|
|
Restricted cash
|
1,062
|
|
|
464
|
|
|
813
|
|
|
1,834
|
|
|
Total cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows
|
$
|
99,055
|
|
|
$
|
138,584
|
|
|
$
|
255,164
|
|
|
$
|
151,023
|
|
iii) Revenue Recognition
The Company recognizes revenue in accordance with ASC 605,
Revenue Recognition
(ASC 605). The Company's customers include enterprises, grid operators, and utilities. The Company derives revenue from the sale of its demand response solutions and EIS and recognizes revenue when persuasive evidence of an arrangement exists, delivery has occurred, the fee is fixed or determinable, and collection is deemed to be reasonably assured. The following is a description of the Company's revenue recognition polices and procedures under ASC 605.
Demand Response
Revenue from the Company's demand response solutions, which are provided to utility customers and grid operators pursuant to contractual commitments over defined service delivery periods, primarily consists of capacity fees, which are paid to the Company for the commitment to deliver MW through curtailment of energy via a portfolio of C&I end-users, and energy fees, which are paid to the Company for actual MW delivery. Revenue is generally recognized as the Company performs these services during the contractual delivery period. In some cases, fees paid are subject to retroactive refund based on how the Company performs over the entire contractual performance period. In cases where the Company is not able to reliably estimate the amount of fees potentially subject to refund or adjustment, revenue is deferred until the end of the delivery period.
The Company's largest customer, PJM Interconnection (PJM), is an electric power grid operator serving the mid-Atlantic region of the United States. The Company currently participates in three PJM programs, referred to as Limited, Extended and Annual. Although each program has a different delivery period, the Company receives payments for all three programs ratably throughout PJM’s fiscal year, which ends May 31. The delivery period for the Limited program is June through September. The delivery period for the Extended program is June through October plus the following May. The delivery period for the Annual program is June through the following May. In all three programs, cash received is subject to retroactive adjustment or refund based on performance during the delivery period. As the Company is unable to reliably estimate this refund amount, revenues are deferred until the completion of the delivery period. Due to the timing of revenue recognition and cash receipts from PJM, significant unbilled or deferred revenue balances may be generated. In addition, contracted payments to C&I end-users may result in significant capitalized incremental direct contract costs and/or accrued capacity payments. In the case of the Limited program, because the delivery period ends before the end of PJM’s fiscal year, a portion of the revenues earned are recorded and accrued as unbilled revenue.
The Company recognizes demand response energy revenues when earned. Energy revenue is deemed to be substantive and represents the culmination of a separate earnings process and is recognized when the energy event is initiated by the electric power grid operator or utility customer and the Company has responded under terms of the contract or open market program. During the years ended December 31, 2016, 2015 and 2014 the Company recognized
$3,128
,
$1,642
, and
$26,460
, respectively, of energy event revenues.
The Company maintains a reserve for customer adjustments and allowances as a reduction to revenues. In determining the revenue reserve estimate, the Company relies on historical data and known performance adjustments. These factors, and unanticipated changes in the economic and industry environment, could cause the Company’s reserve estimates to differ from actual results. The Company records a provision for estimated customer adjustments and allowances in the same period as the related revenues are recorded. These estimates are based on the specific facts and circumstances of a particular program, analysis of credit memo data, historical customer adjustments, and other known factors. If the data the Company uses to calculate these estimates does not properly reflect reserve requirements, then a change in the allowances would be made in the period in which such a determination was made and revenues in that period could be affected. The Company's revenue reserves were
$275
and
$975
as of
December 31, 2016
and
2015
, respectively.
Software: Subscription Software, Procurement Solutions and Professional Service
Subscription software revenues are derived from fees paid by customers for access to and use of the Company's EIS, which is a cloud-based solution. Revenue is recognized ratably over the contractual service period, which is typically three years, commencing upon delivery of the EIS to the customer. The Company generally charges an up front fee related to the installation and activation of EIS. In addition, the Company provides professional services related to the implementation of EIS, including training and integrations services. Revenue for the EIS implementation and activation services is recognized as one unit of accounting over the subscription period.
Revenue from the sale of energy procurement solutions is derived from fees paid by energy suppliers and energy consumers who utilize the Company's online auction platform. Fees are paid by these customers based on the amount of energy consumed under contracts procured using the Company's auction platform. Revenue is recognized monthly as actual or estimated energy is consumed. To the extent actual energy information is not available, the Company utilizes historical usage data and overall industry trends to estimate usage and adjusts this estimate in the period in which actual usage data is received. To date, differences between actual and estimated usage have not been significant. The Company also provides procurement advisory professional services to commercial and industrial customers. Revenue is recognized as these services are provided.
Revenue from professional services is generally recognized as delivered. Revenue from professional services related to the implementation of EIS, which includes training and integration services, is recognized over the term of the EIS subscription. The Company periodically enters into multiple-element arrangements with its customers in which a customer may purchase a combination of EIS and other services, such as demand response, procurement solutions, or professional services. The Company accounts for multi-element arrangements under Accounting Standards Update (ASU) 2009-13,
Multiple Element Arrangements
, whereby the Company assesses whether each element has standalone value and, if so, determines the relative fair value of each element based on the hierarchy provided by ASU 2009-13, which includes best estimate of selling price, and then allocates value to each element in the arrangement based on its relative selling price and recognizes revenue for each element as it is delivered to the customer.
iv) Cost of Revenues
Cost of revenues primarily consist of amounts owed to C&I end-users for their participation in the Company’s demand response network and are generally recognized over the same performance period as the corresponding revenue. The Company enters into contracts with its C&I end-users under which it delivers recurring cash payments to them for the capacity they commit to make available on demand. In certain demand response programs, the Company makes energy payments when a C&I end-user reduces consumption of energy during a demand response event. The demand response equipment and installation costs for the Company’s devices located at its C&I end-user and third-party sites, which monitor energy usage, communicate with C&I end-user sites and, in certain instances, remotely control energy usage to achieve committed capacity, are capitalized and depreciated over the lesser of the remaining estimated customer relationship period or the estimated useful life of the equipment, and this depreciation is reflected in cost of revenues. The Company also includes in cost of revenues the amortization of acquired developed technology, amortization of capitalized internal-use software costs related to its demand response solutions and EIS, telecommunications and data costs incurred as a result of being connected to enterprise customer and C&I end-user sites, the wages and associated benefits that it pays to its professional services personnel for the performance of their services, and related costs of revenue related to the delivery of services of its utility bill management solution.
v) Concentrations of Credit Risk
Financial instruments that could subject the Company to significant concentrations of credit risk principally consist of cash and cash equivalents, accounts receivable and unbilled revenue. The Company maintains its cash and cash equivalent balances with highly rated financial institutions and as a result, such funds are subject to minimal credit risk.
The Company’s significant customers consist of PJM, the Australian Independent Market Operator Wholesale Electricity Market (AEMO), the Korea Power Exchange (KPX) and Southern California Edison Company (SCE). PJM is an electric power grid operator customer in the mid-Atlantic region of the United States that is comprised of multiple utilities and was formed to control the operation of the regional power system, coordinate the supply of electricity, and establish fair and efficient markets. AEMO is an entity that was established to administer and operate the Western Australia wholesale electricity market. KPX is an electric power grid operator in South Korea. SCE is an electrical utility providing service to commercial and residential consumers in southern California.
The following table presents revenue generated from the Company’s significant customers, comprising more than
10%
of the Company’s consolidated revenues for the years ended December 31,
2016
,
2015
or
2014
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
Revenues
|
|
% of Total
Revenues
|
|
Revenues
|
|
% of Total
Revenues
|
|
Revenues
|
|
% of Total
Revenues
|
|
PJM
|
$
|
179,465
|
|
|
44
|
%
|
|
$
|
161,743
|
|
|
40
|
%
|
|
$
|
246,405
|
|
|
52
|
%
|
|
AEMO
|
n/a
|
|
|
< 10%
|
|
|
$
|
28,138
|
|
|
7
|
%
|
|
$
|
54,930
|
|
|
12
|
%
|
The following table presents customers who comprised
10%
or more of the Company’s accounts receivable balance.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
PJM
|
11
|
%
|
|
16
|
%
|
|
21
|
%
|
|
KPX
|
21
|
%
|
|
< 10%
|
|
|
< 10%
|
|
|
AEMO
|
< 10%
|
|
|
11
|
%
|
|
12
|
%
|
|
SCE
|
< 10%
|
|
|
< 10%
|
|
|
17
|
%
|
Unbilled revenue related to PJM was
$43,653
and
$68,859
at
December 31, 2016
and
2015
, respectively. There was no significant unbilled revenue for any other customers at
December 31, 2016
and
2015
.
vi) Cost-Method Investments
The Company accounts for equity investments that do not have a readily determinable fair value in accordance with ASC 325-20,
Cost-Method Investments
, whereby the investments are initially recorded at historical cost as long-term assets and are periodically assessed for indicators of a reduction to fair value that is other than temporary under the provisions of ASC 320,
Investments—Debt and Equity Securities
. During 2016, management recorded impairment losses of
$1,764
, included in "other expense, net", associated with these cost-method investments due to a decline in fair value that was deemed to be other than temporary. The Company's assessment was based on an evaluation of all available information, including current financial forecasts, recent or pending capital investments and financings related to these cost-method investments. As of
December 31, 2016
and 2015, the carrying amount of cost-method investments was
$736
and
$2,500
, respectively. These investments are subject to ongoing risk given the future financial condition and results of operations of the underlying entities. See Note
7
for further discussion of the Company's fair value considerations.
vii) Fair Value of Financial Instruments
The Company measures the fair value of financial instruments pursuant to the guidelines of ASC 820,
Fair Value Measurement
, (ASC 820) which establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to quoted market prices in active markets for identical assets and liabilities (Level 1), then to quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active and model-based valuation techniques for which all significant assumptions are observable in the market (Level 2), and then to model-based techniques that use significant assumptions not observable in the market (Level 3). See Note
7
for further fair value disclosures.
viii) Property and Equipment
Property and equipment, which includes computer equipment, office equipment, internal-use software, furniture and fixtures, and leasehold improvements, is stated at cost and depreciated using the straight-line method over the estimated useful lives of the respective assets, ranging from
three
to
ten
years. Production equipment is depreciated over the lesser of its useful life or the customer relationship period, which historically has been approximately
three
years. Leasehold improvements are amortized over their useful life or the remaining lease term, whichever is shorter. Expenditures that improve or extend the life of an asset are capitalized while repairs and maintenance expenditures are expensed as incurred. The estimated useful lives, by asset classification, are as follows:
|
|
|
|
|
|
|
Estimated Useful Life (Years)
|
|
Production equipment
|
3
|
|
Computers and office equipment
|
3
|
|
Furniture and fixtures
|
5
|
|
Software
|
3 - 5
|
ix) Software Development Costs
The Company delivers its software as a service to its customers. As a result, certain internal use software development costs qualify for capitalization under the provisions of ASC 350-40,
Internal Use Software
, as amended by ASU 2015-05. The Company capitalizes the payroll, payroll-related costs and external fees of its employees and external consultants who devote time to the application development stage of internal-use software projects. The Company amortizes these costs on a straight-line basis over the estimated useful life of the software, which is generally
three
years. The Company’s judgment is required in determining 1) software projects that qualify for capitalization, 2) the point at which various projects enter the stages at which costs may be capitalized, 3) the ongoing value and potential impairment of the capitalized costs, and 4) the estimated useful lives over which the costs are amortized.
x) Business Combinations
The Company records 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 values at the dates of acquisition. The fair value of identifiable intangible assets is based on valuations that use information and assumptions provided by the Company. The Company primarily uses the income approach to determine the estimated fair value of identifiable intangible assets, including customer relationships, non-compete agreements and trade names. The Company estimates 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 the Company at the time. The Company allocates any excess purchase price over the fair value of the net tangible and intangible assets acquired and liabilities assumed to goodwill.
xi) Impairment of Long-Lived Assets
The Company reviews long-lived assets, including property and equipment and intangible assets, for impairment in accordance with ASC 360,
Impairment and Disposal of Long-Lived Assets
, whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable over its remaining estimated useful life. 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. In assessing recoverability, the Company makes assumptions regarding estimated future cash flows. To the extent a fair value estimate is required, the Company generally calculates fair value as the present value of estimated future cash flows to be generated by the asset using a risk-adjusted discount rate, or the value indicated by a probable transaction with a third-party. Impairment expense is recognized in the consolidated statement of operations as the amount by which the carrying value of the asset exceeds its fair value. If these assets are not impaired, but their useful lives have decreased, the remaining net book value is amortized over the revised useful life.
The Company periodically impairs equipment deployed at third-party locations as a result of the removal of such equipment from these sites prior to the end of the originally estimated life of the arrangement. Impairment charges of
$1,104
,
$713
, and
$1,071
, were included in cost of revenues in the accompanying consolidated statements of operations, for the years ended
2016
,
2015
, and
2014
, respectively.
The Company classifies long-lived asset groups as "held for sale" when the Company's 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 Company adjusts the carrying value of the asset group 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".
xii) Intangible Assets
The Company amortizes its intangible assets that have finite lives using either the straight-line method or, if reliably determinable, based on the pattern over 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. The Company reviews its 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. The Company had no indefinite-lived intangible assets as of December 31, 2016 and 2015.
xiii) Goodwill
Goodwill represents the amount of purchase price in excess of the fair values assigned to the underlying identifiable net assets of acquired businesses. In accordance with ASC 350,
Intangibles—Goodwill and Other
(ASC 350), the Company tests goodwill at the reporting unit level for impairment on an annual basis on November 30 and between annual tests if events or circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying value. Events that would indicate impairment and trigger an interim impairment assessment include, but are not limited to, current economic and market conditions, including a decline in market capitalization, a significant adverse change in legal factors, business climate or operational performance of the business, an adverse action or assessment by a regulator, or the realignment of the Company's organization and management structure.
In determining the Company’s reporting units, management considers how the components of the business are managed, whether discrete financial information is available and whether any such components may be aggregated based on economic similarity. As previously discussed, during the first quarter of 2016, the Company commenced operating two reportable segments: Demand Response and Software. Management subsequently concluded that these reportable segments also
represented the Company's new reporting units (for purposes of goodwill impairment testing). Accordingly, goodwill was reallocated from the Company’s 2015 reporting units (previously defined as North America Software and Services and International), to the new reporting units (Demand Response and Software) on a relative fair value basis. Subsequent to a reorganization of the business on September 30, 2016, the Company concluded that, as of the November 30, 2016 goodwill testing date, the Company had three reporting units: (1) Demand Response, (2) Subscription Software and Services and (3) Energy Procurement Solutions, with the latter two reporting units falling within the Software reportable segment. Accordingly, goodwill was reallocated from the Company's first quarter 2016 Software reporting unit to the new Subscription Software and Services and Energy Procurement Solutions reporting units on a relative fair value basis.
In performing the annual goodwill impairment test, the Company utilizes the two-step approach as currently prescribed under ASC 350. The first step compares the carrying value of the reporting unit to its fair value. If the carrying value exceeds fair value, the second step of the test is performed to measure the amount of impairment loss, if any. The second step of the goodwill impairment test compares the implied fair value of a reporting unit’s goodwill to its carrying value. To calculate the implied fair value of goodwill in the second step, the Company allocates the fair value of the reporting unit to all of the assets and liabilities of that reporting unit (including any previously unrecognized intangible assets) as if the reporting unit had been acquired in a current business combination and the fair value was the price paid to acquire the reporting unit. The excess of the fair value of the reporting unit over the amount assigned to the assets and liabilities of the reporting unit represents the implied fair value of goodwill. If the carrying value of goodwill exceeds the implied fair value of goodwill, an impairment loss is recognized for the difference.
