EnerNOC, Inc.
ENERNOC INC (Form: 10-K, Received: 03/13/2015 06:10:41)
Table of Contents

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

 

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

For the fiscal year ended December 31, 2014

or

 

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

For the transition period from                     to                    

Commission file number 001-33471

EnerNOC, Inc.

(Exact Name of Registrant as Specified in its Charter)

 

Delaware   87-0698303
(State or Other Jurisdiction of
Incorporation or Organization)
  (IRS Employer
Identification No.)
One Marina Park Drive
Suite 400
Boston, Massachusetts
 

02210

(Zip Code)

(Address of Principal Executive Offices)  

Registrant’s telephone number, including area code:

(617) 224-9900

Securities registered pursuant to Section 12(b) of the Act:

 

Title of Each Class

 

Name of Each Exchange on Which Registered

Common Stock, $0.001 par value  

The NASDAQ Stock Market LLC

(The NASDAQ Global Market)

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes   ¨         No   x

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes   ¨         No   x

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes   x         No   ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes   x         No   ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ¨

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one).

 

Large accelerated filer   ¨   Accelerated filer   x    Non-accelerated filer   ¨   Smaller reporting company   ¨
 

(Do not check if a smaller reporting company)

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes   ¨         No   x

The aggregate market value of the Registrant’s common stock held by non-affiliates of the Registrant as of June 30, 2014, the last business day of the Registrant’s second quarter of the fiscal year ended December 31, 2014, was approximately $539.3 million based upon the last sale price reported for such date on The NASDAQ Global Market.

The number of shares of the Registrant’s common stock (the Registrant’s only outstanding class of stock) outstanding as of March 9, 2015 was 30,410,840.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s definitive proxy statement for its 2015 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than 120 days after the end of the Registrant’s fiscal year ended December 31, 2014, relating to certain information required in Part III of this Annual Report on Form 10-K are incorporated by reference into this Annual Report on Form 10-K.

 

 

 


Table of Contents

EnerNOC, Inc.

ANNUAL REPORT ON FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2014

Table of Contents

 

         Page  

PART I

    

Item 1.

  Business      1   

Item 1A.

  Risk Factors      12   

Item 1B.

  Unresolved Staff Comments      33   

Item 2.

  Properties      33   

Item 3.

  Legal Proceedings      33   

Item 4.

  Mine Safety Disclosures      34   

Part II

    

Item 5.

  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities      35   

Item 6.

  Selected Financial Data      37   

Item 7.

  Management’s Discussion and Analysis of Financial Condition and Results of Operations      39   

Item 7A.

  Quantitative and Qualitative Disclosures About Market Risk      73   

Item 8.

  Financial Statements and Supplementary Data      74   

Item 9.

  Changes in and Disagreements With Accountants on Accounting and Financial Disclosure      74   

Item 9A.

  Controls and Procedures      75   

Item 9B.

  Other Information      77   

PART III

    

Item 10.

  Directors, Executive Officers and Corporate Governance      77   

Item 11.

  Executive Compensation      77   

Item 12.

  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters      77   

Item 13.

  Certain Relationships and Related Transactions, and Director Independence      77   

Item 14.

  Principal Accounting Fees and Services      77   

PART IV

    

Item 15.

  Exhibits, Financial Statement Schedules      77   

Signatures

     79   

Appendix A

  Consolidated Financial Statements      F-1   
  Report of Ernst & Young LLP, Independent Registered Public Accounting Firm      F-2   

Exhibit Index

  


Table of Contents

This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. For this purpose, any statements contained herein regarding our strategy, future operations, financial condition, future revenues, profits and profit margins, projected costs, market position, prospects, plans and objectives of management, other than statements of historical facts, are forward-looking statements. The words “anticipates,” “believes,” “estimates,” “expects,” “intends,” “may,” “plans,” “projects,” “will,” “would” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. We cannot guarantee that we actually will achieve the plans, intentions or expectations expressed or implied in our forward-looking statements. Matters subject to forward-looking statements involve known and unknown risks and uncertainties, including economic, regulatory, competitive and other factors, which may cause actual results, levels of activity, performance or the timing of events to be materially different than those exposed or implied by forward-looking statements. Important factors that could cause or contribute to such differences include the factors set forth under the caption “Risk Factors” in Item 1A of Part I of this Annual Report on Form 10-K. Although we may elect to update forward-looking statements in the future, we specifically disclaim any obligation to do so, even if our estimates change, and readers should not rely on those forward-looking statements as representing our views as of any date subsequent to March 12, 2015.

Our trademarks include: EnerNOC, EnerNOC Get More from Energy, PowerTalk, DemandSMART, SupplySMART.

Other trademarks or service marks appearing in this Annual Report on Form 10-K are the property of their respective holders.


Table of Contents

PART I

 

Item 1. Business

We use the terms “EnerNOC,” the “Company,” “we,” “us” and “our” in this Annual Report on Form 10-K to refer to the business of EnerNOC, Inc. and its subsidiaries.

Company Overview

We are a leading provider of energy intelligence software, or EIS, and related solutions. Our enterprise customers use our software to transform how they manage and control energy spend for their organizations, while utilities leverage our software to better engage their customers and meet their demand-side management goals and objectives.

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

 

   

energy supplier selection, procurement and implementation;

 

   

energy budget forecasting;

 

   

utility bills and payment;

 

   

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

 

   

project tracking;

 

   

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

 

   

peak demand and the related cost impact.

Our EIS and related solutions provide our enterprise customers the visibility they need to prioritize resources against the activities that will deliver the highest return on investment. We offer our EIS and related solutions to our enterprise customers at four subscription levels: basic, standard, professional, and industrial. We deliver our SaaS solutions on all of the major Internet browsers and on leading mobile device operating systems. In addition to our EIS packages, we sell two categories of premium professional services, which we refer to as Software Enhancement Services and Energy & Procurement Services. Our Software Enhancement Services help our enterprise customers set their energy management strategy and enhance the effectiveness of EIS deployment. Our Energy and Procurement Services consist of audits, retro-commissioning, and supply procurement consulting. Our target enterprise customers for our EIS and related solutions are organizations that spend approximately $100,000/year or more per site on energy, and we sell to these customers primarily through our direct salesforce.

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

Our EIS and related solutions for utilities customers and electric power grid operators also include the demand response solutions and applications, EnerNOC Demand Manager™ and EnerNOC Demand Resource™. EnerNOC Demand Manager is a SaaS application that provides utilities with the underlying technology to manage their demand response programs and secure reliable demand-side resources. Our EnerNOC Demand Manager product consists of long-term contracts with a utility customer for a SaaS solution that allows utilities to

 

1


Table of Contents

manage demand response capacity in utility-sponsored demand response programs. This product provides our utility customers with real-time load monitoring, dispatching applications, customizable reports, measurement and verification, and other professional services. Our EnerNOC Demand Resource is a turnkey demand response resource where we match obligation, in the form of megawatts, or MW, that we agree to deliver to our utility customers and electric power grid operators, with supply, in the form of MW that we are able to curtail from the electric power grid through our arrangements with our enterprise customers. When we are called upon by our utility customers and electric power grid operators to deliver our contracted capacity, we use our Network Operations Center, or NOC, to remotely manage and reduce electricity consumption across our growing network of enterprise customer sites, making demand response capacity available to our utility customers and electric power grid operators on demand while helping our enterprise customers achieve energy savings, improve financial results and realize environmental benefits. We receive recurring payments from our utility customers and electric power grid operators for providing our EnerNOC Demand Resource and we share these recurring payments with our enterprise customers in exchange for those enterprise customers reducing their power consumption when called upon by us to do so. We occasionally reallocate and realign our capacity supply and obligation through open market bidding programs, supplemental demand response programs, auctions or other similar capacity arrangements and third-party contracts to account for changes in supply and demand forecasts, as well as changes in programs and market rules in order to achieve more favorable pricing opportunities. We refer to the above activities as managing our portfolio of demand response capacity.

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

Strategy

Our strategy is to capitalize on our market leading position, established track record, substantial operating experience and scalable and proprietary EIS platform to continue providing our EIS and related solutions to enterprises, utilities, and electric power grid operators. Our goal is to become the leading EIS and related solutions provider for enterprise and utility customers, and the foundational technology to facilitate demand response participation in open market programs worldwide. Key elements of our strategy include:

Expand Sales of our Portfolio of Enterprise and Utility Energy Intelligence Software and Related Solutions.

We intend to continue to leverage our leadership role in the demand response market to deliver a portfolio of EIS and related solutions to enterprise customers who are increasingly trying to gain control of how they buy electricity, how much they use and when they consume electricity, and to utility customers and electric power grid operators who are increasingly trying to improve customer engagement and manage energy demand through improved visibility and control over energy consumption. We believe that our enterprise and utility customers will increasingly look to advanced analytics and trusted third-party providers to help them meet their business objectives. We have recently acquired companies to assist with the advancement of this strategy.

On April 17, 2014, we acquired EnTech Utility Service Bureau, Inc., or Entech US, and EnTech Utility Service Bureau Ltd. , or Entech UK, and on May 9, 2014, we completed the acquisition of the remaining 50% ownership in EnTech USB Private Limited, or Entech India, which was a joint venture between Entech US and a third party. We collectively refer to the entities acquired as Entech. We believe that the combination of Entech’s software and technology, including real-time energy data, tariffs, and monthly utility bill data on our EIS platform will now enable real-time visibility and forecasting of energy costs and empower better energy management across global enterprises.

On December 1, 2014, we acquired Pulse Energy Inc., or Pulse Energy, a leading provider in energy intelligence for utilities’ commercial customers, which helps utilities meet regulated efficiency targets, improve customer satisfaction and brand loyalty, and cross-promote other programs and services. We believe this acquisition will expand and accelerate the growth of our EIS and related solutions by extending our ability to serve our utility and energy retail customers through deep segmentation and energy analytics for small and medium-sized enterprises, as well as commercial, institutional and industrial end-users of energy.

 

2


Table of Contents

On January 5, 2015, we completed the acquisition of World Energy Solutions, Inc., or World Energy, an energy management technology and services provider that helps enterprises simplify the energy and procurement process through a suite of SaaS solutions. We believe this acquisition and the integration of World Energy’s software into our EIS platform will help deliver more value to our enterprise customers through enhanced technology-enabled capabilities to manage the energy procurement process.

Target Expansion by Entering Additional International Markets

We also intend to expand our addressable market by pursuing EIS opportunities in international markets through both organic business development and acquisition. We believe that our scalable technology platform and proprietary operational processes are readily adaptable to the international markets that we are targeting. We also believe that entering new international markets, including Asia and Europe, will provide a significant opportunity to grow our enterprise customer base and provide a differentiated offering to enterprise customers with international operations. To further our presence in international markets, we have undertaken a number of initiatives in addition to our acquisitions of Entech UK, Entech India, Pulse Energy and World Energy.

On December 10, 2013, we entered into an agreement with Marubeni Corporation to form a joint venture to provide demand response applications and solutions in Japan. The new company was formed in January 2014 and named EnerNOC Japan K.K., which will have an exclusive license to market the EnerNOC Demand Resource throughout Japan. EnerNOC Japan K.K. is working on a government-sponsored pilot demand response program with the Tokyo Electric Power Company, Japan’s largest utility.

On February 13, 2014, we acquired Dublin-based Activation Energy DSU Limited, or Activation Energy, the leading provider of demand response software and services in Ireland. This acquisition gave us an immediate presence in Ireland and further strengthens our ability to deliver our full suite of EIS and related solutions applications and applications throughout Europe. Activation Energy participates in the Single Electricity Market, or SEM, a capacity market that spans the island of Ireland.

Also on February 13, 2014, we acquired Entelios AG, or Entelios, a leading provider of demand response in Europe, which is headquartered in Germany. This acquisition accelerated our entry into continental Europe with Entelios’ strong team and existing relationships with leading grid operators, utilities, retailers, and commercial, institutional, and industrial customers. Germany is one of Europe’s largest potential markets for demand response and EIS and related solutions.

On April 2, 2014, we acquired Universal Load Center Co., Ltd. a leading provider of demand response in South Korea. This acquisition gave us an immediate presence in South Korea and further strengthened our ability to deliver our EIS and related solutions throughout Asia.

Energy Intelligence Software and Related Solutions

Our Energy Intelligence Software and Related Solutions for Enterprises

Our EIS and related solutions for enterprise customers includes seven core areas of functionality:

1) Budgets and Procurement, which provides our enterprise customers with the ability to develop accurate energy budgets, track cost accruals, manage exposure to real-time energy prices and procure energy through competitive online auctions.

2) Utility Bill Management, which provides our enterprise customers with a central platform to collect historical utility bills, track trends in utility usage and costs, discover and report billing errors, and streamline accounts payable processes.

3) Visibility and Reporting, which tracks trends in energy and carbon impact, visualizes real-time energy data to understand consumption patterns, automates reporting into benchmarking standards such as ENERGY STAR, and disaggregates and tracks actual consumption and demand costs.

4) Facility Optimization, which allows our enterprise customers to benchmark their facilities against one another, analyze meter data to identify cost savings opportunities and prioritize actions across a portfolio of facilities.

 

3


Table of Contents

5) Project Tracking, which allows our enterprise customers to track the impact of savings measures that have been implemented.

6) Demand Response, which enables enterprise customers participating in demand response programs to measure and manage demand response dispatch performance and track payment history.

7) Demand Management, which alerts our enterprise customers when new demand thresholds are being reached, quantifies the cost impact of demand peaks, forecasts new facility and system peaks and alerts on real-time and day-ahead index prices.

Our Energy Intelligence Software and Related Solutions for Utilities

Our EIS and related solutions for utilities include four key areas of functionality:

1) Customer engagement software that provides customized, timely, and valuable content relating to an enterprise customer’s energy usage or potential energy savings that is relevant for that enterprise customer, both small and large.

2) Energy efficiency, which provides tools that help utilities meet energy efficiency mandates by delivering targeted, automated reports to their customers.

3) Demand response, which helps utilities manage system demand and ensure resilience cost-effectively.

4) Operational effectiveness, which uses software analytics to improve effectiveness and reduce cost-to-serve end users with targeted program design.

Other Products

We provide wireless products for energy management and demand response that are designed to ensure that our enterprise customers can connect their equipment remotely and access meter data securely. These products include cellular modems and an agricultural specific wireless technology solution acquired as part of our acquisition of M2M Communications, or M2M, in January 2011.

Technology and Operations

Since inception, we have focused on delivering industry-leading, technology-enabled EIS and related solutions. Our technology can be broken down into three primary components: our EIS platform, the NOC and the EnerNOC Site Server.

Energy Intelligence Software Platform

Our proprietary platform leverages a technology infrastructure that includes Red Hat Linux, Java JBoss, Oracle Exadata and Adobe Flex. We have expanded our use of cloud services to support the deployment of our EIS, which has resulted in an open component and service based architecture that is highly scalable and capable of performing large scale analytics on demand. Our EIS platform and expanding use of cloud services enables us to efficiently scale our EIS and related solutions in existing and new geographic regions, and rapidly grow the number of enterprise customers, utility customers, and electric power grid operators in our network. We believe that a key factor to successfully offering our EIS and related solutions is integrating data from disparate sources and utilizing it to deliver customer-focused solutions utilizing open protocols.

Currently, our EIS platform collects approximately 1.5 billion monthly readings of facility energy consumption data on a sub-second, 1-minute, 5-minute, 15-minute or hourly basis and integrates that data with near real-time, historical and forecasted market variables. For enterprise customers, we collect this data with an EnerNOC Site Server. For our utility customers, we collect advanced metering infrastructure data directly from our utility customers’ meter data management systems. The applications hosted on our energy intelligence platform measure, manage, benchmark and optimize enterprise customers’ energy consumption and facility operations. We use this data to help our enterprise customers analyze consumption patterns, forecast demand,

 

4


Table of Contents

measure real-time performance during demand response events, continuously monitor building management equipment to optimize system operation, model rates and tariffs and create energy scorecards to benchmark similar facilities. We use this data to provide our utility customers with an integrated customer engagement and demand side management solution to serve their entire commercial, institutional and industrial, and small and medium-sized enterprises customer base. Our EIS and related solutions integrate data from utility meter, billing, and customer systems, as well as other sources, to deliver personalized insight on an enterprise’s energy use, as well as tools for customer administration and support. In addition, our EIS and related solutions have 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.

We have also deployed at certain of our enterprise customer sites the industry’s first presence-enabled smart grid technology, which enables real-time communication through open, standards-based presence technology between most Internet-enabled smart meters or devices and our NOC. The always-on, two-way presence-based connection significantly enhances visibility into our enterprise customer network and also streamlines the enterprise customer site enablement process, allowing us to more efficiently equip enterprise customers and deploy our EIS and related solutions. These devices are “firewall friendly” and can leverage existing enterprise customer networks to facilitate secure, authenticated and encrypted communication, without the need to establish a virtual private network.

Network Operations Center

Our NOC monitors all customer data and health and serves as our 24/7 customer support center. Our technology enables our NOC to automatically respond to signals sent to us by our utility customers and electric power grid operators to deliver demand reductions within targeted geographic regions. We can customize our technology to receive and interpret many types of dispatch signals sent directly from a utility customer or an electric power grid operator to our NOC. Following the receipt of such a signal, our NOC automatically notifies specified enterprise customer personnel of the demand response event. After relaying this notification to our enterprise customers, we initiate processes that reduce their electricity consumption from the electric power grid. These processes may include dimming lights, shifting equipment to power save mode, adjusting heating and cooling set points and activating a back-up generator. 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 enterprise customer 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, Germany, Ireland, Japan, New Zealand, and South Korea.

The EnerNOC Site Server

For our enterprise customers, we install a small device, called an EnerNOC Site Server, or ESS, at each customer site to collect and communicate to our platform near real-time electricity consumption data and, in certain cases, enable remote control of an enterprise customer’s electricity consumption. The ESS communicates to our NOC through the enterprise customer’s secure wireless internet connection or LAN. Our XMPP based communication protocol for communication between the ESS and our datacenters is highly efficient and allows secure communication across firewalls making it easy to apply our technology across a broad range of customers. The ESS is an open, integrated system consisting of a central hardware device residing inside a standard electrical box. The ESS allows our enterprise customers to, among other things, respond quickly and completely to instructions from us to reduce electricity consumption. We also support OpenADR protocol on our most recent ESS devices, an emerging standard for automated demand response communications.

Sales and Marketing

As of December 31, 2014, our sales and marketing team consisted of 306 employees, which included 30 professional services personnel. We organize our sales efforts by customer type. Our utility sales group sells to

utilities, while our enterprise sales group sells to enterprise customers. Our utility sales group is responsible for

 

5


Table of Contents

securing long-term contracts from utilities for our EIS and related solutions. We actively pursue long-term contracts in both restructured markets and in traditionally regulated markets. Our enterprise sales group sells our EIS and related solutions to enterprise customers and is located in major electricity regions throughout the United States and internationally in Australia, Brazil, Canada, China, Germany, India, Ireland, Japan, New Zealand, South Korea and the United Kingdom.

Our marketing group is responsible for influencing all market stakeholders—including customers, energy 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 enterprise and utility 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, 2014, our research and development team consisted of 161 employees. Our research and development team is responsible for developing and enhancing our existing EIS and related solutions, as well as the engineering and design of new functionality.

Our research and development expenses were approximately $20.7 million, $18.3 million and $16.2 million for the years ended December 31, 2014, 2013 and 2012, respectively. During the years ended December 31, 2014, 2013 and 2012, we capitalized internal software development costs of $6.0 million, $7.9 million and $4.7 million, respectively, and these amounts are included as software in property and equipment at December 31, 2014.

Customers

Enterprise Customers

Our EIS and related solutions provide cost effective energy management strategies for our enterprise customers by improving energy supply transparency, increasing energy efficiency, reducing real-time demand for electricity, and mitigating emissions. Our enterprise sales group primarily focuses their efforts on the following seven vertical markets: technology, education, food sales and storage, commercial real estate, government, healthcare and manufacturing/industrial. The following table lists some of our enterprise customers as of December 31, 2014 in each of the seven key vertical markets that our enterprise sales group primarily targets:

 

Technology

 

Education

 

Food Sales and Storage

 

Commercial Real Estate

AT&T

  The California State University   SuperVALU   Morgan Stanley

Level 3 Communications

  Colorado State University   Ahold   Beacon Properties

General Electric

  Wesley College (Perth)   Shop Rite   Equity Office Properties

Genentech

  North Penn School District   Great Lakes Cold Storage   Washington Realty Investment Trust

Verizon

  Wicomico County Public Schools   Perdue Incorporated   Beal Companies

Government

 

Healthcare

 

Manufacturing/Industrial

   

Commonwealth of Massachusetts

  George Washington University Hospital   Pfizer  

Baltimore Regional Cooperative Purchasing Committee

  Temecula Valley Hospital   Kimberly-Clark, Inc.  

County of Los Angeles, CA

  Shriners Hospital for Children   General Motors  

City of Corpus Christi, TX

  Kells West Regional Hospital   Leggett & Platt  

City of Albany, NY

  Genesis Healthcare   US Silica  

Our contracts with enterprise customers typically take two to four months to complete and have terms that generally range between one and five years.

 

6


Table of Contents

Utility Customers and Electric Power Grid Operators

We have significantly grown our base of utility customers and electric power grid operators since inception. As of December 31, 2014, we provided our EIS and related solutions to utility customers, and electric power grid operators in several regions throughout the United States, as well as internationally in Australia, Canada, Germany, Ireland, Japan, New Zealand and South Korea. Our utility customers include Southern California Edison Company and Tennessee Valley Authority, and the electric power grid operators to which we provide our EIS and related solutions include PJM, Australian Independent Market Operator Wholesale Electricity Market, Electric Reliability Council of Texas, or ERCOT, 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 without limitation our ability to negotiate acceptable pricing arrangements in such markets.

Entering into a contract with a utility customer typically takes 12 to 18 months to complete and, when successful, typically results in a multi-million dollar contract with terms that generally range between three and ten years. We refer to these contracts as utility contracts. To date, we have received substantially all of our revenues from our utility customers and electric power grid operators for providing our demand response solutions, EnerNOC Demand Manager and EnerNOC Demand Resource.

Certain of our significant demand response programs are part of deregulated wholesale electricity markets in the United States and internationally. In order to participate in these markets, 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 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 capacity 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 capacity in future periods, we assume the risk of delivery of the committed capacity levels and often are subject to financial penalties for both under-delivery and non-delivery.

Competition

We face competition from other providers of energy intelligence software and services, advanced metering infrastructure service providers, and utilities and competitive electricity suppliers who offer their own energy intelligence software, services and products. We also compete with traditional supply-side resources, such as peaking power plants.

The industry in which we participate is fragmented. When competing for enterprise customers, we believe that the primary factors on which we compete are:

 

   

the ability of the energy intelligence software and service provider to service multiple sites across different geographic regions and to provide additional technology-enabled energy intelligence software and services;

 

   

the ability of the energy intelligence software and service provider to apply customer-specific tariff and other pricing components to energy data;

 

   

the level of sophistication employed by the energy intelligence software and service provider to identify and optimize energy management capabilities and opportunities; and

 

   

the level of demand response capacity payments shared with those enterprise customers for their demand response capacity

When competing for utility customers and electric power grid operators, we believe that the primary factors on which we compete are:

 

   

the level of understanding and ability to segment the commercial and industrial customer base that the energy intelligence software and service provider is able to deliver to the utility;

 

7


Table of Contents
   

the pricing of the demand response or energy efficiency services being offered; and

 

   

the financial stability, historical performance levels and overall experience of the energy management solutions provider.