In order to determine the fair value of its reporting units, the Company utilizes a discounted cash flow model. The key assumptions that drive fair value in the discounted cash flow model are the discount rates, terminal values, growth and profitability rates, and the amount and timing of expected future cash flows based on management's projected financial information. The Company ensures that the collective fair value of the reporting units reconciles to the market capitalization, which is calculated as the market price per share of the Company's common stock multiplied by common shares outstanding, while taking into consideration a reasonable premium that a market participant would pay to obtain control of the Company (i.e. the control premium). Please refer to Note
5
for further discussion of the Company's current year impairment test.
xiv) Research and Development Expenses
Research and development expenses consist primarily of (a) salaries and related personnel costs, including costs associated with stock-based compensation awards, related to the Company’s research and development personnel, (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) other related overhead. Costs incurred in research and development are expensed as incurred.
xv) Stock-Based Compensation
The Company grants share-based awards to employees, non-employees, members of the board and advisory board members. The Company accounts for grants of stock-based compensation in accordance with ASC 718,
Stock Compensation
(ASC 718). The Company accounts for stock-based compensation awards granted to non-employees in accordance with ASC 505-50,
Equity Based Payments to Non-Employees,
which results in the Company continuing to re-measure the fair value of the non-employee share-based awards until such time as the awards vest. All stock-based awards granted, including grants of stock options, restricted stock and restricted stock units, are recognized in the statement of operations based on their fair value as of the date of grant. As of December 31, 2016, the Company had two stock-based compensation plans, which are more fully described in Notes 11 and
12
.
Shares underlying awards of restricted stock and restricted stock units are not transferable until they vest. Restricted stock and restricted stock units typically vest ratably over a
three
year period from the date of issuance, with certain exceptions. The fair value of restricted stock and restricted stock units, upon which vesting is solely service-based, is expensed ratably over the vesting period. With respect to restricted stock and restricted stock units where vesting contains certain performance-based vesting conditions, the fair value is expensed based on the accelerated attribution method as prescribed by ASC 718. With the exception of certain executives whose employment agreements provide for continued vesting in certain circumstances upon departure, if the employee who received the restricted stock or restricted stock unit leaves the Company prior to the vesting date for any reason, the shares of restricted stock or restricted stock unit are forfeited and returned to the Company.
The fair value of stock options is estimated on the date of grant using a lattice valuation model. The lattice model considers characteristics of fair value option pricing that are not available under the Black-Scholes model. Similar to the Black-Scholes model, the lattice model takes into account variables such as expected volatility, dividend yield rate, and risk free interest rate. However, in addition, the lattice model considers the probability that the option will be exercised prior to the end of its contractual life and the probability of termination or retirement of the option holder in computing the value of the option. For these reasons, the Company believes that the lattice model provides a fair value that is more representative of actual experience and future expected experience than the value calculated using the Black-Scholes model.
A summary of significant assumptions used to estimate the fair value of stock options granted to employees in 2015 and 2014 is as follows in the table shown below. The Company did not grant stock options in 2016.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2015
|
|
2014
|
|
Risk-free interest rate
|
2.5
|
%
|
|
2.5
|
%
|
|
Vesting term, in years
|
2.3
|
|
|
2.2
|
|
|
Expected annual volatility
|
70
|
%
|
|
70
|
%
|
|
Expected dividend yield
|
—
|
|
|
—
|
|
|
Exit rate pre-vesting
|
7.70
|
%
|
|
7.70
|
%
|
|
Exit rate post-vesting
|
14.06
|
%
|
|
14.06
|
%
|
The risk-free interest rate is the rate available as of the option date on zero-coupon U.S. Treasury securities with a term equal to the expected life of the option. Volatility measures the amount that a stock price has fluctuated or is expected to fluctuate during a period. The Company calculates volatility using a component of implied volatility and historical volatility to determine the value of share-based payments. The Company has not paid dividends on its common stock in the past and does not plan to pay any dividends in the foreseeable future. In addition, the terms of the 2014 credit facility preclude the Company from paying dividends.
In accordance with ASC 718, the Company records stock-based compensation net of estimated forfeitures. The Company periodically evaluates its employee demographics and historical forfeiture experience to determine if its estimated pre-vesting and post-vesting exit rates need to be revised. During the years ended December 31,
2016
and
2015
, the Company did not change its estimated pre-vesting and post-vesting exit rates.
xvi) Income Taxes
The Company uses the asset and liability method to account for income taxes. Under this method, the Company determines deferred tax assets and liabilities based on the difference between financial reporting and tax bases of its assets and liabilities. The Company measures deferred tax assets and liabilities using enacted tax rates and laws that will be in effect when the differences are expected to reverse. The Company’s deferred tax assets relate primarily to net operating losses and tax credit carryforwards, intangible assets, deferred revenue, and stock-based compensation. The Company has accumulated consolidated net losses since its inception and, as a result, has recorded a valuation allowance against certain of its deferred tax assets given the uncertainty as to the realizability of these assets. Deferred tax liabilities primarily relate to acquisitions, depreciation of property and equipment, and the convertible senior notes issued in 2014.
ASC 740,
Income Taxes
(ASC 740)
,
prescribes a recognition threshold and measurement criteria for tax positions taken or expected to be taken in a tax return. ASC 740 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition and defines the criteria that must be met for the benefits of a tax position to be recognized.
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 the Company’s worldwide income tax provision. Although the Company believes its estimates are reasonable, no assurance can be given that the final outcome of tax matters will be consistent with its historical income tax accruals, and the differences could have a material impact on the Company’s income tax provision and operating results in the period in which such determination is made.
xvii) Foreign Currency Translation
The financial statements of the Company’s international subsidiaries are translated in accordance with ASC 830,
Foreign Currency Matters
(ASC 830), into the Company’s reporting currency, which is the United States dollar. The functional currencies of the Company’s subsidiaries are the local currencies.
Assets and liabilities are translated to the United States dollar from the local functional currency at the exchange rate in effect at each balance sheet date. Revenues and expenses are translated using average exchange rates during the respective periods. Foreign currency translation adjustments are recorded as a component of stockholders’ equity within accumulated other comprehensive loss.
Prior to translation, the Company remeasures foreign currency denominated assets and liabilities, including certain intercompany balances, which have not been deemed a “long-term investment,” as defined by ASC 830, into the functional currency of the respective entity, resulting in unrealized gains or losses recorded in the consolidated statements of operations within other expense, net. Realized and unrealized losses of
$4,400
,
$8,040
, and
$4,417
, arising from transactions denominated in foreign currencies and the remeasurement of certain intercompany balances, are included in the consolidated statements of operations for the years ended December 31,
2016
,
2015
and
2014
, respectively.
xviii) Comprehensive (Loss) Income
Comprehensive (loss) income is defined as the change in equity of a business enterprise during a period resulting from transactions and other events and circumstances from non-owner sources. The Company’s comprehensive (loss) income is composed of net (loss) income and foreign currency translation adjustments. As of December 31,
2016
, accumulated other comprehensive loss was comprised entirely of cumulative foreign currency translation adjustments. The Company presents its components of other comprehensive (loss) income, net of related tax effects, which have not been material to date.
xix) Related Party Transactions
Transactions with related parties that are material to the consolidated financial statements are disclosed. A related party is an entity that can control or significantly influence the management or operating policies of another entity to the extent one of the entities may be prevented from pursuing their own interests. The Company has determined that there were no material related party transactions requiring disclosure in these consolidated financial statements other than as referenced in Note 4 with respect to the sale of a business component to a significant shareholder.
xx) Variable Interest Entities
The Company evaluates all legal entities in which it maintains an ownership interest in accordance with ASC 810.
ENOC Japan was formed in 2014 for the purpose of providing the Company's demand response services in Japan. ENOC Japan meets the definition of a VIE and management has concluded that the Company is the primary beneficiary of ENOC Japan. Therefore, the Company consolidates the financial results of ENOC Japan and accounts for the remaining
40%
as a non-controlling interest. The net assets of ENOC Japan included in the consolidated balance sheets as of December 31, 2016 and 2015 were
$582
and
$757
, respectively. There are no restrictions on the use of these net assets. The Company and the non-controlling interest holder are mutually responsible for the ongoing funding of the entity, as needed, and may do so through additional investments of the entity's common stock whereby following each round of investments the Company will continue to retain a
60%
voting interest. The Company faces financial risks with respect to its investment in ENOC Japan that are inherent in the entity's ongoing business operations.
Recently Adopted Accounting Standards
In November 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-18,
Restricted Cash
(ASU 2016-18). ASU 2016-18 requires that the statement of cash flows explain the changes during the period in cash, cash equivalents and restricted cash. Under the new guidance, restricted cash is included with cash and cash equivalents when reconciling beginning of period and end of period amounts shown on the statement of cash flows. The new guidance, which eliminates inconsistencies in practice with respect to the classification of changes in restricted cash on the statement of cash flows, must be adopted using the retrospective transition method for all periods presented. The Company adopted ASU 2016-18 for the three years ended December 31, 2016 by renaming the line item within cash flows from investing activities from "change in restricted cash and deposits" to "change in deposits" for all periods presented and by restating the amounts in this line from
$3,248
and
$(2,317)
to
$2,899
and
$(3,338)
for the years ended December 31, 2015 and 2014, respectively. This change resulted in an increase in net cash used in investing activities of
$349
and
$1,021
for the years ended December 31, 2015 and December 31, 2014, respectively, reflecting the reclassification of the change in restricted cash.
In August 2016, the FASB issued ASU 2016-15,
Classification of Certain Cash Receipts and Cash Payments
(ASU 2016-15). ASU 2016-15 was issued to reduce the diversity in practice in how certain cash receipts and cash payments are presented in the statement of cash flows, such as payments related to contingent consideration in connection with a business combination and debt prepayment or extinguishment costs. Under the new guidance, payments of contingent consideration should be classified as either cash flows from operating, investing or financing activities depending on the timing of the payment and the amounts originally accrued in purchase accounting. The new guidance is effective for the Company's fiscal year ending December 31, 2018 and interim periods therein and early adoption is permitted. The Company adopted the new guidance retrospectively for the three years ended December 31, 2016 by reclassifying cash outflows related to contingent consideration payments from business combinations. For the year ended December 31, 2016, the Company reclassified
$195
to cash used in financing and
$645
to cash used in operations. These contingent consideration payments of
$840
had been classified within investing activities throughout the nine months ended September 30, 2016. For the year ended December 31, 2015, the Company reclassified
$527
of contingent consideration payments that were previously included in cash used in investing activities to cash used in operating in the amount of
$308
and cash used in financing activities in the amount of
$219
.
In April 2015, the FASB issued ASU 2015-05,
Customer's Accounting for Fees Paid in a Cloud Computing Arrangement
(ASU 2015-05), which
amends Subtopic ASC 350-40,
Internal Use Software,
to exclude cloud-computing arrangements from its scope. The guidance was effective as of January 1, 2016 for arrangements entered into or materially modified after the effective date. The Company adopted this standard prospectively on January 1, 2016 and the adoption of ASU 2015-05 did not have a material impact on the Company's consolidated financial statements.
In December 2016, the FASB issued ASU 2016-19,
Technical Corrections and Improvements
(ASU 2016-19). ASU 2016-19 contains a variety of updates, certain of which did not impact the Company. The guidance amends ASC 350-40,
Intangibles-
Goodwill and Other- Internal Use Software
, to clarify that an entity that obtains a software license from a third-party should account for the license as the acquisition of an intangible asset with an associated liability for the portion of the software license fees not paid on or before the acquisition of the license. The Company adopted ASU 2016-19 as of January 1, 2016 prospectively for all arrangements containing a third-party software license, as defined, entered into or materially modified subsequent to the effective date. The costs of the software licenses acquired in 2016 have been reclassified from property and equipment to intangible assets on the consolidated balance sheet.
In February 2015, the FASB issued ASU 2015-02,
Amendments to the Consolidation Analysis
(ASU 2015-02). ASU 2015-02 updates ASC 810 and provides new guidance on how an entity should determine whether it must consolidate a legal entity under either the traditional voting model or the variable interest model. Under the variable interest model, an entity consolidates the financial results of a legal entity that it has the power to control through its voting rights and/or other contractual rights. The guidance is effective for the Company's fiscal year ended December 31, 2016 and interim periods therein. The adoption of ASU 2015-02 did not impact the Company's conclusions regarding whether it has an ownership interest in a variable interest entity or its determination of whether the Company is the primary beneficiary of a variable interest entity.
In August 2014, the FASB issued ASU 2014-15,
Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern
(ASU 2014-15). ASU 2014-15 requires that the Company evaluate, at each interim and annual reporting period, whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year after the date the financial statements are issued, and provide related disclosures. The Company adopted ASU 2014-15 effective December 31, 2016. The adoption of ASU 2014-15 did not have an impact on the Company's consolidated financial statements and related disclosures.
Recent Accounting Pronouncements
Revenue Recognition
In May 2014, the FASB issued a new standard related to revenue recognition. Under the new standard and its related amendments (collectively known as ASC 606), revenue is recognized when a customer obtains control of promised goods or services. The amount of revenue recognized will reflect the consideration that the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers.
The guidance permits two methods of adoption: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (modified retrospective method). The new standard is effective for annual reporting periods beginning after December 15, 2017, with early adoption permitted, but not before the original effective date of annual reporting periods beginning after December 15, 2016.
The Company has made the election to early adopt ASC 606 using the modified retrospective method as of January 1, 2017. This approach was applied to all contracts not completed as of January 1, 2017. The adoption of ASC 606 is expected to have a material effect on the Company's consolidated financial statements. In addition to the enhanced footnote disclosures related to customer contracts, the Company anticipates that the most significant impact of the new standard will relate to the timing of revenue recognition for certain demand response contracts and energy procurement contracts. In addition, ASC 606 is expected to change the Company's accounting for costs to obtain and fulfill a contract.
The quantitative ranges provided below are estimates of the expected effects of the Company’s adoption of ASC 606. These ranges represent management’s best estimates of the effects of adopting ASC 606 at the time of the preparation of this Annual Report on Form 10-K. The actual impact of ASC 606 is subject to change from these estimates and such change may be significant, pending the completion of the Company’s assessment in the first and second quarters of 2017. In order to complete this assessment, the Company is continuing to update and enhance its internal accounting systems and internal controls over financial reporting.
Demand Response Revenue Recognition
Several of the Company’s demand response contracts provide customers with a right of refund. In general, if the Company fails to curtail the contracted MW during an emergency or test dispatch, the MW short fall typically results in a penalty that could require the Company to reduce (or in some cases refund) fees paid by the customer during the contract period. Under the guidance in effect prior to the adoption of the new standard, certain demand response contracts that included these penalties resulted in fees that were not fixed or determinable, and therefore revenue was deferred until the fees became fixed, which in some cases was upon completion of the contract.
Under the new guidance, variable fees within the transaction price will be estimated and recognized as the Company satisfies its performance obligation, subject to a constraint. As a result, the Company expects that revenue recognition for its demand response contracts will more closely align with its efforts to provide services to the customer under ASC 606.
The Company anticipates that the adoption of ASC 606 associated with open demand response contracts as of January 1, 2017 will result in a decrease to accumulated deficit of less than
$2,000
. This anticipated adjustment represents the gross margin on
approximately
$3,500
to
$4,500
of revenue deferred as of December 31, 2016 under current guidance. Gross margin reflects revenue less cost of revenue, which includes direct and incremental payments to C&I end-users.
In addition to the contracts that are expected to impact accumulated deficit, there are various demand response contracts with performance obligations commencing in 2017 that are expected to have a material impact on the Company’s future quarterly and annual revenues as a result of the application of ASC 606. For example:
|
|
|
|
•
|
The six month delivery period for the PJM Extended program includes June 2017 through October 2017 plus May 2018. The Company anticipates that total contractual fees, prior to any performance-related penalties, will be approximately
$130,000
for this program.
|
|
|
|
|
•
|
The Company expects to participate in approximately six demand response programs for which the delivery period spans the second and third quarters of 2017.
|
Applying the recognition criteria under the current standard, revenue associated with these programs would have been deferred until the completion of the respective delivery period. Applying the guidance in ASC 606, the Company anticipates revenues under these programs to be recognized throughout the related delivery period as the Company satisfies its performance obligations to the extent that it is probable that a significant reversal of cumulative revenue recognized to date will not occur. The amount and timing of revenue recognized for these programs is impacted by the occurrence of future dispatch events, and the Company's estimated performance during these dispatch events, and, therefore, the actual revenue to be recognized over the delivery period may be different than contractual revenues.
Procurement Auction Revenue Recognition
The Company operates an auction platform that streamlines the competitive bidding process between energy suppliers and end-users of energy. The Company receives a fee from the energy supplier based on the end-user’s energy consumption under contracts procured through the auction platform. Under the guidance in effect prior to the adoption of the new standard, revenue is recognized as the end-user consumes energy under the procured contract. Under the new guidance, the variable fee paid by the energy supplier will be estimated and recognized when the Company satisfies its performance obligation (generally upon completion of the auction), to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized to date will not occur.
The Company anticipates this change in the timing of revenue recognition for open procurement contracts as of January 1, 2017 will result in a decrease to accumulated deficit of between
$30,000
and
$35,000
. The Company is currently evaluating the impact of the change in the timing of revenue recognition on the accounting for certain costs to attract end-users of energy to the auction platform. The timing of revenue recognition under ASC 606 is anticipated to generate greater variability in quarterly revenues (relative to the current guidance), as the volume and size of new contracts will have a larger "in-period" impact on reported revenue.
Other Revenue Streams
The Company derives subscription software revenues from fees paid by customers for access to and use of its cloud-based EIS. The Company does not anticipate that the adoption of ASC 606 will have a material impact on these revenue streams.
The Company also provides customized professional service solutions intended to i) help customers manage energy usage and spend and ii) enhance the implementation of subscription software, including training and integration services. In certain contracts, the Company may bundle various solutions offerings resulting in arrangements with multiple deliverables. Aggregate revenue under these arrangements is less than 5% of consolidated revenues. The Company is currently evaluating the impact of the adoption of ASC 606 on these revenue streams.
Costs to Obtain or Fulfill a Contract
Commissions are paid to internal sales representatives as compensation for obtaining subscription software, professional service and procurement solution contracts. Under ASC 606, the Company will capitalize commissions that are incremental as a result of obtaining customer contracts and costs incurred to fulfill a customer contract if those costs are not within the scope of another topic within the accounting literature and meet the specified criteria. Assets recognized for costs to obtain or fulfill a contract will be expensed as the Company transfers the related services to the customer. These assets will be periodically assessed for impairment. The Company anticipates that the adoption of ASC 606 will decrease accumulated deficit by
$3,000
to
$6,000
as of January 1, 2017 related to the capitalization of costs to obtain or fulfill open contracts.
Other Recent Accounting Pronouncements
In February 2017, the FASB issued ASU 2017-05,
Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets
(ASU 2017-05). ASU 2017-05 clarifies the scope of Subtopic 610-20,
Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets
(Subtopic 610-20), which was issued in May 2014 as part of ASC 606 and provides guidance for the recognition of gains and losses from the transfer of nonfinancial assets in contracts with noncustomers. ASU 2017-05 must be adopted at the same time as ASC 606. The Company adopted this guidance as of January 1, 2017 using the modified retrospective method consistent with its adoption of ASC 606. The adoption of ASU 2017-05 and Subtopic 610-20 is not expected to have an impact on the Company's consolidated financial statements.
In January 2017, the FASB issued ASU 2017-04,
Simplifying the Test for Goodwill Impairment
(ASU 2017-04). The new guidance eliminates Step 2 from the goodwill impairment test and, alternatively, requires that an entity should measure the impairment of goodwill assigned to a reporting unit if the carrying value of assets and liabilities assigned to the reporting unit, including goodwill, exceed the reporting unit's fair value. The new guidance must be adopted for annual and interim goodwill tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for impairment calculations performed on testing dates after January 1, 2017. The Company adopted the new guidance as of January 1, 2017. The adoption did not impact the Company's goodwill impairment test performed as of November 30, 2016. The Company does not expect that the adoption of the new guidance will materially impact future goodwill impairment charges. However, the Company expects that the elimination of Step 2 will simplify the measurement of future goodwill impairment charges, if any. The Company adopted ASU 2017-04 on January 1, 2017 and applied the guidance to the impairment calculation that was triggered as of the result of the increased net assets generated upon adoption of ASC 606, as further discussed in Note 5.
Also in January 2017, the FASB issued ASU 2017-01,
Clarifying the Definition of a Business
(ASU 2017-01). The new guidance clarifies the definition of a business for purposes of determining whether transactions should be accounted for as the acquisition or disposal of a business, and impacts all standards applicable to entities that meet the definition of a business. The Company early-adopted the new guidance as of January 1, 2017 prospectively as is permitted by the standard. The adoption of ASU 2017-01 did not have an impact on the Company's consolidated financial statements.
In March 2016, the FASB issued ASU 2016-09,
Improvements to Employee Share-Based Payment Accounting
(ASU 2016-09). ASU 2016-09 simplifies several aspects of the accounting for stock-based compensation.
|
|
|
|
•
|
On a prospective basis, all income tax effects of awards should be recognized in the statement of operations as tax expense or benefit at the time the awards vest or are settled, rather than excess tax benefits and certain deficiencies being recorded as additional paid in capital, and eliminates the requirement that excess tax benefits be realized through a reduction in income taxes payable before they can be recognized.
|
|
|
|
|
•
|
The Company permits employees to elect to satisfy their statutory withholding requirements by allowing the Company to withhold shares that would otherwise be transferred to the employee upon vesting or exercise of the award. The new guidance provides that in assessing whether an entity has withheld amounts that exceed the statutory minimum, the entity may reference the highest statutory rate of the employee's jurisdiction. In addition, the new guidance clarifies that payments made for stock-based award minimum tax withholdings should be classified as financing activities on the statement of cash flows.
|
|
|
|
|
•
|
Entities are required to elect the method of accounting for forfeitures of share-based payments, either by recognizing such forfeitures as they occur or estimating the number of awards expected to be forfeited and adjusting such estimate when it is deemed likely to change. The Company has elected to continue to estimate forfeitures under the current guidance.
|
ASU 2016-09 is effective for the Company's fiscal year ending December 31, 2017 and interim periods therein. The Company adopted the new guidance effective January 1, 2017. The related financial statement impacts of adopting the above aspects of this ASU are not expected to be material to the Company’s consolidated financial statements.
In February 2016, the FASB issued ASU 2016-02,
Leases
(ASU 2016-02). ASU 2016-02 requires lessees to recognize the assets and liabilities on their balance sheet for the rights and obligations created by most leases and continue to recognize expenses on their income statements over the lease term. The standard will also require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. The guidance is effective for annual reporting periods beginning after December 15, 2018 and interim periods within those fiscal years, with early adoption permitted. The Company does not anticipate that it will early adopt the new standard. The Company is currently evaluating the effect of the standard on its consolidated financial statements and related disclosures. The Company expects that the new guidance will require a material increase in the Company's long-lived assets, and a corresponding increase to long-term obligations, associated with its leased office space.
In January 2016, the FASB issued ASU 2016-01,
Recognition and Measurement of Financial Assets and Financial Liabilities
(ASU 2016-01), which provides new guidance on recognition and measurement of financial assets and financial liabilities. ASU 2016-01 will primarily impact the accounting for equity investments whereby equity investments in unconsolidated entities (other than those accounted for under the equity method of accounting) will generally be measured at fair value with changes in fair value recognized through earnings. The Company has equity investments that do not have a readily determinable fair value and have a carrying value of
$736
as of December 31, 2016. Under ASU 2016-01, these investments will be measured at cost, less any impairment, plus or minus change resulting from observable price changes in orderly transactions for identical or similar investments of the same issuer. In general, the new guidance will require modified retrospective application to all outstanding instruments, with a cumulative effect adjustment recorded to opening retained earnings. This guidance will be effective January 1, 2018 for the Company. The Company does not anticipate the adoption of this guidance will have a material effect on its consolidated statements and related disclosures.
2. Segment Information
Effective in the first quarter of
2016
, the Company began operating
two
reportable segments: Demand Response and Software. The Company’s Chief Operating Decision Maker (CODM), who is the Company's Chief Executive Officer, primarily evaluates the business and assesses performance based on the revenue and segment adjusted EBITDA of the Company's Demand Response and Software segments. The Company defines segment adjusted EBITDA as segment income (loss) from operations excluding depreciation, amortization and asset impairments; stock-based compensation and restructuring charges. In addition, the Company does not allocate to its operating segments certain corporate level expenses; gains and losses on the sale of businesses; impairment of goodwill; gains on extinguishment of debt as well as direct and incremental expenses and gains associated with acquisitions, divestitures, reorganizations and escrow settlements. Management considers segment adjusted EBITDA to be an important indicator of the segments' operational strength and the performance of its businesses.
The financial results of each segment are based on revenues from external customers, cost of revenues and operating expenses that are directly attributable to the segment and an allocation of costs from shared functions. These shared functions include, but are not limited to, facilities, human resources, information technology, and engineering. Allocations are made based on management’s judgment of the most relevant cost drivers, such as headcount, number of customer sites, or other operational data that contributes to the shared costs. Certain corporate level expenses, including executive, legal, and finance, have not been allocated as they are not attributable to either segment. Segment level asset information has not been provided as such information is not reviewed by the CODM for purposes of assessing segment performance and allocating resources. There are
no
intersegment sales or transactions. The accounting policies of the reportable segments are consistent with those described in Note 1, “Description of Business, Basis of Presentation and Summary of Significant Accounting Policies.”
Demand Response Segment
The Demand Response segment provides utilities and electric power grid operators with the Company’s demand response solutions. The Demand Response segment is responsible for developing and shaping demand response markets and securing future demand response obligations; procuring MW that are available for curtailment through arrangements with C&I end-users; installing and maintaining a network of EnerNOC site servers to collect energy data for use in the management of demand response programs and to support the Company's subscription software offerings; providing C&I end-users and certain utility customers with software tools to manage their demand response activities; coordinating the curtailment of MW for delivery to utilities and electric power grid operators when called upon; and financially settling with utilities, electric power grid operators, and C&I end-users.
Software Segment
The Software segment provides enterprises with the Company's EIS, which includes subscription software, energy procurement solutions, and professional services. The Software segment is responsible for developing and maintaining the Company's software platform; selling and marketing to enterprise customers; supporting customer relationships and managing customer projects; delivering software implementations, trainings, and other professional services; and managing contracts, invoicing and collection activities related to Software customer contracts.
The following table presents segment revenue and segment adjusted EBITDA, along with the reconciliation of segment adjusted EBITDA to consolidated income (loss) before income tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
Revenues:
|
2016
|
|
2015
|
|
2014
|
|
Demand Response
|
|
|
|
|
|
|
Grid operator
|
$
|
274,728
|
|
|
$
|
258,008
|
|
|
$
|
368,829
|
|
|
Utility
|
61,938
|
|
|
59,784
|
|
|
64,027
|
|
|
Total Demand Response Revenue
|
336,666
|
|
|
317,792
|
|
|
432,856
|
|
|
|
|
|
|
|
|
|
Software
|
|
|
|
|
|
|
Subscription software
|
24,799
|
|
|
19,885
|
|
|
13,880
|
|
|
Procurement solutions
|
35,603
|
|
|
36,428
|
|
|
5,733
|
|
|
Professional services
|
6,891
|
|
|
25,479
|
|
|
19,479
|
|
|
Total Software Revenue
|
67,293
|
|
|
81,792
|
|
|
39,092
|
|
|
|
|
|
|
|
|
|
Consolidated Revenue
|
$
|
403,959
|
|
|
$
|
399,584
|
|
|
$
|
471,948
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
Segment Adjusted EBITDA:
|
|
|
|
|
|
|
Demand Response adjusted EBITDA
|
$
|
68,427
|
|
|
$
|
52,274
|
|
|
$
|
128,670
|
|
|
Software adjusted EBITDA
|
(53,505
|
)
|
|
(58,300
|
)
|
|
(38,551
|
)
|
|
Total Segment adjusted EBITDA
|
14,922
|
|
|
(6,026
|
)
|
|
90,119
|
|
|
Reconciliation to consolidated income (loss) before income tax
|
|
|
|
|
|
|
Corporate unallocated expenses
|
(18,905
|
)
|
|
(18,033
|
)
|
|
(19,726
|
)
|
|
Depreciation, amortization and asset impairments
(1)
|
(34,151
|
)
|
|
(40,287
|
)
|
|
(31,417
|
)
|
|
Stock-based compensation
|
(12,455
|
)
|
|
(14,585
|
)
|
|
(16,063
|
)
|
|
Restructuring charges (Note 3)
|
(7,519
|
)
|
|
—
|
|
|
—
|
|
|
Net gains on sale of businesses (Note 4)
|
19,875
|
|
|
2,991
|
|
|
6,962
|
|
|
Direct and incremental (expenses) gains associated with acquisitions, divestitures, reorganizations and escrow settlements
(2)
|
2,713
|
|
|
(3,222
|
)
|
|
(3,550
|
)
|
|
Impairment of goodwill
|
—
|
|
|
(108,763
|
)
|
|
—
|
|
|
Gain on extinguishment of debt
|
—
|
|
|
9,230
|
|
|
—
|
|
|
Noncontrolling interest expense
|
(68
|
)
|
|
(43
|
)
|
|
(97
|
)
|
|
Interest and other income (expense), net
|
(12,929
|
)
|
|
(16,390
|
)
|
|
(8,355
|
)
|
|
Consolidated income (loss) before income tax
|
$
|
(48,517
|
)
|
|
$
|
(195,128
|
)
|
|
$
|
17,873
|
|
(1)
Includes impairments of production equipment no longer in operation.
(2)
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
.
The Company operates in the major geographic areas noted in the chart below. The “All other” designation includes revenues from other international locations, primarily consisting of Canada, Germany, Japan, Ireland, New Zealand and the United Kingdom. International revenues are based upon customer location and totaled
$91,730
,
$86,983
and
$98,214
for the years ended December 31,
2016
,
2015
and
2014
, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
United States
|
77
|
%
|
|
78
|
%
|
|
79
|
%
|
|
Australia
|
7
|
|
|
7
|
|
|
12
|
|
|
South Korea
|
7
|
|
|
4
|
|
|
—
|
|
|
All other
|
9
|
|
|
11
|
|
|
9
|
|
|
Total
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
As of
December 31, 2016
and
2015
, the long-lived tangible assets related to the Company’s international subsidiaries represented
12%
and
9%
of the Company’s long-lived tangible assets, respectively.
3. Restructuring Activities and Asset Impairment Charges
During the year ended December 31, 2016, the Company implemented a series of restructuring plans that resulted in workforce reductions and the termination of vendor and customer contracts.
Workforce Reductions
On May 23, 2016, the Company's Board of Directors approved a restructuring plan (the Q2 2016 Restructuring Plan) to reduce the Company's North American workforce by approximately
5%
in order to enhance the Company’s strategic focus, deliver operational and cost efficiencies, and sell its utility customer engagement (UCE) business. The Q2 2016 Restructuring Plan resulted in employee related charges of
$1,543
for the year ended December 31, 2016. Specifically, the charges represent severance for terminated employees and retention costs for employees who remained with the Company until the UCE business was sold in August 2016. These expenses were all paid by September 30, 2016.
On September 21, 2016, the Company's Board of Directors approved a restructuring plan (the Q3 2016 Restructuring Plan) to reduce the Company's global workforce by approximately
15%
in order to materially reduce operating expenses, primarily related to the Company’s subscription-based energy intelligence software business. The Q3 2016 Restructuring Plan resulted in employee related charges of
$2,299
. Unpaid severance benefits associated with these charges was
$1,024
as of
December 31, 2016
and is expected to be settled in the first half of 2017.