Our primary competitors include energy management service providers Energy Curtailment Specialists, Inc., Mach Energy, Constellation—an Exelon Corporation, Comverge, Inc., and Hess Inc., as well as energy technology providers including Opower, C3, FirstFuel, Summitt Energy, Schneider Electric and Lucid Design Group, Inc. We believe that our operational experience, deep understanding of energy use by commercial and industrial facilities, our ability to process utility bill data in over 100 countries, our proprietary solutions and data analytics, and leadership in the energy intelligence software and solutions sector gives us an advantage when competing for customers. In addition, across our energy intelligence software platform, we believe that we are unique in our ability to leverage real-time data across applications to unlock the greatest amount of value and efficiency for our customers, which we believe positions us favorably to win in competitive situations.

With respect to our competitors, some providers of advanced metering infrastructure services have added, or may add, energy intelligence software and solutions like ours to their existing business. In addition, some advanced metering infrastructure service providers are substantially larger and better capitalized than we are and have the ability to combine demand response and additional energy intelligence software and solutions into an integrated offering to a large existing customer base.

Utilities and competitive electricity suppliers could and sometimes do also offer their own demand response services and energy intelligence software offerings, which could decrease our base of potential enterprise customers and could decrease our revenues. However, demand response programs, as administered by utilities alone, are bound to standard tariffs to which all enterprise customers in the utility’s service territory must abide. Utilities must treat all rate class customers equally in order to serve them under public utility commission-approved tariffs. In contrast, we have the flexibility to offer customized EIS and related solutions to different enterprise customers. We believe that we also have technology and operational experience at the facility-level that both utilities and competitive electricity suppliers lack. We also believe our technology differentiates us from our competitors and enhances our leadership position. Furthermore, we believe that our EIS and related solutions are complementary to utilities and competitive electricity suppliers’ energy efficiency and demand response efforts because we can help enlist enterprise customers to their existing programs, reduce their workload by serving as a single point of contact for an aggregated pool of enterprise customers who choose to participate in their programs, and act to uphold or enhance enterprise customer engagement and satisfaction. However, utilities and competitive electricity suppliers may offer energy intelligence software and solutions at prices below cost or even for free in order to improve their customer relations or competitive positions, which would decrease our base of potential enterprise customers and could decrease our revenues. For instance, utilities and competitive electricity suppliers are increasingly providing expertise to enterprise customers relating to energy audits, demand reduction or energy efficiency measures.

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 and in turn receive a return on investment. 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 EIS and related 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 EIS and related solutions in restructured or deregulated electricity markets and in traditionally regulated electricity markets. Regulations within both types of markets impact how quickly customers may adopt our EIS and related solutions, the prices we can charge and profit margins we can earn, the MW we can enroll in certain programs, the timing with respect to when we begin earning revenue, and the various ways in which we are permitted or may choose to do business and accordingly, impact our assessments

 

8


Table of Contents

of which potential markets to most aggressively pursue. In addition, certain of our contracts with our utility customers are subject to regulatory approval, which regulatory approval may not be obtained on a timely basis, if at all.

The prices we can charge and revenues and profit margins we earn also can be affected by market regulations, such as program rules that can impact our administrative and compliance costs to manage a portfolio of demand response resources. For example rules that require increased requirements, such as more 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 our enterprise customers and the amounts that we need to pay them for their participation.

In regional electricity markets in which we participate in auctions, changes in auction rules impact our participation in future auctions and the ability to reconfigure positions taken in prior auctions. For example, rules which impact quantities of capacity resources we are permitted to qualify to bid or purchase capacity in an auction or make internal or external transfers capacity 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, our results of operations and financial condition could be significantly and negatively impacted. On an ongoing basis, we assess known, anticipated and potential changes to market rules and projected market prices for the energy intelligence software and solutions that we offer. As a result of such assessment, we may alter our participation in both potential new markets and in markets in which we currently offer our EIS and related solutions, including by determining not to participate in open market bids to provide demand response capacity.

The policies regarding the measurement and verification of demand response resources, safety regulations 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 enterprise customers, even when back-up generators are strictly used to maintain system reliability. As a result, 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 energy intelligence software and 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 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, 2014, we held eight patents in the United States and Australia, and had 41 published patent applications pending. Our patent applications and any future patent applications might not result in a patent being issued within the scope of the claims we seek or at all, and any patents we may 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, 2014, 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.

 

9


Table of Contents

With respect to, among other things, proprietary know-how that is not patentable and processes for which patent protection may not offer the best legal and business protection, we rely on trade secret protection and employ confidentiality and proprietary information agreements to safeguard our interests. Many elements of our EIS and related 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 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

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. As a result, our revenues can fluctuate from quarter to quarter based upon the seasonality of our demand response business in certain of the markets in which we operate, where payments under certain of our long-term contracts and pursuant to certain open market bidding programs in which we participate are higher or concentrated in particular seasons and months. 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. In addition, we participate in the Western Australia demand response program operated by the Australian Independent Market Operator Wholesale Electricity Market. Prior to the fourth quarter of 2014, we recognized demand response capacity-based revenue from Western Australia in September at the end of the annual program year which began on October 1. This typically resulted in higher revenues in the third quarter as compared to our first, second and fourth quarters. As of September 30, 2014, we determined that the amount of fees potentially subject to adjustment or refund was reliably estimable beginning with the new program year in Western Australia commencing on October 1, 2014. Therefore, future revenues will be recognized ratably over the delivery period from October 1 to September 30.

The PJM extended demand response product includes the period of June—October, plus May of the following year. We anticipate the revenue earned from this product will be recognized at the end of the delivery year in May. For further discussion of revenue recognition, please refer to Note 1 contained in Appendix A to the Annual Report on Form 10-K.

Employees

As of December 31, 2014, we had 1,125 full-time employees, including 197 charged to cost of revenues, 306 in sales and marketing, 161 in research and development and 461 in general and administrative, including operations. Professional service employees totaled 127 as of December 31, 2014, including 30 employees charged to general and administrative and 97 employees charged to sales and marketing. Of these full-time employees, 702 were located in the United States with 432 located in New England, 77 located in California, and the remaining full-time employees located in other areas across the United States. In addition, we had 131 full-time employees located in Brazil, 98 located in India, 54 located in Canada, 35 located in Germany, 32 located in Australia, 32 located in the United Kingdom and 41 located in our other international locations. We expect to grow our employee base and our future success will depend 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, 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.

 

10


Table of Contents

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 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.

 

11


Table of Contents
Item 1A. Risk Factors

We operate in a rapidly changing environment that involves a number of risks that could materially affect our business, financial condition or future results, some of which are beyond our control. The following risk factors and other information included in this Annual Report on Form 10-K should be carefully considered. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also adversely affect our business. We refer you to our note on forward-looking statements in Item 7 below, which identifies certain forward-looking statements contained in this report that are qualified by these risk factors.

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, 2014, we had an accumulated deficit of $69.3 million. Although we achieved profitability for the years ended December 31, 2014, 2013 and 2010, with net income of $12.1 million, $22.1 million and $9.6 million, respectively, we incurred net losses for all other fiscal years since our inception. Our operating losses have historically been driven by start-up costs, costs of developing our technology including new product and service offerings, and operating expenses related to increased headcount as a result of our overall growth and expansion into new markets. As we seek to grow our revenues, and enterprise and utility customer base, we plan to continue to invest in our business and employee base in order to capitalize on emerging opportunities and expand our EIS and related solutions, which will require increased operating expenses. Although we believe we will be able to grow our revenues at rates that will allow us to achieve profitability again in the future, these increased operating expenses, as well as other factors, may cause us to incur net losses in the near term.

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

Unfavorable regulatory decisions in markets where we currently operate or choose to operate in the future could significantly and negatively affect our business. For example, in a May 23, 2014 decision by the United States Court of Appeals for the D.C. Circuit, the court held that the Federal Energy Regulatory Commission, or FERC, did not have jurisdiction under the Federal Power Act to issue FERC Order 745, an order that required, among other things, that economic demand response resources participating in the wholesale energy markets administered by electric power grid operators, such as PJM, be paid the locational marginal price of energy. The decision of the D.C. Circuit is presently subject to Petitions for Certiorari brought by the Solicitor General of the United States on behalf of FERC, a of coalition parties including us and other parties seeking a reversal of the decision. If the decision is implemented and FERC Order 745 is invalidated, certain revenues earned prior to May 23, 2014 in connection with our participation in price-based/economic demand response programs, which we have estimated to be approximately $20.1 million, may become subject to refund, which could negatively impact our business and results of operations. Revenue of $2.0 million earned subsequent to May 23, 2014 and through December 31, 2014 has been deferred; we will continue to defer future revenues relating to these programs until final regulation resolution is reached. In the event the court’s decision is broadened to include capacity or ancillary services markets in which we currently operate or choose to operate in the future, our future revenues and profit margins may be significantly reduced and our results of operations and financial condition could be negatively impacted. Program or market rules could also be modified to change the design of or pricing related to a particular demand response program, which may adversely affect our participation in that program or cause us to cease participation in that program altogether, or a demand response program in which we currently participate could be eliminated in its entirety and/or replaced with a new program that is more expensive for us to operate or require substantial changes to the business to enable continued participation. Any elimination or change in the design of any demand response program, including the retroactive application of market rule changes, could adversely impact our ability to successfully manage our portfolio of demand response capacity in that program, especially in the PJM market where we continue to have substantial operations, and could have a material adverse effect on our results of operations and financial condition.

 

12


Table of Contents

Regulators could also modify market rules in certain areas to further limit the use of back-up generators in demand response markets or could implement bidding floors or caps that could lower our revenue opportunities. For example, the Environmental Protection Agency, or the EPA, recently issued a final rule in the National Environmental Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines that will allow emergency generators to participate in emergency demand response programs for up to 100 hours per year. The final rule has been challenged by parties opposing the 100 hour limit, among other things. In the event this final rule is invalidated by a court and the decision is upheld, the result may be a decrease to the 100 hour per year limit for, or the elimination of any, participation by emergency generators in emergency demand response programs. If the final rule is invalidated and a more restrictive rule is adopted, some of the demand response capacity reductions that we aggregate from enterprise customers willing to reduce consumption from the electric power grid by activating their own back-up generators during demand response events would not qualify as capacity without the addition of certain emissions reduction equipment. If this were to occur, we would have to find alternative sources of capacity to meet our capacity obligations to our utility customers and electric power grid operators. If we were unable to procure additional sources of capacity to meet these obligations we could be subject to substantial penalties, and our business and results of operations could be negatively impacted.

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

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

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, 2014, 2013 and 2012, revenues generated from open market sales to PJM, an electric power grid operator, accounted for 52%, 45% and 40%, 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 increases to the operational requirements 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. For example, the introduction in the PJM market of the limited, extended and annual demand response products beginning in the 2014/2015 delivery year could adversely impact our ability to successfully manage our portfolio of demand response capacity in that program and have a material adverse effect on our results of operations and financial condition. In addition, PJM has proposed changes to the operational requirements, compensation, and measurement and verification of demand response resources participating in the PJM capacity market. In the event the proposed changes are implemented, it could adversely impact our ability to successfully manage our portfolio of demand response capacity in that program and have a material adverse effect on our results of operations and financial condition.

 

13


Table of Contents

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 EIS and related 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.

If we fail to successfully educate existing and potential enterprise and utility customers, and electric power grid operators regarding the benefits of our EIS and related solutions or a market otherwise fails to develop for our EIS and related solutions, our ability to sell our EIS and related solutions and grow our business could be limited.

Our future success depends on continued commercial acceptance of our EIS and related solutions. The market for EIS and related solutions in general is relatively new. If we are unable to educate our potential customers about the advantages of our EIS and related solutions over competing products and services, or if our existing customers no longer rely on our EIS and related solutions, our ability to sell our EIS and related solutions will be limited. In addition, the energy intelligence software sector is rapidly evolving and therefore, we cannot accurately assess the size of the market and we may have limited insight into trends that may emerge and affect our business. For example, we may have difficulty predicting customer needs and developing EIS and related solutions that address those needs. If the market for our EIS and related solutions does not continue to develop, our ability to grow our business could be limited and we may not be able to operate profitably.

The success of our business depends in part on our ability to develop new EIS and related solutions and increase the functionality of our current EIS and related solutions.

The market for our EIS and related solutions is characterized by rapid technological changes, frequent new software introductions, Internet- related 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 and related solutions that comply with present or emerging industry regulations and technology standards. Also, any new or modified regulation or technology standard could increase our cost of doing business.

As part of our strategy to enhance our EIS and related solutions and grow our business, we plan to continue to make substantial investments in the research and development of new technologies. Our future success will depend in part on our ability to continue to design and sell new, competitive EIS and related solutions and enhance our existing EIS and related solutions. Initiatives to develop new EIS and related solutions will require continued investment, and we may experience unforeseen problems in the performance of our technologies and operational processes, including new technologies and operational processes that we develop and deploy, to implement our EIS and related solutions. In addition, software addressing our EIS and related solutions is complex and can be expensive to develop, and new software and software enhancements can require long development and testing periods. If we are unable to develop new EIS and related solutions or enhancements to our existing EIS and related solutions on a timely basis, or if the market does not accept our new or enhanced EIS and related solutions, we will lose opportunities to realize revenues and obtain customers, and our business and results of operations will be adversely affected.

 

14


Table of Contents

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.

In addition to organic growth, we intend to continue to pursue growth through the acquisition of companies or assets that may enable us to enhance our technology and capabilities, expand our geographic market, add experienced management personnel and increase our service offerings. However, we may be unable to implement this growth strategy if we cannot identify suitable acquisition candidates, reach agreement on potential acquisitions on acceptable terms, successfully integrate personnel or assets that we acquire or for other reasons. Our acquisition efforts may involve certain risks, including:

 

   

unexpected acquisition costs or liabilities that may cause us to fail to meet our previously stated financial guidance, or the effects of purchase accounting may be different from our expectations;

 

   

problems that may arise with our ability to successfully integrate the acquired businesses, which may result in us not operating as effectively and efficiently as expected, and may include:

 

   

diversion of management time, as well as a shift of focus from operating the businesses to issues related to integration and administration or inadequate management resources available for integration activity and oversight;

 

   

failure to retain and motivate key employees;

 

   

failure to successfully manage relationships with customers and suppliers;

 

   

failure of customers to accept our EIS and related solutions;

 

   

failure to effectively coordinate sales and marketing efforts;

 

   

failure to combine service offerings quickly and effectively;

 

   

failure to effectively enhance acquired technology, applications, services and products or develop new applications, services and products relating to the acquired businesses;

 

   

difficulties and inefficiencies in managing and operating businesses in multiple locations or operating businesses in which we have either limited or no direct experience;

 

   

difficulties integrating financial reporting systems;

 

   

difficulties in the timely filing of required reports with the SEC; and

 

   

difficulties in implementing controls, procedures and policies, including disclosure controls and procedures and internal controls over financial reporting (appropriate for a larger public company) at companies that, prior to their acquisition, lacked such controls, procedures and policies, which may result in ineffective disclosure controls and procedures or material weaknesses in internal controls over financial reporting;

 

   

difficulties in achieving the expected synergies from an acquisition including taking longer than expected to achieve those synergies;

 

   

incurring future impairment charges related to diminished fair value of businesses acquired as compared to the price we paid for them;

 

   

restructuring operations or reductions in workforce, which may result in substantial charges to our operations; and

 

   

issuance of potentially dilutive equity securities, the incurrence of debt or contingent liabilities, which could harm our financial condition.

 

15


Table of Contents

We face risks related to our expansion into international markets.

We intend to expand our addressable market by continuing to pursue opportunities to provide our EIS and related solutions in international markets. New international markets may require us to respond to new and unanticipated regulatory, marketing, sales and other challenges. These compliance efforts may be time-consuming and costly, and there can be no assurance that we will be successful in responding to these and other challenges we may face as we enter and attempt to expand in international markets. International operations also entail a variety of other risks, including:

 

   

Compliance with numerous legislative, regulatory or market requirements of foreign countries;

 

   

currency exchange fluctuations;

 

   

longer payment cycles and greater difficulty in accounts receivable collection;

 

   

compliance with U.S. laws such as the U.S. Foreign Corrupt Practices Act, or FCPA, and local laws prohibiting bribery and corrupt payments to government officials;

 

   

difficulties in developing, staffing, and simultaneously managing a large number of varying foreign operations as a result of distance, language, and cultural differences;

 

   

laws and business practices that favor local competitors or prohibit foreign ownership of certain businesses;

 

   

potentially adverse tax consequences;

 

   

compliance with laws of foreign countries, international organizations such as the European Commission, treaties, and other international laws;

 

   

insufficient revenues to offset increased expenses associated with acquisitions;

 

   

assumption of liabilities and exposure to unforeseen liabilities of acquired companies;

 

   

the inability to continue to benefit from local subsidies due to change in control; and

 

   

unfavorable labor regulations.

International operations are also subject to general geopolitical risks, such as political, social and economic instability and changes in diplomatic and trade relations. One or more of these factors could adversely affect any international operations and result in lower revenue and/or greater operating expenses than we expect and could significantly affect our results of operations and financial condition.

We 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 recurring revenues from the sale of our EIS and related solutions directly or indirectly, to the electric power industry. Sales of our EIS and related solutions to utility customers and electric power grid operators may be deferred, cancelled 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, 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 the spending patterns of our utility customers and electric power grid operators, and on 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

 

16


Table of Contents

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. Pronounced variability or an extended period of reduction in spending by utilities and electric power grid operators could negatively impact our business and make it difficult for us to accurately forecast our future sales.

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 Germany, 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 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 profitability in future periods. Our ability to provide demand response capacity under our utility contracts and in open market bidding programs depends on the amount of MW to satisfy our demand response obligations that we manage across enterprise customers who enter into contracts with us to reduce electricity consumption on demand. If we are unsuccessful in limiting our enterprise customer terminations or if our existing enterprise customers 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.

We face pricing pressure relating to electric capacity made available to electric power grid operators and utilities and in the percentage or fixed amount paid to enterprise customers for making capacity available, which could adversely affect our results of operations and financial condition.

Continued decreases in the price of demand response capacity by our competitors 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 would result in reduced revenues and lower profit margins and would adversely affect our results of operations and financial condition. Additionally, continued

 

17


Table of Contents

increases in the percentage or fixed amount paid to enterprise customers by our competitors for making capacity available could result in a loss of enterprise customers or a decrease in the growth of our business. It also may require us to increase the percentage or fixed amount we pay to our enterprise customers to remain competitive, which would result in increases in the cost of revenues and lower profit margins and would adversely affect our results of operations and financial condition.

Our business is subject to government regulation and may become subject to modified or new government regulation, which may negatively impact our ability to sell and market our EIS and related solutions.

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. In addition, FERC has specified that when a demand response resource makes sales of energy for resale, the resource may become subject to direct regulation by FERC. Additional regulation by FERC or other new or modified government regulations related to the sale, marketing or operation of our EIS and related solutions that 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. Additionally, federal, state, provincial, local or foreign governmental entities may seek to change existing regulations, impose additional regulations or change their interpretation of the applicability of existing regulations. Any modified or new government regulation applicable to our current or future EIS and related solutions, whether at the federal, state, provincial or local level, may negatively impact the installation, servicing and marketing of, and increase our costs and the price related to, our EIS and related solutions. In addition, despite our efforts to manage compliance with any other regulations to which we are subject, we may be found to be in non-compliance with such regulations and therefore subject to sanctions, including penalties or fines, which could have a material adverse effect on our business, financial condition and results of operations.

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

 

18


Table of Contents

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.

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 $160.0 million aggregate principal amount of 2.25% convertible senior notes due 2019, or the Notes, depends on our future performance, which is subject to regulatory, economic, financial, competitive and other factors beyond our control. Our business may not continue to generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we may be required to adopt one or more alternatives, such as selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at such time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations.

We may not have the ability to repay the principal amount of the Notes at maturity, to raise the funds necessary to settle conversions of the Notes or to repurchase the Notes upon a fundamental change, and instruments governing our future debt may contain limitations on our ability to pay cash upon conversion or repurchase of the Notes.

At maturity in 2019, the entire outstanding principal amount of the Notes will become due and payable by us. Holders of the Notes will also have the right to require us to repurchase their Notes upon the occurrence of a fundamental change at a repurchase price equal to 100% of the principal amount of the Notes to be repurchased, plus accrued and unpaid interest, if any. In addition, upon conversion of the Notes following our receipt of stockholder approval, if applicable, unless we elect to deliver solely shares of our common stock to settle such conversion (other than cash in lieu of any fractional share), we will be required to make cash payments in respect of the Notes being converted. However, we may not have enough available cash or be able to obtain financing at the time we are required to repay the principal amount of the Notes, make repurchases of Notes surrendered therefor or settle conversions of the Notes. In addition, our ability to repurchase the Notes or to pay cash upon conversions of the Notes may be limited by law, by regulatory authority or by agreements governing our future indebtedness. Our failure to repay the principal amount of the Notes, repurchase Notes at a time when the repurchase is required or to pay any cash payable on future conversions of the Notes as required by the applicable indenture would constitute a default under the indenture. A default under the indenture or the fundamental change itself could also lead to a default under agreements governing our future indebtedness including the $30.0 million senior secured revolving credit facility with Silicon Valley Bank, or SVB, which we refer to as the 2014 credit facility. If the repayment of the related indebtedness were to be accelerated after any applicable notice or grace periods, we may not have sufficient funds to repay the indebtedness and repurchase the Notes or make cash payments upon conversions thereof.

 

19


Table of Contents

The 2014 credit facility contains financial and operating restrictions that may limit our access to credit. If we fail to comply with covenants contained in the 2014 credit facility, we may be required to repay our indebtedness thereunder.

Provisions in the 2014 credit facility impose restrictions on our ability to, among other things:

 

   

incur additional indebtedness;

 

   

create liens;

 

   

enter into transactions with affiliates;

 

   

transfer assets; make certain acquisitions;

 

   

pay dividends or make distributions on, or repurchase, EnerNOC stock;

 

   

merge or consolidate; or

 

   

undergo a change of control.

In addition, we are required to meet certain financial covenants customary with this type of credit facility, including maintaining minimum unrestricted cash and a minimum specified ratio of current assets to current liabilities. The 2014 credit facility also contains other customary covenants. We may not be able to comply with these covenants in the future. Our failure to comply with these covenants may result in the declaration of an event of default and could cause us to be unable to borrow under the 2014 credit facility. In addition to preventing additional borrowings under the 2014 credit facility, an event of default, if not cured or waived, may result in the acceleration of the maturity of indebtedness outstanding under the 2014 credit facility, which would require us to pay all amounts outstanding. In addition, in the event that we default under the 2014 credit facility while we have letters of credit outstanding, we will be required to post up to 105% of the value of the letters of credit in cash with SVB to collateralize those letters of credit. Furthermore, the 2014 credit facility matures on August 11, 2015. 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, 2014, 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 of third parties to manufacture or install quality products or provide reliable services in a timely manner or at all could cause delays in the delivery of our EIS and related solutions, or could result in a failure to provide accurate data to our customers, which could damage our reputation, cause us to lose customers and have a material adverse effect on our business results of operations and financial condition.