Contract Terminations
During the
year ended December 31, 2016
, the Company terminated certain vendor contracts primarily associated with annual trade shows and conferences and exited a leased facility. As a result, the Company recognized a
$719
charge for termination fees, the surrender of non-refundable deposits, and for a vacated non-cancelable facility lease.
Asset Impairment Charges
During the year ended December 31, 2016, the Company modified a sublease agreement with a third-party for excess office space in its corporate headquarters. In connection with this sublease, the Company determined that the carrying value for the associated leasehold improvements and furniture and fixtures would not be recovered, resulting in a
$2,494
impairment charge. Asset impairment charges also include a
$443
impairment of a German demand response asset group that was classified as held for sale as of December 31, 2016 (as further discussed in Note 4) and a
$21
impairment of leasehold improvements related to a facility vacated in the fourth quarter of 2016.
The following table summarizes the current year restructuring and asset impairment activities. These charges are included in "restructuring and asset impairment charges" on the consolidated statements of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee Related
|
|
Contract Terminations
|
|
Impairment of Long-Lived Assets
|
|
Total
|
|
Accrued restructuring liability at January 1, 2016
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Charges
|
3,842
|
|
|
719
|
|
|
2,958
|
|
|
7,519
|
|
|
Cash payments
|
(2,818
|
)
|
|
(690
|
)
|
|
—
|
|
|
(3,508
|
)
|
|
Adjustments for non-cash items
|
—
|
|
|
—
|
|
|
(2,958
|
)
|
|
(2,958
|
)
|
|
Accrued restructuring liability at December 31, 2016
|
$
|
1,024
|
|
|
$
|
29
|
|
|
$
|
—
|
|
|
$
|
1,053
|
|
As the Company evaluates future cost savings, additional restructuring charges may be incurred.
4. Sale of Businesses and Assets Held for Sale
During the three years ended December 31, 2016, the Company divested certain businesses and long-lived assets that management determined were not strategic to its operations. The Company concluded that none of the dispositions met the criteria of a discontinued operation as none of the operations represented a strategic shift that has had or would have a major effect on the Company's operations and financial results.
The following table summarizes the gains from the sale or divestiture of businesses and long-lived asset groups for the three years ended December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Entity
|
|
2016
|
|
2015
|
|
2014
|
|
Utility Programs Group
|
|
$
|
17,333
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
UCE
|
|
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 long-lived assets
|
|
$
|
19,875
|
|
|
$
|
2,991
|
|
|
$
|
6,962
|
|
The following is a description of each divestiture.
Utility Programs Group (UPG)
In May 2016, the Company sold the UPG business, which provided professional services to utilities with an emphasis on energy efficiency initiatives and was a component of the Software segment. The UPG business was sold to a third-party for
$14,496
in cash, of which
$1,600
was placed in escrow to cover general representations and warranties and is included in "prepaid expenses and other current assets" on the consolidated balance sheet.
Utility Customer Engagement (UCE)
In August 2016, the Company sold the UCE business, which was a component of the Software segment, to a
9%
shareholder for
$11,500
in cash, of which
$1,500
was placed in escrow to cover general representations and warranties and is included in "prepaid expenses and other current assets" on the consolidated balance sheet. Other than amounts held in escrow, there were no significant amounts due to or from the buyer as of December 31, 2016. In connection with the sale of the UCE business, all of the Company's equity interest in a wholly-owned foreign subsidiary was transferred to the buyer and, following the sale, the Company had
no
retained investment or interest in the subsidiary. Accordingly, the net assets of the subsidiary were deconsolidated and the associated cumulative currency translation adjustments, which were in an unrealized loss position prior
to the sale, were reclassified from accumulated other comprehensive loss and included as a reduction to the gain on the sale of the business.
The following table summarizes the calculation of the gains and losses as well as net assets sold associated with the sale of businesses that were transacted during the year ended December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
UPG
|
|
UCE
|
|
Total
|
|
Sale price
|
|
$
|
14,496
|
|
|
$
|
11,500
|
|
|
$
|
25,996
|
|
|
Less:
|
|
|
|
|
|
|
|
Net working capital deficit
(1)
|
|
(4,269
|
)
|
|
(849
|
)
|
|
(5,118
|
)
|
|
Fixed assets
|
|
—
|
|
|
128
|
|
|
128
|
|
|
Intangible assets
|
|
—
|
|
|
5,655
|
|
|
5,655
|
|
|
Goodwill
|
|
1,357
|
|
|
1,025
|
|
|
2,382
|
|
|
Net deferred tax liabilities
|
|
—
|
|
|
(92
|
)
|
|
(92
|
)
|
|
Net (liabilities) assets sold
|
|
(2,912
|
)
|
|
5,867
|
|
|
2,955
|
|
|
Cumulative translation losses include in long-lived asset group
|
|
—
|
|
|
2,403
|
|
|
2,403
|
|
|
Direct and incremental transaction costs
|
|
75
|
|
|
688
|
|
|
763
|
|
|
Gains on sale of businesses
|
|
$
|
17,333
|
|
|
$
|
2,542
|
|
|
$
|
19,875
|
|
(1)
Net working capital deficit primarily includes deferred revenue partially offset by accounts receivable.
German Demand Response Operations (DACH)
In December 2016, in connection with the 2016 restructure activities, the Company entered into an agreement to sell its German business operations (DACH), which were a component of the Demand Response segment. The carrying value of the asset group, which includes fixed assets, intangible assets, working capital and currency translation adjustments, exceeded its fair value. Accordingly, the asset group was adjusted to fair value, less cost to sell, through an impairment charge of
$443
in the three months ended December 31, 2016. The assets and liabilities of the asset group include intangible assets and property and equipment with an adjusted carrying value of
$2,034
, current assets of
$1,381
and current liabilities of
$1,780
, which are classified as held for sale on the consolidated balance sheet as of December 31, 2016. In January 2017, the Company completed the sale of DACH business for nominal consideration, resulting in no net gain or loss. The purchase price may be adjusted 60 days following the close upon finalization of the working capital balance. As a result of the complete liquidation of a foreign entity, the cumulative translation adjustments associated with the business, which are in an unrealized gain position of approximately
$2,370
, were included in the calculation of the impairment of the asset group and have been reclassified from accumulated other comprehensive loss in January 2017 upon the closing of the transaction.
World Energy Efficiency Services (WEES)
The acquisition of World Energy Solutions, Inc. (World Energy) in
January 2015
included the World Energy Efficiency Services business (WEES), which provided comprehensive energy efficiency services in New England. On
July 31, 2015
, a definitive asset purchase agreement was executed and the sale of WEES subsequently closed on
October 16, 2015
. The Company received
$946
in cash for the sale of the business, which included
$196
for working capital, including costs incurred on in-process contracts, and an allocation of goodwill of
$750
from the World Energy acquisition. No gain or loss was recorded on the sale.
Demand Response Resources
On April 22, 2014, the Company entered into an agreement with a third-party enterprise customer to sell its remaining two contractual demand response capacity resources related to an open market demand response program. The third-party paid for the first demand response capacity resource during the year ended December 31, 2014 resulting in a gain of
$2,171
. During the year ended December 31, 2015, the third-party paid for the second demand response capacity resource and the Company recognized a gain on the sale equal to the purchase price of
$2,991
.
Utility Solutions Consulting
On May 30, 2014, the Company sold the Utility Solutions Consulting business, which provided consulting and engineering support services to the global electric utility industry, for
$4,750
in cash. The carrying value of assets sold was
$686
, including goodwill and intangible assets. As a result of the sale, the Company recognized a gain totaling
$3,737
, net of
$327
in direct transaction costs. The Company also recognized a discrete tax charge of
$1,135
resulting from the sale, which was reflected in in the 2014 income tax provision.
Valley Tracker
On December 30, 2014, the Company sold Valley Tracker, which provided automated solutions to certain of the Company's C&I end-users, for
$1,600
in cash. The carrying value of the assets sold was
$512
, including goodwill and intangible assets. As a result of the sale, the Company recognized a gain totaling
$1,054
.
5. Goodwill and Intangible Assets
Goodwill
The following table rolls forward goodwill by reportable segment for the years ended December 31,
2016
and
2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EnerNOC, Inc.
|
|
Demand Response
|
|
Software
|
|
Total Goodwill
(1)
|
|
Balance at December 31, 2014
|
$
|
114,939
|
|
|
|
|
|
|
$
|
114,939
|
|
|
Acquisitions
|
39,579
|
|
|
|
|
|
|
39,579
|
|
|
Impairment charge
|
(108,763
|
)
|
|
|
|
|
|
(108,763
|
)
|
|
Disposals
|
(750
|
)
|
|
|
|
|
|
(750
|
)
|
|
Foreign exchange
|
(5,445
|
)
|
|
|
|
|
|
(5,445
|
)
|
|
Tax adjustment
(2)
|
187
|
|
|
|
|
|
|
187
|
|
|
Balance at December 31, 2015
(1)
|
39,747
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
39,747
|
|
|
Transfers
|
(39,747
|
)
|
|
27,391
|
|
|
12,356
|
|
|
—
|
|
|
Foreign exchange
|
—
|
|
|
(631
|
)
|
|
(72
|
)
|
|
(703
|
)
|
|
Sale of business components (Note 4)
|
—
|
|
|
—
|
|
|
(2,382
|
)
|
|
(2,382
|
)
|
|
Balance at December 31, 2016
(1)
|
$
|
—
|
|
|
$
|
26,760
|
|
|
$
|
9,902
|
|
|
$
|
36,662
|
|
(1)
Accumulated impairment losses as of
December 31, 2016
and
2015
were
$108,763
.
(2)
Purchase price adjustment related to acquisition of Pulse Energy associated with acquired deferred taxes.
The Company performs its annual goodwill impairment test as of November 30. The goodwill test is performed at the reporting unit level, which is one level below the operating segment level and is generally based on how segment management reviews financial results of the business. As discussed in Note 1, 2016, the Company reorganized its reporting structure and began operating as two reportable segments: Software and Demand Response. Accordingly, goodwill was reallocated from the Company's reporting units during the year based on the relative fair value of each business group within its original reporting unit relative to the fair value of that reporting unit as of the date of the realignment. The Company concluded that goodwill was not impaired immediately preceding and following the realignments in 2016.
As discussed in Note 1, management concluded that it had
three
reporting units as of November 30, 2016: (1) Demand Response, (2) Subscription Software and Services, and (3) Energy Procurement Solutions. During 2016, the Company used an income approach to measure the fair value of each reporting unit and compared the resulting fair value to the reporting unit's carrying amount. The income approach utilizes a DCF, which requires the use of significant estimates and assumptions, including projected revenue growth, forecasted gross margins, operating expenses, income taxes, capital expenditures, changes in working capital, projected terminal growth rates, and discount rates. These estimates and assumptions were subsequently corroborated by the Company's market capitalization. The implied control premium was considered reasonable given recent acquisitions within the industry. The fair value of each reporting unit was determined to be in excess of the carrying amount of its net assets, including goodwill. As a result, the Company was not required to apply "Step 2" of the goodwill test.
The 2015 test was performed prior to the Company's reorganization, at which time management determined that the Company had two reporting units: (1) North America Software and Services and (2) International. The resulting fair value for the North American Software and Services reporting unit was less than its carrying value, including goodwill, as of November 30, 2015, primarily due to challenging conditions in demand response markets and more gradual than anticipated acceleration of software sales. The required Step 2 of the test, which compares the implied fair value of a reporting unit’s goodwill to its carrying value, generated a pre-tax goodwill impairment charge of
$108,763
for the year-ending December 31, 2015. The implied fair value of goodwill, which utilized significant unobservable inputs, falls within Level 3 of the fair value hierarchy.
As discussed in Note 1, the Company adopted ASC 606 using the modified retrospective method as of January 1, 2017. In connection with the adoption of ASC 606, the Company anticipates recording an increase to the 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 the Company's annual impairment test on November 30, 2016. Therefore, the Company expects to perform an interim impairment test for the Energy Procurement Solutions reporting unit during the first quarter of 2017. As discussed in Note 1, the Company has early adopted the guidance of ASU 2017-04, which results in the measurement of the impairment of goodwill as the excess of the carrying value of assets and liabilities assigned to the reporting unit, including goodwill, from its fair value. Based on the fair value assumptions used in the November 30, 2016 impairment test, the Company is anticipating recording a goodwill impairment charge in the first quarter of 2017 of up to
$5,800
related to this reporting unit, which is part of the Software segment.
In future periods, the Company 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 Company's market capitalization, reduced future cash flow estimates, an adverse action or assessment by a regulatory
agency, or slower growth rates in the Company's industry. Any of these factors, or others, could require the Company to record a charge to earnings in the consolidated financial statements during the period in which any impairment of goodwill is determined, negatively impacting the Company's results of operations.
Intangible Assets
The following table provides the gross carrying amount and related accumulated amortization of the Company’s definite-lived intangible assets as of December 31,
2016
and December 31,
2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
Average
Amortization
Period (in
years)
|
|
December 31,
|
|
|
|
2016
|
|
2015
|
|
|
Gross
Carrying
Amount
|
|
Accumulated
Amortization
|
|
Gross
Carrying
Amount
|
|
Accumulated
Amortization
|
|
Customer relationships
|
5.5
|
|
$
|
51,029
|
|
|
$
|
(26,231
|
)
|
|
$
|
60,938
|
|
|
$
|
(26,043
|
)
|
|
Customer contracts
|
0.6
|
|
7,993
|
|
|
(7,789
|
)
|
|
8,042
|
|
|
(6,786
|
)
|
|
Employment agreements and non-compete agreements
|
0.6
|
|
941
|
|
|
(844
|
)
|
|
3,055
|
|
|
(2,283
|
)
|
|
Software
|
2.3
|
|
536
|
|
|
(212
|
)
|
|
170
|
|
|
(170
|
)
|
|
Developed technology
|
3.0
|
|
15,597
|
|
|
(5,307
|
)
|
|
24,168
|
|
|
(6,867
|
)
|
|
Trade name
|
0.0
|
|
344
|
|
|
(344
|
)
|
|
1,087
|
|
|
(1,035
|
)
|
|
Patents
|
3.3
|
|
180
|
|
|
(122
|
)
|
|
180
|
|
|
(104
|
)
|
|
Total
|
|
|
$
|
76,620
|
|
|
$
|
(40,849
|
)
|
|
$
|
97,640
|
|
|
$
|
(43,288
|
)
|
Amortization expense is estimated to be approximately
$7,365
,
$5,248
,
$4,490
,
$4,227
and
$14,441
for
2017
,
2018
,
2019
,
2020
and
2021
and beyond, respectively. Amortization expense for acquired developed technology is included in cost of revenue. Amortization expense for all other intangible assets is included as a component of operating expenses. A summary is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
Amortization expense included in cost of revenues
|
$
|
2,184
|
|
|
$
|
3,943
|
|
|
$
|
1,760
|
|
|
Amortization expense included in operating expenses
|
9,162
|
|
|
11,309
|
|
|
7,492
|
|
|
Total amortization expense
|
$
|
11,346
|
|
|
$
|
15,252
|
|
|
$
|
9,252
|
|
6. Net (Loss) Income Per Share
The computation of basic and diluted net (loss) income per share is as follows (in thousands, except per share information):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Numerator:
|
2016
|
|
2015
|
|
2014
|
|
Net (loss) income for basic earnings per share
|
$
|
(50,410
|
)
|
|
$
|
(185,075
|
)
|
|
$
|
12,094
|
|
|
ADD: Interest expense related to convertible notes
|
—
|
|
|
—
|
|
|
—
|
|
|
Net (loss) income for diluted earnings per share
|
$
|
(50,410
|
)
|
|
$
|
(185,075
|
)
|
|
$
|
12,094
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
Basic weighted average common shares outstanding
|
29,328,872
|
|
|
28,432,974
|
|
|
27,857,026
|
|
|
Weighted average common stock equivalents
|
—
|
|
|
—
|
|
|
933,639
|
|
|
Diluted weighted average common shares outstanding
|
29,328,872
|
|
|
28,432,974
|
|
|
28,790,665
|
|
|
|
|
|
|
|
|
|
Basic net (loss) income per share
|
$
|
(1.72
|
)
|
|
$
|
(6.51
|
)
|
|
$
|
0.43
|
|
|
Diluted net (loss) income per share
|
$
|
(1.72
|
)
|
|
$
|
(6.51
|
)
|
|
$
|
0.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average anti-dilutive shares related to:
|
|
|
|
|
|
|
Incremental shares from assumed conversion of convertible notes
|
4,576,630
|
|
|
5,712,862
|
|
|
2,151,754
|
|
|
Stock options
|
243,879
|
|
|
432,166
|
|
|
—
|
|
|
Nonvested restricted stock
|
1,277,234
|
|
|
2,124,833
|
|
|
335,849
|
|
|
Restricted stock units
|
582,530
|
|
|
60,839
|
|
|
7,924
|
|
On May 27, 2015, the Company received stockholder approval to elect to settle conversions of the aggregate outstanding principal amount of its
2.25%
convertible senior notes due August 15, 2019 (the Convertible Notes) by paying or delivering cash, shares of common stock or a combination of cash and shares of common stock. However, for purposes of the calculation of diluted net income per share, it is assumed that conversion would be settled entirely in shares of common stock. For the
years ended December 31,
2016
,
2015
and 2014, the convertible debt is not assumed to be converted as the impact of conversion is anti-dilutive. See Note
10
for further information regarding the Convertible Notes.