Our success depends on our ability to provide quality, reliable, and secure EIS and related solutions in a timely manner, which in part requires the proper functioning of facilities and equipment owned, operated, installed or manufactured by third parties upon which we depend. For example, our reliance on third parties includes:

 

   

utilizing components that we or third parties install or have installed at enterprise customer sites;

 

   

relying on metering information provided by third parties to accurately and reliably provide customer data to our utility customers and electric power grid operators;

 

   

outsourcing email notification and cellular and paging wireless communications that are used to notify our enterprise customers of their need to reduce electricity consumption at a particular time and to execute instructions to devices installed at our enterprise customer sites that are programmed to automatically reduce consumption on receipt of such secure communications; and

 

   

outsourcing certain installation and maintenance operations to third-party providers.

 

20


Table of Contents

Any delays, malfunctions, inefficiencies or interruptions in these products, services or operations could adversely affect the reliability or operation of our EIS and related solutions, which could cause us to experience difficulty monitoring or retaining current customers and attracting new customers. 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.

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 that we enable, in some cases up to a year after enablement. For example, the PJM limited demand response product operates on a June to May program-year basis, which means that a MW that we enable after June of each year will typically not be recognized until the following year. The up-front costs we incur to enable our MW in PJM and other similar markets, coupled with the delay in receiving revenues from those MW, could adversely affect our operating results and could cause the market price of our common stock to decline substantially.

We operate in highly competitive markets; if we are unable to compete successfully, we could lose market share and revenues.

The market for EIS and related solutions is fragmented. Some traditional providers of advanced metering infrastructure services have added, or may add, energy intelligence 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 intelligence 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 EIS and related solutions.

 

21


Table of Contents

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 enterprise customer 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 enterprise customer or customers 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. We incurred aggregate net penalties of $0.1 million, $0.8 million and $1.9 million during the years ended December 31, 2014, 2013 and 2012, respectively.

Our ability to achieve our committed capacity depends on the performance of our enterprise customers, and the failure of these customers to make the appropriate levels of capacity available when called upon could cause us to make refund payments to, or incur penalties imposed by, our utility customers and electric power grid operators.

The capacity level that we are able to achieve is dependent upon the ability of our enterprise customers to curtail their energy usage when called upon by us during a demand response event or a measurement and verification test. 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 enterprise customers to perform when called upon by us. For example, if PJM dispatches a measurement and verification test and our enterprise customers fail to perform or perform in a deficient manner, we may be subject to substantial penalties given that we have enrolled a significant number of MW in the PJM demand response market. In the event that our enterprise customers are unable to perform or perform at levels below which they agreed to perform, we may be

 

22


Table of Contents

unable to achieve our committed capacity levels and may be subject to the refunds or penalties described in the risk factor above, which could have a material adverse effect on our results of operations and financial condition. The capacity level that we are able to achieve also varies with the electricity demand of targeted equipment, such as heating and cooling equipment, at the time an enterprise customer is called to perform. Accordingly, our ability to deliver committed capacity depends on factors beyond our control, such as the temperature and humidity, and then-current electricity use by our enterprise customers when those enterprise customers are called to perform. The correct operation of, and timely communication with, devices used to control equipment are also important factors that affect available capacity.

We expect to continue to expand our sales and marketing, operations, and research and development capabilities, as well as our financial and reporting systems, and as a result we may encounter difficulties in managing our growth, which could disrupt our operations.

We expect to experience continued growth in the number of our employees and significant growth in the scope of our operations. To manage our anticipated future growth, we must continue to implement and improve our managerial, operational, financial and reporting systems, continue to improve our internal controls, procedures and compliance programs, expand our facilities, and continue to recruit and train additional qualified personnel. All of these measures will require significant expenditures and will demand the attention of management. Due to our limited resources, we may not be able to effectively manage the expansion of our operations, continue to implement sufficient internal controls, procedures or compliance programs, or recruit and adequately train additional qualified personnel. The physical expansion of our operations may lead to significant costs and may divert our management and business development resources. Any inability to manage growth could delay the execution of our business plans or disrupt our operations.

We allocate our operations, sales and marketing, research and development, general and administrative, and financial resources based on our business plan, which includes assumptions about the demand for our EIS and related solutions, current and future utility contracts and open market programs with utility customers and electric power grid operators, current and future contracts with enterprise customers, variable prices in open market programs for demand response capacity, the development of ancillary services markets which enable demand response as a revenue generating resource and a variety of other factors relating to electricity markets. However, these factors are uncertain. If our assumptions regarding these factors prove to be incorrect, then actual demand for our EIS and related solutions could be significantly less than the demand we anticipate and we may not be able to sustain our revenue growth or achieve profitability in future periods.

We may require significant additional capital to pursue our growth strategy, but we may not be able to obtain additional financing on acceptable terms or at all.

The growth of our business will depend on substantial amounts of additional capital for marketing and product development of our EIS and related solutions, and posting financial assurances in order to enter into utility contracts and open market bidding programs with utilities and electric power grid operators. Our capital requirements will depend on many factors, including the rate of our revenue and sales growth, our introduction of new EIS and related solutions and enhancements to our existing EIS and related solutions and our expansion of sales and marketing and product development activities. In addition, we may consider strategic acquisitions of complementary businesses or technologies to grow our business, which could require significant capital and could increase our capital expenditures related to future operation of the acquired business or technology. We may not be able to obtain loans or additional capital on acceptable terms or at all.

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 guarantees the services of

 

23


Table of Contents

the individual for a specified period of time. All of the employment arrangements with our key personnel, including the members of our senior management team, provide that employment is at-will and may be terminated by the employee at any time and without notice. The loss of the services of any of our key personnel might impede our operations or the achievement of our strategic and financial objectives. We rely on our research and development team to research, design and develop new and enhanced EIS and related solutions. We rely on our operations team to install, test, deliver and manage our EIS and related solutions. We rely on our sales and marketing team to sell our EIS and related solutions 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 EIS and related solutions. We hold eight patents and numerous trademarks and copyrights, in addition we have filed 41 patent applications pending. 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 secrecy laws, as well as confidentiality and proprietary information agreements and licensing arrangements, to establish and protect our intellectual property. However, we have not obtained confidentiality and proprietary information agreements from all of our customers and vendors, and although we have entered into confidentiality and proprietary information agreements with all of our employees, we cannot be certain that these agreements will be honored. Some of our confidentiality and proprietary information agreements may not be in writing, and some customers are subject to laws and regulations that require them to disclose information that we would otherwise seek to keep confidential. Policing unauthorized use of our intellectual property is difficult and expensive, as is enforcing our rights against unauthorized use. The steps that we have taken or may take may not prevent misappropriation of the intellectual property on which we rely. In addition, effective protection may be unavailable or limited in jurisdictions outside the United States, as the intellectual property laws of foreign countries sometimes offer less protection or have onerous filing requirements. From time to time, third parties may infringe our intellectual property rights. Litigation may be necessary to enforce or protect our rights or to determine the validity and scope of the rights of others. Any litigation could be unsuccessful, cause us to incur substantial costs, divert resources away from our daily operations and result in the impairment of our intellectual property. Failure to adequately enforce our rights could cause us to lose rights in our intellectual property and may negatively affect our business.

We may be subject to damaging and disruptive intellectual property litigation related to allegations that our EIS and related solutions infringe on intellectual property held by others, which could result in the loss of use of those applications, services and products.

Third-party patent applications, patents and other intellectual property rights may relate to our EIS and related solutions. As a result, third-parties may in the future make infringement and other allegations that could subject us to intellectual property litigation relating to our EIS and related solutions which litigation could be time-consuming and expensive, divert attention and resources away from our daily operations, impede or prevent delivery of our EIS and related solutions and require us to pay significant royalties, licensing fees and damages. In addition, parties making infringement and other claims may be able to obtain injunctive or other equitable relief that could effectively block our ability to provide our EIS and related solutions and could cause us to pay substantial damages. In the event of a successful claim of infringement, we may need to obtain one or more licenses from third parties, which may not be available on reasonable terms, or at all.

 

24


Table of Contents

The use of open source software in our systems and technology may expose us to additional risks and harm our intellectual property.

Our information technology and other systems include software that is subject to open source licenses. While we monitor the use of all open source software in our EIS and related solutions and take certain measures to ensure that no open source software is used or distributed in such a way as to subject our EIS or related solutions to any unanticipated conditions or restrictions, such use or distribution could inadvertently occur. In the event that any of our EIS or related solutions were determined to be subject to an open source license, whether through our own incorporation of software or through licensed software from a third-party provider, we could be required to release the affected portions of our source code publicly, make portions of such applications available under open source licenses, re-engineer all, or a portion of, such applications or otherwise be limited in the licensing of our EIS or related solutions, each of which could reduce or eliminate the value of our EIS and related solutions. Many of the risks associated with usage of open source software are outside of our control and cannot be eliminated, and could negatively affect our business, results of operations and financial condition.

If our information technology systems fail to adequately gather, assess and protect data used in providing our EIS and related solutions, or if we experience an interruption in their operation, our business, financial condition and results of operations could be adversely affected.

The efficient operation of our business is dependent on our information technology systems. We rely on our information technology systems to effectively control the devices which enable our EIS and related solutions to gather and assess data used in providing our EIS and related solutions manage relationships with our customers, 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 respond to demand response events. In addition, our information technology systems are vulnerable to damage or interruption from:

 

   

earthquake, fire, flood and other natural disasters;

 

   

terrorist attacks and attacks by computer viruses or hackers;

 

   

power loss; and

 

   

computer systems, Internet, telecommunications or data network failure.

Any interruption in the operation of our information technology systems could result in decreased revenues under our contracts and commitments, reduced profit margins on revenues where fixed payments are due to our enterprise customers, reductions in our demonstrated capacity levels going forward, customer dissatisfaction and lawsuits and could subject us to penalties, any of which could have a material adverse effect on our business, financial condition and results of operations.

Any internal or external security breaches involving our EIS and related solutions and even the perception of security risks involving our EIS and related solutions or the transmission of data over the Internet, whether or not valid, could harm our reputation and inhibit market acceptance of our EIS and related solutions and cause us to lose customers.

We use our EIS and related solutions to compile and analyze sensitive or confidential information related to our customers. In addition, some of our EIS and related solutions allow us to remotely control equipment at enterprise customer sites. Our EIS and related solutions rely on the secure transmission of proprietary data over the Internet for some of this functionality. Well-publicized compromises of Internet security, or cyber-attacks, could have the effect of substantially reducing confidence in the Internet as a medium of data transmission. The occurrence or perception of security breaches in our EIS and related solutions or our customers’ concerns about Internet security or the security of our EIS and related solutions whether or not they are warranted, could have a material adverse effect on our business, harm our reputation, inhibit market acceptance of our EIS and related solutions and cause us to lose customers, any of which could have a material adverse effect on our financial condition and results of operations.

 

25


Table of Contents

We may come into contact with sensitive consumer information or data when we perform operational, installation or maintenance functions for our customers. Even the perception that we have improperly handled sensitive, confidential information could have a negative effect on our business. If, in handling this information, we fail to comply with privacy or security laws, we could incur civil liability to government agencies, customers and individuals whose privacy is compromised. In addition, third parties may attempt to breach our security or inappropriately use our EIS and related solutions particularly as we grow our business, through computer viruses, electronic break-ins and other disruptions. We may also face a security breach or electronic break-in by one of our employees or former employees. If a breach is successful, confidential information may be improperly obtained, and we may be subject to lawsuits and other liabilities.

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 regulatory approval processes. They also tend to be risk averse and tend 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 such as our EIS and related solutions. Accordingly, our potential enterprise and utility customers may take longer to reach a decision to purchase our software and services. 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 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, 2014 and assessed all deficiencies on both an individual basis and in combination to determine if, when aggregated, they constitute 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.

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

 

26


Table of Contents

operators. 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, 2014, we had $22.8 million outstanding letters of credit under the 2014 credit facility, leaving $7.2 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 or all of 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. The number of shares of our common stock that we issued in our initial public offering, or IPO, and follow-on public offerings, together with any subsequent shares of stock we issue, may be sufficient, taking into account prior or future shifts in our ownership over a three-year period, to cause us to undergo an ownership change. 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 liability for us. To date, although we have been able to utilize our net operating loss carryforwards to offset the maximum amount of taxable income allowed by the various tax jurisdictions in which we operate, we may not be able to utilize some or all of these net operating losses in the future.

We may have exposure to additional tax liabilities .

As a multinational corporation, we are subject to income taxes in the U.S. and various foreign jurisdictions. Significant judgment is required in determining our global provision for income taxes 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. Our income tax returns are routinely subject to audits by tax authorities. Although we regularly assess the likelihood of adverse outcomes resulting from these examinations to determine our tax estimates, a final determination of tax audits or tax disputes could have an adverse effect on our financial condition, results of operations and cash flows.

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. We are regularly under audit by tax authorities with respect to these non-income taxes and may have exposure to additional non-income tax liabilities, which could have an adverse effect on our results of operations, financial condition 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.

 

27


Table of Contents

If the software systems we use in providing our EIS and related solutions or the manual implementation of such systems produce inaccurate information or is incompatible with the systems used by our customers, it could preclude us from providing our EIS and related solutions, which could lead to a loss of revenues and trigger penalty payments.

Our software is complex and, accordingly, 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 about the level of demand reduction at an enterprise customer site, which could cause us to fail to meet our commitments to have capacity available or could result in an overpayment or underpayment to us and our enterprise customers by our electric power grid operator and utility customer. Any such failures could also cause us to be subject to penalty payments to our electric power grid operator and utility customers, cause a reduction in our revenue in the period that any adjustment is identified and result in reductions in capacity payments under utility contracts and open market bidding programs in subsequent periods. In addition, such defects and inaccurate data may prevent us from successfully providing our portfolio of additional EIS and related solutions which would result in lost revenues. Software defects or inaccurate data may lead to customer dissatisfaction and our customers may seek to hold us liable for any damages incurred. As a result, we could lose customers, our reputation could be harmed, and our financial condition and results of operations could be materially adversely affected.

We currently serve an enterprise customer base that uses a wide variety of constantly changing hardware, software applications and operating systems. Building control, process control and metering systems frequently reside on non-standard operating systems. Our EIS and related solutions need to interface with these non-standard systems in order to gather and assess data and to implement changes in electricity consumption. Our business depends on the following factors, among others:

 

   

our ability to integrate our technology with new and existing hardware and software systems, including metering, building control, process control, and distributed generation systems;

 

   

our ability to anticipate and support new standards, especially Internet-based standards and building control and metering system protocol languages; and

 

   

our ability to integrate additional software modules under development with our existing technology and operational processes.

If we are unable to adequately address any of these factors, our results of operations and prospects for growth could be materially adversely affected.

We may face certain product liability or warranty claims if we disrupt our customers’ networks or applications.

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 all liability that may be imposed under these types of claims. A material product liability claim may seriously harm our results of operations.

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

 

28


Table of Contents

that currency or maintain receivable and payable 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 risk exposure and may adversely impact our financial condition and results of operations.

An adverse change in the projected cash flows from our acquired businesses or the business climate in which they operate could require us to incur an impairment charge, which would have an adverse impact on our operating results.

We periodically review the carrying value of the goodwill and other long-lived assets reflected in our financial statements to determine if any adverse conditions exist or a change in circumstances has occurred that would indicate impairment of the value of these assets. Conditions that would indicate impairment and necessitate a revaluation of these assets include, but are not limited to, a significant adverse change in the business climate or the legal or regulatory environment within which we operate. If the carrying value of an asset is determined to be impaired we will write-down the carrying value of the intangible asset to its fair value in the period identified. 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. As of December 31, 2014, we had approximately $146.1 million of goodwill and intangible assets, including $66.5 million of goodwill and intangible assets from our acquisitions completed in the year ended December 31, 2014, but not including the acquisition of World Energy in January 2015. It is possible that the continuation of the current global financial and economic turmoil could negatively affect our anticipated cash flows, or the discount rate that is applied to valuing those cash flows, which could require an interim impairment test of goodwill or our intangible assets. Any impairment test could result in a material impairment charge that would have an adverse impact on our financial condition and results of operations.

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 market 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 in some quarter or quarters. Our failure to meet such expectations or our financial guidance could cause the market price of our common stock to decline substantially.

Our quarterly revenues and operating results may vary depending on a number of factors, including:

 

   

demand for and acceptance of our EIS and related solutions;

 

   

the seasonality of our demand response business in certain of the markets in which we operate, where revenues recognized under certain utility contracts and pursuant to certain open market bidding programs can be higher or concentrated in particular seasons and months;

 

   

changes in open market bidding program rules and reductions in pricing for demand response capacity;

 

   

delays in the implementation and delivery of our EIS and related solutions which may impact the timing of our recognition of revenues;

 

   

delays or reductions in spending for EIS and related solutions by our electric power grid operator or utility customers and potential customers;

 

29


Table of Contents
   

the long lead time associated with securing new customer contracts;

 

   

the structure of any forward capacity market in which we participate, which may impact the timing of our recognition of revenues related to that market;

 

   

the mix of our revenues during any period, particularly on a regional basis, since local fees recognized as revenues for demand response capacity tend to vary according to the level of available capacity in given regions;

 

   

the termination or expiration of existing contracts with electric power grid operator, utility and enterprise customers;

 

   

the potential interruptions of our customers’ operations;

 

   

development of new relationships and maintenance and enhancement of existing relationships with customers and strategic partners;

 

   

temporary capacity programs that could be implemented by electric power grid operators and utilities to address short-term capacity deficiencies;

 

   

the imposition of penalties or the reversal of deferred revenue due to our failure to meet a capacity commitment;

 

   

the elimination, modification or flawed design of, or our decision not to participate or to reduce our participation in, any demand response program in which we currently participate;

 

   

global economic and credit market conditions; and

 

   

increased expenditures for sales and marketing, software development and other corporate activities.

Our stock price has been and is likely to continue to be volatile and the market price of our common stock may fluctuate substantially.

Since our common stock began trading on The NASDAQ Global Market, or NASDAQ, on May 18, 2007 through December 31, 2014, our stock price has fluctuated from a low of $4.80 to a high of $50.50. For the period of January 1, 2014, through December 31, 2014, our stock price fluctuated from a high of $24.35 on May 5, 2014 and a low of $12.29 on October 15, 2014. In addition, in the first quarter of 2015 our stock price has traded below the 2014 low.

Our stock price is likely to continue to be volatile and subject to significant price and volume fluctuations in response to market and other factors, including:

 

   

demand for and acceptance of our EIS and related solutions;

 

   

our ability to develop new relationships and maintain and enhance existing relationships with customers and strategic partners;

 

   

termination of or changes in open market bidding program rules and reductions in pricing for demand response capacity;

 

   

the termination or expiration of existing contracts enterprise and utility customers;

 

   

general market conditions and overall fluctuations in equity markets in the United States;

 

   

the elimination, modification or flawed design of, or our decision not to participate or to reduce our participation in, any demand response program in which we currently participate;

 

   

introduction of technological innovations or new EIS and related solutions by us or our competitors;

 

   

actual or anticipated variations in quarterly revenues and operating results;

 

   

the financial guidance we may provide to the public, any changes in such guidance or our failure to meet such guidance;

 

30


Table of Contents
   

changes in estimates or recommendations by securities analysts that cover our common stock;

 

   

delays in the implementation and delivery of our EIS and related solutions which may impact the timing of our recognition of revenues;

 

   

litigation or regulatory enforcement actions;

 

   

changes in the regulations affecting our industry in the United States and internationally;

 

   

the way in which we recognize revenues and the timing associated with our recognition of revenues;

 

   

developments with respect to recent acquisitions, including with respect to expected synergies, and any unforeseen integration costs or impairment charges;

 

   

developments or disputes concerning patents or other proprietary rights;

 

   

period-to-period fluctuations in our financial results;

 

   

the 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 or in general;

 

   

economic and other external factors or other disasters or crises; and

 

   

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.

In addition, the sale of substantial amounts of our common stock by certain of our insiders could adversely impact the trading price of our common stock. As of December 31, 2014, we had outstanding 29,833,578 shares of our common stock and options to purchase 725,578 shares of our common stock (of which 711,605 were exercisable as of that date). We also had outstanding 256,872 unvested restricted stock units and 2,170,267 shares of unvested restricted stock as of December 31, 2014. Further, in August 2014, we issued $160.0 million aggregate principal of 2.25% Notes. The Notes may be converted at an initial conversion rate of 36.0933 shares of our common stock per $1,000 principal amount of the Notes (equivalent to an initial conversion price of approximately $27.71 per share of our common stock). The conversion rate is subject to adjustment if certain events occur. The Notes will mature on August 15, 2019 unless earlier converted or repurchased. The conversion or repurchase of the Notes or a portion of the Notes into our common stock could adversely affect the price of our common stock.

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 on our shares of 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

 

31


Table of Contents

not have the opportunity to do so. Furthermore, these provisions could prevent or frustrate attempts by our stockholders to replace or remove our management. These provisions:

 

   

allow the authorized number of directors to be changed only by resolution of our board of directors;

 

   

require that vacancies on the board of directors, including newly created directorships, be filled only by a majority vote of directors then in office;

 

   

establish a classified board of directors, providing that not all members of the board be elected at one time;

 

   

authorize our board of directors to issue, without stockholder approval, blank check preferred stock that, if issued, could operate as a “poison pill” to dilute the stock ownership of a potential hostile acquirer to prevent an acquisition that is not approved by our board of directors;

 

   

require that stockholder actions must be effected at a duly called stockholder meeting and prohibit stockholder action by written consent;

 

   

prohibit cumulative voting in the election of directors, which would otherwise allow holders of less than a majority of stock to elect some directors;

 

   

establish advance notice requirements for stockholder nominations to our board of directors or for stockholder proposals that can be acted on at stockholder meetings, which were modified in February 2014;

 

   

limit who may call stockholder meetings; and

 

   

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 proscribed 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. 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 covers us downgrades our stock or publishes

 

32


Table of Contents

inaccurate or unfavorable research about our business, our stock price would likely decline. If one or more of these analysts ceases coverage of our company or fails 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.

 

Item 1B. Unresolved Staff Comments

None.

 

Item 2. Properties

Our corporate headquarters and principal office is located in Boston, Massachusetts, where we lease approximately 82,000 square feet of office space under a lease agreement, or the 2012 Lease, expiring in July 2020 with a right to first offer, subject to the rights of existing tenants in the building, whereby we may lease certain additional space in the building during the lease term and the right to extend the lease term for one period of five years upon the expiration of the initial term. The average monthly rent over the initial term of the 2012 Lease is $0.3 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, subject to reduction commencing August 1, 2015, and will be 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.

On October 9, 2014, we entered into an amendment to the 2012 Lease to lease additional space, which commenced on or about January 1, 2015, which was the date on which we had the right to control access and physical use of the leased space, and be subject to the terms and conditions of the 2012 Lease. The lease term for the additional space coincides with the term for the 2012 Lease and expires on July 31, 2020, unless earlier terminated or further extended as provided in the 2012 Lease. The lease amendment contains both a rent holiday, under which lease payments do not commence until June 2015, and escalating rental payments. The amendment to the lease will increase the average monthly rent to $0.4 million, exclusive of operating expenses.

We also lease a number of offices under various other lease agreements in the United States, Australia, Canada, New Zealand, Ireland, the United Kingdom, Germany, Switzerland, Brazil, India, Japan, and South Korea. We do not own any real property. We believe that we have adequate space for our anticipated needs and that suitable additional space will be available at commercially reasonable prices as needed.

 

Item 3. Legal Proceedings

We are subject to legal proceedings, claims and litigation arising in the ordinary course of business. We do not expect the ultimate costs to resolve these matters to have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

On May 3, 2013, a purported shareholder of ours, or the plaintiff, filed a derivative and class action complaint in the United States District Court for the District of Delaware, or the Court, against certain of our officers and directors as well as the Company as a nominal defendant, which we refer collectively to as the defendants. The complaint asserted derivative claims, purportedly brought on behalf of the Company, for breach

 

33


Table of Contents

of fiduciary duty, waste of corporate assets, and unjust enrichment in connection with certain equity grants (awarded in 2010, 2012, and 2013) that allegedly exceeded an annual limit on per-employee equity grants purported to be contained in the Company’s Amended and Restated 2007 Employee, Director and Consultant Stock Plan. The complaint also asserted a direct claim, brought on behalf of the plaintiff and a proposed class of our shareholders, alleging our proxy statement filed on April 26, 2013 was false and misleading because it failed to disclose that the equity grants were improper. The plaintiff sought, among other relief, rescission of the equity grants, unspecified damages, injunctive relief, disgorgement, attorneys’ fees, and such other relief as the Court may deem proper.

On June 27, 2014, the parties engaged in mediation and reached agreement in principle on the terms of a potential settlement. On December 15, 2014, the Court held a fairness hearing and approved the settlement, together with an award of attorneys’ fees to plaintiffs’ counsel in the amount of $0.4 million, a portion of which was covered by our insurance. Pursuant to the settlement, defendant members of our Board of Directors agreed to cause our insurer to make a cash payment of $0.5 million to the Company, and to cause the Company to undertake certain reforms in connection with equity granting practices. The cash payment of $0.5 million was received and recognized in January 2015.

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

 

Item 4. Mine Safety Disclosures

Not applicable.

 

34


Table of Contents

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 2014

   High      Low  

First Quarter

   $ 23.45      $ 16.85  

Second Quarter

   $ 24.35      $ 16.98  

Third Quarter

   $ 21.25      $ 16.91  

Fourth Quarter

   $ 17.15      $ 12.29  

 

Fiscal 2013

   High      Low  

First Quarter

   $ 18.61      $ 11.50  

Second Quarter

   $ 19.08      $ 11.58  

Third Quarter

   $ 16.88      $ 13.17  

Fourth Quarter

   $ 18.92      $ 14.12  

Stockholders

As of March 9, 2015, we had approximately 803 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. 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 deems relevant. Additionally, the terms of the 2014 credit facility preclude us, and the terms of any future debt or credit facility may preclude us, from paying dividends.

Unregistered Sales of Equity Securities

As previously disclosed in our Current Report on Form 8-K on November 26, 2014, we issued 583,218 shares of our common stock as partial consideration to Pulse Energy’s stockholders upon the closing of our acquisition of Pulse Energy. In addition, we may issue up to an additional 699,855 shares of common stock to Pulse Energy’s stockholders if and to the extent that certain earn-out provisions are met.

The issuance of our common stock is exempt from the registration requirements pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended, or the Securities Act, Rule 506 of Regulation D promulgated under the Securities Act, or Regulation D, and/or Regulation S promulgated under the Securities Act, or Regulation S, based upon representations we have obtained from each Pulse Energy stockholder receiving such shares that, among other things, the Pulse Energy stockholder is either (a) an “accredited investor” as that term is defined in Rule 501(a) of Regulation D or (b) not a “U.S. Person” as that term is defined in Rule 902(k) of Regulation S.

 

35


Table of Contents

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, 2014, or fiscal 2014:

 

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(3)
    Approximate Dollar
Value of Shares that
May Yet Be  Purchased
Under the Plans
or Programs(3)
 

October 1, 2014—October 31, 2014

    18,191     $ 16.90           $ 20,027,016  

November 1, 2014—November 30, 2014

    8,829       14.76             20,027,016  

December 1, 2014—December 31, 2014

    23,646       14.03             20,027,016  
 

 

 

   

 

 

   

 

 

   

 

 

 

Total for the fourth quarter of 2014

    50,666     $ 19.50            $ 20,027,016  
 

 

 

   

 

 

   

 

 

   

 

 

 

 

 

(1) We repurchased a total of 50,666 shares of our common stock in the fourth quarter of fiscal 2014, consisting of 18,191, 8,829 and 23,646 shares, respectively, in October, November and December 2014, 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 shares repurchases of our common stock to cover employee minimum statutory income tax withholding obligations in connection with the vesting of restricted stock under our equity incentive plans which we pay in cash to the appropriate taxing authorities on behalf of our employees. Amounts disclosed are rounded to the nearest two decimal places.

 

(3) On August 11, 2014, our Board of Directors authorized the repurchase of up to $50.0 million of our common stock during the period from August 11, 2014 through August 8, 2015. We refer to this as the Repurchase Program. We used $30.0 million of the net proceeds from our offering of the Notes to repurchase 1,514,552 shares of our common stock at a purchase price of $19.79 per share, which was the closing price of the common stock on The NASDAQ Global Select Market on August 12, 2014 under the Repurchase Program. There were no repurchases of our common stock in the fourth quarter of fiscal 2014 pursuant to the Repurchase Program. Additional repurchases of common stock under the Repurchase Program may be executed periodically on the open market as market and business conditions warrant.

 

36


Table of Contents
Item 6. Selected Financial Data

Our selected consolidated financial data set forth below is derived from our audited financial statements, Consolidated balance sheets as of December 31, 2014 and 2013, as well as consolidated statements of operations for the years ended December 31, 2014, 2013, and 2012, and the reports thereon, are contained elsewhere in this Annual Report on Form 10-K. The following selected consolidated financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and accompanying notes thereto included in Item 7 and Appendix A, respectively, to this Annual Report on Form 10-K.

 

    Year Ended December 31,(1)  
    2014(2)     2013     2012     2011     2010  
    (In thousands, except share and per share data)  

Selected Balance Sheet Data:

         

Cash and cash equivalents

  $ 254,351     $ 149,189     $ 115,041     $ 87,297     $ 153,416  

Working capital

    257,831       145,595       116,685       105,839       163,519  

Total assets

    624,702       415,955       355,165       355,260       325,899  

Total long-term debt, including current portion

    138,908                         37  

Total stockholders’ equity

    291,873       269,495       240,022       247,740       226,126  

Selected Statement of Operations Data:

         

Revenues

  $ 471,948     $ 383,460     $ 277,984     $ 286,608     $ 280,157  

Cost of revenues

    257,322       192,292       154,540       163,211       159,832  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gross profit

    214,626       191,168       123,444       123,397       120,325  

Selling and marketing expenses

    76,960       65,915       55,963       51,907       44,029  

General and administrative expenses

    97,729       79,220       71,643       66,773       54,983  

Research and development expenses

    20,671       18,317       16,226       14,254       10,097  

Gain on sale of service lines(3)

    (4,791                        

Gain on the sale of assets(4)

    (2,171                        
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from operations

    26,228       27,716       (20,388     (9,537     11,216  

Interest and other (expense) income, net

    (8,355     (2,988     (134     (2,040     (803
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

    17,873       24,728       (20,522     (11,577     10,413  

Provision for income taxes

    (5,876     (2,640     (1,771     (1,806     (836
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

  $ 11,997     $ 22,088     $ (22,293   $ (13,383   $ 9,577  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) per share, basic

  $ 0.43     $ 0.80     $ (0.84   $ (0.52   $ 0.39  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) per share, diluted

  $ 0.42     $ 0.76     $ (0.84   $ (0.52   $ 0.37  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Weighted average number of basic shares

    27,857,026       27,774,778       26,551,234       25,799,494       24,611,729  

Weighted average number of diluted shares

    28,790,665       29,045,066       26,551,234       25,799,494       26,054,162  

 

 

(1) Includes the results of operations from the date of acquisition relating to our acquisitions of Pulse Energy in December 2014; Entech and Universal Load Center Co., Ltd, or ULC, in April 2014; Entelios and Activation Energy in February 2014; Energy Response in July 2011; Global Energy Partners, Inc., or Global Energy, M2M, and Utility Solutions Consulting in January 2011; and SmallFoot LLC, or SmallFoot, and ZOX, LLC, or Zox, in March 2010.

 

(2)

We recorded certain adjustments related to the presentation of revenue and cost of revenue in our consolidated statement of operations for the year ended December 31, 2014. We have historically recorded revenue and cost of revenues net (as an agent) for certain transactions with enterprise customers and upon further analysis during fiscal 2014, we concluded revenue and cost of revenues for these transactions should be recorded gross (as a principal). We assessed the materiality of the historical misstatements, individually and in the aggregate, on our prior annual and quarterly consolidated financial statements and concluded the effect of the error was not material to our consolidated financial statements for any of the

 

37


Table of Contents
  periods. We recorded an adjustment in the consolidated statement of operations for the year ended December 31, 2014 to correct the presentation of such revenues on a year-to-date basis. This correction resulted in an increase to both grid operator revenue and cost of revenue of $4,344 for the year ended December 31, 2014.

 

(3) Gain on sale of service lines was recognized during the year ended December 31, 2014 from the sale of business components originally acquired through the acquisitions of Global Energy (Utility Solutions Consulting) and M2M (Valley Tracker).

 

(4) In April 2014, we recognized a gain from the sale to a third party of one of our remaining two contractual demand response capacity resources related to an open market demand response program, which allowed the buyer to enroll with the applicable grid operator.

 

38


Table of Contents
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion and analysis of our financial condition and results of operations together with our “Selected Financial Data” and consolidated financial statements and accompanying notes thereto included elsewhere in this Annual Report on Form 10-K. In addition to the historical information, the discussion contains certain forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those expressed or implied by the forward-looking statements due to applications of our critical accounting policies and factors including, but not limited to, those set forth under the caption “Risk Factors” in Item 1A of Part I of this Annual Report on Form 10-K.

Overview

We are a leading provider of energy intelligence software, or EIS, and related solutions. Our enterprise customers use our software to transform how they manage and control spend for their organizations, while utilities leverage our software to better engage their customers and meet their demand-side management goals and objectives.

Our EIS and related solutions provide our enterprise customers with a SaaS solution to manage:

 

   

energy supplier selection, procurement and implementation;

 

   

energy budget forecasting;

 

   

utility bills and payment;

 

   

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

 

   

project tracking;

 

   

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

 

   

peak demand and the related cost impact.

Our EIS and related solutions provide our enterprise customers the visibility they need to prioritize resources against the activities that will deliver the highest return on investment. We offer our EIS and related solutions to our enterprise customers at four subscription levels: basic, standard, professional, and industrial. We deliver our SaaS solutions on all of the major Internet browsers and on leading mobile device operating systems. In addition to our EIS packages, we sell two categories of premium professional services, which we refer to as Software Enhancement Services and Energy and Procurement Services. Our Software Enhancement Services help our enterprise customers set their energy management strategy and enhance the effectiveness of EIS deployment. Our Energy and Procurement Services consist of audits, retro-commissioning, and supply procurement consulting. Our target enterprise customers for our EIS and related solutions are organizations that spend approximately $100,000/year or more per site on energy, and we sell to these customers primarily through our direct salesforce.

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

Our EIS and related solutions for utility customers and electric power grid operators also include the demand response solutions and applications, EnerNOC Demand Manager™ and EnerNOC Demand Resource™. EnerNOC Demand Manager is a SaaS application that provides utilities with the underlying technology to manage their demand response programs and secure reliable demand-side resources. Our EnerNOC Demand Manager product consists of long-term contracts with a utility customer for a SaaS solution that allows utilities to

 

39


Table of Contents

manage demand response capacity in utility-sponsored demand response programs. This product provides our utility customers with real-time load monitoring, dispatching applications, customizable reports, measurement and verification, and other professional services. Our EnerNOC Demand Resource is a turnkey demand response resource where we match obligation, in the form of megawatts, or MW, that we agree to deliver to our utility customers and electric power grid operators, with supply, in the form of MW that we are able to curtail from the electric power grid through our arrangements with our enterprise customers. When we are called upon by our utility customers and electric power grid operators to deliver our contracted capacity, we use our NOC to remotely manage and reduce electricity consumption across our growing network of enterprise customer sites, making demand response capacity available to our utility customers and electric power grid operators on demand while helping our enterprise customers achieve energy savings, improve financial results and realize environmental benefits. We receive recurring payments from our utility customers and electric power grid operators for providing our EnerNOC Demand Resource and we share these recurring payments with our enterprise customers in exchange for those enterprise customers reducing their power consumption when called upon by us to do so. We occasionally reallocate and realign our capacity supply and obligation through open market bidding programs, supplemental demand response programs, auctions or other similar capacity arrangements and third-party contracts to account for changes in supply and demand forecasts, as well as changes in programs and market rules in order to achieve more favorable pricing opportunities. We refer to the above activities as managing our portfolio of demand response capacity.

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

Use of Non-Financial Business and Operational Data

We utilize certain non-financial business and operational data to provide additional insight into factors and opportunities relevant to our business. This non-financial business and operational data does not necessarily have any direct correlation to our financial performance. However, the non-financial business and operational data may provide observations as to the scope of and trends related to our operations and therefore, we believe the utilization of such data can provide insights into certain aspects of our business, such as market share and penetration, and customer composition and depth.

The following table outlines certain non-financial business and operational data utilized as of and for the years ended December 31, 2014 and December 31, 2013:

 

     2014     2013  

Enterprise Customers(1)(7)

     1,300        600   

Enterprise Sites(1)(7)

     35,700        2,800   

Enterprise ARR (in millions)(2)(8)

   $ 20      $ 7   

Enterprise ARR Churn Rate(2)(9)

     18     N/A   

Utility Customers(3)

     52        36   

Utility ARR (in millions)(4)(8)

   $ 67      $ 62   

Utility ARR Churn Rate(4)(9)

     13     N/A   

Grid Operators(5)

     14        8   

Demand Response Customers(6)(7)

     6,500        5,800   

Demand Response Sites(6)(7)

     15,000        13,900   

 

 

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

 

40


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

 

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

 

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

 

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

 

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

 

(7) Amounts rounded to nearest hundred.

 

(8) Amounts rounded to nearest million.

 

(9) Amounts rounded to nearest full percentage point. Prior to December 31, 2014 we did not track churn rate metrics, and as such, values for December 31, 2013 are listed as “N/A” or “not applicable”.

The number of enterprise customers at December 31, 2014 was approximately 1,300 compared to approximately 600 at December 31, 2013. This increase primarily reflects the addition of new customers from our acquisition of Entech. This increase also reflects our ongoing efforts to develop our enterprise sales team, the relative success that our enterprise sales team has had in penetrating the market for our EIS and related solutions for enterprises, and the growing need for our solutions with enterprise customers who are increasingly turning to our EIS and related solutions to make strategic decisions about the how and when they consume or procure energy. The number of enterprise sites at December 31, 2014 was approximately 35,700 compared to approximately 2,800 at December 31, 2013. The number of enterprise sites has typically increased in tandem with the increase in enterprise customers, with most of the increase in sites coming from our acquisition of Entech. Enterprise ARR at December 31, 2014 was approximately $20 million compared to approximately $7 million at December 31, 2013. Enterprise ARR has typically increased in tandem with the increase in enterprise sites, with the increase coming from our organic growth and our acquisition of Entech. We expect that the number of enterprise customers, the number of enterprise sites, and enterprise ARR will continue to increase over time. Our enterprise ARR churn rate was 18% at December 31, 2014. We expect that our enterprise ARR churn

 

41


Table of Contents

rate will decrease over time as we transition enterprise customers from purchasing point solutions to purchasing our comprehensive EIS, and as our base of starting enterprise ARR, from which to measure churn, increases.

The number of utility customers at December 31, 2014 was 52 compared to 36 at December 31, 2013. This increase primarily reflects the addition of new utility customers from our recent acquisitions of Pulse Energy, Entelios, and Activation Energy, as well as the addition of new utility customers that have contracts for our energy services. Utility ARR at December 31, 2014 was approximately $67 million compared to approximately $62 million at December 31, 2013. This increase primarily reflects the acquisition of Pulse Energy and an increase in size of certain utility demand response programs, partially offset by a reduction in size or non-renewal of certain utility demand response programs. Our utility ARR churn rate was 13% at December 31, 2014. In general, we expect that the number of utility customers and utility ARR will increase over time and that our utility ARR churn rate will decrease in future periods depending on the timing and terms of our utility contracts.

The number of grid operator customers at December 31, 2014 was 14 compared to eight at December 31, 2013. This increase primarily reflects the addition of new grid operator customers from our recent acquisitions of Entelios and Activation Energy. In general, we expect that the number of grid operator customers will increase over time.

The number of demand response customers was approximately 6,500 at December 31, 2014 compared to 5,800 at December 31, 2013. The number of demand response sites at December 31, 2014 was approximately 15,000 as compared to approximately 13,900 at December 31, 2013. The number of demand response customers and the number of demand response sites are not necessarily correlated and may increase or decrease in future periods if we choose to participate in additional or different markets in the future.

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

Significant Recent Developments

On December 1, 2014, we acquired the outstanding stock of Pulse Energy, a privately-held company headquartered in Vancouver, Canada, and a leading provider in energy intelligence for utilities’ commercial customers, which helps utilities meet regulated efficiency targets, improves customer satisfaction and brand loyalty, and cross-promote other programs and services. We acquired Pulse Energy for an aggregate purchase price of $24.8 million, consisting of cash, common stock issued and a contingent earn-out payment. We believe that the acquisition of Pulse Energy will expand and accelerate the growth of our EIS and related solutions by extending our ability to serve our utility and retail customers through deep segmentation and energy analytics for small and medium-sized enterprises, as well as commercial, institutional and industrial end-users of energy.

On January 5, 2015, we completed the acquisition of World Energy Solutions, Inc., or World Energy, an energy management technology and services provider that helps enterprises simplify the energy and procurement process through a suite of SaaS solutions. We acquired World Energy for a purchase price of $5.50 per share, and the assumption of debt for a total transaction value of approximately $77.0 million in cash. We believe this acquisition and the integration of World Energy’s software into our EIS platform will help deliver more value to our enterprise customers through enhanced technology-enabled capabilities to manage the energy procurement process.

Revenues and Expense Components

Revenues

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

Our enterprise revenues from the sales of our EIS and related solutions to our enterprise customers generally represent ongoing software or service arrangements under which the revenues are recognized ratably over the

 

42


Table of Contents

same period commencing upon delivery of the EIS and related solutions to the enterprise customer. Under certain of our arrangements, a portion of the fees received may be subject to adjustment or refund based on the validation of the energy savings delivered after the implementation is complete. As a result, we defer the portion of the fees that are subject to adjustment or refund until such time as the right of adjustment or refund lapses, which is generally upon completion and validation of the implementation.

Our EIS and related solutions for utility customers and electric power grid operators also include the demand response applications and solutions, EnerNOC Demand Resource and EnerNOC Demand Manager.

Our utility revenues and grid operator revenues primarily reflect the sale of our EnerNOC Demand Resource solution. The revenues primarily consist of capacity and energy payments, including ancillary services payments, as well as payments derived from the effective management of our portfolio of demand response capacity, including our participation in capacity auctions and third-party contracts and ongoing fixed fees for the overall management of utility-sponsored demand response programs. We derive revenues from our EnerNOC Demand Resource solution by making demand response capacity available in open market programs and pursuant to contracts that we enter into with electric power grid operators and utilities. In certain markets, we enter into contracts with electric power utilities, generally ranging from three to ten years in duration, to deploy our EnerNOC Demand Resource solution. We refer to these contracts as utility contracts. For the year ended December 31, 2014, utility revenue derived from EIS and related solutions was approximately 10%. In the future, we expect an increasing percentage of our utility revenues to be derived from EIS and related solutions.

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

In May 2014, the United States Court of Appeals for the D.C. Circuit held that FERC did not have jurisdiction under the Federal Power Act to issue FERC Order 745, an order that required, among other things, that economic demand response resources participating in the wholesale energy markets administered by electric power grid operators, such as PJM, be paid the locational marginal price of energy. The decision of the D.C. Circuit is presently subject to Petitions for Certiorari brought by the Solicitor General of the United States on behalf of FERC, a coalition of parties including EnerNOC and other parties seeking a reversal of the decision. While we believe that Order 745 was effective and binding and that we delivered service in accordance with the applicable market and program tariffs and manuals, if the decision is implemented and FERC Order 745 is invalidated, certain revenues earned prior to May 23, 2014 in connection with our participation in price-based/economic demand response programs, which we have estimated to be approximately $20.1 million, may become subject to refund. Revenue of $2.0 million earned subsequent to May 23, 2014 and through December 31, 2014 has been deferred; we will continue to defer future revenues relating to these programs until final regulation resolution is reached. For additional information relating to this matter, please refer to Note 15 contained in Appendix A to this Annual Report on Form 10-K.

For further discussion of revenue recognition, please refer to Note 1 contained in Appendix A to the Annual Report on Form 10-K.

Cost of Revenues

Cost of revenues for our EIS and related solutions primarily consists of amounts owed to our enterprise customers for their participation in our demand response network and are generally recognized over the same performance period as the corresponding revenue. We enter into contracts with our enterprise customers under which we deliver recurring cash payments to them for the capacity they commit to make available on demand.

 

43


Table of Contents

We also generally make an energy payment when an enterprise customer reduces consumption of energy from the electric power grid during a demand response event. The EIS equipment and installation costs for our devices located at our enterprise customer sites, which monitor energy usage, communicate with enterprise customer sites and, in certain instances, remotely control energy usage to achieve committed capacity, are capitalized and depreciated over the lesser of the remaining estimated customer relationship period or the estimated useful life of the equipment, and this depreciation is reflected in cost of revenues. We also include in cost of revenues our amortization of acquired developed technology, amortization of capitalized internal-use software costs related to our EIS and related solutions, the monthly telecommunications and data costs we incur as a result of being connected to enterprise customer sites, services and products, third-party services, equipment costs, equipment depreciation, our internal payroll and related costs allocated to an enterprise customer site, the wages and associated benefits that we pay to our project managers for the performance of their services, and related costs of revenue related to the delivery of services of our utility bill management solution. Certain costs, such as equipment depreciation and telecommunications and data costs, are fixed and do not vary based on revenues recognized. These fixed costs could impact our gross margin trends during interim periods as described elsewhere in this Annual Report on Form 10-K.

We capitalize and defer incremental customer contract costs incurred related to the acquisition or origination of a utility contract or open market program in a transaction that results in the deferral or delay of revenue recognition. As of December 31, 2014, and 2013 we had no incremental direct costs deferred related to the acquisition or origination of a utility contract or open market program and during the years ended December 31, 2014, 2013 and 2012, no contract origination costs were deferred. In addition, we capitalize and defer incremental direct costs incurred related to customer contracts where the associated revenues have been deferred as long as the deferred incremental direct costs are deemed realizable. During the years ended December 31, 2014, 2013 and 2012, we capitalized $38.8 million, $25.1 million and $17.7 million, respectively, of incremental direct costs associated with customer contracts. These deferred expenses would not have been incurred without our participation in a certain open market program and will be expensed in proportion to when the related revenue is recognized. Certain of these incremental direct payments are recorded as a reduction of revenues when the associated revenues are recognized as they relate to third-party demand response arrangements where the other third party has become the primary obligor of the demand response obligation. During the years ended December 31, 2014, 2013 and 2012, we expensed $30.6 million, $26.1 million and $10.8 million, respectively, of capitalized incremental direct costs to cost of revenues and recorded $11.1 million, $0.4 million, and $0 million, respectively, as a reduction to revenues. As of December 31, 2014, there have been no material recoverability issues related to capitalized incremental direct costs.