Restricted stock awards are excluded from the calculation of basic weighted average common shares outstanding until they vest. For restricted stock awards that vest based on achievement of performance conditions, the number of contingently issuable common shares included in diluted weighted-average common shares outstanding is based on the number of common shares, if any, that would be issuable under the terms of the arrangement if the end of the reporting period were the end of the contingency period, assuming the result would be dilutive.
The Company includes
254,654
shares of common stock related to a component of the deferred purchase price consideration for a business acquired in 2011 in the calculation of both the basic and diluted weighted-average common shares outstanding as the shares are not subject to adjustment and the issuance of such shares is not subject to any contingency. These shares are expected to be issued in 2018.
The Company excludes common shares held in escrow pursuant to business combinations from the calculation of basic weighted average shares outstanding where the release of such shares is contingent upon an event not solely subject to the passage of time. During the
year ended December 31, 2016
, in accordance with a settlement agreement as further described in Note
15
, the Company received
87,483
shares of its common stock that had been held in escrow related to the acquisition of Pulse Energy Inc. As these shares were delivered to the Company and subsequently retired, they are excluded from basic weighted average shares for the period. As of
December 31, 2016
, there were no further common shares held in escrow.
7. Fair Value Measurements
Financial Instruments and Investments
The Company's financial instruments mainly consist of cash and cash equivalents, restricted cash, accounts receivable, and accounts payable. The carrying amounts of such financial instruments approximate their fair value due to their short-term nature. In addition, the Company has long-term investments in non-marketable equity securities that are accounted for as cost-method investments. These investments are not adjusted to fair value on a recurring basis but are periodically assessed for indications of a reduction in fair value that is other than temporary. The Company's financial instruments also include its Convertible Notes for which fair value is disclosed.
Assets and Liabilities for which Fair Value Disclosure is Required
The following table presents fair value information related to the Company's Convertible Notes:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
December 31, 2015
|
|
Principal amount outstanding
|
$
|
126,800
|
|
|
$
|
126,800
|
|
|
Less: debt discount and issuance costs
|
(11,577
|
)
|
|
(15,546
|
)
|
|
Carrying value, including unamortized debt discount and issuance costs
|
115,223
|
|
|
111,254
|
|
|
Fair value
|
$
|
100,648
|
|
|
$
|
73,624
|
|
The fair value of the Convertible Notes was determined based on the quoted market price as of those dates and is classified as a Level 1 measurement.
Recurring Fair Value Measurements
The following table presents the assets and liabilities measured at fair value on a recurring basis at
December 31, 2016
and
December 31, 2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
Quoted Prices in Active Markets for
Identical Assets (Level 1)
|
|
Significant Other
Observable
Inputs
(Level 2)
|
|
Unobservable
Inputs
(Level 3)
|
|
Fair Value Measurement at December 31, 2016
|
|
|
|
|
|
|
|
|
Assets: Money market funds
|
$
|
76,008
|
|
|
$
|
76,008
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurement at December 31, 2015
|
|
|
|
|
|
|
|
|
Assets: Money market funds
|
$
|
115,847
|
|
|
$
|
115,847
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Liabilities: Contingent purchase price consideration
(1)
|
$
|
840
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
840
|
|
|
|
|
|
(1)
|
The contingent purchase price consideration as of December 31, 2015 relates to the Company's 2014 acquisition of Activation Energy DSU Limited and was reflected in accrued expense and other current liabilities as of December 31, 2015. The amount was paid in full in February 2016.
|
The following is a rollforward of the Level 3 assets and liabilities from January 1, 2014 through
December 31, 2016
:
|
|
|
|
|
|
|
|
|
Liabilities
|
|
Fair Value as of December 31, 2014
|
$
|
649
|
|
|
Cash payment during the period
|
(277
|
)
|
|
Increase due to change in assumptions and present value accretion
|
542
|
|
|
Change due to movement in foreign exchange rates
|
(74
|
)
|
|
Fair Value as of December 31, 2015
|
840
|
|
|
Cash payment during the period
|
(840
|
)
|
|
Fair Value as of December 31, 2016
|
$
|
—
|
|
Non-Recurring Fair Value Measurements
Cost-method investments and non-financial assets, such as intangible assets, property and equipment, and assets and liabilities held for sale, are adjusted to fair value only if an impairment is recognized. There were no assets or liabilities measured at fair value on a non-recurring basis at
December 31, 2015
.
During the year ended December 31, 2016, the Company recorded an impairment loss of
$1,764
, included in "other expense, net", to adjust the carrying amount of cost-method investments due to a decline in fair value that was deemed to be other than temporary. In assessing the fair value of these investments, the Company evaluated all available information, both qualitative and quantitative, including current financial forecasts, recent or pending rounds of financing activity, and other available market data. The fair value of the investments, for which the inputs are categorized as Level 3 on the fair value hierarchy, was determined based on a probability weighted assessment of liquidation scenarios. As of
December 31, 2016
, the carrying value of these investments was
$736
.
As discussed in Note
3
, during the second quarter of 2016 the Company recorded a
$2,494
impairment charge related to leasehold improvements and furniture and fixtures associated with subleased office space. The fair value of the asset group, for which the inputs are categorized as Level 3 on the fair value hierarchy, was determined based on the discrete cash flows of the asset group and incorporated assumptions relative to how a market participant would value the group.
As discussed in Note 4, during the fourth quarter of 2016 the Company recorded a
$443
impairment charge related to its German demand response business meeting the held for sale criteria, which was sold in January 2017. Prior to the sale, the carrying value of the asset group, including fixed assets, intangible assets, working capital and cumulative translation adjustments, were adjusted to fair value less cost to sell. The determination of the fair value less cost to sell of the asset group, for which the inputs are categorized as Level 3 on the fair value hierarchy, was based on the most recent offers to purchase the asset group and incorporated assumptions relative to how a market participant would value the group.
8. Allowance for Doubtful Accounts
The Company reduces gross trade accounts receivable by an allowance for doubtful accounts based on the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. The Company reviews its allowance for doubtful accounts on a regular basis and all past due balances are reviewed individually for collectibility. Account balances are charged against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Provisions for allowance for doubtful accounts are recorded in general and administrative expenses. Below is a summary of the changes in the Company’s allowance for doubtful accounts for the years ended December 31,
2016
,
2015
and
2014
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at
Beginning
of Period
|
|
Additions
Charged to
Expense
|
|
Deductions—Write-offs,
Payments and
Other Adjustments
|
|
Balance at
End of Period
|
|
Year ended December 31, 2016
|
$
|
947
|
|
|
$
|
469
|
|
|
$
|
(334
|
)
|
|
$
|
1,082
|
|
|
Year ended December 31, 2015
|
$
|
679
|
|
|
$
|
1,428
|
|
|
$
|
(1,160
|
)
|
|
$
|
947
|
|
|
Year ended December 31, 2014
|
$
|
454
|
|
|
$
|
468
|
|
|
$
|
(243
|
)
|
|
$
|
679
|
|
9. Property and Equipment
Property and equipment as of
December 31, 2016
and
December 31, 2015
consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
December 31, 2015
|
|
Computers and office equipment
|
$
|
18,074
|
|
|
$
|
30,309
|
|
|
Furniture and fixtures
|
5,343
|
|
|
5,868
|
|
|
Software
|
40,226
|
|
|
50,203
|
|
|
Back-up generators
|
8,057
|
|
|
8,405
|
|
|
Production equipment
|
45,563
|
|
|
48,819
|
|
|
Leasehold improvements
|
15,603
|
|
|
18,146
|
|
|
Construction-in-progress
|
3,205
|
|
|
2,731
|
|
|
|
136,071
|
|
|
164,481
|
|
|
Accumulated depreciation
|
(97,243
|
)
|
|
(114,828
|
)
|
|
Property and equipment, net
|
$
|
38,828
|
|
|
$
|
49,653
|
|
During the year ended December 31, 2016 the Company retired
$44,025
of fully depreciated assets that are no longer in use.
Depreciation expense was
$21,702
,
$24,322
and
$22,165
for the years ended
December 31, 2016
,
2015
and
2014
, respectively. For the years ended
December 31, 2016
,
2015
and
2014
,
$13,581
,
$14,317
and
$13,223
was included in cost of revenues, respectively, with the remainder included in general and administrative expenses.
The following rolls forward capitalized internal use software development costs, that are a component of the "Software" category above:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
|
|
Accumulated Amortization
|
|
Net
|
|
Balance as of December 31, 2015
|
$
|
44,763
|
|
|
$
|
34,702
|
|
|
$
|
10,061
|
|
|
Costs capitalized
|
9,781
|
|
|
—
|
|
|
9,781
|
|
|
Amortization
(1)
|
—
|
|
|
7,254
|
|
|
(7,254
|
)
|
|
Retirement of fully amortized software development costs
|
(16,319
|
)
|
|
(16,319
|
)
|
|
—
|
|
|
Balance as of December 31, 2016
|
$
|
38,225
|
|
|
$
|
25,637
|
|
|
$
|
12,588
|
|
(1)
Amortization of capitalized software development costs was
$6,980
and
$6,162
for the years ended December 31,
2015
and
2014
, respectively.
10. Borrowings and Credit Arrangements
Credit Agreement
In August 2014, the Company entered into a
$30,000
senior secured revolving credit facility (the 2014 credit facility) with Silicon Valley Bank (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, the Company and SVB entered into a third amendment to the 2014 credit facility for a fee of
$75
to extend the maturity date from August 9, 2016 to August 8, 2017. The Company expects to renew the 2014 credit facility prior to its expiration. The letter of credit fee charged under the 2014 credit facility is
1.50%
per annum on the face amount of any letters of credit, plus customary fronting fees. The interest on revolving loans under the 2014 credit facility will accrue, at the Company’s election, at either (i) the LIBOR (determined based on the per annum rate of interest at which deposits in United States dollars are offered to SVB in the London interbank market) plus
2.00%
, or (ii) the “prime rate” as quoted in the Wall Street Journal with respect to the relevant interest period plus
1.00%
. The revolving loans also bear a fee of
0.25%
applied to the unused portion of the revolving loans and the fee is payable quarterly.
The 2014 credit facility is subject to continued covenant compliance and borrowing base requirements. As of
December 31, 2016
, the Company was in compliance with all covenants under the 2014 credit facility. The Company believes that it is probable that it will comply with the covenants of the 2014 credit facility through its expiration date of August 8, 2017. The obligations under the 2014 credit facility and any related bank services provided by SVB are guaranteed by several of the Company’s domestic subsidiaries and are secured by substantially all of the Company’s domestic assets, other than intellectual property and other customarily excluded collateral.
The 2014 credit facility contains customary terms and conditions for credit facilities of this type, including restrictions on the ability of the Company and its subsidiaries to incur additional indebtedness, create liens, enter into transactions with affiliates, transfer assets, pay dividends or make distributions on capital stock of the Company (other than certain permitted distributions set forth therein), consolidate or merge with other entities, or suffer a change in control. In addition, the Company is required to meet certain financial covenants customary with this type of agreement, including maintaining minimum unrestricted cash and a minimum specified ratio of current assets to current liabilities.
The 2014 credit facility contains customary events of default, including for payment defaults, breaches of representations, breaches of affirmative or negative covenants, cross defaults to other material indebtedness, bankruptcy and failure to discharge certain judgments. Upon an event of default under the 2014 credit facility, SVB will have the right to accelerate the Company’s obligations under the 2014 credit facility and require the Company to cash collateralize any outstanding letters of credit. In addition, upon an event of default relating to certain insolvency events involving the Company and its subsidiaries, the obligations under the 2014 credit facility will be automatically accelerated. In the event of a termination or an event of default, the Company may be required to cash collateralize any outstanding letters of credit up to
105%
of their face amount.
As of
December 31, 2016
, the Company had
no
outstanding borrowings and had outstanding letters of credit totaling
$24,389
, under the 2014 credit facility with
$5,611
available under the 2014 credit facility for future borrowings or issuances of additional letters of credit.
Convertible Notes
On August 12, 2014, the Company sold
$160,000
aggregate principal amount of Convertible Notes due August 2019. The net proceeds from the offering were approximately
$155,278
, after deducting the initial purchasers’ discount of
$4,000
and issuance costs of approximately
$722
, of which
$400
was refunded to the Company during the year ended December 31, 2015. Total debt discount and issuance costs were allocated between the liability and equity components based on their relative values, resulting in an allocation of
$3,656
to the liability component and
$666
to the equity component.
The Company accounted for the liability and equity components of the Convertible Notes separately to reflect a non-convertible debt borrowing rate. The fair value of the liability was estimated at
$137,430
using a discounted cash flow technique, which considered debt issuances with similar features of the Company’s debt, excluding the conversion feature. The resulting effective interest rate for the Convertible Notes was
6.14%
. The
$22,566
of gross proceeds that exceeded the estimated fair value of the liability was allocated to the conversion feature (equity component, recorded as additional paid-in capital) with a corresponding offset recognized as a discount to the net carrying value of the Convertible Notes. The discount is being amortized to interest expense over a
five
-year period ending August 15, 2019 using the effective interest method. The Company evaluated the Convertible Notes in accordance with ASC 815-40,
Contracts in Entity’s Own Equity
, and determined that the Convertible Notes contained a single embedded derivative, comprising both the contingent interest feature related to timely filing failure, requiring bifurcation as the feature is not clearly and closely related to the host instrument. The Company determined that the value of this embedded derivative was nominal as of the date of issuance.
The Convertible Notes are senior unsecured obligations and rank equally with all of the Company’s future senior unsecured debt and prior to all future subordinated debt. The Convertible Notes are effectively subordinated to any future secured indebtedness to the extent of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and
other liabilities (including trade payables) of the Company’s subsidiaries. Interest on the Convertible Notes is payable semi-annually in arrears on February 15 and August 15 of each year at a rate of
2.25%
per year. The Convertible Notes will mature on August 15, 2019 unless earlier converted or repurchased.
The Convertible Notes are convertible at an initial conversion rate, subject to adjustment in some events, of
36.0933
shares of the common stock per
one thousand
dollar principal amount of the Convertible Notes (equivalent to an initial conversion price of approximately
$27.71
per share of common stock). The Company may settle conversions of the Convertible Notes by paying or delivering, as the case may be, cash, shares of common stock or a combination of cash and shares of common stock, at its election.