We also capitalize the costs of our production and generation equipment utilized in the delivery of our demand response solutions and expense this equipment over the lesser of its estimated useful life or the term of the contractual arrangement. During the years ended December 31, 2014, 2013 and 2012, we capitalized $10.1 million, $8.7 million and $7.0 million, respectively, of production and generation equipment costs. We believe that the above accounting treatments appropriately match expenses with the associated revenues.

Gross Profit and Gross Margin

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

 

44


Table of Contents

Operating Expenses

Operating expenses consist of selling and marketing, general and administrative, and research and development expenses. Personnel-related costs are the most significant component of each of these expense categories. We grew from 716 full-time employees at December 31, 2013 to 928 full-time employees, not including 197 Entech employees included in cost of revenues at December 31, 2014, primarily as a result of our fiscal 2014 acquisitions to drive overall growth and expansion into new markets. As noted above under “Cost of Revenues,” a portion of our headcount and associated payroll and related expenses are included within cost of revenues. We expect to continue to hire employees to support our growth for the foreseeable future. In addition, we incur significant up-front costs associated with the expansion of the number of contractual MW, which we expect to continue for the foreseeable future. We expect our overall operating expenses to increase in absolute dollar terms for the foreseeable future, as we continue to enable new enterprise customer sites and expand the development of our EIS and related solutions.

In certain forward capacity markets in which we choose to participate, such as PJM, we may install our equipment at an enterprise customer site to allow for the curtailment of MW from the electric power grid up to twelve months in advance of enrolling the enterprise customer in a particular program (i.e., we enable our enterprise customers). As a result, there has been a trend of incurring operating expenses at the time of enablement, including salaries and related personnel costs, associated with enabling certain of our enterprise customers, in advance of recognizing the corresponding revenues.

Selling and Marketing

Selling and marketing expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards made to our sales and marketing personnel, (b) commissions, (c) travel and other out-of-pocket expenses, (d) marketing programs such as trade shows and (e) other related overhead. Commissions are recorded as an expense when earned by the employee. We expect an increase in selling and marketing expenses in absolute dollar terms through at least the end of fiscal 2015 as we invest in infrastructure to support our continued growth; and we expect that selling and marketing expenses as a percentage of total annual revenues will increase in fiscal 2015 due to our ongoing market expansion and the expected reduction in fiscal 2015 revenues compared to fiscal 2014.

General and Administrative

General and administrative expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards and bonuses made to our executive, finance, human resource, information technology and operations organizations, (b) facilities expenses, (c) external accounting and legal professional fees, (d) depreciation and amortization and (e) other related overhead. We expect an increase in general and administrative expenses in absolute dollar terms through at least the end of fiscal 2015 as we invest in infrastructure to support our continued growth; and we expect that general and administrative expenses as a percentage of total annual revenues will increase in fiscal 2015 primarily due to the additional expenses from our recently completed acquisitions and ongoing market expansion, and the expected reduction in fiscal 2015 revenues compared to fiscal 2014.

Research and Development

Research and development expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards made to our research and development personnel, (b) payments to suppliers for design and consulting services, (c) costs relating to the design and development of new energy management applications, solutions and products and enhancement of existing energy management applications, solutions and products, (d) quality assurance and testing, and (e) other related overhead. During the years ended December 31, 2014, 2013 and 2012, we capitalized software development costs of $6.0 million, $7.9 million and $4.7 million, respectively, which are included in property and equipment. We expect an increase in research and development expenses in absolute dollar terms for the foreseeable future as we develop new

 

45


Table of Contents

technologies and enhance our existing technologies to support our continued growth; and we expect that research and development expenses as a percentage of total annual revenues will increase in fiscal 2015 due to the expected reduction in fiscal 2015 revenues compared to fiscal 2014.

Stock-Based Compensation

We grant share-based awards to employees, non-employees, members of the board and advisory board members. We account for grants of stock-based compensation in accordance with ASC 718,  Stock Compensation (ASC 718). We account for share-based awards granted to non-employees in accordance with ASC 505-50, Equity Based Payments to Non-Employees , which results in our continuing to re-measure the fair value of the non-employee share-based awards until such time as the awards vest. All share-based awards granted, including grants of stock options, restricted stock and restricted stock units, are recognized in the statement of operations based on their fair value as of the date of grant. As of December 31, 2014, the Company had one stock-based compensation plan, which is more fully described in Appendix A to this Annual Report on Form 10-K.

All shares underlying awards of restricted stock are restricted in that they are not transferable until they vest. Restricted stock typically vests ratably over a four-year period from the date of issuance, with certain exceptions. The fair value of restricted stock upon which vesting is solely service-based is expensed ratably over the vesting period. With respect to restricted stock where vesting contains certain performance-based vesting conditions, the fair value is expensed based on the accelerated attribution method as prescribed by ASC 718 , over the vesting period. With the exception of certain executives whose employment agreements provide for continued vesting in certain circumstances upon departure, if the employee who received the restricted stock leaves the Company prior to the vesting date for any reason, the shares of restricted stock will be forfeited and returned to the Company.

Interest and Other (Expense) Income, Net

Interest expense primarily consists of interest expense related to our Notes, as well as fees associated with our 2014 credit facility. Interest expense also consists of interest expense associated with letters of credit and other financial assurances. Other income and expense consist primarily of gains or losses on transactions denominated in currencies other than our or our subsidiaries’ functional currency, interest income earned on cash balances, and other non-operating income and expense.

Consolidated Results of Operations

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Revenues

The following table summarizes our revenues for the years ended December 31, 2014 and 2013 (dollars in thousands):

 

     December 31,      Dollar
Change
     Percentage
Change
 
     2014      2013        

Revenues:

           

Grid operator

   $ 368,828      $ 279,258      $ 89,570        32.1

Utility

     62,026        71,611        (9,585      -13.4

Enterprise

     41,094        32,591        8,503        26.1
  

 

 

    

 

 

    

 

 

    

Total revenues

   $ 471,948      $ 383,460      $ 88,488        23.1
  

 

 

    

 

 

    

 

 

    

 

46


Table of Contents

Grid Operator Revenues

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

 

     Revenue Increase (Decrease):  
     December 31, 2013
to
December 31, 2014
 

PJM

   $ 71,487  

IMO

     9,222  

Alberta Electric System Operator (AESO)

     5,716  

SEMO (Ireland)

     4,110  

Other (1)

     (965
  

 

 

 

Total increase in grid operator revenues

   $ 89,570  
  

 

 

 

 

 

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

The increase in revenues from grid operators was primarily due to an increase in pricing and enrolled MW in our PJM and Independent Market Operator (IMO) demand response programs. The increase in IMO revenue was further driven by our ability to recognize revenues in Western Australia ratably over the delivery period of October 1 through September 30, commencing on October 1, 2014. The increase in revenues from grid operators was also due to revenues recognized from our SEMO demand response program in Ireland, for which revenues were recognized for the first time during the year ended December 31, 2014 as a result of our acquisition of Activation Energy. The increase in revenues from grid operators was also a result of an increase in enrolled MW revenues recognized from our participation in certain demand response programs in Alberta, Canada, including ancillary demand responses programs that we did not start participating in until the three month period ended September 30, 2013. We currently expect our total revenues from grid operators to decrease during fiscal 2015 as compared to fiscal 2014 due to significantly reduced capacity prices in IMO, lower revenue from our participation in PJM incremental auctions and deferral of revenue recognition to the second quarter of 2016 relating to our participation in PJM’s extended program in the 2015/2016 delivery year.

Utility Revenues

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

 

     Revenue Increase (Decrease):  
     December 31, 2013
to
December 31, 2014
 

Southern California Edison (SCE)

   $ (5,605

Pacific Gas and Electric (PG&E)

     1,505  

Other (1)

     (5,485
  

 

 

 

Total decrease in utility revenues

   $ (9,585
  

 

 

 

 

 

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

The decrease in utility revenues was primarily due to a decrease of revenues from SCE and PG&E as a result of underperformance penalties and a decrease in enrolled MW. We currently expect our 2015 utility revenues to grow between 13%-21% as compared to 2014 primarily due to the utility contracts acquired with Pulse Energy, expansion of existing utility customer contracts and the sale of our EIS solution to new utility customers.

 

47


Table of Contents

Enterprise Revenues

The increase in revenues from enterprise customers was primarily due to revenues recognized during the year ended December 31, 2014 related to our utility bill management services, which were acquired as part of our acquisition of Entech, as well as, an increase in both the number of enterprise customers and overall consulting engagements. The increase in enterprise revenue was partially offset by the end of certain energy efficiency incentive based programs, from which we derived revenues in 2013, and the completion of our 2010 agreement with the Massachusetts Department of Energy Resources in August 2014. We currently expect our 2015 enterprise revenues to grow between 70%-83% as compared to 2014 due to the acquisition of World Energy, expansion of existing enterprise customer contracts and the sale of our EIS solution to new enterprise customers.

Gross Profit and Gross Margin

The following table summarizes our gross profit and gross margin percentages for our EIS and related solutions for the years ended December 31, 2014 and 2013 (dollars in thousands):

 

Year Ended December 31,
2014   2013
Gross Profit  

Gross Margin

  Gross Profit  

Gross Margin

$214,626   45.5%   $191,168   49.9%

 

   

 

 

The increase in gross profit was primarily due to an increase in grid operator revenues. Our gross margin percentage decreased primarily due to an increase in PJM revenues from delivering demand response which historically yield a lower gross margin than our other programs and solutions, as well as changes to our overall enterprise customer composition. In addition, our gross margin percentage declined due to a decrease in revenues from our SCE demand response program as a result of a decrease in event performance without associated decreases in costs. These decreases in our gross margin were partially offset by an increase in gross margin in our PG&E demand response program, as revenues related to this program were deferred in 2013 with the associated program costs being expensed.

We expect that our overall gross margin percentage for fiscal 2015 will be in the low to mid 40% range. This anticipated decrease in gross margin percentage compared to fiscal 2014 is expected to result primarily from pressure on margins in our grid operator business and in particular, from our participation in PJM incremental auctions. We expect this decrease will be partially offset by revenue growth from our higher margin enterprise and utility businesses.

Operating Expenses and Income

The following table summarizes our operating expenses and income for the years ended December 31, 2014 and 2013 (dollars in thousands):

 

     Year Ended
December 31,
     Percentage
Change
 
     2014      2013     

Operating expenses and income:

        

Selling and marketing

   $ 76,960      $ 65,915        16.8

General and administrative

     97,729        79,220        23.4

Research and development

     20,671        18,317        12.9

Gain on sale of service lines

     (4,791             100.0

Gain on sale of assets

     (2,171             100.0
  

 

 

    

 

 

    

Total operating expenses and income

   $ 188,398      $ 163,452        15.3
  

 

 

    

 

 

    

 

48


Table of Contents

Selling and Marketing Expenses

The following table summarizes our selling and marketing expenses for the years ended December 31, 2014 and 2013 (dollars in thousands):

 

     Year Ended
December 31,
     Percentage
Change
 
     2014      2013     

Payroll and related costs

   $ 49,318      $ 40,613        21.4

Stock-based compensation

     5,488        5,829        -5.9

Other

     22,154        19,473        13.8
  

 

 

    

 

 

    

Total selling and marketing expenses

   $ 76,960      $ 65,915        16.8
  

 

 

    

 

 

    

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

The decrease in stock-based compensation was primarily due to the settlement of a portion of the fiscal 2013 bonuses in shares of our common stock.

Other selling and marketing expenses include advertising, marketing, professional services, amortization and a company-wide overhead cost allocation. The increase in other selling and marketing expenses was primarily attributable to a $1.2 million increase in various marketing initiatives, a $0.8 million increase in amortization expense, and a $0.4 million increase in overhead.

General and Administrative Expenses

The following table summarizes our general and administrative expenses for the years ended December 31, 2014 and 2013 (dollars in thousands):

 

     Year Ended
December 31,
     Percentage
Change
 
     2014      2013     

Payroll and related costs

   $ 54,273      $ 45,279        19.9

Stock-based compensation

     9,225        8,629        6.9

Other

     34,231        25,312        35.2
  

 

 

    

 

 

    

Total general and administrative expenses

   $ 97,729      $ 79,220        23.4
  

 

 

    

 

 

    

The increase in payroll and related costs was primarily attributable to an increase in the number of general and administrative full-time employees from 386 at December 31, 2013 to 461 at December 31, 2014, most of which resulted from acquisitions that we completed during 2014. The increase also resulted from higher overall salary rates and higher bonus expense in 2014 due to a portion of the fiscal 2013 bonuses that were settled in shares of our common stock and recorded in stock-based compensation expense.

The increase in stock-based compensation was primarily due to an increase in the overall grant-date fair value of stock-based awards granted as a result of the increase in our stock price.

Other general and administrative expenses include professional services, rent, depreciation and a company-wide overhead cost allocation. The increase in other general and administrative expenses was primarily attributable to higher professional fees of $6.2 million due to increased accounting, consulting and legal fees

 

49


Table of Contents

incurred related to our recent acquisitions and other matters, including the ongoing derivative and class action complaint, and our international tax planning. Other factors that contributed to the increase: $1.2 million of higher software license fees which was partially the result of our increase in headcount, $0.9 million of higher depreciation costs primarily due to a full year of depreciation expense relative to our corporate headquarters, and higher dues, subscriptions and conference costs of approximately $0.5 million. The increase in other general and administrative expenses was partially offset by a $0.5 million decrease in rent expense, as during the first half of 2013 we incurred rent expense for both our prior and current corporate headquarters.

Research and Development Expenses

The following table summarizes our research and development expenses for the years ended December 31, 2014 and 2013 (dollars in thousands):

 

     Year Ended
December 31,
     Percentage
Change
 
     2014      2013     

Payroll and related costs

   $ 12,069      $ 9,977        21.0

Stock-based compensation

     1,350        1,410        (4.3 )% 

Other

     7,252        6,930        4.6
  

 

 

    

 

 

    

Total research and development expenses

   $ 20,671      $ 18,317        12.9
  

 

 

    

 

 

    

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

Other research and development expenses include technology expenses, professional services, facilities and a company-wide overhead cost allocation. The increase in other research and development expenses was primarily attributable to an increase of $0.8 million in the allocation of company-wide overhead costs, which is based on headcount, higher information technology and communication costs of $0.7 million, and higher consulting and professional fees of $0.3 million, partially offset by decreased software and license costs.

Gain on Sale of Service Lines

On May 30, 2014, we sold Utility Solutions Consulting, a component of our business that we acquired in connection with our acquisition of Global Energy related to consulting and engineering support services to the global electric utility industry, with a particular focus on providing consulting services to utilities for $4.8 million. We recognized a gain from the sale of Utility Solutions Consulting totaling $3.7 million, net of direct transaction costs totaling $0.3 million during the year ended December 31, 2014. We concluded that the Utility Solutions Consulting disposal group meets the criteria of discontinued operations under ASC 205-20, Discontinued Operations (ASC 205-20). However, we determined that the operations of Utility Solutions Consulting were neither quantitatively or qualitatively material to our current or historical consolidated operations and therefore, the results of operations of Utility Solutions Consulting have not been presented as discontinued operations in our accompanying consolidated statements of operations for the years ended December 31, 2014 and 2013.

On December 30, 2014, we sold Valley Tracker, a component of our business that we acquired in connection with our acquisition of M2M related to our automated demand response offering designed to ensure demand response customers can connect their equipment remotely and access meter data securely, for $1.6 million. We recognized a gain from the sale of Valley Tracker totaling $1.1 million during the year ended December 31, 2014. We concluded that the Valley Tracker disposal group does not meet the criteria of

 

50


Table of Contents

discontinued operations under ASC 205-20, Discontinued Operations (ASC 205-20) due to our conclusion that the operations of Valley Tracker do not represent a strategic shift that will have a major effect on our operations and financial results.

Gain on Sale of Assets

On April 22, 2014, we entered into an agreement with a third party, enterprise customer to sell our remaining two contractual demand response capacity resources related to an open market demand response program to that third party allowing the buyer the ability to enroll directly with the applicable grid operator. Under the terms of the agreement, we agreed to sell each of these two demand response capacity resources with such sale and transfer being effective as of the date that each resource has been paid for in full. The aggregate payment of $5.7 million was allocated between each demand response capacity resource with $2.2 million being allocated to the first demand response capacity resource and $3.6 being allocated to the second demand response capacity resource based on each resource’s relative fair value as determined by the potential future cash flows from each resource. As a mechanism to pay the consideration due for the purchase of these demand response capacity resources, the third party has agreed to allow us to withhold all payments that would be due and payable to this third party under our enterprise contractual arrangements and in the event that the payments withheld through March 31, 2015 are not sufficient to cover the purchase price of these demand response capacity resources then the third party is required to pay the remaining amount in cash or would otherwise be in default under the agreement. Upon an event of default, we would retain ownership of any resource where the full purchase price had not been paid, as well as, retain $0.5 million of fees received toward the purchase of that unpaid demand response capacity resource. The third party fully paid the purchase price for the first demand response capacity resource during the three month period ended June 30, 2014 and as a result, the sale of this resource was completed. As a result of the sale, we recognized a gain on the sale of this asset equal to the purchase price of $2.2 million during the year ended December 31, 2014. In addition, we are recognizing the guaranteed fees of $0.5 million ratably through the end of the potential contractual period of March 31, 2015 to the extent that sufficient cash has been received. During the year ended December 31, 2014, we have recognized $0.4 million of these fees which is recorded in other (expense) income, net in the accompanying consolidated statements of operations. As of December 31, 2014, the third party had not made sufficient payments related to the second demand capacity resource and therefore, the sale of this resource has not yet been completed and is not expected to be completed until the first half of 2015.

Interest and Other (Expense) Income, Net

Interest expense was $4.7 million for the year ended December 31, 2014 compared to $1.6 million for the year ended December 31, 2013. This increase was largely due to interest expense recorded on our Notes, which was $3.0 million for the year ended December 31, 2014.

Other expense, net for the year ended December 31, 2014 was $3.7 million, which primarily includes foreign currency gains and losses offset partially by other income. The $2.4 million increase as compared to the year ended December 31, 2013 was primarily due to decreased fluctuations to the U.S. dollar in the Euro, and Australian dollar, which resulted in a loss of $4.4 million for the year ended December 31, 2014, as compared to $1.7 million loss for the year ended December 31, 2013. We currently do not hedge any of our foreign currency transactions.

Income Taxes

We recorded a provision for income taxes of $5.9 million and $2.6 million for the years ended December 31, 2014 and 2013, respectively. The key components of our provision for income taxes are as follows:

 

   

estimated foreign taxes on profits earned by our foreign subsidiaries who have no available net operating loss carryforwards;

 

   

certain state taxes for jurisdictions where we have utilized all available net operating loss carryforwards; and

 

51


Table of Contents
   

amortization of tax deductible goodwill, which generates a deferred tax liability that cannot be offset by net operating losses or other deferred tax assets since its reversal is considered indefinite in nature.

Additionally, the provision for income taxes for the year ended December 31, 2014 includes the following:

 

   

$1.1 million benefit from deferred income taxes due to the release of a portion of the U.S. valuation allowance in connection with the Entech acquisition;

 

   

$1.1 million provision for deferred income taxes in connection with the sale of Utility Solutions Consulting;

Our effective tax rate for the year ended December 31, 2014 was 32.9% compared to an effective tax rate of 10.7% for the year ended December 31, 2013.

We review all available evidence to evaluate the recovery of deferred tax assets, including the recent history of losses in all tax jurisdictions, as well as our ability to generate income in future periods. As of December 31, 2014, due to the uncertainty related to the ultimate use of certain deferred income tax assets, we have provided a valuation allowance on certain of our deferred tax assets.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Revenues

The following table summarizes our revenues for the years ended December 31, 2013 and 2012 (dollars in thousands):

 

     Year Ended
December 31,
     Dollar
Change
     Percentage
Change
 
     2013      2012        

Revenues:

           

Grid operator

   $ 279,258      $ 176,792      $ 102,466        58.0

Utility

     71,611        77,600        (5,989      -7.7

Enterprise

     32,591        23,592        8,999        38.1
  

 

 

    

 

 

    

 

 

    

Total revenues

   $ 383,460      $ 277,984      $ 105,476        37.9
  

 

 

    

 

 

    

 

 

    

Grid Operator Revenues

For the year ended December 31, 2013, our revenues from grid operators increased by $102.5 million, or 58.0%, as compared to 2012. The increase in our revenues from grid operators was primarily attributable to changes in the following operating areas (dollars in thousands):

 

     Revenue Increase:
December 31, 2012
to
December 31, 2013
 

PJM

   $ 63,165  

IMO

     25,422  

AESO

     4,697  

Ontario Power Authority (OPA)

     4,075  

New York Independent System Operator (NYISO)

     2,766  

Other (1)

     2,341  
  

 

 

 

Total increase in grid operator revenues

   $ 102,466  
  

 

 

 

 

 

(1) The amounts included in ‘other’ relate to net increases in various demand response programs, none of which are individually material.

 

52


Table of Contents

The increase in revenues from grid operators for the year ended December 31, 2013, as compared to 2012, was primarily due to an increase in pricing and enrolled MW in our PJM, WA, and NYISO demand response programs. In addition, the increase in revenues from the PJM demand response program was also due to the increase in energy revenues resulting from a significant increase in both the number of dispatches and number of MW’s dispatched as compared to 2012. The increase was also due to revenues recognized from our participation in other international demand response programs, including OPA, and Alberta, Canada. We recognized no material revenues from our participation in either the Alberta, Canada demand response program during the year ended December 31, 2012.

Utility Revenues

For the year ended December 31, 2013, our revenues from utilities decreased by $6.0 million, or 7.7%, as compared to 2012. The overall decrease in our revenues from utilities was primarily attributable to changes in the following existing operating areas (dollars in thousands):

 

     Revenue Increase
(Decrease):
December 31, 2012
to
December 31, 2013
 

Pennsylvania Act 129 (Act 129)

   $ (13,015

PacifiCorp

     5,036  

SCE

     1,934  

PG&E

     532  

Other (1)

     (476
  

 

 

 

Total decrease in utility revenues

   $ (5,989
  

 

 

 

The decrease in revenues from utilities for the year ended December 31, 2013, as compared to 2012, was primarily due to a decrease in revenues from the Act 129 programs, as these programs ended in the third quarter of 2012 and were not renewed for 2013. The decrease in revenues from utilities was partially offset by an increase from our new demand response program with PacifiCorp in the northwestern region of the United States, from which revenues were recognized for the first time during the year ended December 31, 2013.

Enterprise Revenues

For the year ended December 31, 2013, our revenues from enterprise customers increased by $9.0 million, or 38.1%, as compared to 2012, due to the recognition of revenues related to an energy management application for the Massachusetts Department of Energy Resources, under which we did not start recognizing revenues until the fourth quarter of 2012, and an increase in our enterprise customers and overall consulting engagements.

Gross Profit and Gross Margin

The following table summarizes our gross profit and gross margin percentages for our EIS and related solutions for the years ended December 31, 2013 and 2012 (dollars in thousands):

 

Year Ended December 31,
2013   2012
Gross Profit  

Gross Margin

  Gross Profit  

Gross Margin

$191,168   49.9%   $123,444   44.4%

 

   

 

 

The increase in gross profit during the year ended December 31, 2013 as compared to 2012 was primarily due to an increase in revenues related to an increase in pricing and enrolled MW in our PJM and IMO demand response programs, as well as the increase in PJM demand response energy revenues resulting from an increase in both the number of dispatches and number of MW dispatched. The increase in gross profit during the year ended December 31, 2013 as compared to 2012 was also due to an increase in revenues resulting from increased

 

53


Table of Contents

participation in our international demand response programs in Alberta, Canada and New Zealand. We had no material revenues in either Alberta, Canada or New Zealand, and therefore no significant gross profits were recognized during the year ended December 31, 2012 related to these programs. In addition, the increase in gross profit was due to the revenues and associated gross profits recognized from our new demand response program with PacifiCorp, from which revenues and gross profits were recognized for the first time during the three month period ended September 30, 2013. In addition, although revenues related to ISO-NE decreased for the year ended December 31, 2013 as compared to 2012, our gross profits related to ISO-NE increased for the year ended December 31, 2013 due to a reduction of our MW delivery obligations in the ISO-NE market commencing on June 1, 2013, which resulted in a significant reduction of cost of revenues and favorable pricing arrangements under the third-party contracts and capacity auctions in which we participated. The increase in gross profit during the year ended December 31, 2013 as compared to 2012, was also due to increased gross profits from our enterprise products and solutions that resulted from the increase in revenues, as well as a decrease in delivery costs. The increase in gross profit for the year ended December 31, 2013 as compared to 2012 was partially offset by a decrease in revenues from the Act 129 programs, as these programs ended in the third quarter of 2012 and were not renewed for 2013. The increase in gross profit was also partially offset by the recognition of cost of revenues due to the uncertainty of the future recoverability of these costs, in a certain California demand response program where the associated revenues were deferred due to fees not being fixed or determinable.

Our gross margin increased during the year ended December 31, 2013 as compared to 2012 due to the increase in revenues related to our participation in international demand response programs, which to date are higher margin demand response programs, improved management of our portfolio of demand response capacity in certain programs, primarily due to the reduction in our MW delivery obligation in the ISO-NE market for the program year commencing June 1, 2013 through third party contracts and capacity auctions, and lower installed costs associated with our enterprise contracts. The increase in our gross margin during the year ended December 31, 2013 as compared to 2012 was also attributable to the recognition of $1 million of previously deferred revenues from one of our Act 129 programs where the associated costs were recognized in 2012. In addition, the increase in our gross margin was also attributable to higher gross margins from our enterprise revenues, including the recognition of previously deferred revenues related to an energy management application for the Massachusetts Department of Energy Resources for which a portion of the costs had been expensed in prior periods. The increase in our gross margin for the year ended December 31, 2013 as compared to 2012 was partially offset by a decrease in gross margin primarily related to changes in the management of our portfolio of demand response capacity in the PJM demand response program, including a decrease in the percentage of revenues recognized as a result of the adjustment of our zonal capacity obligations through our participation in PJM incremental auctions and an increase in the overall percentage of revenues paid to our enterprise customers. Our increase in gross margin was also partially offset by the recognition of cost of revenues due to the uncertainty of future recoverability of these costs, in a certain California demand response program where the associated revenues were deferred due to fees not being fixed or determinable.

Operating Expenses

The following table summarizes our operating expenses for the years ended December 31, 2013 and 2012 (dollars in thousands):

 

     Year Ended
December 31,
     Percentage
Change
 
     2013      2012     

Operating expenses:

        

Selling and marketing

   $ 65,915      $ 55,963        17.8

General and administrative

     79,220        71,643        10.6

Research and development

     18,317        16,226        12.9
  

 

 

    

 

 

    

Total operating expenses

   $ 163,452      $ 143,832        13.6
  

 

 

    

 

 

    

 

54


Table of Contents

In certain forward capacity markets in which we participate, such as PJM, we may enable our enterprise customers, meaning we may install our equipment at an enterprise customer site to allow for the curtailment of MW from the electric power grid, up to twelve months in advance of enrolling the enterprise customer in a particular program. As a result, there has been a trend of incurring operating expenses at the time of enablement, including salaries and related personnel costs, associated with enabling certain of our enterprise customers, in advance of recognizing the corresponding revenues.

Selling and Marketing Expenses

The following table summarizes our selling and marketing expenses for the years ended December 31, 2013 and 2012 (dollars in thousands):

 

     Year Ended
December 31,
     Percentage
Change
 
     2013      2012     

Payroll and related costs

   $ 40,613      $ 35,374        14.8

Stock-based compensation

     5,829        4,641        25.6

Other

     19,473        15,948        22.1
  

 

 

    

 

 

    

Total selling and marketing expenses

   $ 65,915      $ 55,963        17.8
  

 

 

    

 

 

    

The increase in payroll and other employee related costs for the year ended December 31, 2013 compared to 2012 was primarily due to an increase in the number of selling and marketing full-time employees from 212 at December 31, 2012 to 231 at December 31, 2013, higher benefit costs, as well as higher average expected bonuses on a per employee basis.

The increase in stock-based compensation for the year ended December 31, 2013 compared to 2012 was primarily due to the grant of additional stock-based awards, as well as an increase in the grant date fair value of stock-based awards granted during the year ended December 31, 2013, as a result of the increase in our stock price as compared to 2012.

The increase in other selling and marketing expenses for the year ended December 31, 2013 compared to 2012 was attributable to an increase of $1.8 million in the allocation of company-wide overhead costs, which are allocated based on headcount, that resulted from both the increase in the number of full-time selling and marketing employees in addition to overall higher overhead costs. This increase for the year ended December 31, 2013 compared to 2012, was also due to higher costs associated with various marketing initiatives of $1.1 million, an increase in amortization expense of $0.3 million and an increase of $0.2 million in software licensing fees.

General and Administrative Expenses

The following table summarizes our general and administrative expenses for the years ended December 31, 2013 and 2012 (dollars in thousands):

 

     Year Ended
December 31,
     Percentage
Change
 
     2013      2012     

Payroll and related costs

   $ 45,279      $ 37,538        20.6

Stock-based compensation

     8,629        7,755        11.3

Other

     25,312        26,350        (3.9 )% 
  

 

 

    

 

 

    

Total general and administrative expenses

   $ 79,220      $ 71,643        10.6
  

 

 

    

 

 

    

The increase in payroll and related costs for the year ended December 31, 2013 compared to 2012 was primarily attributable to a 9% increase in the average number of general and administrative full-time employees

 

55


Table of Contents

from fiscal 2012 to fiscal 2013, higher benefit costs, as well as an increase in overall salary rates and expected bonuses on a per employee basis. The increase was also attributable to the hiring of certain highly compensated employees in fiscal 2013.

The increase in stock-based compensation for the year ended December 31, 2013 compared 2012 was primarily due to an increase in the number of stock-based awards granted during the period and an increase in the overall grant-date fair value of stock-based awards granted as a result of the increase in our stock price. The increase in stock-based compensation for the year ended December 31, 2013 compared to 2012 was also due to an increase in the number of stock-based awards granted to new executive officers and new members of our board of directors during the year ended December 31, 2013, as well as fully-vested awards that were granted to existing members of our board of directors during the first quarter of 2013. This increase for the year ended December 31, 2013 was partially offset by the reversal of stock-based compensation expense associated with the resignations of certain executive officers as a result of forfeitures.

The decrease in other general and administrative expenses for the year ended December 31, 2013 compared to 2012 was primarily attributable to a $2.9 million decrease in the allocation of company-wide overhead costs due to a decline in the percentage of general and administrative employees relative to total employees during the year ended December 31, 2013 as compared to 2012, a lease termination charge of $1.1 million recorded during the year ended December 31, 2012 related to our election to terminate the operating lease of our prior corporate headquarters, and lower regulatory compliance fees of $0.8 million. The decrease in other general and administrative expenses for the year ended December 31, 2013 compared to 2012 was also attributable to a decrease in amortization expense of $0.6 million, the reversal of the accrued acquisition contingent consideration liability of $0.4 million, related to the earn-out payment associated with our 2011 acquisition of Energy Response, as the criteria for the earn-out payment were not achieved and the earn-out period lapsed on December 31, 2013, in addition to lower bad debt expenses and lower conference fees. These decreases were partially offset by higher rent and depreciation expenses of approximately $2.8 million related to our new principal executive offices, higher software license fees and insurance costs of $2.1 million and higher professional service fees of $0.8 million.

Research and Development Expenses

The following table summarizes our research and development expenses for the years ended December 31, 2013 and 2012 (dollars in thousands):

 

     Year Ended
December 31,
     Percentage
Change
 
     
     2013      2012     

Payroll and related costs

   $ 9,977      $ 9,172        8.8

Stock-based compensation

     1,410        1,220        15.6

Other

     6,930        5,834        18.8
  

 

 

    

 

 

    

Total research and development expenses

   $ 18,317      $ 16,226        12.9
  

 

 

    

 

 

    

The increase in payroll and other employee related costs for the year ended December 31, 2013 compared to the same period in 2012 was primarily driven by an increase in the number of research and development full-time employees from 90 at December 31, 2012 to 99 at December 31, 2013, an increase in salary rates per full-time employee, as well as, a portion of the bonuses for fiscal 2012 that were settled in shares of our common stock rather than cash and is, therefore, recorded as a component of stock-based compensation expense, and higher benefit costs. These increases for the year ended December 31, 2013 compared to the same period in 2012 were partially offset by an increase in capitalized application development costs primarily related to our continued investment in our EIS and related solutions.

The increase in stock-based compensation for the year ended December 31, 2013 compared to the same period in 2012 was primarily attributable to an increase in the number of stock-based awards granted and an increase in the overall grant-date fair value of the stock-based awards granted as a result of the increase in our

 

56


Table of Contents

stock price. This increase was partially offset by a decrease in the percentage of stock-based compensation expense related to our stock-based awards granted during fiscal 2011 and fiscal 2012 with performance-based vesting conditions that are recognized under the accelerated attribution method and which results in a greater percentage of stock-based compensation expense being recognized in fiscal 2011 and fiscal 2012 as compared to fiscal 2013.

The increase in other research and development expenses for the year ended December 31, 2013 compared to the same period in 2012 was primarily attributable to an increase of $0.9 million in the allocation of company-wide overhead costs, which is based on headcount, higher information technology and communication costs of $0.3 million in support of our business and higher consulting and professional fees of $0.2 million. These increases in other research and development expenses for the year ended December 31, 2013 compared to the same period in 2012 were partially offset by a decrease of $0.3 million in software licenses and fees used in the development of our EIS and related solutions.

Interest and Other (Expense) Income, Net

The increase in interest expense of $0.1 million for the year ended December 31, 2013 compared to 2012 was primarily attributable to higher amortization expense of our deferred financing costs. Other (expense) income, net for the year ended December 31, 2013 was primarily comprised of foreign currency gains (losses) and a nominal amount of interest income. We had approximately $9.8 million at December 31, 2013 exchange rates ($10.9 million Australian) in intercompany receivables denominated in Australian dollars that arose from the acquisition of Energy Response in July 2011. Substantially all of the foreign currency gains (losses) represented unrealized gains (losses) and, therefore, are non-cash in nature. We did not hedge any of our foreign currency transactions.

Income Taxes

We recorded a provision for income taxes of $2.6 million and $1.8 million for the years ended December 31, 2013 and 2012, respectively. Although our federal and state net operating loss carryforwards exceeded our taxable income for the years ended December 31, 2013 and 2012, our annual effective tax rate was greater than zero due to the following:

 

   

estimated foreign taxes on profits earned by our limited risk foreign subsidiaries who provide services to the U.S. parent;

 

   

certain state taxes for jurisdictions where we have utilized all available net operating loss carryforwards; and

 

   

amortization of tax deductible goodwill, which generates a deferred tax liability that cannot be offset by net operating losses or other deferred tax assets since its reversal is considered indefinite in nature.

Our effective tax rate for the year ended December 31, 2013 was 10.7% compared to an effective tax rate of 8.6% for the year ended December 31, 2012.

We review all available evidence to evaluate the recovery of our deferred tax assets, including our history of losses in recent years and our expectations of income in future periods. We believe our history of losses in recent years creates substantial uncertainty around our ability to realize the benefit of our deferred tax assets. As a result, we have provided a valuation allowance against our U.S, Australian and United Kingdom deferred tax assets at December 31, 2013 and December 31, 2012.

Liquidity and Capital Resources

Overview

We have generated significant cumulative losses since inception. As of December 31, 2014, we had an accumulated deficit of $69.3 million. As of December 31, 2014, our principal sources of liquidity were cash and cash equivalents totaling $254.4 million, an increase of $105.2 million from the December 31, 2013 balance of

 

57


Table of Contents

$149.2 million principally driven by the $155.3 million net proceeds from our Notes offering, offset by cash used for acquisitions. At December 31, 2014 and December 31, 2013, the majority of our excess cash was invested in money market funds.

Subsequent to December 31, 2014, we have utilized approximately $77.0 million of our cash and cash equivalents in connection with the acquisition of World Energy. We believe our existing cash and cash equivalents and our anticipated net cash flows from operating activities will be sufficient to meet our anticipated cash needs, including investing activities, for at least the next 12 months. Our future working capital requirements will depend on many factors, including, without limitation, the rate at which we sell our EIS and related solutions to enterprise customers and the increasing rate at which letters of credit or security deposits are required by electric power grid operators and utilities, the introduction and market acceptance of new EIS and related solutions, the expansion of our sales and marketing and research and development activities, and the geographic expansion of our business operations.

Cash Flows

The following table summarizes our cash flows for the years ended December 31, 2014, 2013 and 2012 (dollars in thousands):

 

     Year Ended December 31,  
     2014      2013      2012  

Cash flows provided by operating activities

   $ 60,439      $ 79,464      $ 31,011  

Cash flows used in investing activities

     (74,422      (37,889      (3,585

Cash flows provided by (used in) financing activities

     120,865        (6,804      356  

Effects of exchange rate changes on cash and cash equivalents

     (1,720      (623      (38
  

 

 

    

 

 

    

 

 

 

Net change in cash and cash equivalents

   $ 105,162      $ 34,148      $ 27,744  
  

 

 

    

 

 

    

 

 

 

Cash Flows Provided by Operating Activities

Cash provided by operating activities primarily consists of net income (loss) adjusted for certain non-cash items including depreciation and amortization, stock-based compensation expense, gains on sales of service lines and assets, and the effect of changes in working capital and other activities.

Cash provided by operating activities for the year ended December 31, 2014 was approximately $60.4 million and consisted of net income of $12.0 million and $55.8 million of non-cash items, offset by gains of $7.0 million on the sales of service lines and assets, which are included as a component of net income but represent investing activities and $0.4 million of net cash used in working capital and other activities. The non-cash items primarily consisted of depreciation and amortization, stock-based compensation expense, impairment charges, unrealized foreign exchange translation losses, deferred taxes and non-cash interest expense. Cash provided by working capital and other activities consisted of an increase of $20.3 million in accounts payable, accrued expenses and other current liabilities, an increase in accrued capacity payments of $16.3 million, an increase of $3.6 million in accrued payroll and related expenses, and a decrease in capitalized incremental direct customer contract costs of $2.5 million. These amounts were offset by cash used in working capital and other activities consisting of an increase of $31.1 million in unbilled revenues, primarily related to the PJM demand response market, a decrease of $8.1 million in deferred revenue, and an increase in accounts receivable of $3.0 million.

Cash provided by operating activities for the year ended December 31, 2013 was approximately $79.5 million and consisted of net income of $22.1 million, $47.5 million of non-cash items and $9.9 million of net cash provided by working capital and other activities. The non-cash items primarily consisted of depreciation and amortization, stock-based compensation expense, impairment charges, unrealized foreign exchange translation losses, deferred taxes and non-cash interest expense. Cash provided by working capital and other activities consisted of a decrease in capitalized incremental direct customer contract costs of $2.0 million, an increase of $5.7 million in other noncurrent liabilities primarily due to deferred rent associated with our new corporate

 

58


Table of Contents

headquarters, an increase in accrued capacity payments of $28.5 million, an increase of $0.6 million in accrued payroll and related expenses and an increase of $1.0 million in accounts payable, accrued performance adjustments and accrued expenses primarily due to the repayment of certain accrued performance adjustments. These amounts were offset by cash used in working capital and other activities consisting of an increase in accounts receivable of $1.2 million, an increase of $21.4 million in unbilled revenues primarily related to the PJM demand response market, an increase in prepaid expenses and other assets of $1.5 million and a decrease of $3.8 million in deferred revenue.

Cash provided by operating activities for the year ended December 31, 2012 was approximately $31.0 million and consisted of a net loss of $22.3 million, offset by $42.3 million of non-cash items and $11.0 million of net cash provided by working capital and other activities. The non-cash items primarily consisted of depreciation and amortization, stock-based compensation expense, impairment charges, unrealized foreign exchange translation gains, deferred taxes and non-cash interest expense. Cash provided by working capital and other activities consisted of a decrease of $19.2 million in unbilled revenues relating to the PJM demand response market, a decrease in prepaid expenses and other assets of $2.9 million, an increase of $14.5 million in deferred revenue, an increase of $1.4 million in accrued payroll and related expenses and an increase of $1.6 million in other noncurrent liabilities. These amounts were offset by cash used in working capital and other activities consisting of an increase in accounts receivable of $11.5 million due to the timing of cash receipts under the demand response programs in which we participate, an increase in capitalized incremental direct customer contract costs of $5.7 million, a decrease in accrued capacity payments of $9.2 million, the majority of which was related to the PJM demand response market and a decrease of $2.4 million in accounts payable, accrued performance adjustments and accrued expenses primarily due to the repayment of certain accrued performance adjustments.

Cash Flows Used in Investing Activities

Cash used in investing activities was $74.4 million for the year ended December 31, 2014. During the year ended December 31, 2014, we made payments, net of cash acquired of $3.9 million, $20.2 million, $12.0 million, $0.3 million, and $15.3 million for the acquisitions of Activation Energy, Entelios, Entech, ULC, and Pulse Energy respectively. In addition, during the year ended December 31, 2014, we made payments of $2.5 million to acquire investments and a payment of $0.4 million for the acquisition of a customer contract. Also, during the year ended December 31, 2014, our restricted cash and deposits decreased by $2.3 million due to a decline in deposits principally related to the financial assurances required for the demand response programs in which we participated, as these deposits were replaced with letters of credit. We made $25.6 million of capital expenditures, primarily related to software additions, including capitalized software development costs, to further expand the functionality of our software and solutions, as well as, demand response equipment expenditures due to an increase in our installed customer base. We have also made capital expenditures for office equipment, furniture and fixtures, and leasehold improvements associated with leasing new office space. Cash used in investing activities for the year ended December 31, 2014 was partially offset by $5.9 million and $2.2 million in cash proceeds from our sale of service lines and our sale of assets, respectively.

Cash used in investing activities was $37.9 million for the year ended December 31, 2013. During the year ended December 31, 2013, we incurred $36.7 million in capital expenditures primarily related to our new corporate headquarters, purchases of demand response equipment, as well as capitalized internal use software costs as we continue our investment to further develop and enhance our applications. We also made a payment of $0.7 million to acquire a customer contract. In addition, our restricted cash and deposits increased by $0.5 million primarily due to an increase in restricted cash utilized to collateralize performance obligations under certain demand response arrangements.

Cash used in investing activities was $3.6 million for the year ended December 31, 2012. During the year ended December 31, 2012, we incurred $15.9 million in capital expenditures primarily related to the purchase of office and IT equipment, capitalized internal use software costs, demand response equipment and other miscellaneous capital expenditures. In addition our restricted cash and deposits decreased by $12.4 million due to a decline in deposits principally related to the financial assurances required for the demand response programs in which we participated, as these deposits were replaced with letters of credit.

 

59


Table of Contents

Cash Flows Provided by (Used in) Financing Activities

Cash provided by (used in) financing activities was $120.9 million, ($6.8) million and $0.4 million for the years ended December 31, 2014, 2013 and 2012, respectively. For the year ended December 31, 2014, cash provided by financing activities primarily consisted of the net proceeds from the sale and issuance of our Notes in August 2014 totaling $155.3 million, less $30.0 million of the net proceeds which were used to repurchase shares of our common stock. We realized $1.6 million of cash from the exercise of stock options, recognized an excess tax benefit related to the exercise of stock options, restricted stock and restricted stock units of $0.6 million, and made payments of approximately $6.6 million for employee restricted stock minimum tax withholdings. During the year ended December 31, 2013, cash used in financing activities primarily consisted of payments made to repurchase shares of our common stock of $9.5 million, as well as employee restricted stock minimum tax withholding payments of $0.3 million, partially offset by proceeds that we received from exercises of options to purchase shares of our common stock of $2.4 million. For the year ended December 31, 2012, cash provided by financing activities primarily consisted of proceeds that we received from exercises of options to purchase shares of our common stock.

Borrowings and Credit Arrangements

Credit Agreement

On August 11, 2014, we terminated our 2013 credit facility. There were no outstanding borrowings under the 2013 credit facility as of the date of termination. We did not incur any penalties in connection with this termination.

On August 11, 2014, we entered into our 2014 credit facility. Subject to continued covenant compliance and borrowing base requirements, the 2014 credit facility provides for a one-year revolving line of credit in the aggregate amount of $30.0 million, the full amount of which may be available for issuances of letters of credit. The interest on revolving loans under the 2014 credit facility will accrue, at our election, at either (i) the LIBOR (determined based on the per annum rate of interest at which deposits in United States Dollars are offered to Silicon Valley Bank, or 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 letter of credit fee charged under the 2014 Loan Agreement is 1.50% per annum on the face amount of any letters of credit, plus customary fronting fees. Unless amended, the 2014 credit facility terminates and all amounts outstanding thereunder are due and payable in full on August 11, 2015.

For further discussion of the 2014 credit facility, please refer to Note 10 contained in Appendix A to the Annual Report on Form 10-K.

As of December 31, 2014, we were in compliance with all of our covenants under the 2014 credit facility. We believe that it is reasonably assured that we will comply with the covenants of the 2014 credit facility for the foreseeable future.

As of December 31, 2014, we had no borrowings, but had outstanding letters of credit totaling $22.8 million under the 2014 credit facility, compared to outstanding letters of credit totaling $49.2 million under the 2013 credit facility as of December 31, 2013. The decrease in the amount of outstanding letters of credit from December 31, 2013 to December 31, 2014 is primarily the result of a reduction in the collateral requirements for demand response arrangements and obligations. As of December 31, 2014, we had $7.2 million available under the 2014 credit facility for future borrowings or issuances of additional letters of credit.

Convertible Notes

On August 12, 2014, we entered into a Purchase Agreement with Morgan Stanley & Co. LLC, acting on behalf of itself and the several initial purchasers relating to the sale of $160.0 million aggregate principal amount of 2.25% Notes, in an offering exempt from registration under the Securities Act of 1933, as amended, or the Offering.