Prior to February 15, 2019, holders may convert all or any portion of their Convertible Notes at their option only under the following circumstances: (1) during any fiscal quarter (and only during such fiscal quarter), if the last reported sale price of the common stock for at least
20
trading days (whether or not consecutive) during the period of
30
consecutive trading days ending on the last trading day of the immediately preceding fiscal quarter is greater than or equal to
130%
of the conversion price for the Convertible Notes on each applicable trading day; (2) during the
five
business day period after any five consecutive trading day period (the measurement period) in which the trading price per
one thousand
dollars principal amount of the Convertible Notes for each trading day of the measurement period was less than
98%
of the product of the last reported sale price of the common stock and the conversion rate on each such trading day; or (3) upon the occurrence of specified corporate events. On or after February 15, 2019 holders may convert all or any portion of their Convertible Notes at any time prior to the close of business on the second scheduled trading day immediately preceding the maturity date regardless of the foregoing conditions. The Company may not redeem the Convertible Notes prior to maturity and
no
sinking fund is provided for the Convertible Notes.
If certain events occur prior to maturity, holders may require the Company to repurchase for cash all or any portion of their Convertible Notes at a repurchase price equal to
100%
of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the repurchase date. The Convertible Notes includes customary terms and covenants, including certain events of default after which the Convertible Notes may be declared or become due and payable immediately.
In December 2015, the Company completed repurchases, in cash, of
$33,200
in aggregate principal amount of the outstanding Convertible Notes at a weighted average price of
59.2%
of principal for a total purchase price of
$19,733
plus accrued and unpaid interest in privately-negotiated transactions. The cash consideration was allocated to the fair value of the liability component of the repurchased Convertible Notes immediately before extinguishment. The fair value of the liability component, which is classified as a Level 3 measurement, was determined by comparing the effective yield-to-maturity of the repurchased Convertible Notes as of the extinguishment date to the market yield for nonconvertible debt with similar characteristics. The Company recorded a gain on the extinguishment of the Convertible Notes of
$9,230
for the year ended December 31, 2015 based on the difference between the carrying amount of the repurchased Convertible Notes and the cash consideration. The gain is classified as gain on early extinguishment of debt within the consolidated statements of operations. Following the repurchases, the remaining principal amount outstanding was
$126,800
, which is reflected as convertible senior notes of
$115,223
, net of unamortized debt discount and issuance cost of
$11,577
, on the consolidated balance sheet as of December 31, 2016.
Interest expense under the Convertible Notes is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
Accretion of debt discount and issuance costs
|
$
|
3,969
|
|
|
$
|
4,699
|
|
|
$
|
1,712
|
|
|
2.25% accrued interest
|
2,845
|
|
|
3,532
|
|
|
1,330
|
|
|
Total interest expense from Convertible Notes
|
$
|
6,814
|
|
|
$
|
8,231
|
|
|
$
|
3,042
|
|
11. Stockholder's Equity
2014 Long-Term Incentive Plan
On May 29, 2014, the Company’s stockholders approved the EnerNOC, Inc. 2014 Long-Term Incentive Plan (the 2014 Plan), which was amended by the Company's stockholders at the Annual Meeting held on May 27, 2015 to increase the number of shares of common stock authorized for issuance under the 2014 Plan by
1,700,000
shares. As of
December 31, 2016
,
2,331,831
shares were available for future grant under the 2014 Plan.
World Energy Solutions, Inc. 2006 Stock Incentive Plan
In connection with the Company’s acquisition of World Energy in January 2015, the Company assumed the World Energy Solutions, Inc. 2006 Stock Incentive Plan (the World Energy Plan), which allowed the Company to issue stock awards to
eligible employees of the Company. As of August 2016,
no
further awards could be granted from the World Energy Plan. Awards previously granted under this plan may extend beyond this date.
Share Repurchase Program
On August 6, 2015, the Company’s Board of Directors approved a new share repurchase program, effective upon the expiration of the Company's 2014 Repurchase Program on August 8, 2015, that enabled the Company to repurchase up to
$50,000
of the Company’s common stock during the period from August 9, 2015 through August 9, 2016 (the 2015 Repurchase Program). During the
year ended December 31, 2016
, the Company did not make any repurchases of its common stock under the 2015 Repurchase Program prior to its expiration on August 9, 2016.
The Company withheld
367,154
,
381,930
and
329,377
shares of its common stock during the
years ended December 31,
2016
,
2015
, and
2014
, respectively, to satisfy employee minimum statutory income tax withholding obligations in connection with the vesting of restricted stock and restricted stock units under its equity incentive plans, which the Company pays in cash to the appropriate taxing authorities on behalf of its employees. All withheld shares became immediately available for future issuance under the 2014 Plan.
Employee Stock Purchase Plan
On May 26, 2016, the Company's shareholders approved an employee stock purchase plan (the 2016 ESPP). The 2016 ESPP permits eligible employees, through payroll withholdings, to purchase shares of the Company's common stock at a
15%
discount from the fair market value of the stock as determined on specific dates at six month intervals. The maximum amount of shares issuable under the 2016 ESPP is
3,000,000
. In any six month period, the maximum amount of shares issuable is limited to
500
shares per participant and
350,000
shares for all participants.
No
offerings were made under the ESPP during 2016.
Accumulated Other Comprehensive (Income) Loss
Changes in accumulated other comprehensive (income) loss, which are entirely comprised of foreign currency translation adjustment, net of tax, are as follows:
|
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive (Income) Loss
|
|
Foreign Currency Translation Adjustments
|
|
Balance at December 31, 2014
|
|
$
|
4,752
|
|
|
Other comprehensive loss during 2015
|
|
3,772
|
|
|
Balance at December 31, 2015
|
|
8,524
|
|
|
Other comprehensive income before reclassifications during 2016
|
|
(3,644
|
)
|
|
Reclassification due to liquidation of a foreign entity (Note 4)
|
|
(2,403
|
)
|
|
Balance at December 31, 2016
|
|
$
|
2,477
|
|
12. Stock-Based Compensation
The EnerNOC, Inc. Amended and Restated 2003 Stock Option and Incentive Plan, the EnerNOC, Inc. Amended and Restated 2007 Stock Option and Incentive Plan and the 2014 Plan (collectively the Plans) provide for the grant of incentive stock options, nonqualified stock options, restricted and unrestricted stock awards and other stock-based awards to eligible employees, directors and consultants of the Company. Options granted under the Plans are exercisable for a period determined by the Company, but in no event longer than
ten years
from the date of the grant. Option awards are granted with an exercise price equal to the market price of the Company’s common stock on the date of grant. Stock option awards, restricted stock awards and restricted stock unit awards generally vest ratably over three years, with certain exceptions.
Stock Options
The following is a summary of the Company’s stock option activity during the year ended December 31,
2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2016
|
|
|
|
|
Number of
Shares
Underlying
Options
|
|
Weighted–
Average
Exercise Price
Per Share
|
|
Aggregate
Intrinsic
Value
|
|
Weighted Average Remaining Life (in years)
|
|
Outstanding at December 31, 2015
|
610,855
|
|
|
$
|
18.93
|
|
|
|
|
|
|
Granted
|
—
|
|
|
—
|
|
|
|
|
|
|
Exercised
|
(111,667
|
)
|
|
0.51
|
|
|
|
|
|
|
Cancelled
|
(254,944
|
)
|
|
23.77
|
|
|
|
|
|
|
Outstanding at December 31, 2016
|
244,244
|
|
|
$
|
22.30
|
|
|
$
|
—
|
|
|
|
|
Exercisable at end of period
|
239,748
|
|
|
$
|
22.51
|
|
|
$
|
—
|
|
|
2.0
|
|
Vested or expected to vest at December 31, 2016
|
243,835
|
|
|
$
|
22.31
|
|
|
$
|
—
|
|
|
2.0
|
The total number of shares issuable upon the exercise of "in-the-money" stock options exercisable as of
December 31, 2016
based on the Company's closing stock price of
$6.00
was approximately
198
, the aggregated intrinsic value of which was not material. The total intrinsic value of options exercised during the years ended
December 31, 2016
,
2015
, and
2014
was
$618
,
$795
, and
$1,457
, respectively. As of
December 31, 2016
, the Company had
$4
of unrecognized stock-based compensation expense related to stock options, which will be recognized over a
one
year period.
Restricted Stock
The following table summarizes the Company’s restricted stock activity during the year ended
December 31, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
Number of
Shares
|
|
Weighted Average
Grant Date Fair
Value Per Share
|
|
Nonvested at December 31, 2015
|
2,294,691
|
|
|
$
|
14.20
|
|
|
Granted
|
897,650
|
|
|
6.87
|
|
|
Vested
|
(978,539
|
)
|
|
13.69
|
|
|
Cancelled
|
(838,835
|
)
|
|
10.64
|
|
|
Nonvested at December 31, 2016
|
1,374,967
|
|
|
$
|
11.71
|
|
The Company's Chief Executive Officer is required to receive his performance-based bonus, if achieved, in shares of the Company's common stock. During the
years ended December 31,
2016
,
2015
and
2014
, the Company recorded
$445
,
$265
and
$476
, respectively, of stock-based compensation expense related to this performance based bonus. In accordance with ASC 718, the offsetting credit to this compensation expense is recorded in accrued payroll and related expenses during the year in which the bonus is earned and is reclassified to additional paid-in capital when the shares are issued. The Company issued
42,705
,
72,926
and
6,632
shares of its common stock, during the years ended December 31,
2016
,
2015
, and
2014
, respectively, to satisfy the Company’s bonus obligations to this individual.
For non-vested restricted stock subject to service-based vesting conditions outstanding as of
December 31, 2016
, the Company had
$10,253
of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of
1.9
years. For non-vested restricted stock subject to performance-based vesting conditions outstanding and that were probable of vesting as of
December 31, 2016
, which represents all of the outstanding non-vested restricted stock subject to performance-based vesting conditions, the Company had
$356
of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of
one
year.
Restricted Stock Units
The following table summarizes the Company’s restricted stock unit activity during the
year ended December 31, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
Number of
Shares
|
|
Weighted Average
Grant Date Fair
Value Per Share
|
|
Nonvested at December 31, 2015
|
258,983
|
|
|
$
|
15.27
|
|
|
Granted
|
710,750
|
|
|
6.15
|
|
|
Vested
|
(45,461
|
)
|
|
9.21
|
|
|
Cancelled
|
(218,421
|
)
|
|
7.44
|
|
|
Nonvested at December 31, 2016
|
705,851
|
|
|
$
|
8.90
|
|
For non-vested restricted stock units subject only to service based vesting conditions outstanding as of
December 31, 2016
, the Company had
$2,569
of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted
average period of
2.1
years. As of
December 31, 2016
, the Company had
$1,379
of unrecognized stock-based compensation expense for outstanding performance based restricted stock units that the Company deemed not probable of vesting. There were no outstanding performance based awards that were deemed to be probable of vesting as of
December 31, 2016
.
Stock-Based Compensation
Stock-based compensation recorded in the consolidated statements of operations was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
Selling and marketing expenses
|
$
|
3,287
|
|
|
$
|
4,316
|
|
|
$
|
5,488
|
|
|
General and administrative expenses
|
7,904
|
|
|
8,907
|
|
|
9,225
|
|
|
Research and development expenses
|
1,264
|
|
|
1,362
|
|
|
1,350
|
|
|
Total
(1)
|
$
|
12,455
|
|
|
$
|
14,585
|
|
|
$
|
16,063
|
|
(1)
Stock-based compensation expense for the year ended December 31, 2015 includes
$499
related to the acquisition of World Energy that was settled with the equivalent cash payments.
Stock-based compensation expense related to share-based awards granted to non-employees was not material for the years ended December 31,
2016
,
2015
and
2014
. The Company recognized
no
income tax benefits from stock-based compensation arrangements during the years ended December 31,
2016
and
2015
and recognized
$625
of income tax benefits during the year ended December 31,
2014
.
No
material compensation expense was capitalized during the years ended December 31,
2016
,
2015
and
2014
.
13. Income Taxes
The Company accounts for income taxes in accordance with the asset and liability method of ASC 740. Under ASC 740, deferred tax assets and liabilities are recognized based on the differences between the financial reporting and income tax bases of assets and liabilities using statutory rates. In addition, ASC 740 requires a valuation allowance against deferred tax assets if, based upon the available evidence, it is more likely than not that some or all of the deferred tax assets will not be realized.
The sources of (loss) income before the benefit from or provision for income tax are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
United States
|
$
|
(36,763
|
)
|
|
$
|
(153,844
|
)
|
|
$
|
24,594
|
|
|
International
|
(11,754
|
)
|
|
(41,284
|
)
|
|
(6,721
|
)
|
|
Total (loss) income before income tax
|
$
|
(48,517
|
)
|
|
$
|
(195,128
|
)
|
|
$
|
17,873
|
|
The provision for income tax consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
Current
|
|
|
|
|
|
|
Federal
|
$
|
1,217
|
|
|
$
|
(56
|
)
|
|
$
|
17
|
|
|
State
|
(275
|
)
|
|
376
|
|
|
1,419
|
|
|
Foreign
|
1,513
|
|
|
1,090
|
|
|
4,392
|
|
|
Subtotal, current income tax provision
|
2,455
|
|
|
1,410
|
|
|
5,828
|
|
|
Deferred
|
|
|
|
|
|
|
Federal
|
—
|
|
|
(7,202
|
)
|
|
898
|
|
|
State
|
—
|
|
|
(2,698
|
)
|
|
530
|
|
|
Foreign
|
(494
|
)
|
|
(1,520
|
)
|
|
(1,380
|
)
|
|
Subtotal, deferred income tax (benefit) provision
|
(494
|
)
|
|
(11,420
|
)
|
|
48
|
|
|
Provision for (benefit from) income tax
|
$
|
1,961
|
|
|
$
|
(10,010
|
)
|
|
$
|
5,876
|
|
The Company has provided for non-income based taxes in general and administrative expenses as of
December 31, 2016
,
2015
, and
2014
.
A reconciliation of income tax expense/(benefit) in the consolidated financial statements to the statutory tax rate is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
Federal income tax at statutory federal rate
|
35.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
|
State taxes, net of federal benefit
|
1.8
|
|
|
3.2
|
|
|
8.2
|
|
|
Uncertain tax positions
|
—
|
|
|
—
|
|
|
6.4
|
|
|
Foreign rate differences
|
(6.3
|
)
|
|
(1.4
|
)
|
|
6.2
|
|
|
Non-deductible stock-based compensation expense
|
(7.7
|
)
|
|
(0.6
|
)
|
|
3.5
|
|
|
Convertible debt discount accretion
|
—
|
|
|
—
|
|
|
3.3
|
|
|
Foreign withholding
|
(2.3
|
)
|
|
(0.1
|
)
|
|
2.5
|
|
|
Basis difference on sale of foreign subsidiary
|
9.3
|
|
|
—
|
|
|
—
|
|
|
Acquisition costs
|
—
|
|
|
(0.5
|
)
|
|
2.0
|
|
|
Credits
|
0.1
|
|
|
0.2
|
|
|
(1.2
|
)
|
|
Goodwill impairment
|
—
|
|
|
(8.8
|
)
|
|
—
|
|
|
Unrealized foreign exchange loss
|
(3.1
|
)
|
|
—
|
|
|
—
|
|
|
Other permanent items
|
(0.5
|
)
|
|
(0.3
|
)
|
|
3.6
|
|
|
Other
|
0.7
|
|
|
(1.7
|
)
|
|
(4.5
|
)
|
|
Change in valuation allowance
|
(31.0
|
)
|
|
(19.9
|
)
|
|
(32.1
|
)
|
|
Effective income tax rate
|
(4.0
|
)%
|
|
5.1
|
%
|
|
32.9
|
%
|
The Company’s effective tax rate in
2016
differs from the U.S. federal statutory rate of
35.0%
principally as a result of domestic and certain foreign losses that cannot be benefitted.