 

60


Table of Contents

On August 18, 2014, the Offering closed and we issued the Notes. The net proceeds from the Offering were approximately $155.3 million after deducting the initial purchasers’ discounts of $4.0 million and offering expenses of approximately $0.7 million paid by us. We used $30.0 million of the net proceeds of the offering to repurchase 1,514,552 shares of our common stock from purchasers of the Notes in privately negotiated transactions effected through Morgan Stanley & Co. LLC, as our agent, at a purchase price of $19.79 per share, which was the closing price of the common stock on The NASDAQ Global Select Market on August 12, 2014. On January 5, 2015, we utilized approximately $77.0 million of our cash and cash equivalents in connection with the acquisition of World Energy. We intend to use the remaining net proceeds from the Offering for working capital, additional repurchases of our common stock, and other general corporate purposes, which may include the expansion of our current business through acquisitions of, or investments in, other businesses, products, product rights or technologies.

For further discussion of the Notes, please refer to Note 10 contained in Appendix A to the Annual Report on Form 10-K.

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

 

     Year Ended
December 31,
 
     2014  

Accretion of debt discount

   $         1.5  

Amortization of deferred financing costs

     0.2  
  

 

 

 

Non-cash interest expense

     1.7  

2.25% accrued interest

     1.3  
  

 

 

 

Total interest expense from Notes

   $ 3.0  
  

 

 

 

Contingent Earn-Out Payments

As discussed in Note 2 to our consolidated financial statements contained herein, in connection with our acquisitions of Entelios, Activation Energy, ULC, and Pulse Energy, we may be obligated to pay additional contingent purchase price consideration related to earn-out payments.

The earn-out payment for Entelios, if any, will be based on the achievement of certain minimum defined profit metrics for the years ended December 31, 2014 and 2015. The 1.5 million Euros ($2.0 million) maximum earn-out payment includes up to 0.6 million Euros and 0.9 million Euros related to the achievement of the defined profit metrics for the years ended December 31, 2014 and 2015. If the minimum defined profit metrics are not achieved, there will be no partial payment, however, the amount of the earn-out payment can vary based on the amount that profits exceed the minimum defined profit metrics. We determined that the earn-outs’ fair value as of the acquisition date was 0.1 million Euros ($0.1 million). This reflects our evaluation of the likelihood of the achievement of the contractual conditions that would result in the payment of the contingent consideration and weighted probability assumptions of these outcomes. We did not achieve the 2014 milestones and as a result, there were no changes in the probability of the earn-out payment. This liability has been discounted to reflect the time value of money and therefore, as the milestone date approaches, the fair value of this liability will increase. This increase in fair value is recorded to cost of revenues in our accompanying consolidated statements of operations. During the year ended December 31, 2014, the change in the fair value that resulted from the accretion of the time value of money discount was not material; as a result, the December 31, 2014 liability remained at 0.1 million Euros ($0.1 million) representing the potential payout associated with the 2015 milestones.

The earn-out payment for Activation Energy will be based on the achievement of certain minimum defined MW enrollment, as well as, profit metrics for the years ended December 31, 2014 and 2015. The 1.0 million Euros ($1.4 million) maximum earn-out payment includes up to 0.3 million Euros and 0.7 million Euros related to the achievement of the defined profit metrics for the years ended December 31, 2014 and 2015. If the minimum defined profit metrics are not achieved, there will be no partial payment, however, the amount of the earn-out payment can vary based on the amount that profits exceed the minimum defined profit metrics. We determined that the earn-outs’ fair value as of the acquisition date was 0.2 million Euros ($0.3 million). We

 

61


Table of Contents

recorded our estimate of the fair value of the contingent consideration based on the evaluation of the likelihood of the achievement of the contractual conditions that would result in the payment of the contingent consideration and weighted probability assumptions of these outcomes. At December 31, 2014, the liability was recorded at 0.5 million Euros ($0.5 million) representing the potential payout associated with the 2014 and 2015 milestones. In January 2015, we disbursed 0.3 million Euros ($0.3 million) related to the 2014 milestone.

In connection with our acquisition of ULC in April 2014, we may be obligated to pay additional contingent purchase price consideration related to certain earn-out amounts up to a maximum of $1.8 million. The earn-out payments, if any, will be based on the achievement of certain defined market legislation and certain operational metrics. The market legislation metric was achieved in May 2014, with the $0.3 million payment retained to cover general business representations and warranties to be paid 18 months after the closing date. The remaining $1.5 million is payable to those stockholders of the acquired entity who are employees as of the time of payment. We concluded these payments should be accounted for as compensation arrangements and expensed ratably over the applicable service period for the amount, if achievement is deemed probable. The first performance milestone of $0.5 million was achieved in December 2014, with $0.2 million paid at such time. The remaining $0.3 million will be paid in January 2016 and 2017. The second performance milestone of $1.0 million has not yet been achieved.

The earn-out payment for Pulse Energy, if any, will be based on the achievement of sales targets for the years ended December 31, 2015, 2016 and 2017, to be paid in the form of our common stock if targets are reached. The earn-out is a binary outcome in that either full or no payment is due. We recorded our estimate of the fair value of the contingent consideration based on the evaluation of the likelihood of the achievement of the contractual conditions and weighed probability assumptions of these outcomes. Because the contingent consideration is expected to be settled in our own shares and the criteria in ASC 815, Contracts in Entity’s Own Equity , was met, the fair value of the earn-out was recorded in equity as additional paid-in capital. The fair value of the earn-out has been estimated to equal $1.6 million and will not be re-measured subsequent to the acquisition date due to equity classification.

Capital Spending

We have made capital expenditures primarily for general corporate purposes to support our growth and for equipment installations related to our business. Our capital expenditures totaled $25.6 million, $36.7 million and $15.9 million during the years ended December 31, 2014, 2013 and 2012, respectively. We expect our capital expenditures for 2015 to exceed our capital expenditures for 2014 due primarily to increased site installations, higher capitalized software attributable to capitalized wages consistent with the expected growth in research and development headcount, higher leasehold improvements and office equipment consistent with overall headcount growth. However, we also expect our capital expenditures for 2015 to be less than 2013, as 2013 included capital expenditures related to a lease for our new corporate headquarters.

Contractual Obligations

Information regarding our significant contractual obligations is set forth in the following table and includes the operating lease arrangement described above. Payments due by period have been presented based on payments due subsequent to December 31, 2014 (in millions):

 

     Payments Due By Period  

Contractual Obligations

   Total      Less than
1 Year
     1-3
Years
     3-5
Years
     More than
5 Years
 

Interest on convertible senior notes

   $ 17.9      $ 3.7      $ 7.2      $ 7.0      $  

Operating lease obligations

     45.6        8.8        16.9        15.6        4.3  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual obligations

   $ 63.5      $ 12.5      $ 24.1      $ 22.6      $ 4.3  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

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.

Our fixed interest payments at 2.25% relating to our convertible senior notes, which mature on August 19, 2019, are presented in the table above.

 

62


Table of Contents

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, United Kingdom, Germany, Ireland, South Korea, Brazil and India, as well as certain property and equipment.

In March 2014, we entered into a lease for our California operations. The lease term is through September 2019 and the lease contains both a rent holiday period and escalating rental payments over the lease term. The lease requires payments for additional expenses such as taxes, maintenance, and utilities and contains a fair value renewal option. The lease commenced on April 1, 2014. In addition, in connection with the acquisitions we completed during the year ended December 31, 2014, we acquired certain facility operating lease arrangements which were all considered to contain current market terms and rates. These leases have terms that range from one to ten years and expire through March 2020. Certain of the lease agreements require payments for additional expenses such as taxes, maintenance, and utilities and contain fair value renewal options. There were no ongoing rent holidays or escalating rent payments over the remaining lease terms as of the dates of acquisition.

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

In connection with our acquisition of M2M, we are required to pay additional consideration that was deferred at the date of the acquisition. This deferred purchase price consideration of $7.0 million will be paid upon the earlier of the satisfaction of certain conditions contained in the definitive agreement or seven years after the acquisition date of January 25, 2011. The deferred purchase price consideration is not subject to adjustment or forfeiture. We recorded our estimate of the fair value of the deferred purchase price consideration based on the evaluation of the likelihood of the achievement of the contractual conditions that would result in the payment of the deferred purchase price consideration prior to seven years from the acquisition date and weighted probability assumptions of these outcomes. The cash portion of the deferred purchase price consideration has been recorded as a liability, initially estimated to be less than $0.5 million, discounted to reflect the time value of money. As the milestone payment date approaches, the fair value of this liability will increase. The fair value of the deferred purchase price consideration of $3.4 million, related to the 254,654 shares of common stock to be issued upon the milestone payment date has been classified as additional paid-in capital within stockholders’ equity. With respect to the cash portion of the deferred purchase price consideration, the increase in fair value is recorded as an expense in our accompanying consolidated statements of operations. During each of the years ended December 31, 2014 and 2013, we recorded a charge of less than $0.1 million related to the accretion for the time value of money discount. At December 31, 2014, the liability was recorded at $0.6 million. The deferred purchase price consideration to be paid in shares meets the requirements of an equity instrument and, accordingly, will not be remeasured at fair value each reporting period. This acquisition had no contingent consideration or earn-out payments.

As of December 31, 2014, we had no borrowings, but had outstanding letters of credit totaling $22.8 million under the 2014 credit facility. As of December 31, 2014, we had $7.2 million available under the 2014 credit facility for future borrowings or issuances of additional letters of credit.

We typically grant certain customers a limited warranty that guarantees that our hardware products will substantially conform to current specifications for one year from the delivery date. Based on our operating history, the liability associated with product warranties has been determined to be nominal. We also indemnify our customers from third-party claims relating to the intended use of our products. Pursuant to these clauses, we indemnify and agree to pay any judgment or settlement relating to a claim.

We guarantee the electrical 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, 2014 and 2013 were $23.7 million and $48.9 million, respectively. For the year ended December 31, 2014, these performance guarantees include deposits held by certain customers of $3.0 million. For the year ended

 

63


Table of Contents

December 31, 2013, the performance guarantees included restricted cash utilized to collateralize certain demand response programs of $1.6 million and did not include any deposits held by customers.

Off-Balance Sheet Arrangements

As of December 31, 2014, 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, 2014, we had outstanding letters of credit totaling $22.8 million. For information on these commitments and contingent obligations, see “Liquidity and Capital Resources—Borrowings and Credit Arrangements” above and Note 10 to our consolidated financial statements contained herein.

Additional Information

Non-GAAP Financial Measures

To supplement our consolidated financial statements presented on a GAAP basis, we disclose certain non-GAAP measures that exclude certain amounts, including non-GAAP net income (loss) attributable to EnerNOC, Inc., non-GAAP net income (loss) per share attributable to EnerNOC, Inc., adjusted EBITDA and free cash flow. These non-GAAP measures are not in accordance with, or an alternative for, generally accepted accounting principles in the United States.

The GAAP measure most comparable to non-GAAP net income (loss) attributable to EnerNOC, Inc. is GAAP net income (loss) attributable to EnerNOC, Inc.; the GAAP measure most comparable to non-GAAP net income (loss) per share attributable to EnerNOC, Inc. is GAAP net income (loss) per share attributable to EnerNOC, Inc.; the GAAP measure most comparable to adjusted EBITDA is GAAP net income (loss) attributable to EnerNOC, Inc.; and the GAAP measure most comparable to free cash flow is cash flows provided by (used in) operating activities. Reconciliations of each of these non-GAAP financial measures to the corresponding GAAP measures are included below.

Use and Economic Substance of Non-GAAP Financial Measures

Management uses these non-GAAP measures when evaluating our operating performance and for internal planning and forecasting purposes. Management believes that such measures help indicate underlying trends in our business, are important in comparing current results with prior period results, and are useful to investors and financial analysts in assessing our operating performance. For example, management considers non-GAAP net income attributable to EnerNOC, Inc. to be an important indicator of the overall performance because it eliminates the material effects of events that are either not part of our core operations or are non-cash compensation expenses. In addition, management considers adjusted EBITDA to be an important indicator of our operational strength and performance of our business and a good measure of our historical operating trend. Moreover, management considers free cash flow to be an indicator of our operating trend and performance of our business.

The following is an explanation of the non-GAAP measures that we utilize, including the adjustments that management excluded as part of the non-GAAP measures:

 

   

Management defines non-GAAP net income (loss) attributable to EnerNOC, Inc. as net income (loss) attributable to EnerNOC, Inc. before accretion expense related to the debt-discount portion of interest expense associated with the convertible note issuance, stock-based compensation, and amortization expenses related to acquisition-related intangible assets, net of related tax effects.

 

   

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

 

   

Management defines free cash flow as net cash provided by (used in) operating activities, less capital expenditures, plus net cash provided by (used in) the sale of assets or disposals of components of an

 

64


Table of Contents
 

entity. Management defines capital expenditures as purchases of property and equipment, which includes capitalization of internal-use software development costs.

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

Non-GAAP net income (loss) attributable to EnerNOC, Inc., non-GAAP net income (loss) per share attributable to EnerNOC, Inc., adjusted EBITDA and free cash flow may have limitations as analytical tools. The non-GAAP financial information presented here should be considered in conjunction with, and not as a substitute for or superior to the financial information presented in accordance with GAAP and should not be considered measures of our liquidity. There are significant limitations associated with the use of non-GAAP financial measures. Further, these measures may differ from the non-GAAP information, even where similarly titled, used by other companies and therefore should not be used to compare our performance to that of other companies.

Non-GAAP Net Income (Loss) attributable to EnerNOC, Inc. and Non-GAAP Net Income (Loss) per Share attributable to EnerNOC, Inc.

Net income for the year ended December 31, 2014 was $12.1 million, or $0.43 per basic share and $0.42 per diluted share, compared to net income of $22.1 million, or $0.80 per basic share and $0.76 per diluted share for the year ended December 31, 2013, and a net loss of $22.3 million, or $0.84 per basic and diluted share for the year ended December 31, 2012. Excluding accretion expense related to the debt-discount portion of interest expense associated with the convertible note issuance, stock-based compensation expense, and amortization expenses related to acquisition-related intangible assets, net of related tax effects, non-GAAP net income for the year ended December 31, 2014 was $36.4 million, or $1.26 per diluted share, compared to non-GAAP net income of $45.0 million, or $1.55 per diluted share for the year ended December 31, 2013, and non-GAAP net loss of $1.4 million or $0.05 per diluted share for the year ended December 31, 2012.

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

 

     Year Ended December 31,  
     2014     2013      2012  

GAAP net income (loss) attributable to EnerNOC, Inc.

   $ 12,094     $ 22,088      $ (22,293

ADD: Stock–based compensation expense

     16,063       15,868        13,616  

ADD: Amortization expense of acquired intangible assets

     9,252       7,029        7,241  

ADD: Debt discount portion of convertible debt

     1,474               

ADD: Income tax effect on Non-GAAP adjustments

     (2,486             
  

 

 

   

 

 

    

 

 

 

Non-GAAP net income (loss) attributable to EnerNOC, Inc.

   $ 36,397     $ 44,985      $ (1,436
  

 

 

   

 

 

    

 

 

 

GAAP net income (loss) per diluted share attributable to EnerNOC, Inc.

   $ 0.42     $ 0.76      $ (0.84

ADD: Stock–based compensation expense

     0.56       0.55        0.52  

ADD: Amortization expense of acquired intangible assets

     0.32       0.24        0.27  

ADD: Debt discount portion of convertible debt

     0.05               

ADD: Income tax effect on Non-GAAP adjustments

     (0.09             
  

 

 

   

 

 

    

 

 

 

Non-GAAP net income (loss) per diluted share attributable to EnerNOC, Inc.

   $ 1.26     $ 1.55      $ (0.05
  

 

 

   

 

 

    

 

 

 

Weighted average number of common shares outstanding

       

Basic

     27,857,026       27,774,778        26,551,234  

Diluted

     28,790,665       29,045,066        26,551,234  

 

65


Table of Contents

Adjusted EBITDA

Adjusted EBITDA was $76.4 million, $71.4 million and $18.4 million for the years ended December 31, 2014, 2013 and 2012, respectively.

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

 

     Year Ended December 31,  
     2014      2013      2012  

Net income (loss) attributable to EnerNOC, Inc.

   $ 12,094      $ 22,088        (22,293

Add back:

        

Depreciation and amortization

     31,417        27,844        25,218  

Stock-based compensation expense

     16,063        15,868        13,616  

Direct and incremental expenses related to acquisitions or divestitures

     3,550                

Other expense (income) (1)

     3,699        1,342        (1,457

Interest expense

     4,656        1,646        1,591  

Provision for income tax (2)

     4,891        2,640        1,771  
  

 

 

    

 

 

    

 

 

 

Adjusted EBITDA

   $ 76,370      $ 71,428      $ 18,446  
  

 

 

    

 

 

    

 

 

 

 

 

(1) Other expense primarily relates to foreign exchange losses.

 

(2) Excludes discrete tax provision of $985 recorded during the year ended December 31, 2014 related to our sale of various business components.

Free Cash Flow

Cash flow from operating activities was $60.4 million, $79.5 million and $31.0 million for the years ended December 31, 2014, 2013 and 2012, respectively. We generated $42.9 million, $42.8 million and $15.2 million of free cash flow for the years ended December 31, 2014, 2013 and 2012, respectively. The reconciliation of cash flow from operating activities to free cash flow is set forth below (dollars in thousands):

 

     Year Ended December 31,  
     2014      2013      2012  

Net cash provided by operating activities

   $ 60,439      $ 79,464      $ 31,011  

Add:

        

Net cash provided by the sale of assets

     8,046                

Subtract:

        

Purchases of property and equipment

     (25,553      (36,663      (15,854
  

 

 

    

 

 

    

 

 

 

Free cash flow

   $ 42,932      $ 42,801      $ 15,157  
  

 

 

    

 

 

    

 

 

 

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, estimated fair values of intangible assets and goodwill, amortization methods and periods, certain accrued expenses and other

 

66


Table of Contents

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 (ASC 605). Our customers include enterprises, grid operators, and utilities. We derive recurring revenues from the sale of our EIS and related solutions. We do not recognize any revenues until persuasive evidence of an arrangement exists, delivery has occurred, the fee is fixed or determinable, and we deem collection to be reasonably assured. In making these judgments, we evaluate the following criteria:

 

   

Evidence of an arrangement .    We consider a definitive agreement signed by the customer and us or an arrangement enforceable under the rules of an open market bidding program to be representative of persuasive evidence of an arrangement.

 

   

Delivery has occurred .    We consider delivery to have occurred when service has been delivered to the customer and no significant post-delivery obligations exist. In instances where customer acceptance is required, delivery is deemed to have occurred when customer acceptance has been achieved.

 

   

Fees are fixed or determinable .    We consider the fee to be fixed or determinable unless the fee is subject to refund or adjustment or is not payable within normal payment terms. If the fee is subject to refund or adjustment and we cannot reliably estimate this amount, we recognize revenues when the right to a refund or adjustment lapses. If we offer payment terms significantly in excess of our normal terms, we recognize revenues as the amounts become due and payable or upon the receipt of cash.

 

   

Collection is reasonably assured .    We conduct credit reviews at the inception of an arrangement to determine the creditworthiness of the customer. Collection is reasonably assured if, based upon evaluation, we expect that the customer will be able to pay amounts under the arrangement as payments become due. If we determine that collection is not reasonably assured, revenues are deferred and recognized upon the receipt of cash.

We maintain a reserve for customer adjustments and allowances as a reduction in revenues. In determining our revenue reserve estimate, and in accordance with internal policy, we rely on historical data and known performance adjustments. These factors, and unanticipated changes in the economic and industry environment, could cause our reserve estimates to differ from actual results. We record a provision for estimated customer adjustments and allowances in the same period as the related revenues are recorded. These estimates are based on the specific facts and circumstances of a particular program, analysis of credit memo data, historical customer adjustments, and other known factors. If the data we use to calculate these estimates do not properly reflect reserve requirements, then a change in the allowances would be made in the period in which such a determination was made and revenues in that period could be affected.

Revenues from grid operators and revenues from utilities principally represent demand response revenues. During the years ended December 31, 2014, 2013 and 2012, revenues from grid operators and utilities were comprised of $424.5 million, $342.1 million and $244.8 million, respectively, of demand response revenues.

Our enterprise revenues from the sales of our EIS and related solutions to our enterprise customers generally represent ongoing software or service arrangements under which the revenues are recognized ratably over the

 

67


Table of Contents

same period commencing upon delivery of the EIS and related solutions to the enterprise customer. Under certain of our arrangements, a portion of the fees received may be subject to adjustment or refund based on the validation of the energy savings delivered after the implementation is complete. As a result, we defer the portion of the fees that are subject to adjustment or refund until such time as the right of adjustment or refund lapses, which is generally upon completion and validation of the implementation.

Our EIS and related solutions for utility customers and electric power grid operators also include the demand response applications and solutions, EnerNOC Demand Resource and EnerNOC Demand Manager. Our grid operator revenues and utility revenues primarily reflect the sale of our EnerNOC Demand Resource solution. The revenues primarily consist of capacity and energy payments, including ancillary services payments, as well as payments derived from the effective management of our portfolio of demand response capacity, including our participation in capacity auctions and third-party contracts and ongoing fixed fees for the overall management of utility-sponsored demand response programs. We derive revenues from our EnerNOC Demand Resource solution by making demand response capacity available in open market programs and pursuant to contracts that we enter into with electric power grid operators and utilities. In certain markets, we enter into contracts with electric power utilities, generally ranging from three to ten years in duration, to deploy our EnerNOC Demand Resource solution. We refer to these contracts as utility contracts.

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

For further discussion of revenue recognition, please refer to Note 1 contained in Appendix A to the 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 values at the dates of acquisition. The fair value of identifiable intangible assets is based on detailed valuations that use information and assumptions provided by us. We estimate the fair value of contingent consideration at the time of the acquisition using all pertinent information known to us at the time to assess the probability of payment of contingent amounts. We allocate any excess purchase price over the fair value of the net tangible and intangible assets acquired and liabilities assumed to goodwill.

We primarily use the income approach to determine the estimated fair value of identifiable intangible assets, including customer relationships, non-compete agreements and trade names. This approach determines fair value by estimating the after-tax cash flows attributable to an in-process project over its useful life and then discounting these after-tax cash flows back to a present value. We base our revenue assumptions on estimates of relevant market sizes, expected market growth rates and expected trends, including introductions by competitors of new EIS and related solutions, services and products. We base the discount rate used to arrive at a present value as of the date of acquisition on the time value of money and market participant investment risk factors. The use of different assumptions could materially impact the purchase price allocation and our financial condition and results of operations.

We utilize the cost approach to determine the estimated fair value of acquired intangible assets related to acquired in-process research and development, given the stage of development as of the acquisition date, and the

 

68


Table of Contents

lack of sufficient information regarding future expected cash flows. The cost approach calculates fair value by calculating the reproduction cost of an exact replica of the subject intangible asset. We calculate the replacement cost based on actual development costs incurred through the date of acquisition. In determining the appropriate valuation methodology, we consider, among other factors: the in-process projects’ stage of completion; the complexity of the work completed as of the acquisition date; the costs already incurred; the projected costs to complete; the expected introduction date; and the estimated useful life of the technology. We believe that the estimated in-process research and development amounts, so determined, represented the fair value at the date of acquisition and did not exceed the amount a third party would pay for the projects.

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 ten 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 and discount rates. If these estimates or related assumptions change in the future, we may be required to record impairment charges. 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. If the estimate of an intangible asset’s remaining useful life is changed, we will amortize the remaining carrying value of the intangible asset prospectively over the revised remaining useful life.

During the years ended December 31, 2014, and 2013, we did not identify any adverse conditions or change in expected cash flows or useful lives of its definite-lived intangible assets that could indicate the existence of a potential impairment.

We had no indefinite-lived intangible assets as of December 31, 2014 and 2013, respectively.

In estimating the useful life of the acquired assets, we considered ASC 350-30-35, General Intangibles Other Than Goodwill (ASC 350-30-35), which lists the pertinent factors to be considered when estimating the useful life of an intangible asset. These factors include a review of the expected use by the combined Company of the assets acquired, the expected useful life of another asset (or group of assets) related to the acquired assets, legal, regulatory or other contractual provisions that may limit the useful life of an acquired asset or may enable the extension of the useful life of an acquired asset without substantial cost, the effects of obsolescence, demand, competition and other economic factors, and the level of maintenance expenditures required to obtain the expected future cash flows from the asset.

Goodwill

In accordance with ASC 350, Intangibles—Goodwill and Other (ASC 350), we test goodwill at the reporting unit level for impairment on an annual basis and between annual tests if events and circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying value. We have determined that we currently have two reporting units: (1) North America and Utility Bill Management (UBM) operations and (2) the International operations. Events that would indicate impairment and trigger an interim impairment assessment include, but are not limited to, current economic and market conditions, including a decline in market capitalization, a significant adverse change in legal factors, business climate or operational performance of the business, and an adverse action or assessment by a regulator. Our annual impairment test date is November 30 (Impairment Test Date).

In performing the test, we utilize the two-step approach prescribed under ASC 350. The first step requires a comparison of the carrying value of the reporting units to the fair value of these units. We consider a number of factors to determine the fair value of a reporting unit, including an independent valuation to conduct this test. The

 

69


Table of Contents

valuation is based upon expected future discounted operating cash flows of the reporting unit as well as analysis of recent sales or offerings of similar companies. We base the discount rate used to arrive at a present value as of the date of the impairment test on its weighted average cost of capital (WACC). If the carrying value of the reporting unit exceeds its fair value, we will perform the second step of the goodwill impairment test to measure the amount of impairment loss, if any. The second step of the goodwill impairment test compares the implied fair value of a reporting unit’s goodwill to its carrying value.

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

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

Impairment of Long-Lived Assets

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

During the years ended December 31, 2014, 2013 and 2012, we identified certain impairment indicators related to certain demand response equipment as a result of the removal of such equipment from operational sites during each of these respective years. As such, the equipment had no remaining useful life and no fair value. The remaining net carrying value was written off, resulting in the recognition of impairment charges of $1.1 million, $0.7 million, and $2.1 million, respectively, which is included in cost of revenues in the accompanying consolidated statements of operations.

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 who devote time to the development of internal-use computer software in addition to applicable third-party costs. We amortize these costs on a straight-line basis over the estimated useful life of the software, which is generally two 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 $6.0 million, $7.9 million and $4.7 million for the years ended December 31, 2014, 2013 and 2012, respectively, have been capitalized.

 

70


Table of Contents

The costs for the development of new software and substantial enhancements to existing software that is intended to be sold or marketed (external use software) are expensed as incurred until technological feasibility has been established, at which time any additional costs would be capitalized. We determine that technological feasibility of external use software is established at the time a working model of software is completed. Because we believe our current process for developing external use software will be essentially completed concurrently with the establishment of technological feasibility, no such costs have been capitalized to date.

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. For such awards, 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 which 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 recognized, 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. We consider a number of factors to determine the fair value of stock option awards. The model requires us to make estimates of the following assumptions:

Risk-free interest rate —The yield on zero-coupon U.S. Treasury securities, for a period that is commensurate with the award’s expected life, is used as the risk-free interest rate.

Vesting term —We use the weighted average vesting term of our stock option awards.

Expected volatility —We are responsible for estimating volatility and have considered a number of factors, including third-party estimates, when estimating volatility. We currently use a combination of historical and implied volatility, which is weighted based on a number of factors.

Expected dividend yield —We use a zero percent dividend yield because we have not paid dividends on our common stock in the past and do not plan to pay any dividends in the foreseeable future.

Exit rate pre-vesting and post-vesting —We use a forfeiture rate that is estimated based upon actual forfeitures one quarter in arrears for certain demographic employee pools. We believe that this historical data is currently the best estimate of the expected pre- and post-vesting forfeiture rates.

The fair value of stock awards where vesting is solely based on service vesting conditions is expensed ratably over the vesting period. With respect to certain awards of 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, Stock Compensation (ASC 718) over the vesting period.

Accounting for Income Taxes

We use the asset and liability method for accounting for income taxes. Under this method, we determine deferred tax assets and liabilities based on the difference between 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 deferred tax assets relate primarily to net operating losses and tax credit carryforwards, intangible assets, deferred revenue, and stock-based compensation. We have accumulated consolidated net losses since our inception and as a result, we have recorded a valuation allowance against certain of our deferred tax assets. Our deferred tax liabilities primarily relate to our acquisitions, depreciation of property and equipment, and the convertible debt issued in 2014.

 

71


Table of Contents

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.

We have $1.8 million and $0.6 million of unrecognized tax benefits as of December 31, 2014 and 2013, respectively.

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

In April 2014, the Financial Accounting Standards Board, or FASB, issued ASU No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (ASU 2014-08). ASU 2014-08 amends the definition of discontinued operations under ASC 205-20 to only those disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity’s operations and financial results will be reported as discontinued operations in the financial statements. This guidance is effective for all disposals (or classifications as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance. We have early adopted this guidance as of January 1, 2014. The adoption of this guidance was evaluated in connection with the sale of Utility Solutions Consulting and was deemed immaterial to our consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (ASU 2014-09). ASU 2014-09 provides guidance for revenue recognition and the standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. The new guidance is effective for annual and interim periods beginning after December 15, 2016, with no early adoption permitted. Therefore, ASU No 2014-09 will be effective for us beginning in the first quarter of fiscal year 2017, and allows for full retrospective adoption applied to all periods presented or retrospective adoption with the cumulative effect of initially applying this update recognized at the date of initial application. We have not yet determined the method of adoption and are currently in the process of evaluating the impact of adoption of this ASU on our consolidated financial position and results of operations.

 

72


Table of Contents

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, 2014

   1st Qtr      2nd Qtr      3rd Qtr(1)      4th Qtr  

Revenues

   $ 52,508      $ 44,055      $ 329,422      $ 45,963  

Gross profit

     16,369        16,253        160,858        21,146  

Operating expenses

     47,351        43,165        48,345        49,537  

(Loss) income from operations

     (30,982      (26,912      112,513        (28,391

Net (loss) income

     (30,433      (27,405      96,655        (26,820

Basic net (loss) income per share:

   $ (1.09    $ (0.96    $ 3.48      $ (0.98

Diluted net (loss) income per share:

   $ (1.09    $ (0.96    $ 3.11      $ (0.98

Year Ended December 31, 2013

   1st Qtr      2nd Qtr      3rd Qtr      4th Qtr  

Revenues

   $ 32,850      $ 36,153      $ 278,473      $ 35,984  

Gross profit

     10,653        12,280        152,401        15,834  

Operating expenses

     40,594        44,805        40,042        38,011  

(Loss) income from operations

     (29,941      (32,525      112,359        (22,177

Net (loss) income

     (30,537      (34,351      106,857        (19,881

Basic net (loss) income per share:

   $ (1.12    $ (1.23    $ 3.83      $ (0.71

Diluted net (loss) income per share:

   $ (1.12    $ (1.23    $ 3.70      $ (0.71

 

 

(1) We recorded certain adjustments related to the presentation of revenue and cost of revenue in our consolidated statement of operations for the three months ended September 30, 2014. We have historically recorded revenue and cost of revenues net (as an agent) for certain transactions with enterprise customers and upon further analysis during the quarter ended September 30, 2014, we concluded revenue and cost of revenues for these transactions should be recorded gross (as a principal). We assessed the materiality of the historical misstatements, individually and in the aggregate, on our prior annual and quarterly consolidated financial statements and concluded the effect of the error was not material to our consolidated financial statements for any of the periods. We recorded an adjustment in the consolidated statement of operations for the three months ended September 30, 2014 to correct the presentation of such revenues through the nine month period ended September 30, 2014. This correction resulted in an increase to both grid operator revenue and cost of revenue of $4,344 for the three month period ended September 30, 2014.

 

Item 7A. Quantitative and Qualitative Disclosure About Market Risk

Financial Instruments, Other Financial Instruments, and Derivative Commodity Instruments

ASC 825, Financial Instruments , requires disclosure about fair value of financial instruments. Financial instruments principally consist of cash equivalents, marketable securities, accounts receivable, and debt obligations. The fair value of these financial instruments approximates their carrying amount.

Foreign Currency Exchange Risk

Our international business is subject to risks, including, but not limited to unique economic conditions, changes in political climate, differing tax structures, other regulations and restrictions, and foreign exchange rate volatility. Accordingly, our future results could be materially adversely impacted by changes in these or other factors.

 

73


Table of Contents

A majority of our foreign expense and sales activities are transacted in local currencies, including Australian dollars, Euros, Brazilian real, British pounds, Canadian dollars, Indian rupee, Japanese yen, South Korean Won and New Zealand dollars. Fluctuations in the foreign currency rates could affect our sales, cost of revenues and profit margins and could result in exchange losses. In addition, currency devaluations can result in a loss if we maintain deposits or receivables (third party or intercompany) in a foreign currency. During each of the years ended December 31, 2014, 2013 and 2012, our sales generated outside the United States were 21%, 19% and 12%, respectively. We anticipate that sales generated outside the United States will continue to represent greater than 10% of our consolidated sales and will continue to grow in subsequent fiscal years.

The operating expenses of our international subsidiaries that are incurred in local currencies did not have a material adverse effect on our business, results of operations or financial condition for fiscal 2014. Our operating results and certain assets and liabilities that are denominated in foreign currencies are affected by changes in the relative strength of the U.S. dollar against the applicable foreign currency. Our operating expenses denominated in foreign currencies are positively affected when the U.S. dollar strengthens against the applicable foreign currency and adversely affected when the U.S. dollar weakens.

During the years ended December 31, 2014, 2013 and 2012, we recognized foreign exchange (losses) gains of ($4.4) million, ($1.7) million and $1.1 million, respectively. This primarily relates to intercompany receivables denominated in foreign currencies, largely driven by fluctuations to the U.S. dollar in the Euro, and Australian dollar.

We currently do not have a program in place that is designed to mitigate our exposure to changes in foreign currency exchange rates. We are evaluating certain potential programs, including the use of derivative financial instruments, to reduce our exposure to foreign exchange gains and losses, and the volatility of future cash flows caused by changes in currency exchange rates. The utilization of forward foreign currency contracts would reduce, but would not eliminate, the impact of currency exchange rate movements.

Interest Rate Risk

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

As of December 31, 2014, we had no aggregate principal amount outstanding under the 2014 credit facility, but had outstanding letters of credit totaling $22.8 million under the 2014 credit facility.

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

 

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.

 

74


Table of Contents
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, 2014. 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.

Our assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of the recently acquired Entech US and Entech UK, Entelios AG, Activation Energy DSU Limited, Universal Load Center Co., Ltd, and Pulse Energy Inc. These operations comprised $75.6 million of total assets as of December 31, 2014 and $11.9 million of revenues for the year then ended.

Based on this assessment, management believes that, as of December 31, 2014, 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, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

75


Table of Contents

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, 2014 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.

As indicated in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Pulse Energy, Entech US and Entech UK, Entelios AG, Activation Energy DSU Limited and Universal Load Center Co., Ltd., which is included in the 2014 consolidated financial statements of EnerNOC, Inc. and constituted $75.6 million of total assets as of December 31, 2014 and $11.9 million of revenues for the year then ended. Our audit of internal control over financial reporting of EnerNOC, Inc. also did not include an evaluation of the internal control over financial reporting of Pulse Energy Inc., Entech US and Entech UK, Entelios AG, Activation Energy DSU Limited and Universal Load Center Co., Ltd.

In our opinion, EnerNOC, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, 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, 2014 and December 31, 2013, and the related consolidated statements of operations, comprehensive income (loss), changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2014 of EnerNOC, Inc. and our report dated March 12, 2015 expressed an unqualified opinion thereon.

Boston, Massachusetts

March 12, 2015

 

76


Table of Contents
Item  9B. Other Information

Not applicable.

PART III

 

Item  10. Directors, Executive Officers and Corporate Governance

The information required by this Item will be contained in our definitive proxy statement for our 2015 Annual Meeting of Stockholders under the captions “Directors and Executive Officers,” “Corporate Governance and Board Matters—Corporate Code of Conduct and Ethics,” “Corporate Governance and Board Matters—Procedures for Recommending Nominees for Our Board of Directors,” “Corporate Governance and Board Matters—Committees of the Board of Directors—Audit Committee,” and “Section 16(a) Beneficial Ownership Reporting Compliance” and is incorporated by reference herein.

 

Item  11. Executive Compensation

The information required by this Item will be contained in our definitive proxy statement for our 2015 Annual Meeting of Stockholders under the captions “Information About Executive and Director Compensation,” “Corporate Governance and Board Matters—Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report” and is incorporated by reference herein.

 

Item  12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this Item will be contained in our definitive proxy statement for our 2015 Annual Meeting of Stockholders under the captions “Equity Compensation Plan Information” and “Security Ownership of Certain Beneficial Owners and Management” and is incorporated by reference herein.

 

Item  13. Certain Relationships and Related Transactions, and Director Independence

The information required by this Item will be contained in our definitive proxy statement for our 2015 Annual Meeting of Stockholders under the captions “Certain Relationships and Related Transactions” and “Corporate Governance and Board Matters—Board Determination of Independence” and is incorporated by reference herein.

 

Item  14. Principal Accounting Fees and Services

The information required by this Item will be contained in our definitive proxy statement for our 2015 Annual Meeting of Stockholders under the proposal captioned “Ratification of Appointment of Independent Registered Public Accounting Firm” and is incorporated by reference herein.

PART IV

 

Item  15. Exhibits, Financial Statement Schedules

 

(a) The following are filed as part of this Annual Report on Form 10-K:

 

1. Financial Statements

The following consolidated financial statements beginning on page F-1 of Appendix A are included in this Annual Report on Form 10-K:

 

   

Report of Independent Registered Public Accounting Firm

 

   

Consolidated Balance Sheets as of December 31, 2014 and 2013

 

   

Consolidated Statements of Operations for the Years ended December 31, 2014, 2013 and 2012

 

   

Consolidated Statements of Comprehensive Income (Loss) for the Years ended December 31, 2014, 2013 and 2012

 

77


Table of Contents
   

Consolidated Statements of Changes in Stockholders’ Equity for the Years ended December 31, 2014, 2013 and 2012

 

   

Consolidated Statements of Cash Flows for the Years ended December 31, 2014, 2013 and 2012

 

   

Notes to Consolidated Financial Statements

 

(b) Exhibits

The exhibits listed in the Exhibit Index immediately preceding the exhibits are filed with or incorporated by reference in this Annual Report on Form 10-K.

 

(c) Financial Statement Schedules

All other schedules have been omitted since the required information is not present, or not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or the Notes thereto.

 

78


Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

    EnerNOC, Inc.
Date: March 12, 2015   By:   / S /     T IMOTHY G. H EALY
   

 

    Name:   Timothy G. Healy
    Title:   Chairman of the Board and
Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

Signature

  

Title

  

Date

/ S / T IMOTHY G. H EALY

Timothy G. Healy

  

Chairman of the Board,

Chief Executive Officer and Director (principal executive officer)

   March 12, 2015

/ S / N EIL M OSES

Neil Moses

  

Chief Financial Officer and Chief Operating Officer (principal financial and principal accounting officer)

   March 12, 2015

/ S / D AVID B. B REWSTER

David B. Brewster

  

Director and President

   March 12, 2015

/ S / K IRK A RNOLD

Kirk Arnold

  

Director

   March 12, 2015

/ S / J AMES P. B AUM

James P. Baum

  

Director

   March 12, 2015

/ S / A RTHUR W. C OVIELLO , J R .

Arthur W. Coviello, Jr.

  

Director

   March 12, 2015

/ S / R ICHARD D IETER

Richard Dieter

  

Director

   March 12, 2015

/ S / TJ G LAUTHIER

TJ Glauthier

  

Director

   March 12, 2015

/ S / P ETER G YENES

Peter Gyenes

  

Director

   March 12, 2015

 

79


Table of Contents

APPENDIX A

EnerNOC, Inc.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

     Page  

Consolidated Financial Statements of EnerNOC, Inc.:

  

Report of Independent Registered Public Accounting Firm

     F-2   

Consolidated Balance Sheets as of December 31, 2014 and 2013

     F-3   

Consolidated Statements of Operations for the Years Ended December 31, 2014, 2013 and 2012

     F-4   

Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December  31, 2014, 2013 and 2012

     F-5   

Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December  31, 2014, 2013 and 2012

     F-6   

Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012

     F-7   

Notes to Consolidated Financial Statements

     F-8   

 

F-1


Table of Contents

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

EnerNOC, Inc.

We have audited the accompanying consolidated balance sheets of EnerNOC, Inc. as of December 31, 2014 and December 31, 2013, and the related consolidated statements of operations, comprehensive income (loss), changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits 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 the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of EnerNOC, Inc. at December 31, 2014 and December 31, 2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), EnerNOC, Inc.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 12, 2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Boston, Massachusetts

March 12, 2015

 

F-2


Table of Contents

EnerNOC, Inc.

CONSOLIDATED BALANCE SHEETS

(in thousands, except par value and share data)

 

     December 31,  
     2014     2013  

Assets

  

Current assets

    

Cash and cash equivalents

   $ 254,351     $ 149,189  

Restricted cash

     813       1,834  

Trade accounts receivable, net of allowance for doubtful accounts of $679 and $454 at December 31, 2014 and 2013, respectively

     40,875       35,933  

Unbilled revenue

     97,512       66,675  

Capitalized incremental direct customer contract costs

     7,633       9,509  

Deferred tax assets

     6,524       1,443  

Prepaid expenses and other current assets

     12,613       5,419  

Assets held for sale

           681  
  

 

 

   

 

 

 

Total current assets

     420,321       270,683  

Property and equipment, net of accumulated depreciation of $94,976 and $75,810 at December 31, 2014 and 2013, respectively

     50,458       47,419  

Goodwill

     114,939       77,104  

Intangible assets, net

     31,111       17,186  

Capitalized incremental direct customer contract costs, net of current portion

     982       1,995  

Deferred tax assets

     680       235  

Deposits and other assets

     6,211       1,333  
  

 

 

   

 

 

 

Total assets

   $ 624,702     $ 415,955  
  

 

 

   

 

 

 

Liabilities and Stockholders’ Equity

    

Current liabilities

    

Accounts payable

   $ 9,250     $ 2,031  

Accrued capacity payments

     92,332       76,676  

Accrued payroll and related expenses

     18,446       13,370  

Accrued expenses and other current liabilities

     28,724       11,865  

Deferred revenue

     13,738       20,625  

Liabilities held for sale

           521  
  

 

 

   

 

 

 

Total current liabilities

     162,490       125,088  

Accrued acquisition consideration

     1,198       566  

Convertible senior notes

     138,908        

Deferred tax liability

     16,449       6,211  

Deferred revenue

     5,816       6,819  

Other liabilities

     7,721       7,776  

Commitments and contingencies (Note 15)

            

Stockholders’ equity

    

Undesignated preferred stock, $0.001 par value; 5,000,000 shares authorized; no shares issued

            

Common stock, $0.001 par value; 50,000,000 shares authorized, 29,833,578 and 29,920,807 shares issued and outstanding at December 31, 2014 and 2013, respectively

     30       30  

Additional paid-in capital

     365,855       353,354  

Accumulated other comprehensive loss

     (4,752     (2,535

Accumulated deficit

     (69,260     (81,354
  

 

 

   

 

 

 

Total EnerNOC, Inc. stockholders’ equity

     291,873       269,495  

Noncontrolling interest

     247        
  

 

 

   

 

 

 

Total stockholders’ equity

     292,120       269,495  
  

 

 

   

 

 

 

Total liabilities and stockholders’ equity

   $ 624,702     $ 415,955  
  

 

 

   

 

 

 

 

F-3


Table of Contents

EnerNOC, Inc.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share and per share data)

 

     Year Ended December 31,  
     2014     2013     2012  

Revenues

      

Grid operator

   $ 368,828     $ 279,258     $ 176,792  

Utility

     62,026       71,611       77,600  

Enterprise

     41,094       32,591       23,592  
  

 

 

   

 

 

   

 

 

 

Total revenues

     471,948       383,460       277,984  

Cost of revenues

     257,322       192,292       154,540  
  

 

 

   

 

 

   

 

 

 

Gross profit

     214,626       191,168       123,444  

Operating expenses (income):

      

Selling and marketing

     76,960       65,915       55,963  

General and administrative

     97,729       79,220       71,643  

Research and development

     20,671       18,317       16,226  

Gain on sale of service lines (Note 16)

     (4,791            

Gain on the sale of assets (Note 17)

     (2,171            
  

 

 

   

 

 

   

 

 

 

Total operating expenses and income

     188,398       163,452       143,832  
  

 

 

   

 

 

   

 

 

 

Income (loss) from operations

     26,228       27,716       (20,388

Other (expense) income, net

     (3,699     (1,342     1,457  

Interest expense

     (4,656     (1,646     (1,591
  

 

 

   

 

 

   

 

 

 

Income (loss) before income tax

     17,873       24,728       (20,522

Provision for income tax

     (5,876     (2,640     (1,771
  

 

 

   

 

 

   

 

 

 

Net income (loss)

     11,997       22,088       (22,293

Net loss attributable to noncontrolling interest

     (97            
  

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to EnerNOC, Inc.

   $ 12,094     $ 22,088     $ (22,293
  

 

 

   

 

 

   

 

 

 

Net income (loss) per common share

      

Basic

   $ 0.43     $ 0.80     $ (0.84

Diluted

   $ 0.42     $ 0.76     $ (0.84

Weighted average number of common shares used in computing net income (loss) per common share

      

Basic

     27,857,026       27,774,778       26,551,234  

Diluted

     28,790,665       29,045,066       26,551,234  

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

 

F-4


Table of Contents

EnerNOC, Inc.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

 

     Year Ended December 31,  
             2014                     2013                     2012          

Net income (loss)

   $ 11,997     $ 22,088     $ (22,293

Foreign currency translation adjustments

     (2,261     (1,833     253  
  

 

 

   

 

 

   

 

 

 

Comprehensive income (loss)

     9,736       20,255       (22,040

Comprehensive loss attributable to noncontrolling interest

     (141            
  

 

 

   

 

 

   

 

 

 

Comprehensive income (loss) attributable to EnerNOC, Inc.

   $ 9,877     $ 20,255     $ (22,040
  

 

 

   

 

 

   

 

 

 

 

 

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

 

F-5


Table of Contents

EnerNOC, Inc.

CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDERS’ EQUITY

(in thousands, except share data)

 

    Common Stock     Additional
Paid in
Capital
    Accumulated
Other

Comprehensive
Loss
    Accumulated
Deficit
    Noncontrolling
Interest
    Total  
    Number of
Shares
    Amount            

Balances as of December 31, 2011

    27,306,548     $ 27     $ 329,817     $ (955   $ (81,149   $     $ 247,740  

Issuance of common stock upon exercise of stock options

    189,385         356             356  

Issuance of restricted stock

    1,581,878       2       (2            

Vesting of restricted stock units

    92,042