Deferred income tax assets (liabilities) consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
Deferred income tax assets:
|
|
|
|
|
Net operating loss carryforwards
|
$
|
43,768
|
|
|
$
|
28,855
|
|
|
Tax deductible goodwill
|
12,025
|
|
|
14,537
|
|
|
Intangible assets
|
976
|
|
|
—
|
|
|
Reserves and accruals
|
5,183
|
|
|
5,210
|
|
|
Deferred revenue
|
2,250
|
|
|
2,251
|
|
|
Deferred rent
|
2,496
|
|
|
3,249
|
|
|
Stock awards
|
3,385
|
|
|
7,450
|
|
|
Tax credits and other
|
4,536
|
|
|
5,338
|
|
|
Total deferred income tax assets
|
74,619
|
|
|
66,890
|
|
|
Deferred income tax liabilities:
|
|
|
|
|
Property and equipment
|
(6,811
|
)
|
|
(8,182
|
)
|
|
Convertible Notes
|
(4,081
|
)
|
|
(5,360
|
)
|
|
Intangible assets
|
—
|
|
|
(2,973
|
)
|
|
Other
|
—
|
|
|
(80
|
)
|
|
Total deferred income tax liabilities
|
(10,892
|
)
|
|
(16,595
|
)
|
|
Net deferred income tax assets before valuation allowance
|
63,727
|
|
|
50,295
|
|
|
Valuation allowance
|
(63,105
|
)
|
|
(50,192
|
)
|
|
Net deferred tax asset
|
$
|
622
|
|
|
$
|
103
|
|
The Company has provided a valuation allowance against certain U.S. and foreign deferred tax assets. The valuation allowance
increased
$12,913
during the year ended
December 31, 2016
, due to losses not being benefitted, inclusive of deductible goodwill impairment. Deferred taxes include
$5,540
deferred tax asset related to net operating loss carryforwards,
$540
deferred tax liability related to intangible assets and
$5,001
valuation allowance in Germany, which is held for sale as of December 31, 2016.
As of
December 31, 2016
, the Company has U.S. federal and state net operating loss carryforwards of
$112,194
and
$94,362
, respectively. The losses expire at various times through 2036. The Company’s U.S. net operating loss carryforwards at
December 31, 2016
include
$28,965
in income tax deductions, which pursuant to ASU 2016-09 will be included in the Company's deferred tax assets as of January 1, 2017, subject to any valuation allowance requirements. The Company has U.S.
tax credits of
$2,220
, which begin to expire in
2020
. As of
December 31, 2016
, the Company has foreign net operating loss carryforwards of
$42,416
, of which
$1,450
will expire at various times through
2036
and
$40,966
will never expire.
Activity related to unrecognized tax benefits was as follows:
|
|
|
|
|
|
|
|
Balance at December 31, 2013
|
$
|
554
|
|
|
Adjustments based on tax positions related to prior year
|
1,171
|
|
|
Additions based on tax positions related to the current year
|
69
|
|
|
Balance at December 31, 2014
|
$
|
1,794
|
|
|
Adjustments based on tax positions related to prior year
|
(52
|
)
|
|
Additions based on tax positions related to the current year
|
85
|
|
|
Balance at December 31, 2015
|
$
|
1,827
|
|
|
Adjustments based on tax positions related to prior year
|
(25
|
)
|
|
Additions based on tax positions related to the current year
|
656
|
|
|
Balance at December 31, 2016
|
$
|
2,458
|
|
The increase in the Company’s unrecognized tax benefits in 2016 relates primarily to foreign withholding taxes.
Of the Company’s unrecognized tax benefits, if recognized, approximately
$1,001
would impact the effective tax rate. The Company’s policy is to recognize both accrued interest and penalties related to unrecognized benefits in income tax expense. The amount of interest and penalties recorded in income tax expense is
$144
and
$103
as of December 31, 2016 and 2015, respectively. No significant unrecognized tax benefits are expected to reverse in the next twelve months.
The Company files federal and state income tax returns in the United States, as well as income tax returns in Australia, Brazil, Canada, Germany, India, Ireland, Japan, South Korea, New Zealand, and the United Kingdom. Tax years 2010 and forward are open in the material jurisdictions in which the Company operates. The Company recently began a federal IRS examination for 2014, however, the Company is not under examination in any other jurisdiction.
The Company provides for income taxes on the earnings of foreign subsidiaries unless the subsidiaries’ earnings are considered permanently reinvested. Income taxes have not been provided on certain outside basis differences of foreign subsidiaries of approximately
$938
because such outside basis differences are considered to be indefinitely reinvested in the business. A determination of the amount of the unrecognized deferred tax liability related to the undistributed earnings is not practicable.
14. Employee Savings and Retirement Plan
The Company has established a savings program for its U.S. employees that is designated to be qualified under Section 401(k) of the Internal Revenue Code. At the discretion of the Company’s Board of Directors, the Company may make matching contributions to the 401(k) Plan, which may vest ratably over periods ranging from
one
to
three
years. The Company matches a portion of the employee’s contribution to the 401(k) Plan resulting in a
$1,989
,
$1,549
, and
$1,454
contribution to the savings plan for the years ended
December 31, 2016
, 2015 and 2014, respectively.
15. Commitments and Contingencies
Operating Leases
The Company leases office space under various operating leases. In addition to rent, the leases require the Company to pay for taxes, insurance, maintenance and other operating expenses. Certain of these leases provided rent holidays at their inception and contain escalation clauses. The Company recognizes rent expense on a straight-line basis over the term of the lease, excluding renewal periods, unless renewal of the lease is reasonably assured. The Company's corporate headquarters lease also contains certain provisions requiring the Company to restore certain aspects of the leased space to its initial condition. The Company recorded the estimated fair value of these asset retirement obligations as the related leasehold improvements were incurred and is accreting the liability to fair value over the life of the lease as a component of operating expenses. As of
December 31, 2016
, the Company’s asset retirement obligation totaled
$512
and accretion expense related to this liability was
$81
during the year ended
December 31, 2016
. In addition, certain leases have provided incentives to the Company to build out the related facilities. The Company records these incentives as deferred rent and reflects these amounts as reductions of lease expense over the lease term. As of
December 31, 2016
and
2015
, the Company had a deferred rent liability representing rent expense recorded on a straight-line basis in excess of contractual lease payments of
$6,406
and
$8,037
, respectively.
The Company has entered into sublease arrangements for certain excess space related to these leased facilities. As of
December 31, 2016
, future noncancelable sublease rentals are
$7,379
over the next four years.
At
December 31, 2016
, future minimum lease payments for operating leases with noncancelable terms of
more than one year
were as follows:
|
|
|
|
|
|
|
|
|
Operating Leases
|
|
2017
|
$
|
7,944
|
|
|
2018
|
7,931
|
|
|
2019
|
7,388
|
|
|
2020
|
3,826
|
|
|
2021
|
419
|
|
|
Thereafter
|
292
|
|
|
Total minimum lease payments (not reduced by sublease rentals)
|
$
|
27,800
|
|
Rent expense under operating leases was
$6,885
,
$8,526
and
$6,728
for the years ended December 31,
2016
,
2015
and
2014
, respectively.
Letters of Credit
As of
December 31, 2016
, the Company was contingently liable under outstanding letters of credit for
$24,389
under its 2014 credit facility.
Performance Guarantees
The Company is subject to performance guarantee requirements under certain utility and electric power grid operator customer contracts and open market bidding program participation rules, which may be secured by cash or letters of credit. Performance guarantees as of
December 31, 2016
were
$22,892
and included deposits held by certain customers of
$132
and restricted cash of
$44
. These amounts primarily represent up-front payments required by utility and electric power grid operator customers as a condition of participation in certain demand response programs and to ensure that the Company will deliver its committed capacity amounts in those programs. If the Company fails to meet its minimum committed capacity requirements, a portion or all of the deposits may be forfeited. The Company assessed the probability of default under these customer contracts and open market bidding programs and has determined the likelihood of default and loss of deposits to be remote.
Under certain utility and electric power grid operator customer contracts, if the Company does not achieve the required performance guarantee requirements, the customer can terminate the arrangement and the Company would potentially be subject to termination penalties. Under these arrangements, the Company defers all fees received up to the amount of the potential termination penalty until the Company has concluded that it can reliably determine that the potential termination penalty will not be incurred or the termination penalty lapses. As of
December 31, 2016
, the Company had
$500
in deferred fees for these arrangements, which were included in deferred revenues as of
December 31, 2016
. As of
December 31, 2016
, the maximum termination penalty to which the Company could be subject under these arrangements, which the Company has deemed not probable of being incurred, was approximately
$3,267
.
As of December 31,
2016
and December 31,
2015
, the Company accrued in the accompanying consolidated balance sheets
$141
and
$647
, respectively, of performance adjustments related to fees received for its contractual commitments and participation in certain demand response programs. The Company believes that it is probable that these performance adjustments will be refunded to the utility or electric power grid operator, as the utility or electric power grid operator has the right to require repayment at any point at its discretion, the amounts have been classified as a current liability.
In 2006, a local municipality advanced the Company funds to acquire backup generators. The agreement required these generators remain active in the regional demand response program. Due to certain events transpiring in 2016, mainly related to restrictions on the use of backup generators, the Company removed these generators from the market. The related letter of credit, which was required upon advancement of funds, was
$671
as of December 31, 2016, for which the Company has recorded a corresponding liability in "accrued expenses and other current liabilities" on the accompanying balance sheet.
Limited Warranties
The Company typically grants customers a limited warranty that guarantees its hardware will substantially conform to current specifications for
1 year
from the delivery date. Based on the Company’s operating history, the potential liability associated with product warranties has been determined to be nominal.
Health Insurance Arrangement
In connection with the Company’s agreement for its employee health insurance plan, the Company could be subject to an additional payment for the run out of claims if the agreement is terminated. The Company has not elected to terminate this agreement nor does the Company believe that termination is probable for the foreseeable future. As a result, the Company has determined that it is not probable that a loss is likely to occur and no amounts have been accrued related to this potential payment upon termination. As of December 31,
2016
, the payment due upon termination would be
$951
.
Enterprise Customer Matter
The Company is currently involved in an ongoing matter related to a review of certain services provided under a contractual arrangement with an enterprise customer. No lawsuit has been filed and the Company does not currently believe it is probable that a loss has been incurred and therefore, no amounts have been accrued related to this matter. However, the Company has determined that it is reasonably possible that it may incur a loss related to this matter. The potential amount of such a loss is not currently estimable because the matter is at an early stage and involves unresolved questions of fact.
Indemnification and other Contingencies
The Company includes indemnification provisions in certain of its contracts. These indemnification provisions include provisions indemnifying the customer against losses, expenses, and liabilities from damages that could be awarded against the customer in the event that the Company’s services and related enterprise software platforms are found to infringe upon a patent or copyright of a third-party. The Company believes that its internal business practices and policies and the ownership of information limits the Company’s risk in paying out any claims under these indemnification provisions.
In August 2016, a former employee filed a complaint and demand for a trial jury in state court in the Commonwealth of Massachusetts against the Company related to the payment of commissions and other claims. In September 2016, the Company answered the complaint, denying the claims. The Company does not currently believe it is probable that a loss has been incurred and therefore, no amounts have been accrued related to this matter. However, the Company has determined that it is reasonably possible that a loss may have been incurred related to this matter. The potential amount of such a loss is not currently estimable because the matter is in its early stages and involves unresolved questions of fact.
The Company is subject to legal proceedings, claims and litigation arising in the ordinary course of business. The Company does not expect the ultimate costs to resolve these matters to have a material adverse effect on Company’s consolidated financial condition, results of operations or cash flows.
Escrow Settlement
On July 27, 2016, the Company and the former shareholders of Pulse Energy Inc. (Pulse Energy) reached a settlement with respect to claims made by the Company related to certain general representations and warranties made by the former shareholders related to the stock purchase agreement pursuant to which the Company acquired Pulse Energy in December 2014. In accordance with the settlement agreement,
$2,900
of the cash and
87.483
shares of the Company's common stock that were held in escrow as security for indemnification obligations were released to the Company in settlement of the claims. As a result, the Company recorded a gain of
$3,535
for the year ended December 31, 2016, which is included in the consolidated statement of operations within general and administrative expenses. The gain includes the
$2,900
of cash and
$635
, which represents the fair value of the
87.483
common shares as of the date of the settlement. The fair value of the shares, which were subsequently retired, was recorded as an adjustment to additional paid-in capital.
16. Business Combinations
The Company did not enter into a business acquisition during the year ended December 31, 2016. During the years ended December 31, 2015 and 2014, the Company completed a series of business acquisitions including World Energy in the first quarter of 2015 and Pulse Energy, Entech, Entelios AG (Entelios), Activation Energy DSU Limited (Activation Energy), and Universal Load Center Co., Ltd. (ULC) during the year ended 2014. For each of these acquisitions, the Company concluded that the acquisition represented a business combination under the provisions of ASC 805,
Business Combinations
(ASC 805). The Company also concluded that each acquisition individually and in aggregate did not represent a material business combination and, therefore, no pro forma information was provided in the period of the acquisition. The Company’s consolidated results of operations include the results of operations for each of the acquired entities following the acquisition date. All transaction costs were expensed as incurred and are included in general and administrative expenses. Details of the transactions, including the components and allocation of the purchase price, and components of consideration are outlined, by entity, in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
World Energy
|
|
Pulse Energy
|
|
EnTech
|
|
Entelios
|
|
Activation Energy
|
|
ULC
|
|
Date of Acquisition
|
January 2015
|
|
December 2014
|
|
April 2014
|
|
February 2014
|
|
February 2014
|
|
April 2014
|
|
Net tangible assets acquired:
|
$
|
826
|
|
|
$
|
287
|
|
|
$
|
1,208
|
|
|
$
|
(50
|
)
|
|
$
|
752
|
|
|
$
|
476
|
|
|
Identifiable intangible assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed technology
|
12,240
|
|
|
8,500
|
|
|
700
|
|
|
1,770
|
|
|
545
|
|
|
—
|
|
|
Customer relationships and contracts
|
29,160
|
|
|
1,000
|
|
|
3,900
|
|
|
4,084
|
|
|
2,042
|
|
|
—
|
|
|
Non-compete agreements
|
—
|
|
|
600
|
|
|
1,000
|
|
|
204
|
|
|
220
|
|
|
—
|
|
|
Trade name
|
—
|
|
|
30
|
|
|
260
|
|
|
218
|
|
|
82
|
|
|
—
|
|
|
Total intangible identifiable assets
|
41,400
|
|
|
10,130
|
|
|
5,860
|
|
|
6,276
|
|
|
2,889
|
|
|
—
|
|
|
Deferred income tax liabilities, net
(3)
|
(1,892
|
)
|
|
(2,316
|
)
|
|
(1,689
|
)
|
|
—
|
|
|
(361
|
)
|
|
—
|
|
|
Goodwill
(1)
|
39,579
|
|
|
16,710
|
|
|
7,168
|
|
|
15,653
|
|
|
1,581
|
|
|
413
|
|
|
Total Consideration
|
$
|
79,913
|
|
|
$
|
24,811
|
|
|
$
|
12,547
|
|
|
$
|
21,879
|
|
|
$
|
4,861
|
|
|
$
|
889
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of consideration:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid at closing to sellers
|
$
|
68,538
|
|
|
$
|
15,532
|
|
|
$
|
12,547
|
|
|
$
|
21,784
|
|
|
$
|
4,561
|
|
|
$
|
714
|
|
|
Cash settlement of stock awards and warrants
|
1,804
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Fair value of contingent consideration
|
—
|
|
|
1,587
|
|
|
—
|
|
|
95
|
|
|
300
|
|
|
175
|
|
|
Replacement share-based awards issued
|
103
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Retirement of debt
|
9,468
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Fair value of shares issued upon acquisition
(2)
|
—
|
|
|
7,692
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total Consideration:
|
$
|
79,913
|
|
|
$
|
24,811
|
|
|
$
|
12,547
|
|
|
$
|
21,879
|
|
|
$
|
4,861
|
|
|
$
|
889
|
|
|
Transaction costs incurred
|
$
|
367
|
|
|
$
|
364
|
|
|
$
|
311
|
|
|
$
|
511
|
|
|
$
|
159
|
|
|
$
|
96
|
|
|
|
|
|
(1)
|
Goodwill related to the acquisitions of World Energy, EnTech, Entelios, Activation Energy, and ULC is not deductible for tax purposes.
|
|
|
|
|
(2)
|
Represents
583,218
shares of the Company's common stock.
|
|
|
|
|
(3)
|
Deferred taxes relate to the book to tax difference of acquired definite lived intangible assets where the book amortization expense is not deductible for tax purposes.
|
The following table summarizes the identifiable intangible assets acquired in business combinations for the three years ended December 31, 2016. All intangible assets are subject to amortization and have no significant residual value. There were no intangible assets acquired with indefinite lives or with renewal or extension terms:
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Weighted Average Amortization Period as of Acquisition Date (in Years)
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Asset Class
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World Energy
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Pulse Energy
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EnTech
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Entelios
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Activation Energy
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Developed technology
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9
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5
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5
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2
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2
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Customer relationships and contracts
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14
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2
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9
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7.5
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7.3
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Non-compete agreements
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N/A
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3
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3
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3.9
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3.7
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Trade name
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N/A
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2
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2
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2
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2
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World Energy
On
January 5, 2015
, the Company completed the acquisition of all outstanding stock of World Energy, an energy management software and services firm that helps enterprises simplify the energy procurement process through a suite of SaaS tools, including on-line energy procurement auctions. The Company acquired World Energy for a purchase price of
$79,913
, consisting of
$68,538
in cash paid at closing (which represented
$5.50
per share of World Energy's outstanding common stock), the retirement of
$9,468
of outstanding debt,
$58
for the settlement of outstanding warrants, and
$1,849
deemed to be purchase price related to the fair value of settled or exchanged outstanding equity awards, which were required to be settled or exchanged. The Company cash-settled the outstanding restricted stock awards and vested stock options for which the per share exercise price was equal to or less than
$5.50
per share, and issued replacement awards for vested, out-of-the-money stock options and non-vested options for total value of
$3,027
. Of this amount,
$1,849
was determined to represent purchase price consideration and
$1,178
was determined to be post combination stock-based compensation expense. The Company recognized
$443
as stock based compensation on the acquisition date as there was no remaining service period and will recognize the remaining
$735
over the remaining service period, which is anticipated to expire
2.3
years following the acquisition date.
Pulse Energy
On
December 1, 2014
, the Company completed an acquisition of all outstanding stock of Pulse Energy, a privately-held company headquartered in Vancouver, Canada, and a global leader in energy intelligence for utilities’ commercial customers. The purchase price, as disclosed above, included
$1,587
representing the fair value, classified as a Level 3 measurement due to
significant unobservable inputs, of contingent consideration (earn-out), which was based on the achievement of sales targets during the years ending December 31, 2015, 2016 and 2017. The fair value of the contingent consideration was recorded as an adjustment to additional paid-in capital as it was expected to be settled (if achieved) in the Company's own shares. The earn-out targets were not achieved.
EnTech
On
April 17, 2014
, the Company and two of its subsidiaries completed acquisitions of all outstanding stock of EnTech Utility Service Bureau, Inc. (EnTech US), and EnTech Utility Service Bureau Ltd. (EnTech UK), privately-held companies headquartered in the United States and the United Kingdom, respectively, that are leading providers of global utility bill management (UBM) software. In connection with the acquisition of EnTech US, the Company acquired EnTech US’s
50%
ownership in EnTech USB Private Limited (EnTech India), a joint venture entity in India, which performs development and data processing services principally for EnTech US. On May 9, 2014, the Company completed the acquisition of the remaining
50%
ownership of EnTech India. The Company collectively refers to the entities acquired as EnTech. There were no earn-out or other additional contingent purchase price arrangements related to the acquisition of EnTech.
Entelios
On
February 13, 2014
, the Company and one of its subsidiaries completed an acquisition of all outstanding stock of Entelios, a privately-held company headquartered in Germany that is a leading provider of demand response in Europe. The Company acquired Entelios for an aggregate purchase price, exclusive of potential contingent consideration, of
$21,784
(
16,000
Euros based on the exchange rate on the closing date of the acquisition), all of which was paid in cash. Included in the consideration paid at closing,
$6,884
(
5,056
Euros) was paid as consideration to allow Entelios to settle its outstanding debt and related tax obligations. In addition to the amounts paid at closing, the agreement provided additional consideration related to an earn-out amount up to a maximum of
$2,042
(
1,500
Euros) if certain financial metrics were achieved in 2014 and 2015. As of the acquisition date, the Company determined that the fair value of the earn-out was
$95
(
70
Euros). This fair value was included as a component of the purchase price resulting in an aggregate purchase price of
$21,879
. The earnout measures were not achieved and the Company reversed this liability in December 2015.
Activation Energy
On
February 13, 2014
, the Company and one of its subsidiaries completed an acquisition of all outstanding stock of Activation Energy, a privately-held company headquartered in Ireland that is the leading provider of demand response software and services in Ireland. The purchase price included contingent consideration up to a maximum of
$1,398
(
1,027
Euros). The Company determined that the initial fair value, classified as a Level 3 measurement due to significant unobservable inputs, of the contingent consideration as of the acquisition date was
$300
(
220
Euros). In February 2015, the Company made a payment of
$277
(
257
Euro). As of December 31, 2015, the liability was adjusted to
$840
(
770
Euros), reflecting the maximum amount due upon achievement of the performance criteria. This amount was subsequently paid in February 2016.
ULC
On
April 2, 2014
, one of the Company’s subsidiaries completed the acquisition of all outstanding stock of ULC, a privately-held company headquartered in South Korea that provides demand response software and services in that market. In addition to the amounts paid at closing, the agreement provided additional contingent consideration of up to
$1,750
related to the achievement of operational metrics. The Company concluded that
$1,500
of the contingent consideration should be accounted for as a compensation arrangement. Accordingly, this amount was excluded from the acquisition purchase price and is being recorded as compensation expense over the service period for amounts deemed probable of achievement. The remaining
$175
was included as a component of purchase price and was paid out in the fourth quarter of 2015.
17. Subsequent Events
In March 2017, the Company entered into a joint venture agreement with Cheng Long Intelligent Engineering Co. Ltd. (the JV Partner) in order to provide its demand response solutions in Taiwan through a subsidiary of the Company, EnerNOC Taiwan Limited. The Company will initially own
67%
and the JV Partner will own
33%
of EnerNOC Taiwan Limited. The JV Partner has the option to purchase additional shares of the entity, contingent upon the achievement of certain operational milestones, such that its ownership interest may increase to no higher than
49%
. The Company will consolidate the financial results of EnerNOC Taiwan Limited as of the formation of the entity. Also in March 2017, EnerNOC Taiwan Limited was awarded a demand response contract with Taiwan Power Company, which is the state-owned electric utility serving the Taiwan market.
In March 2017, the Company entered into an asset purchase agreement to sell certain customer contracts related to a component of the business that provides professional services, including energy audits and facility commissioning and retro-commissioning services, for a transaction price of
$2,000
.
Exhibit Index
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Number
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Exhibit Title
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2.1
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Agreement and Plan of Merger, dated as of November 4, 2014, by and among World Energy Solutions, Inc., EnerNOC, Inc. and Wolf Merger Sub Corporation filed as Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed November 5, 2014 (File No. 001-33471), is hereby incorporated by reference as Exhibit 2.1.
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2.2
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Form of Tender and Support Agreement filed as Exhibit 2.2 to the Registrant’s Current Report on Form 8-K filed November 5, 2014 (File No. 001-33471), is hereby incorporated by reference as Exhibit 2.2.
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3.1
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Amended and Restated Certificate of Incorporation of EnerNOC, Inc., filed as Exhibit 3.2 to the Registrant’s Form S-1/A filed May 3, 2007 (File No. 333-140632), is hereby incorporated by reference as Exhibit 3.1.
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3.2
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Second Restated Bylaws of EnerNOC, Inc., filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed February 12, 2014 (File 001-33471), is hereby incorporated by reference as Exhibit 3.2.
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3.3
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First Amendment to Second Restated Bylaws of EnerNOC, Inc., filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed July 16, 2015 (File No. 001-33471), is hereby incorporated by reference as Exhibit 3.3.
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4.1
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Form of Specimen Common Stock Certificate, filed as Exhibit 4.1 to the Registrant’s Form S-1/A filed May 3, 2007 (File No. 333-140632), is hereby incorporated by reference as Exhibit 4.1.
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4.2
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Indenture (including the form of Notes) dated August 18, 2014, between EnerNOC, Inc. and Wells Fargo Bank, National Association filed as Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed August 18, 2014 (File No. 001-33471), is hereby incorporated by reference as Exhibit 4.2.
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4.3
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Form of 2.25% Convertible Senior Note due 2019 filed as Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed August 18, 2014 (File No. 001-33471), is hereby incorporated by reference as Exhibit 4.3.
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10.1
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Loan and Security Agreement, dated as of August 11, 2014, between Silicon Valley Bank and EnerNOC, Inc., as amended on October 23, 2014, August 11, 2015 and August 3, 2016, filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed November 4, 2016 (File No. 001-33471), is hereby incorporated by reference as Exhibit 10.1.
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10.2
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Purchase Agreement, among EnerNOC, Inc., and Morgan Stanley & Co. LLC, acting on behalf of itself and the several initial purchasers named in Schedule I thereto, dated August 12, 2014 filed as Exhibit 1.1 to the Registrant’s Current Report on Form 8-K filed August 13, 2014 (File No. 001-33471), is hereby incorporated by reference as Exhibit 10.2.
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10.3@
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Offer Letter, dated April 18, 2013 by and between EnerNOC, Inc. and Neil Moses, filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed April 23, 2013 (File No. 001-33471), is hereby incorporated by reference as Exhibit 10.3.
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10.4@
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Severance Agreement, dated as of April 22, 2013, by and between EnerNOC, Inc. and Neil Moses, filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed April 23, 2013 (File No. 001-33471), is hereby incorporated by reference as Exhibit 10.4.
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10.5
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EnerNOC, Inc. Fourth Amended and Restated Non-Employee Director Compensation Policy, as amended, filed as Exhibit 10.14 to the Registrant’s Annual Report on Form 10-K filed March 7, 2014 (File No. 001-33471), is hereby incorporated by reference as Exhibit 10.5.
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10.6@
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Second Amended and Restated Employment Agreement, dated as of March 1, 2010, by and between Timothy G. Healy and EnerNOC, Inc., as amended by the First Amendment to the Second Amended and Restated Employment Agreement, dated as of March 1, 2012, filed as Exhibit 10.3 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2011 (File No. 001-33471), is hereby incorporated by reference as Exhibit 10.6.
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10.7@
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Second Amended and Restated Employment Agreement, dated as of March 1, 2010, by and between David B. Brewster and EnerNOC, Inc., filed as Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2009 (File No. 001-33471), is hereby incorporated by reference as Exhibit 10.7.
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10.8@
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Offer Letter, dated June 6, 2013 by and between EnerNOC, Inc. and Matthew Cushing filed as Exhibit 10.1 to the Registrant’s Form 10-Q filed May 9, 2014 (File No. 001-33471), is hereby incorporated by reference as Exhibit 10.8.
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10.9@
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Severance Agreement, dated as of June 11, 2013, by and between EnerNOC, Inc. and Matthew Cushing filed as Exhibit 10.2 to the Registrant’s Form 10-Q filed May 9, 2014 (File No. 001-33471), is hereby incorporated by reference as Exhibit 10.9.
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10.10
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Lease Agreement, dated as of July 5, 2012, between EnerNOC, Inc. and Fallon Cornerstone ONEMPDLLC, filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed November 6, 2012 (File No. 001-33471), is hereby incorporated by reference as Exhibit 10.10.
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10.11
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First Amendment to Office Lease dated October 9, 2014, between EnerNOC, Inc. and Fallon Cornerstone One MPD filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed October 16, 2014 (File No. 001-33471), is hereby incorporated by reference as Exhibit 10.11.
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10.12@
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Amended and Restated 2007 Employee, Director and Consultant Stock Plan of EnerNOC, Inc. dated May 28, 2013, filed as Exhibit 10.11 to the Registrant’s Annual Report on Form 10-K filed March 7, 2014 (File No. 001-33471), is hereby incorporated by reference as Exhibit 10.12.
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10.13@
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EnerNOC, Inc. Amended and Restated 2007 Employee, Director and Consultant Stock Plan and HMRC Sub-Plan for UK Employees and Australian Sub-Plan, and forms of agreement thereunder, filed as Exhibit 10.11 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2011 (File No. 001-33471), is hereby incorporated by reference as Exhibit 10.13.
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10.14@
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EnerNOC, Inc. 2014 Long-Term Incentive Plan and Australian Sub-Plan, and forms of agreement thereunder, filed as Exhibit 10.22 to the Registrant’s Annual Report on Form 10-K filed on March 10, 2016 (File No. 001-33471), is hereby incorporated by reference as Exhibit 10.14.
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10.15@
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World Energy Solutions, Inc. 2006 Stock Incentive Plan, dated May 17, 2012, filed as Exhibit 99.1 to the Registrant’s Registration Statement on Form S-8 filed March 3, 2015 (File No. 333-202479), is hereby incorporated by reference as Exhibit 10.15.
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10.16@
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Summary of 2017 Executive Bonus Plan, filed in the Registrant’s Current Report 8-K filed on March 10, 2017 (File No. 001-33471), is hereby incorporated by reference as Exhibit 10.16.
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10.17@
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Form of Indemnification Agreement between EnerNOC, Inc. and each of the directors and executive officers thereof, filed as Exhibit 10.21 to the Registrant’s Registration Statement on Form S-1, as amended, filed May 3, 2007 (File No. 333-140632), is hereby incorporated by reference as Exhibit 10.17.
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10.18@
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Offer Letter, dated as of June 22, 2016, between EnerNOC, Inc. and William Sorenson, filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated June 23, 2016 (File No. 001-33471), is hereby incorporated by reference as Exhibit 10.18.
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10.19@
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Form of Severance Agreement, by and between EnerNOC, Inc. and William Sorenson, filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K dated June 23, 2016 (File. No. 001-33471), is hereby incorporated by reference as Exhibit 10.19.
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10.20@
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EnerNOC, Inc. 2016 Employee Stock Purchase Plan, filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated June 2, 2016 (File No. 001-33471), is hereby incorporated by reference as Exhibit 10.20.
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21.1*
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Subsidiaries of EnerNOC, Inc.
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23.1*
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Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm.
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31.1*
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Certification of Principal Executive Officer of EnerNOC, Inc. pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
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31.2*
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Certification of Principal Financial Officer of EnerNOC, Inc. pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
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32.1*
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Certification of the Principal Executive Officer and Principal Financial Officer of EnerNOC, Inc. pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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101.00
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The following materials from EnerNOC, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2016, formatted in XBRL (eXtensible Business Reporting Language); (i) Consolidated Balance Sheets as of December 31, 2016 and 2015, (ii) Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014, (iii) Consolidated Statements of Changes in Stockholders’ Equity and Comprehensive Income (Loss) for the years ended December 31, 2016, 2015 and 2014, (iv) Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014, and (v) Notes to Consolidated Financial Statements.
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@
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Management contract, compensatory plan or arrangement.
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*
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Filed herewith.
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